Harvest Oil & Gas Corp. - Annual Report: 2008 (Form 10-K)
UNITED
STATES
SECURITIES AND EXCHANGE
COMMISSION
Washington,
D.C. 20549
FORM 10–K
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þ
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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, 2008
OR
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o
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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Commission
File Number
001-33024
EV
Energy Partners, L.P.
(Exact
name of registrant as specified in its charter)
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Delaware
(State
or other jurisdiction of incorporation or organization)
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20–4745690
(I.R.S.
Employer Identification No.)
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1001
Fannin, Suite 800, Houston, Texas
(Address
of principal executive offices)
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77002
(Zip
Code)
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Registrant’s
telephone number, including area code: (713) 651-1144
Securities
registered pursuant to Section 12(b) of the Act:
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Common
Units Representing Limited Partner Interests
(Title
of each class)
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NASDAQ
Stock Market LLC
(Name
of each exchange on which
registered)
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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 if disclosure of delinquent filers pursuant to Item 405 of
Regulation S–K is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III or any amendment to the
Form
10–K. 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 definition of “large accelerated filer,” “accelerated
filer” and “smaller reporting company” in Rule 12b–2 of the Exchange
Act. Check one:
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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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Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b–2 of the Exchange Act).
YES o NO þ
The
aggregate market value of the common units held by non–affiliates at June 30,
2008 based on the closing price on the NASDAQ Global Market on June 30, 2008 was
$335,643,089.
As of
March 2, 2009, the registrant had 13,130,471 common units
outstanding.
GLOSSARY OF OIL AND NATURAL GAS TERMS
Bbl. One stock tank barrel or
42 U.S. gallons liquid volume.
Bcf. One billion cubic
feet.
Bcfe. One billion cubic feet
equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of
oil, condensate or natural gas liquids.
Btu. A British thermal unit
is a measurement of the heat generating capacity of natural gas. One
Btu is the heat required to raise the temperature of a one–pound mass of pure
liquid water one degree Fahrenheit at the temperature at which water has its
greatest density (39 degrees Fahrenheit).
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.
Developed acres. Acres spaced
or assigned to productive wells.
Dry hole or well. A well found to be
incapable of producing hydrocarbons in sufficient quantities such that proceeds
from the sale of such production would exceed production expenses and
taxes.
Field. An area consisting of
a single reservoir or multiple reservoirs all grouped on or related to the same
individual geological structural feature and/or stratigraphic
condition.
Gross acres or gross wells. The total acres
or wells, as the case may be, in which a working interest is
owned.
MBbls. One thousand barrels
of oil or other liquid hydrocarbons.
Mcf. One thousand cubic
feet.
Mcfe. One thousand cubic feet
equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of
oil, condensate or natural gas liquids.
MMBbls. One million
barrels.
MMBtu. One million British
thermal units.
MMcf. One million cubic
feet.
Natural gas liquids. The
hydrocarbon liquids contained within natural gas.
Net acres or net wells. The sum of the
fractional working interests owned in gross acres or gross wells, as the case
may be.
NYMEX. The New York
Mercantile Exchange.
Oil. Crude oil and
condensate.
Productive well. A well that
is found to be capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceeds production expenses and
taxes.
Proved reserves. Proved oil
and natural gas reserves, as defined by the Securities and Exchange Commission
(the “SEC”) in Article 4–10(a)(2) of Regulation S–X, are the estimated
quantities of oil, natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e.,
prices and costs as of the date the estimate is made. Prices include
consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based on future
conditions. Comprehensive SEC oil and natural gas reserve definitions
can be found on the SEC’s website at www.sec.gov/about/forms/forms-x.pdf.
Proved developed reserves.
Reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and natural
gas expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery are included in “proved developed reserves” only after
testing by a pilot project or after the operation of an installed program has
confirmed through production response that increased recovery will be
achieved.
Proved undeveloped drilling
location. A site on which a development well can be drilled consistent
with spacing rules for purposes of recovering proved undeveloped
reserves.
Proved undeveloped reserves
or PUDs.
Reserves that are expected to be recovered from new wells on undrilled acreage
or from existing wells where a relatively major expenditure is required for
recompletion. Reserves on undrilled acreage are limited to those drilling units
offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units are claimed only where it can
be demonstrated with certainty that there is continuity of production from the
existing productive formation. Estimates for proved undeveloped reserves are not
attributed to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same
reservoir.
Recompletion. The completion
for production of an existing wellbore in another formation from that which the
well has been previously completed.
Reservoir. A porous and
permeable underground formation containing a natural accumulation of produceable
oil and/or natural gas that is confined by impermeable rock or water barriers
and is individual and separate from other reserves.
Standardized measure. Standardized measure
is the present value of estimated future net revenues to be generated from the
production of proved reserves, determined in accordance with the rules and
regulations of the Securities and Exchange Commission (using prices and costs in
effect as of the date of estimation) without giving effect to non–property
related expenses such as certain general and administrative expenses, debt
service and future federal income tax expenses or to depreciation, depletion and
amortization and discounted using an annual discount rate of 10%. Our
standardized measure includes future obligations under the Texas gross margin
tax, but it does not include future federal income tax expenses because we are a
partnership and are not subject to federal income taxes.
Successful well. A well
capable of producing oil and/or natural gas in commercial
quantities.
Undeveloped acreage. Lease
acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of natural gas and oil regardless
of whether such acreage contains proved reserves.
Working interest. The
operating interest that gives the owner the right to drill, produce and conduct
operating activities on the property and a share of
production.
Workover. Operations on a
producing well to restore or increase production.
References
in this Annual Report on Form 10–K to “EV Energy Partners, L.P.,” “we,” “our” or
“us” or like terms when used in a historical context prior to October 1,
2006 refer to the combined operations of CGAS Exploration, Inc. and
EV Properties, L.P. (collectively, the “Predecessors”). When used in
a historical context on or after October 1, 2006, the present tense or
prospectively, those terms refer to EV Energy Partners, L.P. and its
subsidiaries. Reference to “EnerVest” refers to EnerVest, Ltd. and
its partnerships and other entities under common ownership.
Overview
We are a
Delaware limited partnership formed in April 2006 by EnerVest to acquire,
produce and develop oil and natural gas properties. Our general
partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership,
and the general partner of our general partner is EV Management, LLC (“EV
Management”), a Delaware limited liability company. Our common units
are traded on the NASDAQ Global Market under the symbol “EVEP.” Our
business activities are primarily conducted through wholly–owned
subsidiaries.
We
operate in one reportable segment engaged in the exploration, development and
production of oil and natural gas properties. At December 31, 2008,
our properties were located in the Appalachian Basin (primarily in Ohio and West
Virginia), Michigan, the Monroe Field in Northern Louisiana, Central and East
Texas (which includes the Austin Chalk area), the Permian Basin, the San Juan
Basin and the Mid–Continent areas in Oklahoma, Texas, Kansas and Louisiana, and
we had estimated net proved reserves of 5.9 MMBbls of oil, 266.0 Bcf of
natural gas and 9.6 MMBbls of natural gas liquids, or 359.2 Bcfe, and a present
value of future net pre-tax cash flows discounted at 10% of $442.9 million.
The
decrease in commodity prices at December 31, 2008 compared with December 31,
2007 had a significant impact on our estimated net proved reserves at December
31, 2008. The prices used in determining our estimated net proved
reserves at December 31, 2008 were $44.60 per Bbl of oil, $5.71 per MMBtu
of natural gas and $25.38 per Bbl of natural gas liquids as compared with $95.95
per Bbl of oil, $6.795 per MMBtu of natural gas and $57.50 per Bbl of natural
gas liquids at December 31. 2007. Had the commodity prices at
December 31, 2008 been the same as those in effect at December 31, 2007, our
estimated net proved reserves at December 31, 2008 would have been approximately
17% higher and the present value of future net pre-tax cash flows discounted at
10% at December 31, 2008 would have been approximately 87% higher.
Oil and
natural gas reserve information is derived from our reserve report prepared by
Cawley, Gillespie & Associates, Inc., our independent reserve
engineers. The following table summarizes information about our oil and
natural gas reserves by geographic region as of December 31,
2008:
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Estimated
Net Proved Reserves
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||||||||||||||||||||
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Oil
(MMBbls)
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Natural
Gas (Bcf)
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Natural
Gas
Liquids (MMBbls)
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Bcfe
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PV–10 (1)
($
in millions)
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||||||||||||||||
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Appalachian
Basin
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1.0 | 47.6 | – | 53.3 | $ | 88.3 | ||||||||||||||
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Michigan
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– | 53.4 | – | 53.4 | 55.5 | |||||||||||||||
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Monroe
Field
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– | 71.5 | – | 71.5 | 64.8 | |||||||||||||||
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Central
and East Texas
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2.1 | 16.9 | 1.8 | 40.4 | 65.5 | |||||||||||||||
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Permian
Basin
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0.5 | 23.6 | 4.0 | 50.8 | 67.5 | |||||||||||||||
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San
Juan Basin
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1.2 | 36.5 | 3.8 | 66.2 | 64.1 | |||||||||||||||
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Mid–Continent
area
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1.1 | 16.5 | – | 23.6 | 37.2 | |||||||||||||||
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Total
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5.9 | 266.0 | 9.6 | 359.2 | $ | 442.9 | ||||||||||||||
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(1)
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At
December 31, 2008 our standardized measure of discounted future net
cash flows as calculated in accordance with Statement of Financial
Accounting Standards (“SFAS”) No. 69, Disclosures About Oil and Gas
Producing Activities, was $441.9 million. Because we are a
limited partnership, we made no provision for federal income taxes in the
calculation of standardized measure; however, we made a provision for
future obligations under the Texas gross margin tax. The
present value of future net pre–tax cash flows attributable to estimated
net proved reserves, discounted at 10% per annum (“PV–10”), is a
computation of the standardized measure of discounted future net cash
flows on a pre tax
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basis.
PV–10 is computed on the same basis as standardized measure but does
not include a provision for federal income taxes or the Texas gross margin
tax. PV–10 may be considered a non–GAAP financial measure under
the SEC’s regulations. We believe PV–10 to be an important measure
for evaluating the relative significance of our oil and natural gas
properties. We further believe investors and creditors may
utilize our PV–10 as a basis for comparison of the relative size and value
of our reserves to other companies. PV–10, however, is not a
substitute for the standardized measure. Our PV–10 measure and the
standardized measure do not purport to present the fair value of our oil
and natural gas reserves.
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The table
below provides a reconciliation of PV–10 to the standardized measure at
December 31, 2008 (dollars in millions):
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PV–10
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$ | 442.9 | ||
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Future
Texas gross margin taxes, discounted at 10%
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(1.0 | ) | ||
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Standardized
measure
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$ | 441.9 |
Developments
in 2008
In 2008,
we completed the following acquisitions:
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·
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in
May, we acquired oil properties in South Central Texas (the “Charlotte
acquisition”) for $17.4 million;
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·
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in
August 2008, we acquired oil and natural gas properties in Michigan,
Central and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle
and Kansas) and Eastland County, Texas (the “August acquisitions”) for
$58.8 million;
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·
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in
September 2008, we issued 236,169 of our common units to acquire natural
gas properties in West Virginia (the “West Virginia acquisition”) from
EnerVest;
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·
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in
September 2008, we acquired oil and natural gas properties in the San Juan
Basin (the “San Juan acquisition”) from institutional partnerships managed
by EnerVest for $114.7 million in cash and 908,954 of our common
units.
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Business
Strategy
Our
primary business objective is to provide stability and growth in our cash
distributions per unit over time. We intend to accomplish this objective
by executing the following business strategies:
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·
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replace
and increase our reserves and production over the long term by pursuing
acquisitions of long–lived producing oil or natural gas properties with
low decline rates, predictable production profiles and relatively low risk
drilling opportunities;
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·
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maintain
conservative levels of indebtedness to reduce risk and facilitate
acquisition opportunities;
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·
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reduce
exposure to commodity price risk through
hedging;
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·
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establish
an inventory of proved undeveloped reserves sufficient to mitigate
production declines;
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·
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retain
control over the operation of a substantial portion of our
production; and
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·
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focus
on controlling the costs of our
operations.
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Competitive
Strengths
We
believe that we are well positioned to achieve our primary business objective
and to execute our strategies because of the following competitive
strengths:
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·
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Drilling inventory. We
have a substantial inventory of low risk, proved undeveloped drilling
locations.
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·
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Long life reserves with predictable decline rates. Our
properties generally have a long reserve to production index, with
predictable decline rates.
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·
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Experienced management team. Our
management is experienced in oil and natural gas acquisitions and
operations. Our executive officers average over 25 years of
industry experience and over ten years of experience acquiring and
managing oil and natural gas properties for EnerVest
partnerships.
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·
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Relationship with
EnerVest. Our relationship with EnerVest provides us
with a wide breadth of operational, technical, risk management and other
expertise across a wide geographical range, which will assist us in
evaluating acquisition and development opportunities. EnerVest’s
primary business is to acquire and manage oil and natural gas properties
for partnerships formed with institutional investors. These
partnerships focus on maximizing investment returns for investees,
including the sale of oil and natural gas
properties.
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Our Relationship with
EnerVest
One of
our principal attributes is our relationship with EnerVest. Through
our omnibus agreement, EnerVest agrees to make available its personnel to permit
us to carry on our business. We therefore benefit from the technical
expertise of EnerVest, which we believe would generally not otherwise be
available to a company of our size.
EnerVest’s
principal business is to act as general partner or manager of EnerVest
partnerships, formed to acquire, explore, develop and produce oil and natural
gas properties. A primary investment objective of the EnerVest
partnerships is to make periodic cash distributions. EnerVest was formed
in 1992, and has acquired for its own account and for the EnerVest partnerships
oil and natural gas properties for a total purchase price of more than
$3.2 billion, which includes over $700 million related to our acquisitions
of oil and natural gas properties. EnerVest acts as an operator of over
12,400 oil and natural gas wells in 11 states.
EnerVest
and its affiliates have a significant interest in our partnership through their
71.25% ownership of our general partner, which, in turn, owns a 2% general
partner interest in us and all of our incentive distribution rights.
Additionally, as of March 2, 2009, EnerVest owned an aggregate of
0.5% of our outstanding common units and 57.0% of our outstanding subordinated
units. At the closing of our initial public offering, we entered into
the omnibus agreement with EnerVest that governs our relationship with them
regarding certain reimbursement and indemnification matters.
While our
relationship with EnerVest is a significant attribute, it is also a source of
potential conflicts. For example, we have acquired oil and natural gas
properties from partnerships formed by EnerVest and partnerships in which
EnerVest has an interest, and we may do so in the future. In
addition, EnerVest is not restricted from competing with us. It may
acquire, develop or dispose of oil and natural gas properties or other assets in
the future without any obligation to offer us the opportunity to purchase or
participate in the development of those assets. In addition, the principal
business of the EnerVest partnerships is to acquire and develop oil and natural
gas properties. Properties targeted by the EnerVest partnerships for
acquisition typically have a lower amount of proved producing reserves and
higher risk exploitation and development opportunities than the properties that
we will target. The agreement for one of the current EnerVest
partnerships, however, provides that if EnerVest becomes aware, other than in
its capacity as an owner of our general partner, of acquisition opportunities
that are suitable for purchase by the EnerVest partnership, EnerVest must first
offer those opportunities to that EnerVest partnership, in which case we would
be offered the opportunities only if the EnerVest partnership chose not to
pursue the acquisition. EnerVest’s obligation to offer acquisition
opportunities to its existing EnerVest partnership will not apply to acquisition
opportunities which we generate internally, and EnerVest has agreed with us that
for so long as it controls our general partner it will not enter into any
agreements which would limit our ability to pursue acquisition opportunities
that we generate internally.
Our Areas of
Operation
At
December 31, 2008, our properties were located in the Appalachian Basin
(primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern
Louisiana, Central and East Texas (which includes the Austin Chalk area), the
Permian Basin, the San Juan Basin and the Mid–Continent areas in Oklahoma,
Texas, Kansas and Louisiana.
Appalachian
Basin
We
acquired our Appalachian Basin properties at our formation, and we acquired
additional properties in the Appalachian Basin, primarily in West Virginia, in
December 2007 and September 2008. Our activities are concentrated in
the Ohio and West Virginia areas of the Appalachian Basin. Our Ohio area
properties are producing primarily from the Clinton formation and other Devonian
age sands in 22 counties in Eastern Ohio and two counties in Western
Pennsylvania. Our West Virginia area properties are producing primarily
from the Balltown, Benson and Big Injun formations in 22 counties in North
Central West Virginia and one county in Southwestern
Pennsylvania. Our estimated net proved reserves as of December 31,
2008 were 53.3 Bcfe, 89% of which is natural gas. During the year
ended December 31, 2008, we drilled ten wells, all of which were successfully
completed as producers. EnerVest operated wells representing 97% of
our estimated net proved reserves in this area, and we own an average 92%
working interest in 1,401 gross producing wells.
Michigan
We
acquired our Michigan properties in January 2007, and we acquired additional
properties in Michigan in August 2008. The properties are located in
the Antrim Shale reservoir in Otsego and Montmorency counties in northern
Michigan. Our estimated net proved reserves as of December 31, 2008
were 53.4 Bcfe, 100% of which is natural gas. During the year ended
December 31, 2008, we recompleted three wells and deepened one well, all of
which were successfully completed as producers. EnerVest operated
wells representing 98% of our estimated net proved reserves in this area, and we
have an average 85% working interest in 373 gross producing wells.
Monroe
Field
We
acquired our Monroe Field properties at our formation, and we acquired
additional properties in the Monroe Field in March 2007. The
properties are located in three parishes in Northeast Louisiana. Our
estimated net proved reserves as of December 31, 2008 were 71.5 Bcfe, 100% of
which is natural gas. During the year ended December 31, 2008, we
drilled six wells, one of which was successfully completed as a
producer. Three of the remaining five wells are awaiting completion
in 2009. EnerVest operated wells representing 100% of our estimated
net proved reserves in this area, and we own an average 100% working interest in
3,957 gross producing wells.
Central
and East Texas
We, along
with certain institutional partnerships managed by EnerVest, acquired our
Central and East Texas properties in June 2007, May 2008 and August
2008. The properties are primarily located in the Austin Chalk
formation in 12 counties in Central and East Texas, as well as Atascosa and
Eastland counties in Texas. Our portion of the estimated net proved
reserves as of December 31, 2008 was 40.4 Bcfe, 42% of which is natural
gas. During the year ended December 31, 2008, we drilled 21 wells,
all of which were successfully completed as producers. EnerVest
operated wells representing 89% of our estimated net proved reserves in this
area, and we own an average 17% working interest in 1,693 gross producing
wells.
Permian
Basin
We
acquired our Permian Basin properties in October 2007. The properties
are primarily located in the Yates, Seven Rivers, Queen, Morrow, Clear Fork and
Wichita Albany formations in four counties in New Mexico and
Texas. Our estimated net proved reserves as of December 31, 2008 were
50.8 Bcfe, 47% of which is natural gas. During the year ended
December 31, 2008, we drilled 14 wells, all of which were successfully completed
as producers. EnerVest operated wells representing 100% of our
estimated net proved reserves in this area, and we own an average 89%
working interest in 158 gross producing wells.
San
Juan Basin
We
acquired our San Juan Basin properties in September 2008. The
properties are primarily located in Rio Arriba County, New Mexico and La Plata
County in Colorado. Our estimated net proved reserves as of
December 31, 2008 were 66.2 Bcfe, 55% of which is natural
gas. During the year ended December 31, 2008, we drilled one well,
which was successfully completed as a producer. EnerVest operated
wells representing 95% of our estimated net proved reserves in this area, and we
own an average 87% working interest in 186 gross producing
wells.
Mid–Continent
Area
We
acquired our Mid–Continent area properties in December 2006, August 2008 and
September 2008. The properties are primarily located in 25 counties
in Western Oklahoma, 15 counties in Texas, four parishes in North Louisiana and
six counties in Kansas. Our estimated net proved reserves as of
December 31, 2008 were 23.6 Bcfe, 70% of which is natural
gas. During the year ended December 31, 2008, we drilled eight wells,
all of which were successfully completed as producers. EnerVest
operated wells representing 42% of our estimated net proved reserves in this
area, and we own an average 24% working interest in 557 gross
producing wells.
Our Oil and Natural Gas
Data
Our
Reserves
The
following table presents our estimated net proved oil and natural gas reserves
and the present value of our estimated net proved reserves at December 31,
2008:
|
Reserve
Data:
|
||||
|
Estimated net proved
reserves:
|
||||
|
Oil (MMBbls)
|
5.9 | |||
|
Natural gas liquids
(MMBbls)
|
9.6 | |||
|
Natural gas
(Bcf)
|
266.0 | |||
|
Total (Bcfe)
|
359.2 | |||
|
Proved developed
(Bcfe)
|
340.9 | |||
|
Proved undeveloped
(Bcfe)
|
18.3 | |||
|
Proved developed reserves as a %
of total proved reserves
|
94.9 | % | ||
|
Standardized measure (in
millions)
|
$ | 441.9 | ||
Proved
developed reserves are reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved
undeveloped reserves are proved reserves that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion. See “Glossary of Oil and
Natural Gas Terms.”
The data
in the above table represents estimates only. Oil and natural gas reserve
engineering is inherently a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured exactly. The
accuracy of any reserve estimate is a function of the quality of available data
and engineering and geological interpretation and judgment. Accordingly,
reserve estimates may vary from the quantities of oil and natural gas that are
ultimately recovered. Please read “Risk Factors” in Item 1A.
Future
prices received for production and costs may vary, perhaps significantly, from
the prices and costs assumed for purposes of these estimates. Standardized
measure is the present value of estimated future net revenues to be generated
from the production of proved reserves, determined in accordance with the rules
and regulations of the SEC (using prices and estimated costs in effect as of the
date of estimation) without giving effect to non–property related expenses such
as certain general and administrative expenses and debt service or to
depreciation, depletion and amortization and discounted using an annual discount
rate of 10%. Because we are a limited partnership which passes through our
taxable income to our unitholders, we have made no provisions for federal income
taxes in the calculation of standardized measure; however, we have made a
provision for future obligations under the Texas gross margin tax.
Standardized measure does not give effect to derivative transactions.
The standardized measure shown should not be construed as the current
market value of the reserves. The 10% discount factor, which is required
by Financial Accounting Standards Board pronouncements, is not necessarily the
most appropriate discount rate. The present value, no matter what discount
rate is used, is materially affected by assumptions as to timing of future
production, which may prove to be inaccurate.
Our Productive
Wells
The
following table sets forth information relating to the productive wells in which
we owned a working interest as of December 31, 2008. Productive wells
consist of producing wells and wells capable of production, including natural
gas wells awaiting pipeline connections to commence deliveries and oil wells
awaiting connection to production facilities. Gross wells are the
total number of producing wells in which we have a working interest in,
regardless of our percentage interest. A net well is not a physical
well, but is a concept that reflects the actual total working interest we hold
in a given well. We compute the number of net wells we own by totaling the
percentage interests we hold in all our gross wells.
Our wells
may produce both oil and natural gas. We classify a well as an oil well if
the net equivalent production of oil was greater than natural gas for the
well.
|
Gross
Wells
|
Net
Wells
|
|||||||||||||||||||||||
|
Oil
|
Natural
Gas
|
Total
|
Oil
|
Natural
Gas
|
Total
|
|||||||||||||||||||
|
Appalachian
Basin:
|
||||||||||||||||||||||||
|
Operated
|
18 | 1,305 | 1,323 | 17 | 1,240 | 1,257 | ||||||||||||||||||
|
Non–operated
|
– | 78 | 78 | – | 31 | 31 | ||||||||||||||||||
|
Michigan:
|
||||||||||||||||||||||||
|
Operated
|
– | 347 | 347 | – | 311 | 311 | ||||||||||||||||||
|
Non–operated
|
– | 26 | 26 | – | 8 | 8 | ||||||||||||||||||
|
Monroe
Field:
|
||||||||||||||||||||||||
|
Operated
|
– | 3,957 | 3,957 | – | 3,957 | 3,957 | ||||||||||||||||||
|
Non–operated
|
– | – | – | – | – | – | ||||||||||||||||||
|
Central
and East Texas:
|
||||||||||||||||||||||||
|
Operated
|
682 | 562 | 1,244 | 206 | 66 | 272 | ||||||||||||||||||
|
Non–operated
|
164 | 285 | 449 | 7 | 13 | 20 | ||||||||||||||||||
|
Permian
Basin:
|
||||||||||||||||||||||||
|
Operated
|
7 | 144 | 151 | 7 | 132 | 139 | ||||||||||||||||||
|
Non–operated
|
1 | 6 | 7 | – | 2 | 2 | ||||||||||||||||||
|
San
Juan Basin
|
||||||||||||||||||||||||
|
Operated
|
19 | 140 | 159 | 19 | 136 | 155 | ||||||||||||||||||
|
Non–operated
|
– | 22 | 22 | – | 6 | 6 | ||||||||||||||||||
|
Mid–Continent
area:
|
||||||||||||||||||||||||
|
Operated
|
34 | 82 | 116 | 25 | 69 | 94 | ||||||||||||||||||
|
Non–operated
|
212 | 96 | 308 | 26 | 17 | 43 | ||||||||||||||||||
|
Total
(1)
|
1,137 | 7,050 | 8,187 | 307 | 5,988 | 6,295 | ||||||||||||||||||
|
(1)
|
In
addition, we own small royalty interests in over 300
wells.
|
Our Developed and
Undeveloped Acreage
The
following table sets forth information relating to our leasehold acreage as
of December 31, 2008:
|
Developed
Acreage
|
Undeveloped
Acreage
|
|||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||
|
Appalachian
Basin
|
37,841 | 36,033 | 77,556 | 66,703 | ||||||||||||
|
Michigan
|
27,457 | 25,822 | – | – | ||||||||||||
|
Monroe
Field (1)
|
6,169 | 6,169 | 172,163 | 147,484 | ||||||||||||
|
Central
and East Texas
|
861,442 | 104,419 | 44,209 | 4,486 | ||||||||||||
|
Permian
Basin
|
8,576 | 8,485 | 5,610 | 3,761 | ||||||||||||
|
San
Juan Basin
|
32,953 | 32,727 | 42,497 | 42,289 | ||||||||||||
|
Mid–Continent
area
|
63,009 | 39,076 | 254 | 254 | ||||||||||||
|
Total
|
1,037,447 | 252,731 | 342,289 | 264,977 | ||||||||||||
|
(1)
|
There
are no spacing requirements on substantially all of the wells on our
Monroe Field properties; therefore, one developed acre is assigned to each
productive well for which there is no spacing unit
assigned.
|
Substantially
all of our developed and undeveloped acreage is held by production, which means
that as long as our wells on the acreage continue to produce, we will continue
to hold the leases.
Title to
Properties
As is
customary in the oil and natural gas industry, we initially conduct only a
cursory review of the title to our properties on which we do not have proved
reserves. Prior to the commencement of drilling operations on those
properties, we conduct a thorough title examination and perform curative work
with respect to significant defects. To the extent title opinions or other
investigations reflect title defects on those properties, we are typically
responsible for curing any title defects at our expense. We generally will
not commence drilling operations on a property until we have cured any material
title defects on such property. Prior to completing an acquisition of
producing natural gas leases, we perform title reviews on the most significant
leases and, depending on the materiality of the properties, we may obtain a
title opinion or review previously obtained title opinions. As a result,
we have obtained title opinions on a significant portion of our natural gas
properties and believe that we have satisfactory title to our producing
properties in accordance with standards generally accepted in the natural gas
and oil industry. Our properties are subject to customary royalty and
other interests, liens for current taxes and other burdens that we believe do
not materially interfere with the use of or affect our carrying value of the
properties.
Our Drilling
Activity
We intend
to concentrate our drilling activity on low risk development drilling
opportunities. The number and types of wells we drill will vary depending
on the amount of funds we have available for drilling, the cost of each well,
the size of the fractional working interests we acquire in each well, the
estimated recoverable reserves attributable to each well and the accessibility
to the well site.
The
following table summarizes our approximate gross and net interest in development
wells completed by us during the years ended December 31, 2008 and 2007 and the
three months ended December 31, 2006 and by our predecessors during
the nine months ended September 30, 2006, regardless of when drilling was
initiated. The information should not be considered indicative of future
performance, nor should it be assumed that there is necessarily any correlation
between the number of productive wells drilled, quantities of reserves found or
economic value.
|
Successor
|
Predecessors
|
|||||||||||||||
|
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||
|
Year
Ended December 31,
|
December
31,
|
September
30,
|
||||||||||||||
|
2008
|
2007
|
2006
|
2006
|
|||||||||||||
|
Gross
wells:
|
||||||||||||||||
|
Productive
|
58.0 | 27.0 | 7.0 | 30.0 | ||||||||||||
|
Dry
|
2.0 | 1.0 | – | 4.0 | ||||||||||||
|
Total
|
60.0 | 28.0 | 7.0 | 34.0 | ||||||||||||
|
Net
wells:
|
||||||||||||||||
|
Productive
|
28.2 | 20.5 | 7.0 | 20.6 | ||||||||||||
|
Dry
|
2.0 | 1.0 | – | 1.0 | ||||||||||||
|
Total
|
30.2 | 21.5 | 7.0 | 21.6 | ||||||||||||
As of
December 31, 2008, we were participating in the drilling of 2 gross (0.3 net)
wells.
Well
Operations
We have
entered into operating agreements with EnerVest. Under these operating
agreements, EnerVest acts as contract operator of the oil and natural gas wells
and related gathering systems and production facilities in which we own an
interest, if our interest entitles us to control the appointment of the operator
of the well, gathering system or production facilities. As contract
operator, EnerVest designs and manages the drilling and completion of our wells
and manages the day to day operating and maintenance activities for
our wells.
Under
these operating agreements, EnerVest has established a joint account for each
well in which we have an interest. We are required to pay our working
interest share of amounts charged to the joint account. The joint account
is charged with all direct expenses incurred in the operation of our wells and
related gathering systems and production facilities.
The
determination
of which direct expenses can be charged to the joint account and the manner of
charging direct expenses to the joint account for our wells is done in
accordance with the Council of Petroleum Accountants Societies (“COPAS”) model
form of accounting procedure.
Under the
COPAS model form, direct expenses include the costs of third party services
performed on our properties and wells, as well as gathering and other equipment
used on our properties. In addition, direct expenses include the allocable
share of the cost of services performed on our properties and wells by EnerVest
employees. The allocation of the cost of EnerVest employees who perform
services on our properties is based on time sheets maintained by EnerVest’s
employees. Direct expenses charged to the joint account also include an
amount determined by EnerVest to be the fair rental value of facilities owned by
EnerVest and used in the operation of our properties.
Principal Customers and Marketing
Arrangements
The
market for our oil, natural gas and natural gas liquids production depends on
factors beyond our control, including the extent of domestic production and
imports of oil, natural gas and natural gas liquids, the proximity and capacity
of natural gas pipelines and other transportation facilities, the demand for
oil, natural gas and natural gas liquids, the marketing of competitive fuels and
the effect of state and federal regulation. The oil and natural gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual consumers.
Our oil,
natural gas and natural gas liquids production is sold to a variety of
purchasers. The terms of sale under the majority of existing
contracts are short–term, usually one year or less in duration. The
prices received for oil, natural gas and natural gas liquids sales are generally
tied to monthly or daily indices as quoted in industry
publications.
In 2008,
Southern Union Gas Services, Enbridge Marketing (U.S.), L.P. and CMS Energy
Corporation accounted for 11%, 10% and 10%, respectively, of our consolidated
oil, natural gas and natural gas liquids revenues. In 2007, Enbridge
Marketing (U.S.), L.P. accounted for 15% of our consolidated oil, natural gas
and natural gas liquids revenues. In 2006, Exelon Energy Company,
Kastle Resources Enterprises, Inc. and Ergon Oil Purchasing, Inc. accounted for
32%, 17% and 14%, respectively, of the combined oil, natural gas and natural gas
liquids revenues of us and our predecessors. We believe that the loss
of a major customer would have a temporary effect on our revenues but that over
time, we would be able to replace our major customers.
Competition
The oil
and natural gas industry is highly competitive. We encounter strong
competition from other independent operators and from major oil companies in
acquiring properties, contracting for drilling equipment and securing trained
personnel. Many of these competitors have financial and technical
resources and staffs substantially larger than ours. As a result, our
competitors may be able to pay more for desirable leases, or to evaluate, bid
for and purchase a greater number of properties or prospects than our financial
or personnel resources will permit.
We are
also affected by competition for drilling rigs and the availability of related
equipment. In the past, the oil and natural gas industry has experienced
shortages of drilling rigs, equipment, pipe and personnel, which has delayed
development drilling and other 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 drilling rights, and we cannot assure you that we will be
able to compete satisfactorily when attempting to make further
acquisitions.
Seasonal Nature of
Business
Seasonal
weather conditions and lease stipulations can limit our drilling and producing
activities and other operations in certain areas of the Appalachian Basin and
Michigan. As a result, we generally perform the majority of our drilling
in these areas during the summer and autumn months. In addition, the
Monroe Field properties in Louisiana are subject to flooding. These
seasonal anomalies can pose challenges for meeting our well drilling objectives
and increase competition for equipment, supplies and personnel during the
drilling season, which could lead to shortages and increase costs or delay our
operations. Generally the demand for natural gas is higher in the summer
and winter months. In addition, certain natural gas users utilize
natural gas storage facilities and purchase some of their anticipated winter
requirements during the off–peak months. This can also lessen seasonal
demand fluctuations.
Environmental Matters and
Regulation
Our
operations are subject to stringent and complex federal, state and local laws
and regulations that govern the protection of the environment as well as the
discharge of materials into the environment. These laws and regulations
may, among other things:
|
|
·
|
require
the acquisition of various permits before drilling
commences;
|
|
|
·
|
restrict
the types, quantities and concentration of various substances that can be
released into the environment in connection with drilling, production and
transportation activities;
|
|
|
·
|
limit
or prohibit drilling activities on lands lying within wilderness, wetlands
and other protected areas;
and
|
|
|
·
|
require
remedial measures to mitigate pollution from former and ongoing
operations, such as site restoration, pit closure and plugging of
abandoned wells.
|
These
laws, rules and regulations may also restrict the rate of oil and natural gas
production below the rate that would otherwise be possible. The regulatory
burden on the oil and natural gas industry increases the cost of doing business
in the industry and consequently affects profitability. Additionally,
Congress and federal, state and local agencies frequently revise environmental
laws and regulations, and such changes could result in increased costs for
environmental compliance, such as waste handling, permitting, or cleanup for the
oil and natural gas industry and could have a significant impact on our
operating costs.
The
following is a summary of some of the existing laws, rules and regulations to
which our business operations are subject.
Solid
and Hazardous Waste Handling
The
federal Resource Conservation and Recovery Act (the “RCRA”) and comparable state
statutes regulate the generation, transportation, treatment, storage, disposal
and cleanup of hazardous solid waste. Although oil and natural gas
waste generally is exempt from regulations as hazardous waste under RCRA, we
generate waste as a routine part of our operations that may be subject to
RCRA. Although a substantial amount of the wastes generated in our
operations are regulated as non–hazardous solid wastes rather than hazardous
wastes, there is no guarantee that the EPA or individual states will not adopt
more stringent requirements for the handling of non–hazardous wastes or
categorize some non–hazardous wastes as hazardous 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.
We
currently own, lease, or operate numerous properties that have been used for oil
and natural gas exploration and production for many years. Although we
believe we have utilized operating and waste disposal practices that were
standard in the industry at the time, hazardous substances, wastes or
hydrocarbons may have been released on or under the properties owned or leased
by us, or on or under other locations, including off-site locations, where such
substances have been taken for disposal. In addition, some of these
properties have been operated by third parties or by previous owners or
operators whose treatment and disposal of hazardous substances, wastes, or
hydrocarbons were not under our control. These properties and the
substances disposed or released on them may be subject to RCRA and analogous
state laws. In the future, we could be required to remediate
property, including groundwater, containing or impacted by previously disposed
wastes (including wastes disposed or released by prior owners or operators, or
property contamination, including groundwater contamination by prior owners or
operators) or to perform remedial plugging operations to prevent future or
mitigate existing contamination.
Comprehensive
Environmental Response, Compensation and Liability Act
The
Comprehensive Environmental Response, Compensation and Liability Act (the
“CERCLA”) imposes joint and several liability for costs of investigation and
remediation and for natural resource damages without regard to fault or legality
of the original conduct, on certain classes of persons with respect to the
release into the environment of substances designated under CERCLA as
hazardous substances (“Hazardous Substances”). These classes of persons,
or so–called potentially responsible parties (“PRPs”) include the current and
past owners or operators of a site where the release occurred and anyone who
disposed or arranged for the disposal of a hazardous substance found at the
site. CERCLA also authorizes the EPA and, in some instances, third
parties to take actions in response to threats to the public health or
the
environment
and to seek to recover from the PRPs the costs of such action. Many
states have adopted comparable or more stringent state
statutes.
Although
CERCLA generally exempts “petroleum” from the definition of Hazardous Substance,
in the course of its operations, we have generated and will generate wastes that
may fall within CERCLA’s definition of Hazardous Substance and may have disposed
of these wastes at disposal sites owned and operated by others. We
may also be the owner or operator of sites on which Hazardous Substances have
been released. To our knowledge, neither we nor our predecessors have
been designated as a PRP by the EPA under CERCLA; we also do not know of any
prior owners or operators of our properties that are named as PRPs related to
their ownership or operation of such properties. In the event
contamination is discovered at a site on which we are or have been an owner or
operator or to which we sent Hazardous Substances, we could be liable for the
costs of investigation and remediation and natural resources
damages.
Clean
Water Act
The
Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state
laws impose restrictions and strict controls with respect to the discharge of
pollutants, including spills and leaks of produced water and other oil and
natural gas wastes, into waters of the United States, a term broadly defined.
The discharge of pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by EPA or an analogous state
agency. The Clean Water Act also prohibits the discharge of dredge and
fill material in regulated waters, including wetlands, unless authorized by a
permit issued by the U.S. Army Corps of Engineers. Federal and state
regulatory agencies can impose administrative, civil and criminal penalties, as
well as require remedial or mitigation measures, for non–compliance with
discharge permits or other requirements of the federal Clean Water Act and
analogous state laws and regulations. In the event of an unauthorized
discharge of wastes, we may be liable for penalties and
costs.
Oil
Pollution Act
The
primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”)
which amends and augments oil spill provisions of the Clean Water Act, imposes
certain duties and liabilities on certain "responsible parties" related to the
prevention of oil spills and damages resulting from such spills in or
threatening United States waters or adjoining shorelines. A liable
"responsible party" includes the owner or operator of a facility, vessel or
pipeline that is a source of an oil discharge or that poses the substantial
threat of discharge, or in the case of offshore facilities, the lessee or
permittee of the area in which a discharging facility is located. OPA
assigns joint and several liability, without regard to fault, to each liable
party for oil removal costs and a variety of public and private
damages. Although defenses exist to the liability imposed by OPA,
they are limited. In the event of an oil discharge or substantial
threat of discharge, the Company may be liable for costs and
damages.
Air
Emissions
Our
operations are subject to local, state and federal regulations for the control
of emissions from sources of air pollution. Federal and state laws
require new and modified sources of air pollutants to obtain permits prior to
commencing construction. Major sources of air pollutants are subject
to more stringent, federally imposed requirements including additional
permits. Federal and state laws designed to control hazardous (toxic)
air pollutants, might require installation of additional
controls. Administrative enforcement actions for failure to comply
strictly with air pollution regulations or permits are generally resolved by
payment of monetary fines and correction of any identified
deficiencies. Alternatively, regulatory agencies could bring lawsuits
for civil penalties or require us to forego construction, modification or
operation of certain air emission sources.
National
Environmental Policy Act
Oil and
natural gas exploration and production activities on federal lands may be
subject to the National Environmental Policy Act (the “NEPA”) which requires
federal agencies, including the Department of Interior, to evaluate major agency
actions having the potential to significantly impact the environment. In
the course of such evaluations, an agency will prepare an Environmental
Assessment that assesses the potential direct, indirect and cumulative impacts
of a proposed project and, if necessary, will prepare a more detailed
Environmental Impact Statement that may be made available for public review and
comment. All of our current exploration and production activities, as well
as proposed exploration and development plans, on federal lands require
governmental permits that are subject to the requirements of NEPA. This
process has the potential to delay or impose additional conditions upon the
development of oil and natural gas projects.
Climate
Change Legislation
More
stringent laws and regulations relating to climate change and greenhouse gases
(“GHGs”) may be adopted in the future and could cause us to incur material
expenses in complying with them. The U.S. Congress last session
considered climate change related legislation to regulate GHG emissions that
could affect our operations and our regulatory costs, as well as the value of
oil and natural gas generally. Although that legislation did not
pass, expectations are that Congress will continue to consider some type of
climate change legislation and that EPA may consider climate change–related
regulatory initiatives. As a result, there is a great deal of
uncertainty as to how and when federal regulation of GHGs might take
place. In addition to possible federal regulation, a number of
states, individually and regionally, also are considering or have implemented
GHG regulatory programs. These potential federal and state
initiatives may result in so–called cap–and–trade programs, under which overall
GHG emissions are limited and GHG emissions are then allocated and sold, and
possibly other regulatory requirements, that could result in our incurring
material expenses to comply, e.g., by being required to purchase or to surrender
allowances for GHGs resulting from our operations. These regulatory
initiatives also could adversely affect the marketability of the oil and natural
gas we produce. The impact of such future programs cannot be predicted, but we
do not expect our operations to be affected any differently than other similarly
situated domestic competitors.
OSHA and Other Laws and
Regulation
We are
subject to the requirements of the federal Occupational Safety and Health Act
(the “OSHA”) and comparable state statutes. These laws and the
implementing regulations strictly govern the protection of the health and safety
of employees. The OSHA hazard communication standard, the EPA community
right–to–know regulations under the Title III of CERCLA and similar state
statutes require that we organize and/or disclose information about hazardous
materials used or produced in our operations. We believe that we are in
substantial compliance with these applicable requirements and with other OSHA
and comparable requirements.
We
believe that we are in substantial compliance with all existing environmental
laws and regulations applicable to our current operations and that our continued
compliance with existing requirements will not have a material adverse impact on
our financial condition and results of operations. We did not incur
any material capital expenditures for remediation or pollution control
activities for the years ended December 31, 2008 and 2007 and the three months
ended December 31, 2006, and our predecessors did not incur any material
capital expenditures for remediation or pollution control activities for the
nine months ended September 30, 2006. Additionally, we are not aware of
any environmental issues or claims that will require material capital
expenditures during 2008 or that will otherwise have a material impact on our
financial position or results of operations in the future. However, we
cannot assure you that the passage of more stringent laws and regulations in the
future will not have a negative impact our business activities, financial
condition, results of operations and ability to pay distributions to our
unitholders.
Other Regulation of the Oil and
Natural Gas
Industry
The oil
and natural gas industry is extensively regulated by numerous federal, state 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 natural gas and oil facilities. Our
operations may be subject to such laws and regulations. Presently, it is not
possible to accurately estimate the costs we could incur to comply with any such
facility security laws or regulations, but such expenditures could be
substantial.
Drilling
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
drilling of wells, drilling bonds and reports concerning operations. Most
states and some counties and municipalities in which we operate also regulate
one or more of the following:
|
|
·
|
the
location of wells;
|
|
|
·
|
the
method of drilling and casing
wells;
|
|
|
·
|
the
surface use and restoration of properties upon which wells are
drilled;
|
|
|
·
|
the
plugging and abandoning of
wells; and
|
|
|
·
|
notice
to surface owners and other third
parties.
|
State
laws regulate the size and shape of drilling and spacing units or proration
units governing the pooling of oil and natural gas oil properties. Some
states allow forced pooling or integration of tracts 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 natural gas liquids
within its jurisdiction.
We do not
control the availability of transportation and processing facilities used in the
marketing of our production. For example, we may have to shut–in a
productive natural gas well because of a lack of available natural gas gathering
or transportation facilities.
Federal
Natural Gas Regulation
The
availability, terms and cost of transportation significantly affect sales of
natural gas. The interstate transportation and sale for resale of natural
gas is subject to federal regulation, including regulation of the terms,
conditions and rates for interstate transportation, storage and various other
matters, primarily by the Federal Energy Regulatory Commission (“FERC”).
Federal and state regulations govern the price and terms for access to
natural gas pipeline transportation. FERC’s regulations for
interstate natural gas transmission in some circumstances may also affect the
intrastate transportation of natural gas. FERC regulates the rates, terms
and conditions applicable to the interstate transportation of natural gas by
pipelines under the Natural Gas Act, or NGA, as well as under Section 311
of the Natural Gas Policy Act, or NGPA.
Since
1985, FERC has implemented regulations intended to increase competition within
the natural gas industry by making natural gas transportation more accessible to
natural gas buyers and sellers on an open-access, nondiscriminatory basis.
FERC has announced several important transportation related policy
statements and rule changes, including a statement of policy and final rule
issued February 25, 2000, concerning alternatives to its traditional
cost-of-service rate-making methodology to establish the rates interstate
pipelines may charge for their services. The final rule revises FERC’s
pricing policy and current regulatory framework to improve the efficiency of the
market and further enhance competition in natural gas
markets.
FERC has
also issued several other generally pro–competitive policy statements and
initiatives affecting rates and other aspects of pipeline transportation of
natural gas. On May 31, 2005, FERC generally reaffirmed its policy of
allowing interstate pipelines to selectively discount their rates in order to
meet competition from other interstate pipelines. On June 15, 2006,
the FERC issued an order in which it declined to establish uniform standards for
natural gas quality and interchangeability, opting instead for a
pipeline–by–pipeline approach. Four days later, on June 19, 2006, in
order to facilitate development of new storage capacity, FERC established
criteria to allow providers to charge market–based (i.e. negotiated) rates for
storage services. On June 19, 2008, the FERC removed the rate ceiling
on short–term releases by shippers of interstate pipeline transportation
capacity.
Although
natural gas prices are currently unregulated, Congress historically has been
active in the area of natural gas regulation. We cannot predict whether
new legislation to regulate natural gas might be proposed, what proposals, if
any, might actually be enacted by Congress or the various state legislatures,
and what effect, if any, the proposals might have on the operations of the
underlying properties. Sales of condensate and natural gas liquids are not
currently regulated and are made at market prices.
State
Natural Gas Regulation
The
various states regulate the drilling for, and the production, gathering and sale
of, natural gas, including imposing severance taxes and requirements for
obtaining drilling permits. States also regulate the method of developing
new fields, the spacing and operation of wells and the prevention of waste of
natural gas resources. States may regulate rates of production and may
establish maximum daily production allowables from natural gas wells based on
market demand or resource conservation, or both. States do not regulate
wellhead prices or engage in other similar direct economic regulation, but there
can be no assurance that they will not do so in the future. The effect of
these regulations may be to limit the amounts of natural gas that may be
produced from our wells and to limit the number of wells or locations we can
drill.
Other
Regulation
In
addition to the regulation of oil and natural gas pipeline transportation rates,
the oil and natural gas industry generally is subject to compliance with various
other federal, state and local regulations and laws. Some of those laws
relate to occupational safety, resource conservation and equal employment
opportunity. We do not believe that compliance with these laws will have a
material adverse effect upon the unitholders.
Employees
EV
Management, the general partner of our general partner, has four full time
employees and two executive officers who spend a significant amount of
their time on our operations. At December 31, 2008, EnerVest, the
sole member of EV Management, had approximately 500 full–time employees,
including over 70 geologists, engineers and land professionals. To carry
out our operations, EnerVest employs the people who will provide direct support
to our operations. None of these employees are covered by collective
bargaining agreements. We consider EV Management’s relationship with
its employees to be good, and EnerVest considers its relationships with its
employees to be good.
Available
Information
Our
annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on
Form 8–K and amendments to those reports filed or furnished pursuant to Section
13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange
Act”), are made available free of charge on our website at www.evenergypartners.com as
soon as reasonably practicable after these reports have been electronically
filed with, or furnished to, the SEC. These documents are also
available on the SEC’s website at www.sec.gov or
you may read and copy any materials that we file with the SEC at the SEC’s
Public Reference Room at 100 F Street, NE, Washington DC 20549. Our
website also includes our Code of Business Conduct and the charters of our Audit
Committee and Compensation Committee. No information from either the
SEC’s website or our website is incorporated herein by reference.
Limited partner interests are
inherently different from capital stock of a corporation, although many of the
business risks to which we are subject are similar to those that would be faced
by a corporation engaged in similar businesses. If any of the following risks were
actually to occur, our business, financial condition or results of
operations or cash
flows could be
materially adversely affected.
Risks Related to Our
Business
We may not have sufficient cash from
operations following the establishment of cash reserves and payment of fees and
expenses, including cost reimbursements to our general partner, to enable us to
make cash distributions to holders of our common units and subordinated units at
the current distribution rate under our cash
distribution policy.
In order
to make our cash distributions at our current quarterly distribution rate of
$0.751 per common and subordinated unit, we will require available cash of
approximately $14.0 million per quarter based on the common units,
subordinated units and unvested phantom units outstanding as of March 2,
2009. We may not have sufficient available cash from operating
surplus each quarter to enable us to make cash distributions at this anticipated
quarterly distribution rate under our cash distribution policy. The amount
of cash we can distribute on our units principally depends upon the amount of
cash we generate from our operations, which will fluctuate from quarter to
quarter based on, among other things:
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the
amount of oil and natural gas we
produce;
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the
prices at which we sell our oil and natural gas
production;
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our
ability to acquire additional oil and natural gas properties at
economically attractive
prices;
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our
ability to hedge commodity
prices;
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the
level of our capital
expenditures;
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the
level of our operating and administrative costs;
and
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the
level of our interest expense, which depends on the amount of our
indebtedness and the interest payable
thereon.
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In
addition, the actual amount of cash we will have available for distribution will
depend on other factors, some of which are beyond our control,
including:
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the
amount of cash reserves established by our general partner for the proper
conduct of our business and for capital expenditures to maintain our
production levels over the long–term, which may be
substantial;
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the
cost of acquisitions;
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our
debt service requirements and other
liabilities;
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fluctuations
in our working capital needs;
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our
ability to borrow funds and access capital
markets;
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the
timing and collectibility of receivables;
and
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prevailing
economic conditions.
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As a
result of these factors, the amount of cash we distribute to our unitholders may
fluctuate significantly from quarter to quarter and may be less than the
quarterly distribution amount that we expect to distribute.
Oil
and natural gas prices have recently declined substantially. If there
is a sustained recession in the United States or globally, oil and natural gas
prices may continue to fall and may become and remain depressed for a long
period of time, which may adversely affect our results of
operations.
The
United States is currently experiencing a recession. The reduced
economic activity associated with the recession has reduced the demand for, and
so the prices we receive for, our oil and natural gas production. A
continued sustained reduction in the prices we receive for our oil and natural
gas production will have a material adverse effect on our results of
operations. Because we have hedged the prices we will receive for a
substantial portion of our oil and natural gas production through 2013, the
effects on us of a decline in oil and natural gas prices over the near term will
be mitigated.
If oil and natural gas prices
remain
depressed for a
prolonged period, our cash flows from operations will decline and we may have to
lower our distributions or may not be able to pay distributions at
all.
Our
revenue, profitability and cash flow depend upon the prices for oil and natural
gas. The prices we receive for oil and natural gas production are
volatile and a drop in prices can significantly affect our financial results and
impede our growth, including our ability to maintain or increase our borrowing
capacity, to repay current or future indebtedness and to obtain additional
capital on attractive terms, all of which can affect our ability to pay
distributions. Changes in oil and natural gas prices have a
significant impact on the value of our reserves and on our cash
flows. Prices for oil and natural gas may fluctuate widely in
response to relatively minor changes in the supply and demand, market
uncertainty and a variety of additional factors that are beyond our control,
such as:
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the
domestic and foreign supply of and demand for oil and natural
gas;
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the
price and quantity of foreign imports of oil and natural
gas;
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the
level of consumer product
demand;
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weather
conditions;
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the
value of the U.S dollar relative to the currencies of other
countries;
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overall
domestic and global economic
conditions;
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political
and economic conditions and events in foreign oil and natural gas
producing countries, including embargoes, continued hostilities in the
Middle East and other sustained military campaigns, conditions in South
America, China and Russia, and acts of terrorism or
sabotage;
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the
ability of members of the Organization of Petroleum Exporting Countries to
agree to and maintain oil price and production
controls;
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technological
advances affecting energy
consumption;
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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 and capacity of natural gas pipelines and other transportation
facilities to our
production; and
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the
price and availability of alternative
fuels.
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Lower oil
or natural gas prices will decrease our revenues, but may also reduce the amount
of oil or natural gas that we can economically produce. This may result in
our having to make substantial downward adjustments to our estimated proved
reserves. If this occurs, or if our estimates of development costs
increase, production data factors change or drilling results deteriorate,
accounting rules may require us to write down, as a non–cash charge to earnings,
the carrying value of our oil and natural gas properties for impairments.
We are required to perform impairment tests on our assets whenever events
or changes in circumstances lead to a reduction of the estimated useful life or
estimated future cash flows that would indicate that the carrying amount may not
be recoverable or whenever management’s plans change with respect to
those
assets.
We may incur impairment charges in the future, which could have a material
adverse effect on our results of operations in the period taken and our ability
to borrow funds under our credit facility, which may adversely affect our
ability to make cash distributions to our unitholders.
Our
hedging transactions and cash and cash equivalents expose us to counterparty
credit risk.
Our
hedging transactions expose us to risk of financial loss if a counterparty fails
to perform under a derivative contract. To mitigate counterparty
credit risk, we conduct our hedging activities with financial institutions who
are lenders under our credit facility. The current disruptions
occurring in the financial markets could lead to sudden changes in a
counterparty’s liquidity, which could impair their ability to perform under the
terms of the derivative contract. We are unable to predict sudden
changes in a counterparty’s creditworthiness or ability to
perform. Even if we do accurately predict sudden changes, our ability
to negate the risk may be limited depending upon market conditions.
During
periods of falling commodity prices, such as in late 2008, our hedge receivable
positions increase, which increases our exposure. If the
creditworthiness of our counterparties deteriorates and results in their
nonperformance, we could incur a significant loss.
As of
December 31, 2008, we had $41.6 million in cash and cash equivalents, including
investments in money market accounts with a major financial
institution. We are unable to predict sudden changes in solvency of
our financial institutions. In the event of a bank failure, we could incur a
significant loss.
Current or future
distressed financial conditions of customers could have an adverse impact on us
in the event these customers are unable to pay us for the products or services
we provide.
Some of
our customers are experiencing, or may experience in the future, severe
financial problems that have had or may have a significant impact on their
creditworthiness. We cannot provide assurance that one or more of our
financially distressed customers will not default on their obligations to us or
that such a default or defaults will not have a material adverse effect on our
business, financial position, future results of operations or future cash
flows. Furthermore, the bankruptcy of one or more of our customers,
or some other similar proceeding or liquidity constraint, might make it unlikely
that we would be able to collect all or a significant portion of amounts owed by
the distressed entity or entities. In addition, such events might
force such customers to reduce or curtail their future use of our products and
services, which could have a material adverse effect on our results of
operations and financial condition.
We
may be unable to integrate successfully the operations of our recent or future
acquisitions with our operations and we may not realize all the anticipated
benefits of the recent acquisitions or any future
acquisition.
Integration
of our recent acquisitions with our business and operations has been a complex,
time consuming and costly process. Failure to successfully assimilate
our past or future acquisitions could adversely affect our financial condition
and results of operations.
Our
acquisitions involve numerous risks, including:
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operating
a significantly larger combined organization and adding
operations;
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difficulties
in the assimilation of the assets and operations of the acquired business,
especially if the assets acquired are in a new business segment or
geographic area;
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the
risk that oil and natural gas reserves acquired may not be of the
anticipated magnitude or may not be developed as
anticipated;
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the
loss of significant key employees from the acquired
business:
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the
diversion of management’s attention from other business
concerns;
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the
failure to realize expected profitability or
growth;
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the
failure to realize expected synergies and cost
savings;
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coordinating
geographically disparate organizations, systems and facilities;
and
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coordinating
or consolidating corporate and administrative
functions.
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Further,
unexpected costs and challenges may arise whenever businesses with different
operations or management are combined, and we may experience unanticipated
delays in realizing the benefits of an acquisition. If we consummate
any future acquisition, our capitalization and results of operation may change
significantly, and you may not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider in evaluating
future acquisitions.
The
amount of cash we have available for distribution to holders of our common units
and subordinated units depends on our cash flows.
The
amount of cash that we have available for distribution depends primarily upon
our cash flows, including financial reserves and cash flows from working capital
borrowing, and not solely on profitability, which will be affected by non cash
items. As a result, we may make cash distributions during periods
when we record losses for financial accounting purposes and may not make cash
distributions during periods when we record net income for financial accounting
purposes.
We have
significant indebtedness under our credit facility. Restrictions in our credit facility may limit our ability to make distributions to you
and may limit our ability to capitalize on acquisitions and other business
opportunities.
Our
credit facility contains covenants limiting our ability to make distributions,
incur indebtedness, grant liens, make acquisitions, investments or dispositions
and engage in transactions with affiliates, as well as containing covenants
requiring us to maintain certain financial ratios and tests. In addition,
the borrowing base under our facility is subject to periodic review by our
lenders. Difficulties in the credit markets may cause the banks to be
more restrictive when redetermining our borrowing base. Our next
semi-annual scheduled borrowing base redetermination is April 1, 2009. As a
result of the steep decline in oil and natural gas prices, we would expect that
the borrowing base under our facility will be
reduced.
Unless we replace the oil and
natural gas reserves we produce, our revenues and production will decline, which
would adversely affect our cash flows from operations and our ability to
make distributions to our
unitholders.
Producing
reservoirs are characterized by declining production rates that vary depending
upon reservoir characteristics and other factors. Our decline rate may
change when we drill additional wells, make acquisitions or under other
circumstances. Our future cash flows and income and our ability to
maintain and to increase distributions to unitholders are highly dependent on
our success in efficiently developing and exploiting our current reserves and
economically finding or acquiring additional recoverable reserves. We may
not be able to develop, find or acquire additional reserves to replace our
current and future production at acceptable costs, which would adversely affect
our business, financial condition and results of operations. Factors that
may hinder our ability to acquire additional reserves include competition,
access to capital, prevailing oil and natural gas prices and the number and
attractiveness of properties for sale.
Our estimated oil and natural gas
reserve quantities and future production rates are based on many assumptions
that may prove to be inaccurate. Any material inaccuracies in these
reserve estimates or the underlying assumptions will materially affect the
quantities and present value of our reserves.
Numerous
uncertainties are inherent in estimating quantities of oil and natural gas
reserves. Our estimates of our net proved reserve quantities are
based upon reports from Cawley Gillespie & Associates, Inc., an
independent petroleum engineering firm used by us. The process of
estimating oil and natural gas reserves is complex, requiring significant
decisions and assumptions in the evaluation of available geological, engineering
and economic data for each reservoir, and these reports rely upon various
assumptions, including assumptions regarding future oil and natural gas prices,
production levels, and operating and development costs. As a result,
estimated quantities of proved reserves and projections of future production
rates and the timing of development expenditures may prove to be inaccurate.
Over time, we may make material changes to reserve estimates taking into
account the results of actual drilling and production. Any significant
variance in our assumptions and actual results could greatly affect our
estimates of reserves, the economically recoverable quantities of oil and
natural gas attributable to any particular group of properties, the
classifications of reserves based on risk of recovery, and estimates of the
future net cash flows. In addition, our wells are characterized by low
production rates per well. As a result, changes in future production costs
assumptions could have a significant effect on our proved reserve
quantities.
The
standardized measure of discounted future net cash flows of our estimated net
proved reserves is not necessarily the same as the current market value of our
estimated net proved reserves. We base the discounted future net cash
flows from
our
estimated net proved reserves on prices and costs in effect on the day of the
estimate. Actual prices received for production and actual costs of such
production will be different than these assumptions, perhaps
materially.
The
timing of both our production and our incurrence of expenses in connection with
the development and production of our properties will affect the timing of
actual future net cash flows from proved reserves, and thus their actual present
value. In addition, the 10% discount factor we use when calculating
discounted future net cash flows may not be the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with us
or the oil and natural gas industry in general. Any material
inaccuracy in our reserve estimates or underlying assumptions will materially
affect the quantities and present value of our reserves which could adversely
affect our business, results of operations, financial condition and our ability
to make cash distributions to our unitholders.
Our
acquisition and development operations will require substantial capital
expenditures, which will reduce our cash available for
distribution. We may be unable to obtain needed capital or financing
on satisfactory terms, which could lead to a decline in our production and
reserves.
The
oil and natural gas industry is capital intensive. We make and expect to
continue to make substantial capital expenditures in our business for the
development, production and acquisition of oil and natural gas reserves.
These expenditures will be deducted from our revenues in determining our
cash available for distribution. We intend to finance our future capital
expenditures with cash flows from operations, borrowings under our credit
facility and the issuance of debt and equity securities. The incurrence of
debt will require that a portion of our cash flows from operations be used for
the payment of interest and principal on our debt, thereby reducing our ability
to use cash flows to fund working capital, capital expenditures and
acquisitions. Our cash flows from operations and access to capital are
subject to a number of variables, including:
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the
estimated quantities of our oil and natural gas
reserves;
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the
amount of oil and natural gas we produce from existing
wells;
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the
prices at which we sell our
production; and
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our
ability to acquire, locate and produce new
reserves.
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If
our revenues or the borrowing base under our credit facility decrease as a
result of lower commodity prices, operating difficulties, declines in reserves
or for any other reason, we may have limited ability to obtain the capital
necessary to sustain our operations at current levels. Our credit facility
may restrict our ability to obtain new financing. If additional capital is
needed, we may not be able to obtain debt or equity financing on terms favorable
to us, or at all. If cash generated by operations or available under our
credit facility is not sufficient to meet our capital requirements, the failure
to obtain additional financing could result in a curtailment of our operations
relating to development of our prospects, which in turn could lead to a possible
decline in our reserves and production, which could lead to a decline in our oil
and natural gas reserves, and could adversely affect our business, results of
operation, financial conditions and ability to make distributions to our
unitholders. In addition, we may lose opportunities to acquire oil and
natural gas properties and businesses.
We may incur substantial debt in the
future to enable us to maintain or increase our production levels and to
otherwise pursue our business plan. This debt may restrict our
ability to make distributions.
Our
business requires a significant amount of capital expenditures to maintain and
grow production levels. If prices were to decline for an extended period
of time, if the costs of our acquisition and development operations were to
increase substantially, or if other events were to occur which reduced our
revenues or increased our costs, we may be required to borrow significant
amounts in the future to enable us to finance the expenditures necessary to
replace the reserves we produce. The cost of the borrowings and our
obligations to repay the borrowings will reduce amounts otherwise available for
distributions to our unitholders.
We will rely on development drilling
to assist in
maintaining our levels
of production. If our development drilling is unsuccessful, our cash
available for distributions and financial condition will be adversely
affected.
Part of
our business strategy will focus on maintaining production levels by drilling
development wells. Although we and our predecessors and their affiliates
were successful in development drilling in the past, we cannot assure you that
we will continue to maintain production levels through development drilling.
Our drilling involves numerous risks, including the risk that we will not
encounter commercially productive oil or natural gas reservoirs. We must
incur significant expenditures to drill and complete wells. Additionally,
seismic technology does not allow us to know conclusively, prior to drilling a
well, that oil or natural gas is present or economically producible. The
costs of drilling and completing wells are often uncertain, and it is possible
that we will make substantial expenditures on development drilling and not
discover reserves in commercially viable quantities. These expenditures
will reduce cash available for distribution to our
unitholders.
Our
drilling operations may be curtailed, delayed or cancelled as a result of a
variety of factors, including:
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unexpected
drilling conditions;
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facility
or equipment failure or
accidents;
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shortages
or delays in the availability of drilling rigs and
equipment;
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adverse
weather conditions;
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compliance
with environmental and governmental
requirements;
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title
problems;
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unusual
or unexpected geological
formations;
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pipeline
ruptures;
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fires,
blowouts, craterings and
explosions; and
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uncontrollable
flows of oil or natural gas or well
fluids.
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Properties that we buy may not
produce as projected and we may be unable to determine reserve potential,
identify liabilities associated with the properties or obtain protection from
sellers against such liabilities, which could adversely affect our cash
available for distribution.
One of
our growth strategies is to capitalize on opportunistic acquisitions of oil and
natural gas reserves. Any future acquisition will require an assessment of
recoverable reserves, title, future oil and natural gas prices, operating costs,
potential environmental hazards, potential tax and ERISA liabilities, and other
liabilities and similar factors. Ordinarily, our review efforts are
focused on the higher valued properties and are inherently incomplete
because it generally is not feasible to review in depth every individual
property involved in each acquisition. Even a detailed review of records
and properties may not necessarily reveal existing or potential problems, nor
will it permit a buyer to become sufficiently familiar with the properties to
assess fully their deficiencies and potential. Inspections may not always
be performed on every well, and potential problems, such as ground water
contamination and other environmental conditions and deficiencies in the
mechanical integrity of equipment are not necessarily observable even when an
inspection is undertaken. Any unidentified problems could result in
material liabilities and costs that negatively impact our financial conditions
and results of operations and our ability to make cash distributions to our
unitholders.
Additional
potential risks related to acquisitions include, among other
things:
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incorrect
assumptions regarding the future prices of oil and natural gas or the
future operating or development costs of properties
acquired;
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incorrect
estimates of the oil and natural gas reserves attributable to a property
we acquire;
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an
inability to integrate successfully the businesses we
acquire;
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the
assumption of liabilities;
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limitations
on rights to indemnity from the
seller;
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the
diversion of management’s attention from other business
concerns; and
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losses
of key employees at the acquired
businesses.
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If we
consummate any future acquisitions, our capitalization and results of operations
may change significantly.
Our hedging activities could result
in financial losses or could reduce our net income, which may adversely affect
our ability to pay distributions to our unitholders.
To
achieve more predictable cash flows and to reduce our exposure to fluctuations
in the prices of oil and natural gas, we have and may continue to enter into
hedging arrangements for a significant portion of our oil and natural gas
production. If we experience a sustained material interruption in our
production, we might be forced to satisfy all or a portion of our hedging
obligations without the benefit of the cash flows from our sale of the
underlying physical commodity, resulting in a substantial diminution of our
liquidity. Lastly, an attendant risk exists in hedging activities
that the counterparty in any derivative transaction cannot or will not perform
under the instrument and that we will not realize the benefit of the
hedge.
Our
ability to use hedging transactions to protect us from future oil and natural
gas price declines will be dependent upon oil and natural gas prices at the time
we enter into future hedging transactions and our future levels of hedging, and
as a result our future net cash flows may be more sensitive to commodity price
changes.
Our
policy has been to hedge a significant portion of our near–term estimated oil
and natural gas production. However, our price hedging strategy and
future hedging transactions will be determined at the discretion of our general
partner, which is not under an obligation to hedge a specific portion of our
production. The prices at which we hedge our production in the future
will be dependent upon commodities prices at the time we enter into these
transactions, which may be substantially higher or lower than current oil and
natural gas prices. Accordingly, our price hedging strategy may not
protect us from significant declines in oil and natural gas prices received for
our future production. Conversely, our hedging strategy may limit our
ability to realize cash flows from commodity price increases. It is
also possible that a substantially larger percentage of our future production
will not be hedged as compared with the next few years, which would result in
our oil and natural gas revenues becoming more sensitive to commodity price
changes.
We may be unable
to compete effectively with larger companies, which may adversely affect our
ability to generate sufficient revenue and our ability to pay distributions to
our unitholders.
The oil
and natural gas industry is intensely competitive, and we compete with other
companies that have greater resources than us. Our ability to acquire
additional properties and to discover reserves in the future will be dependent
upon our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Many of our larger
competitors not only drill for and produce oil and natural gas, but also carry
on refining operations and market petroleum and other products on a regional,
national or worldwide basis. These companies may be able to pay more
for natural gas properties and evaluate, bid for and purchase a greater number
of properties than our financial or human resources permit. In
addition, these companies may have a greater ability to continue drilling
activities during periods of low oil and natural gas prices, to contract for
drilling equipment, to secure trained personnel, and to absorb the burden of
present and future federal, state, local and other laws and
regulations. The oil and natural gas industry has periodically
experienced shortages of drilling rigs, equipment, pipe and personnel, which has
delayed development drilling and other exploitation activities and has caused
significant price increases. Competition has been strong in hiring
experienced personnel, particularly in the accounting and financial reporting,
tax and land departments. In addition, competition is strong for
attractive oil and natural gas producing properties, oil and natural gas
companies, and undeveloped leases and drilling rights. We may be
often outbid by competitors in our attempts to acquire properties or
companies. Our inability to compete effectively with larger companies
could have a material adverse impact on our business activities, financial
condition and results of operations.
Our business is subject to
operational risks that will not be fully insured, which, if they were to occur,
could adversely affect our financial condition or results of operations and, as
a result, our ability to pay distributions to our
unitholders.
Our
business activities are subject to operational risks,
including:
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damages
to equipment caused by adverse weather conditions, including hurricanes
and flooding;
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facility
or equipment malfunctions;
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pipeline
ruptures or spills;
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fires,
blowouts, craterings and
explosions; and
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uncontrollable
flows of oil or natural gas or well
fluids.
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In
addition, a portion of our natural gas production is processed to extract
natural gas liquids at processing plants that we own or that are owned by
others. If these plants were to cease operations for any reason, we
would need to arrange for alternative transportation and processing
facilities. These alternative facilities may not be available, which
could cause us to shut–in our natural gas production, or the alternative
facilities could be more expensive than the facilities we currently
use.
Any of
these events could adversely affect our ability to conduct operations or cause
substantial losses, including personal injury or loss of life, damage to or
destruction of property, natural resources and equipment, pollution or other
environmental contamination, loss of wells, regulatory penalties, suspension of
operations, and attorney’s fees and other expenses incurred in the prosecution
or defense of litigation.
As is
customary in the industry, we maintain insurance against some but not all of
these risks. Additionally, we may elect not to obtain insurance if we
believe that the cost of available insurance is excessive relative to the
perceived risks presented. Losses could therefore occur for uninsurable or
uninsured risks or in amounts in excess of existing insurance coverage.
The occurrence of an event that is not fully covered by insurance could
have a material adverse impact on our business activities, financial condition,
results of operations and ability to pay distributions to our
unitholders.
Our ability to make distributions to
our unitholders and to pursue our business strategies may be adversely affected
if we incur costs and liabilities due to a failure to comply with environmental
regulations or a release of hazardous substances into the
environment.
We
may incur significant costs and liabilities as a result of environmental
requirements applicable to the operation of our wells, gathering systems and
other facilities. These costs and liabilities could arise under a wide
range of federal, state and local environmental laws and regulations, including,
for example:
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the
Clean Air Act and comparable state laws and regulations that impose
obligations related to air
emissions;
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the
Clean Water Act and comparable state laws and regulations that impose
obligations related to discharges of pollutants into regulated bodies of
water;
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the
RCRA, and comparable state laws that impose requirements for the handling
and disposal of waste from our facilities;
and
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the
CERCLA and comparable state laws that regulate the cleanup of hazardous
substances that may have been released at properties currently or
previously owned or operated by us or at locations to which we have sent
waste for disposal.
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Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial requirements, and
the issuance of orders enjoining future operations. Certain
environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution
Act and analogous state laws and regulations, impose strict joint and several
liability for costs required to clean up and restore sites where hazardous
substances or other waste products have been disposed of or otherwise
released. More stringent laws and regulations, including any related
to climate change and greenhouse gases, may be adopted in the
future. Moreover,
it is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the release
of hazardous substances or other waste products into the
environment.
We are subject to complex federal,
state, local and other laws and regulations that could adversely affect the
cost, manner or feasibility of conducting our
operations.
Our oil
and natural gas exploration, production and transportation operations are
subject to complex and stringent laws and regulations. In order to conduct
our operations in compliance with these laws and regulations, we must obtain and
maintain numerous permits, approvals and certificates from various federal,
state and local governmental authorities. Failure or delay in obtaining
regulatory approvals or drilling permits could have a material adverse effect on
our ability to develop our properties, and receipt of drilling permits with
onerous conditions could increase our compliance costs. In addition,
regulations regarding conservation practices and the protection of correlative
rights affect our operations by limiting the quantity of oil and natural gas we
may produce and sell.
We are
subject to federal, state and local laws and regulations as interpreted and
enforced by governmental authorities possessing jurisdiction over various
aspects of the exploration, production and transportation of oil and natural
gas. While the cost of compliance with these laws has not been material to
our operations in the past, the possibility exists that new laws, regulations or
enforcement policies could be more stringent and significantly increase our
compliance costs. If we are not able to recover the resulting costs
through insurance or increased revenues, our ability to pay distributions to our
unitholders could be adversely affected.
Changes in interest rates could adversely impact
our unit price and our ability to issue additional equity and incur
debt.
Interest
rates on future credit facilities and debt offerings could be higher than
current levels, causing our financing costs to increase accordingly. As
with other yield oriented securities, our unit price is impacted by the
level of our cash distributions and implied distribution yield. The
distribution yield is often used by investors to compare and rank related
yield oriented securities for investment decision-making purposes.
Therefore, changes in interest rates, either positive or negative, may
affect the yield requirements of investors who invest in our units, and a rising
interest rate environment could have an adverse impact on our unit price and our
ability to issue additional equity to make acquisitions, incur debt or for other
purposes.
We may encounter obstacles to
marketing our oil and natural gas, which could adversely impact our
revenues.
The
marketability of our production will depend in part upon the availability and
capacity of natural gas gathering systems, pipelines and other transportation
facilities owned by third parties. Transportation space on the
gathering systems and pipelines we utilize is occasionally limited or
unavailable due to repairs or improvements to facilities or due to space being
utilized by other companies that have priority transportation
agreements. Our access to transportation options can also be affected
by U.S. federal and state regulation of oil and natural gas production and
transportation, general economic conditions and changes in supply and
demand. The availability of markets are beyond our control. If
market factors dramatically change, the impact on our revenues could be
substantial and could adversely affect our ability to produce and market oil and
natural gas, the value of our units and our ability to pay distributions on our
units.
We may experience a temporary
decline in revenues and production if we lose one of our significant
customers.
To the
extent any significant customer reduces the volume of its oil or natural gas
purchases from us, we could experience a temporary interruption in sales of, or
a lower price for, our oil and natural gas production and our revenues and cash
available for distribution could decline which could adversely affect our
ability to make cash distributions to our unitholders.
Our ability to make distributions
will depend on our ability to successfully drill and complete wells on our
properties. Seasonal weather conditions and lease stipulations
may adversely affect our ability to
conduct drilling activities in some of the areas where we
operate.
Drilling
operations in the Appalachian Basin and Michigan are adversely affected by
seasonal weather conditions, primarily in the spring. Many municipalities
in Appalachia impose weight restrictions on the paved roads that lead to our
jobsites due to the muddy conditions caused by spring thaws. In addition,
our Monroe Field properties in Louisiana are subject
to flooding. This limits our access to these jobsites and our ability to
service wells in these areas on a year around basis.
We
depend upon access to the public equity markets to fund our growth
strategy. Currently, stock prices are depressed and if they remain
depressed for an extended period of time, our growth strategy will be adversely
affected.
We are
experiencing unprecedented disruption in the United States and international
financial markets. Equity prices for master limited partnerships, as
well as for corporate stocks, have fallen substantially recently. In
addition, the current disruption in the financial markets has reduced the
likelihood that we could successfully issue common units or other equity
securities to fund our growth. If the disruption in the financial
markets continues for a substantial period of time, our ability to fund growth
will be adversely affected.
Risks Inherent in an Investment in
Us
Sales
of our common units by the selling unitholders may cause our unit price to
decline.
Sales of
substantial amounts of our common units in the public market, or the perception
that these sales may occur, could cause the market price of our common units to
decline. In addition, the sale of these units could impair our
ability to raise capital through the sale of additional common
units.
EnerVest controls our general partner, which
has sole responsibility for conducting our business and managing our
operations. EnerVest, EV Investors, L.P. (“EV Investors”) and EnCap Investments, L.P.
(“EnCap”), which
are limited partners of our general
partner, will have conflicts of interest, which may permit them to favor their
own interests to your detriment.
EnerVest
owns and controls our general partner and EnCap owns a 23.75% limited
partnership interest in our general partner. Conflicts of interest may
arise between EnerVest, EnCap and their respective affiliates, including our
general partner, on the one hand, and us and our unitholders, on the other hand.
In resolving these conflicts of interest, our general partner may favor its own
interests and the interests of its owners over the interests of our unitholders.
These conflicts include, among others, the following
situations:
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we
have acquired oil and natural gas properties from partnerships formed by
EnerVest and partnerships and companies in which EnerVest and EnCap have
an interest, and we may do so in the
future;
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neither
our partnership agreement nor any other agreement requires EnerVest or
EnCap to pursue a business strategy that favors us or to refer any
business opportunity to us;
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our
general partner is allowed to take into account the interests of parties
other than us, such as EnerVest and EnCap, in resolving conflicts of
interest;
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our
general partner determines the amount and timing of our drilling program
and related capital expenditures, asset purchases and sales, borrowings,
issuance of additional partnership securities and reserves, each of which
can affect the amount of cash that is distributed to
unitholders;
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our
partnership agreement does not restrict our general partner from causing
us to pay it or its affiliates for any services rendered to us or entering
into additional contractual arrangements with any of these entities on our
behalf;
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our
general partner 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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Many of the directors and officers
who have responsibility for our management have significant duties with, and
will spend significant time serving, entities that compete with us in seeking
out acquisitions and business opportunities and, accordingly, may have conflicts
of interest in allocating time or pursuing business
opportunities.
In order
to maintain and increase our levels of production, we will need to acquire oil
and natural gas properties. Several of the officers and directors of EV
Management, the general partner of our general partner, who have
responsibilities for managing our operations and activities hold similar
positions with other entities that are in the business of identifying and
acquiring oil and natural gas properties. For example, Mr. Walker is
Chairman and Chief Executive Officer of EV Management and President and Chief
Executive Officer of EnerVest, which is in the business of acquiring oil and
natural gas properties and managing the EnerVest partnerships that are in that
business. Mr. Houser, President and
Chief
Operating Officer and a director of EV Management, is also Executive Vice
President and Chief Operating Officer of EnerVest. We cannot assure you
that these conflicts will be resolved in our favor. Mr. Gary R.
Petersen, a director of EV Management, is also a senior managing director of
EnCap, which is in the business of investing in oil and natural gas companies
with independent management which in turn is in the business of acquiring oil
and natural gas properties. Mr. Petersen is also a director of
several oil and natural gas producing entities that are in the business of
acquiring oil and natural gas properties. The existing positions of these
directors and officers may give rise to fiduciary obligations that are in
conflict with fiduciary obligation owed to us. The EV Management officers
and directors may become aware of business opportunities that may be appropriate
for presentation to us as well as the other entities with which they are or may
be affiliated. Due to these existing and potential future affiliations
with these and other entities, they may have fiduciary obligations to present
potential business opportunities to those entities prior to presenting them to
us, which could cause additional conflicts of interest. They may also
decide that the opportunities are more appropriate for other entities which they
serve and elect not to present them to us.
Neither EnerVest nor EnCap is
limited in its ability to compete with us for acquisition or drilling
opportunities. This could cause conflicts of interest and limit our
ability to acquire additional assets or businesses which in turn could adversely
affect our ability to replace reserves, results of operations and cash available
for distribution to our unitholders.
Neither
our partnership agreement nor the omnibus agreement between us, EnerVest and
others prohibits EnerVest, EnCap and their affiliates from owning assets or
engaging in businesses that compete directly or indirectly with us. For
instance, EnerVest, EnCap and their respective affiliates may acquire, develop
or dispose of additional oil or natural gas properties or other assets in the
future, without any obligation to offer us the opportunity to purchase or
develop any of those assets. Each of these entities is a large,
established participant in the energy business, and each has significantly
greater resources and experience than we have, which factors may make it more
difficult for us to compete with these entities with respect to commercial
activities as well as for acquisition candidates. As a result, competition
from these entities could adversely impact our results of operations and
accordingly cash available for distribution.
Cost reimbursements due to our
general partner and its affiliates for services provided may be substantial and
could reduce our cash available for distribution to
you.
Pursuant
to the omnibus agreement we entered into with EnerVest, our general partner and
others, EnerVest will receive reimbursement for the provision of various general
and administrative services for our benefit. In addition, we entered
into contract operating agreements with a subsidiary of EnerVest pursuant
to which the subsidiary will be the contract operator of all of the wells for
which we have the right to appoint an operator. Payments for these
services will be substantial and will reduce the amount of cash available for
distribution to unitholders. In addition, under Delaware partnership
law, our general partner has unlimited liability for our obligations, such as
our debts and environmental liabilities, except for our contractual obligations
that are expressly made without recourse to our general partner. To the
extent our general partner incurs obligations on our behalf, we are obligated to
reimburse or indemnify it. If we are unable or unwilling to reimburse or
indemnify our general partner, our general partner may take actions to cause us
to make payments of these obligations and liabilities. Any such payments
could reduce the amount of cash otherwise available for distribution to our
unitholders.
Our partnership agreement limits our
general partner’s fiduciary duties to holders of our common units and
subordinated units.
Although
our general partner has a fiduciary duty to manage us in a manner beneficial to
us and our unitholders, the directors and officers of EV Management, the general
partner of our general partner, have a fiduciary duty to manage our general
partner in a manner beneficial to its owners. Our partnership agreement
contains provisions that reduce the standards to which our general partner and
its affiliates would otherwise be held by state fiduciary duty laws. For
example, our partnership agreement permits our general partner and its
affiliates to make a number of decisions either in their individual capacities,
as opposed to in its capacity as our general partner, or otherwise free of
fiduciary duties to us and our unitholders. This entitles our general
partner and its affiliates to consider only the interests and factors that they
desire, and they have no duty or obligation to give any consideration to any
interest of, or factors affecting, us, our affiliates or any limited partner.
Examples include:
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whether
or not to exercise its right to reset the target distribution levels of
its incentive distribution rights at higher levels and receive, in
connection with this reset, a number of Class B units that are
convertible at any time following the first anniversary of the issuance of
these Class B units into common
units;
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whether
or not to exercise its limited call
right;
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how
to exercise its voting rights with respect to the units it
owns;
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whether
or not to exercise its registration
rights; and
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whether
or not to consent to any merger or consolidation of the partnership or
amendment to the partnership
agreement.
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Our partnership agreement restricts
the remedies available to holders of our common units and subordinated units for
actions taken by our general partner that might otherwise constitute breaches of
fiduciary duty.
Our
partnership agreement contains provisions restricting the remedies available to
unitholders for actions taken by our general partner or its affiliates that
might otherwise constitute breaches of fiduciary duty. For example, our
partnership agreement:
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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, meaning it believed the decision was in
the best interests of our
partnership;
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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 the general partner of our general partner and not involving a vote
of unitholders must be on terms no less favorable to us than those
generally being provided to or available from unrelated third parties or
must be “fair and reasonable” to us, as determined by our general partner
in good faith and that, in determining whether a transaction or resolution
is “fair and reasonable,” our general partner may consider the totality of
the relationships between the parties involved, including other
transactions that may be particularly advantageous or beneficial to
us; and
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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 non-appealable judgment
entered by a court of competent jurisdiction determining that the general
partner or those other persons acted in bad faith or engaged in fraud or
willful misconduct or, in the case of a criminal matter, acted with
knowledge that the conduct was
criminal.
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Our general partner may elect to
cause us to issue Class B units to it in connection with a resetting of the
target distribution levels related to our general partner’s incentive
distribution rights without the approval of the conflicts committee or holders
of our common units and subordinated units. This may result in lower
distributions to holders of our common units in certain
situations.
Our
general partner has the right, at a time when there are no subordinated units
outstanding and it has received incentive distributions at the highest level to
which it is entitled (25%) for each of the prior four consecutive fiscal
quarters, to reset the initial cash target distribution levels at higher levels
based on the distribution at the time of the exercise of the reset election.
Following a reset election by our general partner, the minimum quarterly
distribution amount will be reset to an amount equal to the average cash
distribution amount per common unit for the two fiscal quarters immediately
preceding the reset election (such amount is referred to as the “reset
minimum quarterly distribution”) and the target distribution levels will be
reset to correspondingly higher levels based on percentage increases above the
reset minimum quarterly distribution amount.
In
connection with resetting these target distribution levels, our general partner
will be entitled to receive a number of Class B units. The
Class B units will be entitled to the same cash distributions per unit as
our common units and will be convertible into an equal number of common units.
The number of Class B units to be issued will be equal to that number
of common units whose aggregate quarterly cash distributions equaled the average
of the distributions to our general partner on the incentive distribution rights
in the prior two quarters. We anticipate that our general partner would
exercise this reset right in order to facilitate acquisitions or internal growth
projects that would not be sufficiently accretive to cash distributions per
common unit without such conversion; however, it is possible that our general
partner could exercise this reset election at a time when it is experiencing, or
may be expected to experience, declines in the cash distributions it receives
related to its incentive distribution rights and may therefore desire to be
issued our Class B units, which are entitled to receive cash distributions
from us on the same priority as our common units, rather than retain the right
to
receive
incentive distributions based on the initial target distribution levels.
As a result, a reset election may cause our common unitholders to
experience dilution in the amount of cash distributions that they would have
otherwise received had we not issued new Class B units to our general
partner in connection with resetting the target distribution levels related to
our general partner incentive distribution rights.
Holders of our common units have
limited voting rights and are not entitled to elect our general partner or the
board of directors of its general partner.
Unlike
the holders of common stock in a corporation, unitholders have only limited
voting rights on matters affecting our business and, therefore, limited ability
to influence management’s decisions regarding our
business. Unitholders will not elect our general partner, its general
partner or the members of its board of directors, and will have no right to
elect our general partner, its general partner or its board of directors on an
annual or other continuing basis. The board of directors of EV
Management is chosen by EnerVest, the sole member of EV Management.
Furthermore, if the unitholders were dissatisfied with the performance of
our general partner, they will have only a limited ability to remove our general
partner. As a result of these limitations, the price at which the common
units will trade could be diminished because of the absence or reduction of a
takeover premium in the trading price.
Even if holders of our common units
are dissatisfied, they will have difficulty
removing our general
partner without its consent.
The vote
of the holders of at least 66 2/3% of all outstanding units voting together
as a single class is required to remove the general partner. As of
March 2, 2009, our general partner, its owners and their affiliates, and EnCap
own 19.5% of our aggregate outstanding common and subordinated units.
Also, if our general partner is removed without cause during the
subordination period and units held by our general partner and its affiliates
are not voted in favor of that removal, all remaining subordinated units will
automatically convert into common units and any existing arrearages on our
common units will be extinguished. A removal of our general partner under
these circumstances would adversely affect our common units by prematurely
eliminating their distribution and liquidation preference over our subordinated
units, which would otherwise have continued until we had met certain
distribution and performance tests. Cause is narrowly defined to mean that
a court of competent jurisdiction has entered a final, non–appealable judgment
finding the general partner liable for actual fraud or willful or wanton
misconduct in its capacity as our general partner. Cause does not include
most cases of charges of poor business management, so the removal of the general
partner because of the unitholder’s dissatisfaction with our general partner’s
performance in managing our partnership will most likely result in the
termination of the subordination period and conversion of all subordinated units
to common units.
Our partnership agreement restricts
the voting rights of unitholders owning 20% or more of our common
units.
Unitholders’
voting rights are further restricted by the partnership agreement provision
providing that any units held by a person that owns 20% or more of any class of
units then outstanding, other than our general partner, its affiliates, their
transferees and persons who acquired such units with the prior approval of the
board of directors of our general partner, cannot vote on any matter. Our
partnership agreement also contains provisions limiting the ability of
unitholders to call meetings or to acquire information about our operations, as
well as other provisions limiting the unitholders’ ability to influence the
manner or direction of management.
Control of our general partner may
be transferred to a third party without unitholder
consent.
Our
general partner may transfer its general partner interest to a third party in a
merger or in a sale of all or substantially all of its assets without the
consent of the unitholders. Furthermore, our partnership agreement does
not restrict the ability of the owners of our general partner or EV Management,
from transferring all or a portion of their respective ownership interest in our
general partner or EV Management to a third party. The new owners of our
general partner or EV Management would then be in a position to replace the
board of directors and officers of EV Management with its own choices and
thereby influence the decisions taken by the board of directors and
officers.
We may issue additional units
without your approval, which would dilute your existing ownership
interests.
Our
partnership agreement does not limit the number of additional limited partner
interests that we may issue at any time without the approval of our unitholders.
The issuance by us of additional common units or other equity securities
of equal or senior rank will have the following effects:
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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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because
a lower percentage of total outstanding units will be subordinated units,
the risk that a shortfall in the payment of the minimum quarterly
distribution will be borne by our common unitholders will
increase;
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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 the common units may
decline.
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EnerVest, EV Investors and EnCap may
sell common units in the public markets, which sales could have an adverse
impact on the trading price of the common units.
EnerVest,
EV Investors and EnCap hold an aggregate of 2.2 million subordinated
units. All of the subordinated units will convert into common units
at the end of the subordination period and some may convert
earlier. The sale of these units in the public markets could have an
adverse impact on the price of the common units or on any trading market that
may develop.
We have the right to borrow to make
distributions. Repayment of these borrowings will decrease cash
available for future distributions, and covenants in our credit facility may
restrict our ability to make distributions.
Our
partnership agreement allows us to borrow to make distributions. We may
make short term borrowings under our credit facility, which we refer to as
working capital borrowings, to make distributions. The primary purpose of
these borrowings would be to mitigate the effects of short term fluctuation in
our working capital that would otherwise cause volatility in our quarter to
quarter distributions.
The terms
of our credit facility may restrict our ability to pay distributions if we do
not satisfy the financial and other covenants in the facility.
Our partnership agreement requires
that we distribute all of our available cash, which could limit our ability to
grow our reserves and production.
Our
partnership agreement provides that we will distribute all of our available cash
each quarter. As a result, we will be dependent on the issuance of
additional common units and other partnership securities and borrowings to
finance our growth. A number of factors will affect our ability to issue
securities and borrow money to finance growth, as well as the costs of such
financings, including:
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general
economic and market conditions, including interest rates, prevailing at
the time we desire to issue securities or borrow
funds;
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conditions
in the oil and natural gas
industry;
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our
results of operations and financial
condition; and
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prices
for oil and natural gas.
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Our general partner has a limited
call right that may require you to sell your units at an undesirable time or
price.
If at any
time our general partner and its affiliates own more than 80% of 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, you may be required to
sell your common units at an undesirable time or price and may not receive any
return on your investment. You may also incur a tax liability upon a sale
of your units.
Your liability may not be limited if
a court finds that unitholder action constitutes control of our
business.
A general
partner of a partnership generally has unlimited liability for the obligations
of the partnership, except for those contractual obligations of the partnership
that are expressly made without recourse to the general partner. Our
partnership is organized under Delaware law and we conduct business in a number
of other states. The limitations on the liability of holders of limited
partner interests for the obligations of a limited partnership have not been
clearly established in some of the other states in which we do business.
You could be liable for any and all of our obligations as if you were a
general partner if:
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a
court or government agency determined that we were conducting business in
a state but had not complied with that particular state’s partnership
statute; or
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your
right to act with other unitholders to remove or replace the general
partner, to approve some amendments to our partnership agreement or to
take other actions under our partnership agreement constitutes “control”
of our business.
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Unitholders may have liability to
repay distributions that were wrongfully distributed to
them.
Under
certain circumstances, unitholders may have to repay amounts wrongfully returned
or distributed to them. Under Section 17–607 of the Delaware Revised
Uniform Limited Partnership Act, we may not make a distribution to you if the
distribution would cause our liabilities to exceed the fair value of our assets.
Delaware law provides that for a period of three years from the date of
the impermissible distribution, limited partners who received the distribution
and who knew at the time of the distribution that it violated Delaware law will
be liable to the limited partnership for the distribution amount.
Substituted limited partners are liable for the obligations of the
assignor to make contributions to the partnership that are known to the
substituted limited partner at the time it became a limited partner and for
unknown obligations if the liabilities could be determined from the partnership
agreement. Liabilities to partners on account of their partnership
interest and liabilities that are non–recourse to the partnership are not
counted for purposes of determining whether a distribution is
permitted.
If we distribute cash from capital
surplus, which is analogous of a return of capital, our minimum quarterly
distribution rate will be reduced proportionately, and the distribution
thresholds after which the incentive distribution rights entitle our general
partner to an increased percentage of distributions will be proportionately
decreased.
Our cash
distribution will be characterized as coming from either operating surplus or
capital surplus. Operating surplus generally means amounts we receive from
operating sources, such as sale of our oil and natural gas production, less
operating expenditures, such as production costs and taxes, and less estimated
maintenance capital, which are generally amounts we estimate we will need to
spend in the future to maintain our production levels over the long term.
Capital surplus generally means amounts we receive from non–operating
sources, such as sales of properties and issuances of debt and equity
securities. Cash representing capital surplus, therefore, is analogous to
a return of capital. Distributions of capital surplus are made to our
unitholders and our general partner in proportion to their percentage interests
in us, or 98 percent to our unitholders and two percent to our general
partner, and will result in a decrease in our minimum quarterly distribution and
a lower threshold for distributions on the incentive distribution rights held by
our general partner.
Our
partnership agreement allows us to add to operating surplus up to two times the
amount of our most recent minimum quarterly distribution. As a result, a
portion of this amount, which is analogous to a return of capital, may be
distributed to the general partner and its affiliates, as holders of incentive
distribution rights, rather than to holders of common units as a return of
capital.
If we fail to
maintain an effective system of internal controls, we may not be able to
accurately report our financial results or prevent fraud. As a
result, current and potential unitholders could lose confidence in our financial
reporting, which would harm our business and the trading price of our
units.
Effective
internal controls are necessary for us to provide reliable financial reports,
prevent fraud and operate successfully as a public company. If we cannot
provide reliable financial reports or prevent fraud, our reputation and
operating results would be harmed. We cannot be certain that our efforts
to maintain our internal controls will be successful, that we will be able to
maintain adequate controls over our financial processes and reporting in the
future or that we will be able to continue to comply with our obligations under
Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to
maintain effective internal controls, or difficulties encountered in
implementing or improving our internal controls, could harm our operating
results or cause us to fail to meet our reporting obligations. Ineffective
internal controls could also cause investors to lose confidence in our reported
financial information, which would likely have a negative effect on the trading
price of our units.
Tax Risks to Common
Unitholders
Our tax treatment depends on our
status as a partnership for federal income tax purposes and not being subject to
a material amount of entity–level taxation by individual states. If
the Internal Revenue Service treats us as a corporation or we become subject to
a material amount of entity-level taxation for state tax purposes, it would
reduce the amount of cash available for distribution to our
unitholders.
The
anticipated after–tax economic benefit of an investment in the common units
depends largely on our being treated as a partnership for federal income tax
purposes. We have not requested, and do not plan to request, a ruling from
the Internal Revenue Service, which we refer to as the IRS, on this or any other
tax matter affecting us.
If we
were treated as a corporation for federal income tax purposes, we would pay
federal income tax on our taxable income at the corporate tax rate, which is
currently a maximum of 35%, and would likely pay state income tax at varying
rates. Distributions to you would generally be taxed again as corporate
distributions, and no income, gains, losses or deductions would flow through to
you. Because a tax would be imposed upon us as a corporation, our cash
available for distribution to you would be substantially reduced.
Therefore, treatment of us as a corporation would result in a material
reduction in the anticipated cash flows and after–tax return to the unitholders,
likely causing a substantial reduction in the value of our common
units.
Current
law may change so as to cause us to be treated as a corporation for federal
income tax purposes or otherwise subject us to entity–level taxation. In
addition, because of widespread state budget deficits and other reasons, to the
extent they were not already doing so, several states, including Texas, have
implemented or are evaluating ways to subject partnerships to entity–level
taxation through the imposition of state income, franchise and other forms of
taxation. For example, the Texas gross margin or franchise tax will be
imposed at a maximum effective rate of 0.7% of our gross 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 you.
The
partnership agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to taxation as a
corporation or otherwise subjects us to entity-level taxation for federal, state
or local income tax purposes, the minimum quarterly distribution amount and the
target distribution levels will be adjusted to reflect the impact of that law on
us.
An IRS contest of our federal income
tax positions may adversely affect the market for our common units, and the cost
of any IRS contest will reduce our cash available for distribution to our
unitholders.
We have
not requested a ruling from the IRS with respect to our treatment as a
partnership for federal income tax purposes or any other matter affecting us.
It may be necessary to resort to administrative or court proceedings to
sustain some or all of our counsel’s conclusions or the positions we take.
A court may not agree with all of our counsel’s conclusions or positions
we take. Any contest with the IRS may materially and adversely impact the
market for our common units and the price at which they trade. In
addition, our costs for any contest with the IRS will be borne indirectly by our
unitholders and our general partner because the costs will reduce our cash
available for distribution.
You may be required to pay taxes on
income from us even if you do not receive any cash distributions
from us.
Because
our unitholders will be treated as partners to whom we will allocate taxable
income which could be different in amount than the cash we distribute, you will
be required to pay any federal income taxes and, in some cases, state and local
income taxes on your share of our taxable income even if you receive no cash
distributions from us. You may not receive cash
distributions from us equal to your share of our taxable income or even equal to
the tax liability that results from that income.
Tax gain or loss on disposition of
common units could be more or less than expected.
If you
sell your common units, you will recognize a gain or loss equal to the
difference between the amount realized and your tax basis in those common units.
Prior distributions to you in excess of the total net taxable income you
were allocated for a common unit, which decreased your tax basis in that common
unit, will, in effect, become taxable income to you if the common unit is sold
at a price greater than your tax basis in that common unit, even if the price is
less than your original cost. A substantial portion of the amount
realized, whether or not representing gain, may be ordinary income. In addition,
if you sell your units, you may incur a tax liability in excess of the amount of
cash you receive from the sale.
Tax–exempt entities and foreign
persons face unique tax issues from owning common units that may result in
adverse tax consequences to them.
Investment
in common units by tax–exempt entities, such as individual retirement accounts
(known as IRAs), other retirement plans and non–U.S. persons raises issues
unique to them. For example, virtually all of our income allocated to
organizations that are exempt from federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and will be taxable
to them. Distributions to non–U.S. persons will be reduced by
withholding taxes at the highest applicable effective tax rate, and
non–U.S. persons will be required to file United States federal tax returns
and pay tax on their share of our taxable income.
We will treat each purchaser of our
common units as having the same tax benefits without regard to the actual common
units purchased. The IRS may challenge this treatment, which could adversely
affect the value of the common units.
Because
we cannot match transferors and transferees of common units and because of other
reasons, we will take depreciation and amortization positions that may not
conform to all aspects of existing Treasury Regulations. A successful IRS
challenge to those positions could adversely affect the amount of tax benefits
available to you. It also could affect the timing of these tax benefits or
the amount of gain from the sale of common units and could have a negative
impact on the value of our common units or result in audit adjustments to your
tax returns.
The sale or exchange of 50% or more
of our capital and profits interests during any twelve–month period will result
in the termination of our partnership for federal income tax
purposes.
We will
be considered to have terminated our partnership for federal income tax purposes
if there is a sale or exchange of 50% or more of the total interests in our
capital and profits within a twelve–month period. For example, an exchange
of 50% of our capital and profits could occur if, in any twelve–month period,
holders of our subordinated and common units sell at least 50% of the interests
in our capital and profits. Our termination would, among other things,
result in the closing of our taxable year for all unitholders and could result
in a deferral of depreciation deductions allowable in computing our taxable
income.
Unitholders may be subject to state
and local taxes and tax return filing requirements in states where they do not
live as a result of investing in our common units.
In
addition to federal income taxes, you will likely be subject to other taxes,
including state and local taxes, unincorporated business taxes and estate,
inheritance or intangible taxes that are imposed by the various jurisdictions in
which we do business or own property, even if you do not live in any of those
jurisdictions. You will likely be required to file foreign, state and
local income tax returns and pay state and local income taxes in some or all of
these jurisdictions. Further, you may be subject to penalties for failure
to comply with those requirements. We own assets and do business in the
states of Texas, Louisiana, Oklahoma, New Mexico, Colorado, Kansas, Michigan,
Ohio, West Virginia and Pennsylvania. Each of these states, other than
Texas, currently imposes a personal income tax. As we make
acquisitions or expand our business, we may own assets or do business in
additional states that impose a personal income tax. It is your
responsibility to file all United States federal, foreign, state and local tax
returns.
None.
Information
regarding our properties is contained in Item 1. Business “—Our Areas of
Operation” and “—Our Oil and Natural Gas Data” contained
herein.
We are
involved in disputes or legal actions arising in the ordinary course of
business. We do not believe the outcome of such disputes or legal
actions will have a material adverse effect on our consolidated financial
statements.
None.
Our
common units are traded on the NASDAQ Global Market under the symbol
“EVEP.” At the close of business on March 2, 2009, based upon
information received from our transfer agent and brokers and nominees, we had
120 common unitholders of record. This number does not include owners
for whom common units may be held in “street” names.
The
following table sets forth the range of the daily high and low sales prices per
common unit and cash distributions to common unitholders for 2008 and
2007:
|
Price
Range
|
||||||||||||
|
High
|
Low
|
Cash
Distribution
per
Common Unit (1)
|
||||||||||
|
2008:
|
||||||||||||
|
First Quarter
|
$ | 34.45 | $ | 21.50 | $ | 0.620 | ||||||
|
Second Quarter
|
33.08 | 25.10 | 0.700 | |||||||||
|
Third Quarter
|
29.20 | 16.73 | 0.750 | |||||||||
|
Fourth Quarter
|
19.50 | 8.78 | 0.751 | (2) | ||||||||
|
2007:
|
||||||||||||
|
First Quarter
|
$ | 36.74 | $ | 21.25 | $ | 0.460 | ||||||
|
Second Quarter
|
40.75 | 34.52 | 0.500 | |||||||||
|
Third Quarter
|
44.13 | 30.01 | 0.560 | |||||||||
|
Fourth Quarter
|
39.00 | 30.68 | 0.600 | |||||||||
|
(1)
|
Cash
distributions are declared and paid in the following calendar
quarter.
|
|
(2)
|
On
January 28, 2009, the board of directors of EV Management declared a
quarterly cash distribution for the fourth quarter of 2008 of $0.751 per
unit. The distribution was paid on February 13,
2009.
|
|
|
Cash
Distributions to Unitholders
|
We intend
to continue to make cash distributions to unitholders on a quarterly basis,
although there is no assurance as to the future cash distributions since they
are dependent upon future earnings, cash flows, capital requirements, financial
condition and other factors. Our credit agreement prohibits us from
making cash distributions if any potential default or event of default, as
defined in the credit agreement, occurs or would result from the cash
distribution.
Our
partnership agreement requires that, within 45 days after the end of each
quarter, we distribute all of our available cash (as defined in our partnership
agreement) to unitholders of record on the applicable record
date. The amount of available cash generally is all cash on hand at
the end of the quarter:
|
|
·
|
less the amount of cash
reserves established by our general partner
to:
|
|
|
·
|
provide
for the proper conduct of our
business;
|
|
|
·
|
comply
with applicable law, any of our debt instruments or other
agreements; or
|
|
|
·
|
provide
funds for distributions to our unitholders and to our general partner for
any one or more of the next
four quarters;
|
|
|
·
|
plus, if our general
partner so determines, all or a portion of cash on hand on the date of
determination of available cash for the quarter including cash from
working capital borrowings.
|
Working
capital borrowings are borrowings used solely for working capital purposes or to
pay distributions to unitholders.
Initially,
our general partner was entitled to 2% of all quarterly distributions that we
made prior to our liquidation. Our general partner has the right, but
not the obligation, to contribute a proportionate amount of capital to us to
maintain its current general partner interest. The general partner’s
initial 2% interest in these distributions will be reduced if we issue
additional units in the future and our general partner does not contribute a
proportionate share of capital to us to maintain its 2% general partnership
interest. When we issued common units in 2007, our general partner
contributed to us an amount of cash necessary to maintain its 2%
interest.
Our
general partner also holds incentive distribution rights that entitle it to
receive increasing percentages, up to a maximum of 25%, of the cash we
distribute from operating surplus (as defined in our partnership agreement) in
excess of $0.46 per unit per quarter. The maximum distribution
percentage of 25% includes distributions paid to our general partner on its 2%
general partner interest and assumes that our general partner maintains its
general partner interest at 2%. The maximum distribution percentage
of 25% does not include any distributions that our general partner may receive
on common and subordinated units that it owns. For additional
information on our distributions, please see Note 11 of the Notes to
Consolidated/Combined Financial Statements in Item 8. “Financial Statements and
Supplementary Data.”
During
the subordination period, the common units will have the right to receive
distributions of available cash from operating surplus each quarter in an amount
equal to $0.40 per common unit plus any arrearages in the payment of the
minimum quarterly distribution on the common units from prior quarters, before
any distributions of available cash from operating surplus may be made on the
subordinated units. These units are deemed “subordinated” because for a
period of time, referred to as the subordination period, the subordinated units
will not be entitled to receive any distributions until the common units have
received the minimum quarterly distribution plus any arrearages from prior
quarters. Furthermore, no arrearages will be paid on the subordinated
units. The practical effect of the subordinated units is to increase the
likelihood that during the subordination period there will be available cash to
be distributed on the common units.
The
subordination period will extend until the first day of any quarter beginning
after September 30, 2011 that each of the following tests are
met:
|
|
·
|
distributions
of available cash from operating surplus on each of the outstanding common
units, subordinated units and the 2% general partner interest equaled or
exceeded the minimum quarterly distribution for each of the three
consecutive, non–overlapping four quarter periods immediately
preceding that date;
|
|
|
·
|
the
“adjusted operating surplus” (as defined in our partnership agreement)
generated during each of the three consecutive, non–overlapping
four quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distributions on all of the
outstanding common and subordinated units and the 2% general partner
interest during those periods on a fully diluted basis during those
periods; and
|
|
|
·
|
there
are no arrearages in payment of the minimum quarterly distribution on the
common units.
|
When the
subordination period expires, each outstanding subordinated unit will convert
into one common unit and will then participate pro rata with the other common
units in distributions of available cash. In addition, if the unitholders
remove our general partner other than for cause and units held by the general
partner and its affiliates are not voted in favor of such
removal:
|
|
·
|
the
subordination period will end and each subordinated unit will immediately
convert into one common unit;
|
|
|
·
|
any
existing arrearages in payment of the minimum quarterly distribution on
the common units will be extinguished;
and
|
|
|
·
|
the
general partner will have the right to convert its 2% general partner
interest and its incentive distribution rights into common units or to
receive cash in exchange for those
interests.
|
In
addition, if the tests for ending the subordination period are satisfied for any
three consecutive, non–overlapping four quarter periods ending on or after
September 30, 2009, 25% of the subordinated units will convert into an
equal number of common units, and if the tests for ending the subordination
period are satisfied for any three consecutive, non–overlapping four quarter
periods ending after September 30, 2010, an additional 25% of the
subordinated units will convert into common units. The second early
conversion of subordinated units may not occur, however, until at least one year
following the end of the period for the first early conversion of subordinated
units.
In
addition to the early conversion of subordinated units described above, all of
the subordinated units will convert into an equal number of common units if the
following tests are met:
|
|
·
|
distributions
of available cash from operating surplus on each of the outstanding common
units, subordinated units and the 2% general partner interest equaled or
exceeded $2.00 (125% of the annualized minimum quarterly distribution) for
each of the two consecutive, non-overlapping four-quarter periods ending
on or after September 30,
2009;
|
|
|
·
|
the
adjusted operating surplus generated during each of the two consecutive,
non-overlapping four-quarter periods immediately preceding that date
equaled or exceeded the sum of a distribution of $2.00 per common
unit (125% of the annualized minimum quarterly distribution) on all of the
outstanding common and subordinated units and the 2% general partner
interest during those periods on a fully diluted
basis; and
|
|
|
·
|
there
are no arrearages in payment of the minimum quarterly distribution on the
common units.
|
Our
partnership agreement requires that we make distributions of available cash from
operating surplus for any quarter during the subordination period in the
following manner:
|
|
·
|
first, 98% to the
common unitholders, pro rata, and 2% to the general partner, until we
distribute for each outstanding common unit an amount equal to the minimum
quarterly distribution for that
quarter;
|
|
|
·
|
second, 98% to the
common unitholders, pro rata, and 2% to the general partner, until we
distribute for each outstanding common unit an amount equal to any
arrearages in payment of the minimum quarterly distribution on the common
units for any prior quarters during the subordination
period;
|
|
|
·
|
third, 98% to the
subordinated unitholders, pro rata, and 2% to the general partner, until
we distribute for each subordinated unit an amount equal to the minimum
quarterly distribution for that
quarter; and
|
|
|
·
|
thereafter, cash in
excess of the minimum quarterly distributions is distributed to the
unitholders and the general partner based on the percentages
below.
|
Our
general partner is entitled to incentive distributions if the amount we
distribute with respect to one quarter exceeds specified target levels shown
below:
|
Marginal
Percentage Interest in Distributions
|
||||||||||||
|
Total
Quarterly Distributions
Target
Amount
|
Limited
Partner
|
General
Partner
|
||||||||||
|
Minimum
quarterly distribution
|
$0.40
|
98%
|
2%
|
|||||||||
|
First
target distribution
|
Up
to $0.46
|
98%
|
2%
|
|||||||||
|
Second
target distribution
|
Above
$0.46, up to $0.50
|
85%
|
15%
|
|||||||||
|
Thereafter
|
Above
$0.50
|
75%
|
25%
|
|||||||||
Technical
Termination of Partnership
A sale or
exchange of more than 50% of the total interests in our capital and profits
occurred over the twelve months ended September 30, 2008 and resulted in our
termination and immediate reconstitution as a new partnership for federal income
tax purposes. This termination did not affect our classification as a
partnership for federal income tax purposes or
affect
the nature or extent of our “qualifying income” for federal income tax
purposes. The closing of our taxable years will result in us filing
two tax returns (and unitholders receiving two Schedule K–1’s) for one fiscal
year. We will be required to reset the depreciation schedule for
depreciable assets for federal income tax purposes. This will result
in a deferral of depreciation deductions allowable in computing the taxable
income allocated to unitholders, which effect we do not expect to be
material.
Unregistered
Sales of Equity Securities
None.
Issuer
Purchases of Equity Securities
None.
The
following table shows selected financial data of us and our
predecessors for the periods and as of the dates indicated. The
selected financial data for the years ended December 31, 2008 and 2007 and three
months ended and as of December 31, 2006 are derived from our audited financial
statements. The selected financial data for the nine months ended and
as of September 30, 2006 and for the years ended and as of December 31,
2005 and 2004 are derived from the audited financial statements of our
predecessors. The selected financial data should be read in conjunction
with “Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations” and “Item 8. Financial Statements and Supplementary
Data,” both contained herein.
|
Successor
|
Predecessors
(1)
|
|||||||||||||||||||||||
|
Three
Months Ended
|
Nine
Months Ended
|
|||||||||||||||||||||||
|
Year
Ended December 31,
|
December
31,
|
September
30,
|
Year
Ended December 31,
|
|||||||||||||||||||||
|
2008
(2)
|
2007
(3)
|
2006
(4)
|
2006
|
2005
(5)
|
2004
|
|||||||||||||||||||
|
Statement
of Operations Data:
|
||||||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||||||
|
Oil, natural gas and natural gas
liquids
revenues
|
$ | 192,757 | $ | 89,422 | $ | 5,548 | $ | 34,379 | $ | 45,148 | $ | 28,336 | ||||||||||||
|
Gain (loss) on derivatives, net
(6)
|
1,597 | 3,171 | 999 | 1,254 | (7,194 | ) | (1,890 | ) | ||||||||||||||||
|
Transportation
and marketing–related
revenues
|
12,959 | 11,415 | 1,271 | 4,458 | 6,225 | 3,438 | ||||||||||||||||||
|
Total
revenues
|
207,313 | 104,008 | 7,818 | 40,091 | 44,179 | 29,884 | ||||||||||||||||||
|
Operating
costs and expenses:
|
||||||||||||||||||||||||
|
Lease operating
expenses
|
42,681 | 21,515 | 1,493 | 6,085 | 7,236 | 6,615 | ||||||||||||||||||
|
Cost of purchased natural
gas
|
9,849 | 9,830 | 1,153 | 3,860 | 5,660 | 3,003 | ||||||||||||||||||
|
Production taxes
|
9,088 | 3,360 | 109 | 185 | 292 | 119 | ||||||||||||||||||
|
Exploration expenses (7)
|
– | – | – | 1,061 | 2,539 | 1,281 | ||||||||||||||||||
|
Dry hole costs (7)
|
– | – | – | 354 | 530 | 440 | ||||||||||||||||||
|
Impairment of unproved oil and
natural
gas
properties (7)
|
– | – | – | 90 | 2,041 | 1,415 | ||||||||||||||||||
|
Asset retirement obligations
accretion
expense
|
1,434 | 814 | 89 | 129 | 171 | 160 | ||||||||||||||||||
|
Depreciation, depletion and
amortization
|
38,032 | 19,759 | 1,180 | 4,388 | 4,409 | 4,135 | ||||||||||||||||||
|
General and administrative
expenses
|
13,653 | 10,384 | 2,043 | 1,491 | 1,016 | 1,155 | ||||||||||||||||||
|
Total
operating costs and expenses
|
114,737 | 65,662 | 6,067 | 17,643 | 23,894 | 18,323 | ||||||||||||||||||
|
Operating
income
|
92,576 | 38,346 | 1,751 | 22,448 | 20,285 | 11,561 | ||||||||||||||||||
|
Other
income (expense), net
|
133,144 | (27,102 | ) | 1,616 | (229 | ) | (428 | ) | 12 | |||||||||||||||
|
Income
before income taxes and equity in
income
(loss) of affiliates
|
225,720 | 11,244 | 3,367 | 22,219 | 19,857 | 11,573 | ||||||||||||||||||
|
Income
taxes
|
(235 | ) | (54 | ) | – | (5,809 | ) | (5,349 | ) | (2,521 | ) | |||||||||||||
|
Equity
in income (loss) of affiliates
|
– | – | – | 164 | 565 | (621 | ) | |||||||||||||||||
|
Net
income
|
$ | 225,485 | $ | 11,190 | $ | 3,367 | $ | 16,574 | $ | 15,073 | $ | 8,431 | ||||||||||||
|
General
partner’s interest in net income,
including
incentive distribution rights
|
$ | 54,643 | $ | 1,670 | $ | 67 | ||||||||||||||||||
|
Limited
partners’ interest in net income
|
$ | 170,842 | $ | 9,520 | $ | 3,300 | ||||||||||||||||||
|
Net
income per limited partner unit:
|
||||||||||||||||||||||||
|
Common units (basic and
diluted)
|
$ | 11.14 | $ | 0.74 | $ | 0.43 | ||||||||||||||||||
|
Subordinated units (basic
and diluted)
|
$ | 11.14 | $ | 0.74 | $ | 0.43 | ||||||||||||||||||
|
Cash
distributions per common unit
|
$ | 2.67 | $ | 1.92 | $ | – | ||||||||||||||||||
|
Financial
Position (at end ofperiod):
|
||||||||||||||||||||||||
|
Working capital
|
$ | 94,817 | $ | 16,438 | $ | 12,006 | $ | 9,190 | $ | (642 | ) | $ | 3,094 | |||||||||||
|
Total assets
|
979,995 | 607,541 | 132,689 | 95,749 | 77,351 | 58,801 | ||||||||||||||||||
|
Long–term debt
|
467,000 | 270,000 | 28,000 | 10,350 | 10,500 | 2,850 | ||||||||||||||||||
|
Owners’ equity
|
457,484 | 283,030 | 96,253 | 63,240 | 40,910 | 41,215 | ||||||||||||||||||
|
(1)
|
The
financial statements of our predecessors were prepared on a combined basis
as the entities were under common
control.
|
|
(2)
|
Includes
the results of (i) the Charlotte acquisition in May 2008, (ii) the August
acquisitions in August 2008, (iii) the West Virginia acquisition in
September 2008 and (iv) the San Juan acquisition in September
2008.
|
|
(3)
|
Includes
the results of (i) the acquisition of natural gas properties in Michigan
in January 2007, (ii) the acquisition of additional natural gas properties
in the Monroe Field in March 2007, (iii) the acquisition of oil and
natural gas properties in Central and East Texas in June 2007, (iv) the
acquisition of oil and natural gas properties in the Permian Basin in
October 2007 and (v) the acquisition of oil and natural gas properties in
the Appalachian Basin in December
2007.
|
|
(4)
|
Includes
the results of the acquisition of oil and natural gas properties in the
Mid–Continent area in December
2006.
|
|
(5)
|
Includes
the results of an acquisition by our predecessors of oil and natural gas
properties in the Monroe Field in March
2005.
|
|
(6)
|
Our
predecessors accounted for their derivative instruments as cash flow
hedges in accordance with SFAS No. 133. Accordingly, the
changes in fair value of the derivative instruments were reported in
accumulated other comprehensive income (“AOCI”) and reclassified to net
income in the periods in which the contracts were settled. As
of October 1, 2006, we elected not to designate our derivative instruments
as hedges in accordance with SFAS No. 133. The amount in AOCI
at that date related to derivative instruments that previously were
designated and accounted for as cash flow hedges continued to be deferred
until the underlying production was produced and sold, at which time
amounts were reclassified from AOCI and reflected as a component of
revenues. Changes in the fair value of derivative instruments
that existed at October 1, 2006 and any derivative instruments entered
into thereafter are no longer deferred in AOCI, but rather are recorded
immediately to net income as “Gain (loss) on mark–to–market
derivatives, net”, which in included in “Other income (expense), net” in
our consolidated statement of
operations.
|
|
(7)
|
Exploration
expenses, dry hole costs and impairment of unproved properties were
incurred by one of our predecessors with respect to properties we did not
acquire.
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations should
be read in conjunction with “Item 8. Financial Statements and Supplementary
Data” contained herein.
OVERVIEW
We are a
Delaware limited partnership formed in April 2006 by EnerVest to acquire,
produce and develop oil and natural gas properties. We consummated
the acquisition of our predecessors and an initial public offering of our common
units effective October 1, 2006. Our general partner is EV Energy GP
and the general partner of our general partner is EV Management.
Acquisitions
in 2008
In 2008,
we completed the following acquisitions:
|
|
·
|
in
May, we acquired oil properties in South Central Texas for $17.4
million;
|
|
|
·
|
in
August 2008, we acquired oil and natural gas properties in Michigan,
Central and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle
and Kansas) and Eastland County, Texas for $58.8
million;
|
|
|
·
|
in
September 2008, we issued 236,169 common units to EnerVest to acquire
natural gas properties in West
Virginia;
|
|
|
·
|
in
September 2008, we acquired oil and natural gas properties in the San Juan
Basin from institutional partnerships managed by EnerVest for $114.7
million in cash and 908,954 of our common
units.
|
Our
Assets
As of
December 31, 2008, our properties were located in the Appalachian Basin
(primarily in Ohio and West Virginia), Michigan, the Monroe Field in Northern
Louisiana, Central and East Texas (which includes the Austin Chalk area), the
Permian Basin, the San Juan Basin and the Mid–Continent areas in Oklahoma,
Texas, Kansas and Louisiana, and we had estimated net proved reserves of 5.9
MMBbls of oil, 266.0 Bcf of natural gas and 9.6 MMBbls of natural gas
liquids, or 359.2 Bcfe, and a standardized measure of $441.9 million.
Business
Environment
The U.S.
and other world economies are currently in a recession which could last well
into 2009 and beyond. Additionally, the capital markets are
experiencing significant volatility, and many financial institutions have
liquidity concerns, prompting government intervention to mitigate pressure on
the capital markets. The primary effects of the recession on our
business are expected to be a continuation in the low prices we receive for our
production, which we discuss in this section. Our primary exposure to
the current crisis in the debt and equity markets includes the
following,
|
|
·
|
our
revolving credit facility;
|
|
|
·
|
our
cash investments;
|
|
|
·
|
counterparty
nonperformance risks; and
|
|
|
·
|
our
ability to finance the replacement of our reserves and our growth by
accessing the capital markets,
|
which we
discuss under “—Liquidity and Capital Resources” below.
Our
primary business objective is to provide stability and growth in cash
distributions per unit over time. The amount of cash we can
distribute on our units principally depends upon the amount of cash generated
from our operations, which will fluctuate from quarter to quarter based on,
among other things:
|
|
·
|
the
prices at which we will sell our oil and natural gas
production;
|
|
|
·
|
our
ability to hedge commodity prices;
|
|
|
·
|
the
amount of oil and natural gas we produce;
and
|
|
|
·
|
the
level of our operating and administrative
costs.
|
Oil and
natural gas prices have been, and are expected to be,
volatile. Factors affecting the price of oil include the current
worldwide recession, geopolitical activities, worldwide supply disruptions,
weather conditions, actions taken by the Organization of Petroleum Exporting
Countries and the value of the U.S. dollar in international currency
markets. Factors affecting the price of natural gas include North
American weather conditions, industrial and consumer demand for natural gas,
storage levels of natural gas and the availability and accessibility of natural
gas deposits in North America.
Oil and
natural gas prices have declined significantly since September 30,
2008. This has reduced, and will continue to reduce, our cash flows
from operations. In order to mitigate the impact of lower oil and
natural gas prices on our cash flows, we are a party to derivative agreements,
and we intend to enter into derivative agreements in the future to reduce the
impact of oil and natural gas price volatility on our cash flows. By
removing a significant portion of our price volatility on our future oil and
natural gas production through 2013, we have mitigated, but not eliminated, the
potential effects of changing oil and natural gas prices on our cash flows from
operations for those periods. If the global recession continues,
commodity prices may be depressed for an extended period of time, which could
alter our acquisition and exploration plans, and adversely affect our growth
strategy and ability to access additional capital in the capital
markets.
The
primary factors affecting our production levels are capital availability, our
ability to make accretive acquisitions, the success of our drilling program and
our inventory of drilling prospects. In addition, we face the
challenge of natural production declines. As initial reservoir
pressures are depleted, production from a given well decreases. We
attempt to overcome this natural decline by drilling to find additional reserves
and acquiring more reserves than we produce. Our future growth will
depend on our ability to continue to add reserves in excess of
production. We will maintain our focus on
costs to
add reserves through drilling and acquisitions as well as the costs necessary to
produce such reserves. Our ability to add reserves through drilling
is dependent on our capital resources and can be limited by many factors,
including our ability to timely obtain drilling permits and regulatory
approvals. Any delays in drilling, completion or connection to
gathering lines of our new wells will negatively impact our production, which
may have an adverse effect on our revenues and, as a result, cash available for
distribution.
We focus
our efforts on increasing oil and natural gas reserves and production while
controlling costs at a level that is appropriate for long–term
operations. Our future cash flows from operations are dependent on
our ability to manage our overall cost structure.
Factors
Affecting 2008 Operations
In
addition, the following events impacted our business in 2008:
|
|
·
|
Third
party natural gas liquids fractionation facilities in Mt. Belvieu, TX
sustained damage from Hurricane Ike, which caused a reduction in the
volume of natural gas liquids that were fractionated and sold during the
third and fourth quarters of 2008. In addition, these
facilities underwent a mandatory five year turnaround during the fourth
quarter of 2008. As of December 31, 2008, we estimate that
approximately 37.7 MBbls of natural gas liquids that we produced remained
in storage at Mt. Belvieu. These natural gas liquids will be
fractionated and sold in the future, which we currently estimate to occur
primarily during the first quarter of
2009.
|
|
|
·
|
We
also experienced production curtailments in the Monroe Field of
approximately 3.5 Mmcf from mid–May of 2008 through mid–October of
2008. These curtailments totaled approximately 590 Mmcf of
natural gas for the year. However, during this period, we were
contractually entitled to receive payment from the purchaser for the
amount of natural gas production curtailed, subject to the purchaser
recouping such amounts out of a percentage of future
production.
|
Critical
Accounting Policies
The
discussion and analysis of our financial condition and results of operations is
based upon the consolidated financial statements, which have been prepared in
accordance with U.S. generally accepted accounting principles. The
preparation of these consolidated financial statements requires us to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses and related disclosures about contingent
assets and liabilities. Certain of our accounting policies involve
estimates and assumptions to such an extent that there is reasonable likelihood
that materially different amounts could have been reported under different
conditions or if different assumptions had been used. We base these
estimates and assumptions on historical experience and on various other
information and assumptions that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgments about
the carrying values of assets and liabilities that are not readily apparent from
other sources. Estimates and assumptions about future events and
their effects cannot be perceived with certainty and, accordingly, these
estimates may change as additional information is obtained, as more experience
is acquired, as our operating environment changes and as new events
occur.
Our
critical accounting policies are important to the portrayal of both our
financial condition and results of operations and require us to make difficult,
subjective or complex assumptions or estimates about matters that are uncertain.
We would report different amounts in our consolidated financial
statements, which could be material, if we used different assumptions or
estimates. We believe that the following are the critical accounting
policies used in the preparation of our consolidated financial
statements.
Oil
and Natural Gas Properties
We
account for our oil and natural gas properties using the successful efforts
method of accounting. Under this method, costs of productive
exploratory wells, development dry holes and productive wells and undeveloped
leases are capitalized. Oil and natural gas lease acquisition costs
are also capitalized. Exploration costs, including personnel costs,
certain geological and geophysical expenses and delay rentals for oil and
natural gas leases, are charged to expense during the period the costs are
incurred. Exploratory drilling costs are initially capitalized, but
charged to expense if and when the well is determined not to have found reserves
in commercial quantities.
No gains
or losses are recognized upon the disposition of oil and natural gas properties
except in transactions such as the significant disposition of an amortizable
base that significantly affects the unit–of–production amortization
rate. Sales proceeds are credited to the carrying value of the
properties.
The
application of the successful efforts method of accounting requires managerial
judgment to determine the proper classification of wells designated as
development or exploratory which will ultimately determine the proper accounting
treatment of the costs incurred. The results from a drilling
operation can take considerable time to analyze and the determination that
commercial reserves have been discovered requires both judgment and industry
experience. Wells may be completed that are assumed to be productive
and actually deliver oil and natural gas in quantities insufficient to be
economic, which may result in the abandonment of the wells at a later
date. Wells are drilled that have targeted geologic structures that
are both developmental and exploratory in nature, and an allocation of costs is
required to properly account for the results. Delineation seismic
incurred to select development locations within an oil and natural gas field is
typically considered a development cost and capitalized, but often these seismic
programs extend beyond the reserve area considered proved and management must
estimate the portion of the seismic costs to expense. The evaluation
of oil and natural gas leasehold acquisition costs requires managerial judgment
to estimate the fair value of these costs with reference to drilling activity in
a given area. Drilling activities in an area by other companies may
also effectively condemn leasehold positions.
The
successful efforts method of accounting can have a significant impact on the
operational results reported when we are entering a new exploratory area in
hopes of finding an oil and natural gas field that will be the focus of future
developmental drilling activity. The initial exploratory wells may be
unsuccessful and will be expensed. Seismic costs can be substantial
which will result in additional explorations expenses when
incurred.
We assess
our proved oil and natural gas properties for possible impairment whenever
events or circumstances indicate that the recorded carrying value of the
properties may not be recoverable. Such events include a projection
of future oil and natural gas reserves that will be produced from a field, the
timing of this future production, future costs to produce the oil and natural
gas and future inflation levels. If the carrying amount of a property
exceeds the sum of the estimated undiscounted future net cash flows, we
recognize an impairment expense equal to the difference between the carrying
value and the fair value of the property, which is estimated to be the expected
present value of the future net cash flows from proved
reserves. Estimated future net cash flows are based on management’s
expectations for the future and include estimates of oil and natural gas
reserves and future commodity prices and operating costs. Downward
revisions in estimates of reserve quantities or expectations of falling
commodity prices or rising operating costs could result in a reduction in
undiscounted future cash flows and could indicate a property
impairment.
Estimates
of Oil and Natural Gas Reserves
Our
estimates of proved oil and natural gas reserves are based on the quantities of
oil and natural gas which geological and engineering data demonstrate, with
reasonable certainty, to be recoverable in future years from known reservoirs
under existing economic and operating conditions. The accuracy of any
reserve estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. For example, we must estimate
the amount and timing of future operating costs, severance taxes, development
costs and workover costs, all of which may vary considerably from actual
results. In addition, as prices and cost levels change from year to
year, the estimate of proved reserves also changes. Any significant
variance in these assumptions could materially affect the estimated quantity and
value of our reserves. Our independent reserve engineers prepare our
reserve estimates at the end of each year.
Despite
the inherent imprecision in these engineering estimates, our reserves are used
throughout our financial statements. For example, since we use the
units–of–production method to amortize the costs of our oil and natural gas
properties, the quantity of reserves could significantly impact our
depreciation, depletion and amortization expense. Our reserves are
also the basis of our supplemental oil and natural gas disclosures.
Accounting
for Derivatives
We use
derivatives to hedge against the variability in cash flows associated with the
forecasted sale of our anticipated future oil and natural gas
production. We generally hedge a substantial, but varying, portion of
our anticipated oil and natural gas production for the next 12 – 60
months. We do not use derivative instruments for trading
purposes. We have elected not to apply hedge accounting to our
derivatives. Accordingly, we carry our derivatives at fair value on
our consolidated balance sheet, with the changes in the fair value included in
our consolidated statement of operations in the period in which the change
occurs. Our results of operations would potentially have been
significantly different had we elected and qualified for hedge accounting on our
derivatives.
In
determining the amounts to be recorded, we are required to estimate the fair
values of the derivatives. We base our estimates of fair value upon
various factors that include closing prices on the NYMEX, volatility, the time
value of options and the credit worthiness of the counterparties to our
derivative instruments. These pricing and discounting variables are
sensitive to market volatility as well as changes in future price forecasts and
interest rates.
Accounting
for Asset Retirement Obligations
We have
significant obligations to remove tangible equipment and facilities and restore
land at the end of oil and natural gas production operations. Our
removal and restoration obligations are primarily associated with plugging and
abandoning wells. Estimating the future restoration and removal costs
is difficult and requires management to make estimates and judgments because
most of the removal obligations are many years in the future and contracts and
regulations often have vague descriptions of what constitutes
removal. Asset removal technologies and costs are constantly
changing, as are regulatory, political, environmental, safety and public
relations considerations.
SFAS No.
143, Accounting for Asset
Removal Obligations, together with the related FASB Interpretation No.
47, Accounting for Conditional
Asset Retirement Obligations, an Interpretation of FASB Statement No.
143, requires that the discounted fair value of a liability for an asset
retirement obligation be recognized in the period in which it is incurred with
the associated asset retirement cost capitalized as part of the carrying cost of
the oil and natural gas asset. In periods subsequent to initial
measurement of the asset retirement obligation, we recognize period to period
changes in the liability resulting from the passage of time and revisions to
either the timing or the amount of the original estimates.
Inherent
in the present value calculation are numerous assumptions and judgments
including the ultimate settlement amounts, inflation factors, credit adjusted
discount rates, timing of settlement and changes in the legal, regulatory,
environmental and political environments. To the extent future
revisions of these assumptions impact the present value of the existing asset
retirement obligation liability, a corresponding adjustment is made to the oil
and natural gas property balance.
Revenue
Recognition
Oil,
natural gas and natural gas liquids revenues are recognized when production is
sold to a purchaser at fixed or determinable prices, when delivery has occurred
and title has transferred and collectibility of the revenue is
probable. Virtually all of our contracts’ pricing provisions are tied
to a market index, with certain adjustments based on, among other factors,
whether a well delivers to a gathering or transmission line, quality of oil,
natural gas and natural gas liquids and prevailing supply and demand conditions,
so that prices fluctuate to remain competitive with other available
suppliers.
There are
two principal accounting practices to account for natural gas
imbalances. These methods differ as to whether revenue is recognized
based on the actual sale of natural gas (sales method) or an owner's entitled
share of the current period's production (entitlement method). We
follow the sales method of accounting for natural gas revenues. Under
this method of accounting, revenues are recognized based on volumes sold, which
may differ from the volume to which we are entitled based on our working
interest. An imbalance is recognized as a liability only when the
estimated remaining reserves will not be sufficient to enable the under–produced
owner(s) to recoup its entitled share through future
production. Under the sales method, no receivables are recorded where
we have taken less than our share of production.
We own
and operate a network of natural gas gathering systems in the Monroe field in
Northern Louisiana which gather and transport owned natural gas and a small
amount of third party natural gas to intrastate, interstate and local
distribution pipelines. Natural gas gathering and transportation
revenue is recognized when the natural gas has been delivered to a custody
transfer point.
RESULTS OF
OPERATIONS
|
Successor
|
Non–GAAP
Combined
(1)
|
Successor
|
Predecessors
(2)
|
|||||||||||||||||
|
Year
Ended December 31,
|
Three
Months
Ended
December
31,
|
Nine
Months
Ended
September
30,
|
||||||||||||||||||
|
2008
|
2007
|
2006
|
2006
|
2006
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Oil, natural gas and natural gas
liquids revenues
|
$ | 192,757 | $ | 89,422 | $ | 39,927 | $ | 5,548 | $ | 34,379 | ||||||||||
|
Gain on derivatives,
net
|
1,597 | 3,171 | 2,253 | 999 | 1,254 | |||||||||||||||
|
Transportation and
marketing–related revenues
|
12,959 | 11,415 | 5,729 | 1,271 | 4,458 | |||||||||||||||
|
Total revenues
|
207,313 | 104,008 | 47,909 | 7,818 | 40,091 | |||||||||||||||
|
Operating
costs and expenses:
|
||||||||||||||||||||
|
Lease operating
expenses
|
42,681 | 21,515 | 7,578 | 1,493 | 6,085 | |||||||||||||||
|
Cost of purchased natural
gas
|
9,849 | 9,830 | 5,013 | 1,153 | 3,860 | |||||||||||||||
|
Production taxes
|
9,088 | 3,360 | 294 | 109 | 185 | |||||||||||||||
|
Exploration
expenses
|
– | – | 1,061 | – | 1,061 | |||||||||||||||
|
Dry hole costs
|
– | – | 354 | – | 354 | |||||||||||||||
|
Impairment of unproved oil and
natural gas properties
|
– | – | 90 | – | 90 | |||||||||||||||
|
Asset retirement obligations
accretion expense
|
1,434 | 814 | 218 | 89 | 129 | |||||||||||||||
|
Depreciation, depletion and
amortization
|
38,032 | 19,759 | 5,568 | 1,180 | 4,388 | |||||||||||||||
|
General and administrative
expenses
|
13,653 | 10,384 | 3,534 | 2,043 | 1,491 | |||||||||||||||
|
Total operating costs and
expenses
|
114,737 | 65,662 | 23,710 | 6,067 | 17,643 | |||||||||||||||
|
Operating
income
|
92,576 | 38,346 | 24,199 | 1,751 | 22,448 | |||||||||||||||
|
Other
income (expense), net:
|
||||||||||||||||||||
|
Interest expense
|
(16,128 | ) | (8,009 | ) | (707 | ) | (134 | ) | (573 | ) | ||||||||||
|
Gain (loss) on mark–to–market
derivatives, net
|
148,713 | (19,906 | ) | 1,719 | 1,719 | – | ||||||||||||||
|
Other income,
net
|
559 | 813 | 375 | 31 | 344 | |||||||||||||||
|
Total other income (expense),
net
|
133,144 | (27,102 | ) | 1,387 | 1,616 | (229 | ) | |||||||||||||
|
Income
before income taxes and equity in income of
affiliates
|
$ | 225,720 | $ | 11,244 | $ | 25,586 | $ | 3,367 | $ | 22,219 | ||||||||||
|
Production
data:
|
||||||||||||||||||||
|
Oil (MBbls)
|
437 | 225 | 165 | 18 | 147 | |||||||||||||||
|
Natural gas liquids
(MBbls)
|
543 | 199 | – | – | – | |||||||||||||||
|
Natural gas
(MMcf)
|
14,578 | 9,254 | 3,900 | 625 | 3,275 | |||||||||||||||
|
Net production
(MMcfe)
|
20,457 | 11,798 | 4,893 | 734 | 4,159 | |||||||||||||||
|
Average
sales price per unit:
|
||||||||||||||||||||
|
Oil (Bbl)
|
$ | 94.76 | $ | 74.42 | $ | 63.54 | $ | 56.65 | $ | 64.38 | ||||||||||
|
Natural gas liquids
(Bbl)
|
54.75 | 54.18 | – | – | – | |||||||||||||||
|
Natural gas
(Mcf)
|
8.34 | 6.69 | 7.54 | 7.24 | 7.60 | |||||||||||||||
|
Average
unit cost per Mcfe:
|
||||||||||||||||||||
|
Production
costs:
|
||||||||||||||||||||
|
Lease operating
expenses
|
$ | 2.09 | $ | 1.82 | $ | 1.55 | $ | 2.04 | $ | 1.46 | ||||||||||
|
Production
taxes
|
0.44 | 0.28 | 0.06 | 0.15 | 0.04 | |||||||||||||||
|
Total
|
2.53 | 2.10 | 1.61 | 2.19 | 1.50 | |||||||||||||||
|
Depreciation, depletion
andamortization
|
1.86 | 1.67 | 1.14 | 1.61 | 1.06 | |||||||||||||||
|
General and administrative
expenses
|
0.67 | 0.88 | 0.72 | 2.78 | 0.36 | |||||||||||||||
|
(1)
|
Our
results of operations for the year ended December 31, 2006 are
derived from the combination of the results of the combined operations of
our predecessors for the nine months ended September 30, 2006 and the
results of our operations for the three months ended December 31,
2006. The combined results of operations for the year ended
December 31, 2006 are unaudited and do not necessarily represent the
results that would have been achieved during this period had the business
been operated by us for the entire
year.
|
|
(2)
|
The
financial statements of our predecessors include substantial operations
that we did not acquire. In
addition,
|
| · | one of the predecessors incurred substantial expenses related to exploration activities, which we do not plan to do; | |
|
|
·
|
the
contracts under which our predecessors reimbursed EnerVest for general and
administrative costs were different than the contracts under which we
reimburse EnerVest; and
|
|
|
·
|
our
predecessors did not incur the additional costs of being a public
company.
|
Year
Ended December 31, 2008 Compared with the Year Ended December 31,
2007
Oil,
natural gas and natural gas liquids revenues for 2008 totaled $192.8 million, an
increase of $103.4 million compared with 2007. This increase was
primarily the result of $93.3 million related to the oil and natural gas
properties that we acquired in 2008 and 2007 and $10.1 million related to higher
prices for oil, natural gas liquids and natural gas.
Transportation
and marketing–related revenues for 2008 increased $1.5 million compared with
2007 primarily due an increase in the price of natural gas transported through
our gathering systems in the Monroe Field.
Lease
operating expenses for 2008 increased $21.2 million compared with 2007
primarily as the result of $20.4 million of lease operating expenses associated
with the oil and natural gas properties that we acquired in 2008 and
2007. Lease operating expenses per Mcfe were $2.09 in 2008 compared
with $1.82 in 2007. This increase is primarily the result of oil and
natural gas properties that we acquired in 2008 and 2007 having lease operating
expenses of $2.34 per Mcfe for 2008.
The cost
of purchased natural gas for 2008 was flat compared with 2007
primarily due to an increase in the price of natural gas that we purchased and
transported through our gathering systems in the Monroe Field partially offset
by a decrease in the volume of natural gas transported.
Production
taxes for 2008 increased $5.7 million compared with 2007 primarily as the result
of $5.5 million of production taxes associated with the oil and natural gas
properties that we acquired in 2008 and 2007 and $0.2 million of higher
production taxes associated with our increased oil, natural gas and natural gas
liquids revenues. Production taxes for 2008 were $0.44 per Mcfe
compared with $0.28 per Mcfe for 2007. This increase is primarily the
result of the oil and natural gas properties that we acquired in 2008 and 2007
having production taxes of $0.63 per Mcfe for 2008.
Depreciation,
depletion and amortization for 2008 increased $18.3 million compared with 2007
primarily due to the oil and natural gas properties that we acquired in 2008 and
2007. Depreciation, depletion and amortization for 2008 was
$1.86 per Mcfe compared with $1.67 per Mcfe for 2007. This increase
is primarily due to the oil and natural gas properties that we acquired in 2008
and 2007 having depreciation, depletion and amortization of $2.10 per Mcfe for
2008.
General
and administrative expenses include the costs of administrative employees and
related benefits, management fees paid to EnerVest, professional fees and other
costs not directly associated with field operations. General and
administrative expenses for 2008 increased $3.3 million compared with 2007
primarily due to (i) an additional $2.4 million of fees paid to EnerVest under
the omnibus agreement, (ii) an increase of $0.8 million in accounting and tax
service costs and (iii) an overall increase in costs related to our significant
growth. General and administrative expenses were $0.67 per Mcfe in
2008 compared with $0.88 per Mcfe in 2007.
Interest
expense for 2008 increased $8.1 million compared with 2007 primarily due to
$10.8 million of additional interest expense from the increase in borrowings
outstanding under our credit facility offset by $2.7 million due to lower
weighted average effective interest rates in 2008 compared with
2007.
Gain on
mark–to–market derivatives, net for 2008 included (i) $13.0 million of net
realized losses on our oil and natural gas derivative instruments, (ii) $1.6
million of net realized losses on our interest rate swaps and (iii) $163.3
million of net unrealized gains on the mark–to–market of
derivatives. The net realized losses on our oil and natural gas
derivatives were primarily incurred during the first six months of 2008 when oil
and natural gas prices were rising. The net unrealized gains on our
mark–to market derivatives were due to the significant decline in oil and
natural gas prices at December 31, 2008 compared with December 31,
2007.
Year
Ended December 31, 2007 Compared with the Year Ended December 31,
2006
Oil,
natural gas and natural gas liquids revenues for 2007 totaled $89.4 million, an
increase of $49.5 million compared with 2006. This increase was
primarily the result of an increase of $67.6 million related to the oil and
natural gas properties
that we
acquired in 2007 and December 2006 offset by a decrease of $18.3 million related
to the oil and natural gas properties that we did not acquire from one of our
predecessors.
Transportation
and marketing–related revenues for 2007 increased $5.7 million compared with
2006 primarily due to $7.3 million in transportation and marketing–related
revenues from the March 2007 acquisition of natural gas properties in the Monroe
Field partially offset by lower volumes of natural gas transported through our
gathering systems due to the permanent shut–down of a compressor in the Monroe
Field in May 2007.
Lease
operating expenses for 2007 increased $13.9 million compared with 2006 as
the result of (i) an increase of $16.5 million related to the oil and natural
gas properties that we acquired in 2007 and December 2006; (ii) a decrease of
$1.8 million related to the oil and natural gas properties that we did not
acquire from one of our predecessors; and (iii) a decrease of $0.8 million
related to the oil and natural gas properties that we acquired at our
formation. Lease operating expenses per Mcfe were $1.82 in 2007
compared with $1.55 in 2006. This increase is primarily the result of
the oil and natural gas properties that we acquired in 2007 and December 2006
having lease operating expenses of $1.83 per Mcfe.
The cost
of purchased natural gas for 2007 increased $4.8 million compared with
2006 primarily due to (i) an increase of $5.5 million in costs from the March
2007 acquisition of natural gas properties in the Monroe Field; (ii) a decrease
of $0.4 million related to a decrease in prices for purchased natural gas; and
(iii) a decrease of $0.3 million related to a 8% decrease in the volume of
purchased natural gas.
Production
taxes for 2007 increased $3.1 million compared with 2006 primarily as the
result of $3.1 million of production taxes associated with the oil and natural
gas properties that we acquired in 2007 and December 2006. Production
taxes for 2006 were $0.28 per Mcfe compared with $0.06 per Mcfe for
2006. This increase is primarily the result of the oil and natural
gas properties that we acquired in 2007 and December 2006 having production
taxes of $0.34 per Mcfe.
Depreciation,
depletion and amortization increased $13.7 million compared with 2006 primarily
due to (i) an increase of $15.4 million related to the oil and natural gas
properties that we acquired in the 2007 and December 2006; (ii) a decrease of
$2.6 million related to the oil and natural gas properties that we did not
acquire from one of our predecessors and (iii) an increase of $1.4 million
related to the oil and natural gas properties that we acquired at our
formation. Depreciation, depletion and amortization for 2007 was
$1.63 per Mcfe compared with $1.14 per Mcfe for 2006. This increase
is primarily due to the oil and natural gas properties that we acquired in 2007
and December 2006 having a depreciation, depletion and amortization rate of
$1.71 per Mcfe.
General
and administrative expenses for 2007 totaled $10.4 million, an increase of $6.8
million compared with 2006. General and administrative expenses were
$0.88 per Mcfe in 2007 compared with $0.72 per Mcfe in 2006. These
increases are primarily the result of (i) $2.8 million of fees paid to EnerVest
under the omnibus agreement, (ii) $2.5 million of compensation cost, including
$1.5 million of compensation cost related to our phantom units, (iii) $0.3
million related to a write–off of spare parts inventory and other items
associated with the acquisition of the assets of one of our predecessors, (iv)
costs incurred to meet the reporting requirements of the Sarbanes–Oxley Act and
(v) an overall increase in costs related to being a public
partnership.
Interest
expense for 2007 totaled $8.0 million, an increase of $7.3 million, or 1,033%,
compared with 2006 primarily as a result of an increase in our long–term debt
utilized to fund a portion of the 2007 acquisitions.
Gain on
mark–to–market derivatives, net for 2007 included $9.0 million of realized gains
and $28.9 million of unrealized losses on the mark–to–market of
derivatives.
LIQUIDITY AND CAPITAL
RESOURCES
Historically,
our primary sources of liquidity and capital have been issuances of equity
securities, borrowings under our credit facility and cash flows from operations,
and our primary uses of cash have been acquisitions of oil and natural gas
properties and related assets, development of our oil and natural gas
properties, distributions to our partners and working capital
needs. For 2009, we believe that cash on hand and net cash flows
generated from operations will be adequate to fund our capital budget and
satisfy our short–term liquidity needs. We may also utilize various
financing sources available to us, including the issuance of equity or debt
securities through public offerings or private placements, to fund our
acquisitions and long–term liquidity needs. Our ability to complete
future offerings of
equity or
debt securities and the timing of these offerings will depend upon various
factors including prevailing market conditions and our financial
condition.
In the
past we accessed the equity markets to finance our significant
acquisitions. Our common unit price, as well as the unit price of
other master limited partnerships, has declined substantially over the past
year. The financial markets are undergoing unprecedented disruptions,
and many financial institutions have liquidity concerns prompting intervention
from governments. The disruption in the financial markets has reduced
our ability to access the public equity or debt markets until conditions improve
dramatically. Until these conditions improve, we are unlikely to
access the public equity or debt markets, which may limit our ability to pursue
significant acquisitions.
Available
Credit Facility
We have a
$700.0 million facility that expires in October 2012. Borrowings
under the facility are secured by a first priority lien on substantially all of
our assets and the assets of our subsidiaries. We may use borrowings
under the facility for acquiring and developing oil and natural gas properties,
for working capital purposes, for general corporate purposes and for funding
distributions to partners. We also may use up to $50.0 million of
available borrowing capacity for letters of credit. The facility
contains certain covenants which, among other things, require the maintenance of
a current ratio (as defined in the facility) of greater than 1.0 and a ratio of
total debt to earnings plus interest expense, taxes, depreciation, depletion and
amortization expense and exploration expense of no greater than 4.0 to
1.0. As of December 31, 2008, we were in compliance with all of the
facility covenants.
Borrowings
under the facility may not exceed a “borrowing base” determined by the lenders
based on our oil and natural gas reserves. As of December 31, 2008,
the borrowing base was $525.0 million. The borrowing base is subject
to scheduled redeterminations as of April 1 and October 1 of each year with an
additional redetermination once per calendar year at our request or at the
request of the lenders and with one calculation that may be made at our request
during each calendar year in connection with material acquisitions or
divestitures of properties. The borrowing base is determined by each
lender based on the value of our proved oil and natural gas reserves using
assumptions regarding future prices, costs and other matters that may vary by
lender. As a
result of the steep decline in oil and natural gas prices, we would expect that
the lenders will decrease our borrowing base at the upcoming borrowing base
redetermination. Should the amount of our borrowing base decrease
below the amount outstanding under the facility, we would be required to repay
any such deficiency in two equal installments 60 and 120 days after the
borrowing base redetermination. We believe that we could repay any
such deficiency through available cash, if any, the monetization of our
derivative agreements, the sale of oil and natural gas properties, reductions in
our capital expenditures and operating costs or reductions in our quarterly
distributions.
If the
disruption in the financial markets continues for an extended period of time,
replacement of our facility may be more expensive. In addition, since
our borrowing base is subject to periodic review by our lenders, difficulties in
the credit markets may cause the banks to be more restrictive when redetermining
our borrowing base.
Borrowings
under the facility will bear interest at a floating rate based on, at our
election, a base rate or the London Inter–Bank Offered Rate plus applicable
premiums based on the percent of the borrowing base that we have
outstanding.
At
December 31, 2008, we had $467.0 million outstanding under the
facility. In February 2009, we repaid $17.0 million of the amount
outstanding under the facility.
Cash
and Short–term Investments
Current
conditions in the financial markets also elevate the concern over our cash and
short–term investments. At December 31, 2008, we had $41.6 million of
cash and short–term investments, which included $36.6 million of short–term
investments. With regard to our short–term investments, we invest in
money market accounts with a major financial
institution.
Counterparty
Exposure
At
December 31, 2008, our open commodity derivative contracts were in a net
receivable position with a fair value of $162.7 million. All of our
commodity derivative contracts are with major financial institutions who are
also lenders under our credit facility. Should one of these financial
counterparties not perform, we may not realize the benefit of some of our
derivative instruments under lower commodity prices and we could incur a
loss.
Cash
Flows
Cash
flows provided (used) by type of activity were as follows:
|
Successor
|
Predecessors
|
|||||||||||||||
|
Year
Ended
December
31,
|
Three
Months
Ended
December
31,
|
Nine
Months
Ended
September
30,
|
||||||||||||||
|
2008
|
2007
|
2006
|
2006
|
|||||||||||||
|
Operating
activities
|
$ | 104,371 | $ | 56,114 | $ | 2,863 | $ | 20,114 | ||||||||
|
Investing
activities
|
(210,009 | ) | (467,056 | ) | (70,688 | ) | (7,041 | ) | ||||||||
|
Financing
activities
|
137,046 | 419,287 | 69,700 | (17,330 | ) | |||||||||||
Operating
Activities
Cash
flows from operations provided $104.4 million in 2008 compared with $56.1
million in 2007. The increase reflects our significant growth
primarily as a result of our acquisitions.
Cash
flows from operating activities provided $56.1 million in 2007. Cash
flows from operating activities provided $2.9 million in the three months ended
December 31, 2006 and $20.1 million in the nine months ended September 30,
2006.
Investing
Activities
Our
principal recurring investing activity is the acquisition and development of oil
and natural gas properties. During 2008, we spent $177.0 million on
the acquisitions of oil and natural gas properties in 2008 and $33.0 million for
the development of our oil and natural gas properties. During 2007,
we spent $456.5 million on the acquisitions of oil and natural properties in
2007 and $10.5 million for the development of oil and natural gas
properties. During the three months ended December 31, 2006, we spent
$69.6 million for the acquisition of our predecessors the acquisition of oil and
natural gas properties in December 2006 and $1.2 million for the development of
oil and natural gas properties, primarily related to development drilling on our
Appalachian Basin properties. During the nine months ended September
30, 2006, our predecessors spent $6.9 million for the development of oil and
natural gas properties, primarily related to development drilling on the Ohio
properties.
Financing
Activities
During
2008, we borrowed $197.0 million to finance the acquisitions of oil and natural
gas properties in 2008 and we paid distributions of $45.3 million to our general
partners and holders of our common and subordinated units. In
addition, as we acquired the San Juan Basin oil and natural gas properties from
institutional partnerships managed by EnerVest, we carried over the historical
costs related to EnerVest’s interests and applied purchase accounting to the
remaining interests and recorded deemed distributions of $13.9 million related
to the difference between the purchase price allocation and the amount paid for
the San Juan acquisition.
During
2007, we received net proceeds of $219.7 million from our private equity
offerings in February and June 2007. From these net proceeds, we
repaid $196.4 million of borrowings outstanding under our credit
facility. We borrowed $438.4 million under our credit facility to
finance the acquisitions of oil and natural gas properties in 2007
acquisitions. We paid $25.1 million of distributions to holders of
our common and subordinated units. In addition, as we acquired
certain oil and natural gas properties from institutional partnerships managed
by EnerVest, we carried over the historical costs related to EnerVest’s
interests and applied purchase accounting to the remaining interests and
recorded deemed distributions of $16.2 million related to the difference between
the purchase price allocations and the amounts paid for these
acquisitions.
During
the three months ended December 31, 2006, we received proceeds of $81.1 million
from our initial public offering. From these net proceeds, we paid
offering costs of $4.4 million, distributions of $24.1 million to the owners of
the predecessors and repaid $10.4 million of borrowings outstanding under our
predecessors’ credit facility. In addition, we borrowed $28.0 million
under our credit facility to finance our acquisition of oil and natural gas
properties in December 2006. During the nine months ended September
30, 2006, our predecessors received contributions from partners of $16.0 million
and paid distributions and dividends to partners of $33.3 million.
Capital
Requirements
In
anticipation of a continued economic recession and the corresponding depressed
prices for oil and natural gas, we have reduced our planned 2009 capital
expenditures budget. We currently expect 2009 spending for the
development of our oil and natural gas properties to be between
$17.0 million and $20.0 million.
In 2009,
we also currently expect to make distributions of approximately $56.2 million to
our unitholders based on our current quarterly distribution rate of $0.751 per
common unit, subordinated unit and unvested phantom unit
outstanding.
We are
actively engaged in the acquisition of oil and natural gas
properties. We would expect to finance any significant acquisition of
oil and natural gas properties in 2009 through the issuance of equity or debt
securities.
Contractual
Obligations
In the
table below, we set forth our contractual cash obligations as of
December 31, 2008. Some of the figures we include in this table
are based on our estimates and assumptions about these obligations, including
their duration, anticipated actions by third parties and other
factors. The contractual cash obligations we will actually pay in
future periods may vary from those reflected in the table because the estimates
and assumptions are subjective. Amounts in the table represent
obligations where both the timing and amount of payment streams are
known.
|
Payments
Due by Period (amounts in thousands)
|
||||||||||||||||||||
|
Total
|
Less
Than
1
Year
|
1
– 3
Years
|
4
– 5
Years
|
After
5
Years
|
||||||||||||||||
|
Total
debt
|
$ | 467,000 | $ | – | $ | – | $ | 467,000 | $ | – | ||||||||||
|
Estimated
interest payments (1)
|
83,009 | 22,135 | 44,272 | 16,602 | – | |||||||||||||||
|
Purchase
obligation (2)
|
7,500 | 7,500 | – | – | – | |||||||||||||||
|
Total
|
$ | 557,509 | $ | 29,635 | $ | 44,272 | $ | 483,602 | $ | – | ||||||||||
|
(1)
|
Amounts
represent the expected cash payments for interest based on the debt
outstanding and the weighted average effective interest rate of 4.74% as
of December 31, 2008.
|
|
(2)
|
Amounts
represent payments to be made under our omnibus agreement with EnerVest
based on the amount that we pay as of December 31, 2008. This
amount will increase or decrease as we purchase or divest
assets. While these payments will continue for periods
subsequent to December 31, 2009, no amounts are shown as they cannot be
quantified.
|
Our asset
retirement obligations are not included in the table above given the uncertainty
regarding the actual timing of such expenditures. The total amount of
our asset retirement obligations at December 31, 2008 is $34.6
million.
Off–Balance
Sheet Arrangements
As of
December 31, 2008, we had no off–balance sheet arrangements.
NEW ACCOUNTING
STANDARDS
In
September 2006, the Financial Accounting Standards Board (“FASB”) issued
SFAS No. 157, Fair
Value Measurements, to provide guidance for using fair value to measure
assets and liabilities. SFAS No. 157 was to be effective for
financial statements issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years; however, in February 2008, the
FASB issued FASB Staff Position FAS 157–2, Effective Date of FASB Statement No.
157, which delayed the effective date of SFAS No. 157 for all
nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for
our financial assets and financial liabilities. We adopted SFAS No.
157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities,
and the adoption did not have a material impact on our consolidated financial
statements.
In
February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities – Including an amendment of FASB Statement No.
115. SFAS No. 159 permits entities to choose to
measure
many
financial instruments and certain other items at fair value that are not
currently required to be measured at fair value. Unrealized
gains and losses on items for which the fair value option has been selected are
reported in earnings. SFAS No. 159 also establishes presentation and
disclosure requirements designed to facilitate comparisons between entities that
choose different measurement attributes for similar types of assets and
liabilities. SFAS No. 159 was effective for fiscal years beginning
after November 15, 2007. We have elected not to apply the provisions
of SFAS No. 159.
In
December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS
No. 141(R)”) to significantly change the accounting for business
combinations. Under SFAS No. 141(R), an acquiring entity will be
required to recognize all the assets acquired and liabilities assumed in a
transaction at the acquisition date fair value with limited exceptions and will
change the accounting treatment for certain specific items,
including:
|
|
·
|
acquisition
costs will generally be expensed as
incurred;
|
|
|
·
|
noncontrolling
interests will be valued at fair value at the date of acquisition;
and
|
|
|
·
|
liabilities
related to contingent consideration will be recorded at fair value at the
date of acquisition and subsequently remeasured each subsequent reporting
period.
|
SFAS No.
141(R) is effective for fiscal years beginning after December 15, 2008 and must
be applied prospectively to business combinations completed on or after that
date. We adopted SFAS No. 141(R) on January 1, 2009, and there was no
impact on our consolidated financial statements.
In
December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements – An Amendment of ARB No. 51, to
establish new accounting and reporting standards for the noncontrolling interest
in a subsidiary and for the deconsolidation of a subsidiary. SFAS No.
160 requires the recognition of a noncontrolling interest (minority interest) as
equity in the consolidated financial statements and separate from the parent’s
equity. The amount of net income attributable to the noncontrolling
interest will be included in consolidated net income on the face of the income
statement. SFAS No. 160 clarifies that changes in a parent’s
ownership interest in a subsidiary that do not result in deconsolidation are
equity transactions if the parent retains its controlling financial
interest. In addition, SFAS No. 160 requires that a parent recognize
a gain or loss in net income when a subsidiary is
deconsolidated. SFAS No. 160 also includes expanded disclosure
requirements regarding the interests of the parent and its noncontrolling
interest. SFAS No. 160 is effective for fiscal years beginning after
December 15, 2008. We adopted SFAS No. 160 on January 1, 2009, and
there was no impact on our consolidated financial statements.
In March 2008, the FASB
issued SFAS No. 161, Disclosures
about Derivative Instruments and Hedging Activities—an amendment of FASB
Statement No. 133. SFAS No. 161
requires enhanced disclosures about an entity’s derivative and hedging
activities and how they affect an entity’s financial position, financial
performance and cash flows. SFAS No. 161 is effective for fiscal years and
interim periods beginning after November 15, 2008. We adopted
the disclosure requirements of SFAS No. 161 on January 1,
2009.
In March
2008, the FASB issued Emerging Issues Task Force 07-04, Application of the Two–Class Method
under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships (“EITF 07–04”), to provide guidance as to how current period
earnings should be allocated between limited partners and a general partner when
the partnership agreement contains incentive distribution
rights. EITF 07–04 is to be applied retrospectively for all financial
statements presented and is effective for fiscal years beginning after December
15, 2008. We will adopt EITF 07–04 for the quarter ending March 31,
2009, and we have not yet determined the impact, if any, on our calculation of
net income per limited partner unit.
In May
2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles. SFAS No. 162 identifies the sources for accounting
principles and the framework for selecting the principles to be used in
preparing financial statements of nongovernmental entities that are presented in
conformity with generally accepted accounting principles (GAAP) in the United
States. SFAS No. 162 was effective on November 15, 2008.
In
December 2008, the SEC published Modernization of Oil and Gas
Reporting, a revision to its oil and natural gas reporting
disclosures. The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions
about reserves volumes. The new requirements also will allow companies to
disclose their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (i) report the independence and
qualifications of its reserves preparer or auditor; (ii) file reports when a
third party is relied upon to prepare reserves estimates or
conducts
a
reserves audit; and (iii) report oil and natural gas reserves using an average
price based upon the prior 12 month period rather than year end
prices. The new disclosure requirements are effective for
registration statements filed on or after January 1, 2010, and for annual
reports on Forms 10–K and 20–F for fiscal years ending on or after December 31,
2009. We will adopt the new disclosure requirements when they become
effective.
FORWARD–LOOKING
STATEMENTS
This Form
10–K contains forward–looking statements within the meaning of Section 27A
of the Securities Act of 1933, as amended, and Section 21E of the Exchange
Act (each a “forward–looking statement”). These forward–looking
statements relate to, among other things, the following:
|
|
·
|
our
future financial and operating performance and
results;
|
|
|
·
|
our
business strategy;
|
|
|
·
|
our
estimated net proved reserves and standardized
measure;
|
|
|
·
|
market
prices;
|
|
|
·
|
our
future derivative activities; and
|
|
|
·
|
our
plans and forecasts.
|
We have
based these forward–looking statements on our current assumptions, expectations
and projections about future events.
The words
“anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,”
“project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,”
“would,” “may,” “likely” and similar expressions, and the negative thereof, are
intended to identify forward–looking statements. These statements
discuss future expectations, contain projection of results of operations or of
financial condition or state other “forward–looking” information. We
do not undertake any obligation to update or revise publicly any forward–looking
statements, except as required by law. These statements also involve
risks and uncertainties that could cause our actual results or financial
condition to materially differ from our expectations in this Form 10–K
including, but not limited to:
|
|
·
|
fluctuations
in prices of oil and natural gas;
|
| · | the current disruptions in the financial markets; | |
| · | the severity and length of the current global economic recession; | |
|
|
·
|
future
capital requirements and availability of
financing;
|
|
|
·
|
uncertainty
inherent in estimating our
reserves;
|
|
|
·
|
risks
associated with drilling and operating
wells;
|
|
|
·
|
discovery,
acquisition, development and replacement of oil and natural gas
reserves;
|
|
|
·
|
cash
flows and liquidity;
|
|
|
·
|
timing
and amount of future production of oil and natural
gas;
|
|
|
·
|
availability
of drilling and production
equipment;
|
|
|
·
|
marketing
of oil and natural gas;
|
|
|
·
|
developments
in oil and natural gas producing
countries;
|
|
|
·
|
competition;
|
|
|
·
|
general
economic conditions;
|
|
|
·
|
governmental
regulations;
|
|
|
·
|
receipt
of amounts owed to us by purchasers of our production and counterparties
to our derivative financial instrument
contracts;
|
|
|
·
|
hedging
decisions, including whether or not to enter into derivative financial
instruments;
|
|
|
·
|
events
similar to those of September 11,
2001;
|
|
|
·
|
actions
of third party co–owners of interest in properties in which we also own an
interest;
|
|
|
·
|
fluctuations
in interest rates and the value of the U.S. dollar in international
currency markets; and
|
|
|
·
|
our
ability to effectively integrate companies and properties that we
acquire.
|
All of
our forward–looking information is subject to risks and uncertainties that could
cause actual results to differ materially from the results
expected. Although it is not possible to identify all factors, these
risks and uncertainties include the risk factors and the timing of any of those
risk factors identified in the “Risk Factors” section included in Item
1A.
Our
revenues, operating results, financial condition and ability to borrow funds or
obtain additional capital depend substantially on prevailing prices for oil and
natural gas. Declines in oil or natural gas prices may materially
adversely affect our financial condition, liquidity, ability to obtain financing
and operating results. Lower oil or natural gas prices also may
reduce the amount of oil or natural gas that we can produce
economically. A decline in oil and/or natural gas prices could have a
material adverse effect on the estimated value and estimated quantities of our
oil and natural gas reserves, our ability to fund our operations and our
financial condition, cash flows, results of operations and access to
capital. Historically, oil and natural gas prices and markets have
been volatile, with prices fluctuating widely, and they are likely to continue
to be volatile.
We are
exposed to certain market risks that are inherent in our financial statements
that arise in the normal course of business. We may enter into
derivative agreements to manage or reduce market risk, but do not enter into
derivative agreements for speculative purposes.
We do not
designate these or future derivative agreements as hedges for accounting
purposes pursuant to SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended. Accordingly,
the changes in the fair value of these derivative agreements are recognized
currently in earnings.
At
December 31, 2008, the fair value associated with our derivative agreements was
a net asset of $144.7 million.
Commodity
Price Risk
Our major
market risk exposure is to oil, natural gas and natural gas liquids prices which
have historically been volatile. As such, future earnings are subject
to change due to changes in these prices. Realized prices are
primarily driven by the prevailing worldwide price for oil and regional spot
prices for natural gas production. We have used, and expect to
continue to use, derivative agreements to reduce our risk of changes in the
prices of oil and natural gas. Pursuant to our risk management
policy, we engage in these activities as a hedging mechanism against price
volatility associated with pre–existing or anticipated sales of oil and natural
gas.
As of
December 31, 2008, we had entered into derivative agreements with the following
terms:
|
Period
Covered
|
Index
|
Hedged
Volume
per
Day
|
Weighted
Average
Fixed
Price
|
Weighted
Average
Floor
Price
|
Weighted
Average
Ceiling
Price
|
|||||||||||||
|
Oil
(Bbls):
|
||||||||||||||||||
|
Swaps – 2009
|
WTI
|
1,781 | $ | 93.10 | $ | $ | ||||||||||||
|
Collar – 2009
|
WTI
|
125 | 62.00 | 73.90 | ||||||||||||||
|
Swaps – 2010
|
WTI
|
1,725 | 90.84 | |||||||||||||||
|
Swaps – 2011
|
WTI
|
480 | 109.38 | |||||||||||||||
|
Collar – 2011
|
WTI
|
1,100 | 110.00 | 166.45 | ||||||||||||||
|
Swaps – 2012
|
WTI
|
460 | 108.76 | |||||||||||||||
|
Collar – 2012
|
WTI
|
1,000 | 110.00 | 170.85 | ||||||||||||||
|
Swap – 2013
|
WTI
|
500 | 72.50 | |||||||||||||||
|
Natural
Gas (MMBtu):
|
||||||||||||||||||
|
Swaps – 2009
|
Dominion
Appalachia
|
6,400 | 9.03 | |||||||||||||||
|
Swaps – 2010
|
Dominion
Appalachia
|
5,600 | 8.65 | |||||||||||||||
|
Swap – 2011
|
Dominion
Appalachia
|
2,500 | 8.69 | |||||||||||||||
|
Collar – 2011
|
Dominion
Appalachia
|
3,000 | 9.00 | 12.15 | ||||||||||||||
|
Collar – 2012
|
Dominion
Appalachia
|
5,000 | 8.95 | 11.45 | ||||||||||||||
|
Swaps – 2009
|
NYMEX
|
9,000 | 8.05 | |||||||||||||||
|
Collars – 2009
|
NYMEX
|
7,000 | 7.79 | 9.50 | ||||||||||||||
|
Swaps – 2010
|
NYMEX
|
13,500 | 8.28 | |||||||||||||||
|
Collar – 2010
|
NYMEX
|
1,500 | 7.50 | 10.00 | ||||||||||||||
|
Swaps – 2011
|
NYMEX
|
12,500 | 8.53 | |||||||||||||||
|
Swaps - 2012
|
NYMEX
|
12,500 | 9.01 | |||||||||||||||
|
Swap – 2013
|
NYMEX
|
4,000 | 7.50 | |||||||||||||||
|
Swaps – 2009
|
MICHCON_NB
|
5,000 | 8.27 | |||||||||||||||
|
Swap – 2010
|
MICHCON_NB
|
5,000 | 8.34 | |||||||||||||||
|
Collar – 2011
|
MICHCON_NB
|
4,500 | 8.70 | 11.85 | ||||||||||||||
|
Collar – 2012
|
MICHCON_NB
|
4,500 | 8.75 | 11.05 | ||||||||||||||
|
Swaps – 2009
|
HOUSTON
SC
|
5,620 | 8.25 | |||||||||||||||
|
Collar – 2010
|
HOUSTON
SC
|
3,500 | 7.25 | 9.55 | ||||||||||||||
|
Collar - 2011
|
HOUSTON
SC
|
3,500 | 8.25 | 11.65 | ||||||||||||||
|
Collar – 2012
|
HOUSTON
SC
|
3,000 | 8.25 | 11.10 | ||||||||||||||
|
Swaps – 2009
|
EL
PASO PERMIAN
|
3,500 | 7.80 | |||||||||||||||
|
Swap – 2010
|
EL
PASO PERMIAN
|
2,500 | 7.68 | |||||||||||||||
|
Swap – 2011
|
EL
PASO PERMIAN
|
2,500 | 9.30 | |||||||||||||||
|
Swap – 2012
|
EL
PASO PERMIAN
|
2,000 | 9.21 | |||||||||||||||
|
Swap – 2013
|
EL
PASO PERMIAN
|
3,000 | 6.77 | |||||||||||||||
|
Swap – 2013
|
SAN
JUAN BASIN
|
3,000 | 6.66 | |||||||||||||||
Interest
Rate Risk
Our
floating rate credit facility also exposes us to risks associated with changes
in interest rates and as such, future earnings are subject to change due to
changes in these interest rates. As of December 31, 2008, we had
entered into interest rate swaps with the following terms:
|
Period
Covered
|
Notional
Amount
|
Fixed
Rate
|
||||||
|
January
2009 – July 2012
|
$ | 35,000 | 4.043 | % | ||||
|
January
2009 – July 2012
|
40,000 | 4.050 | % | |||||
|
January
2009 – July 2012
|
70,000 | 4.220 | % | |||||
|
January
2009 – July 2012
|
20,000 | 4.248 | % | |||||
|
January
2009 – July 2012
|
35,000 | 4.250 | % | |||||
The
following tables set forth the required cash payments for our long–term debt and
the related weighted average effective interest rate as of December 31 2008 and
2007:
|
As
of December 31, 2008
|
||||||||||||||||||||||||||||||||
|
Expected
Maturity Date
|
||||||||||||||||||||||||||||||||
|
2009
|
2010
|
2011
|
2012
|
2013
|
Thereafter
|
Total
|
Fair
Value
|
|||||||||||||||||||||||||
|
Long–term
debt:
|
||||||||||||||||||||||||||||||||
|
Variable
|
$ | 467,000 | $ | 467,000 | $ | 467,000 | ||||||||||||||||||||||||||
|
Average interest
rate
|
4.74 | % | 4.74 | % | ||||||||||||||||||||||||||||
A 1%
change in interest rates would result in an estimated $4.7 million change in
interest expense.
|
As
of December 31, 2007
|
||||||||||||||||||||||||||||||||
|
Expected
Maturity Date
|
||||||||||||||||||||||||||||||||
|
2008
|
2009
|
2010
|
2011
|
2012
|
Thereafter
|
Total
|
Fair
Value
|
|||||||||||||||||||||||||
|
Long–term
debt:
|
||||||||||||||||||||||||||||||||
|
Variable
|
$ | 270,000 | $ | 270,000 | $ | 270,000 | ||||||||||||||||||||||||||
|
Average interest
rate
|
7.16 | % | 7.16 | % | ||||||||||||||||||||||||||||
MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management,
including our Chief Executive Officer and Chief Financial Officer, is
responsible for establishing and maintaining adequate internal control over our
financial reporting. Our internal control system was designed to
provide reasonable assurance to our Management and Directors regarding the
preparation and fair presentation of published financial
statements. Because of its inherent limitations, internal control
over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Management
conducted an evaluation of the effectiveness of internal control over financial
reporting based on the Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on this evaluation, management concluded
that EV Energy Partners, L.P.’s internal control over financial reporting was
effective as of December 31, 2008.
Deloitte &
Touche LLP, our independent registered public accounting firm, has issued an
attestation report on the effectiveness on our internal control over financial
reporting as of December 31, 2008 which is included in ”Item 8. Financial
Statements and Supplementary Data” contained herein.
| /s/ JOHN B. WALKER
|
/s/ MICHAEL E.
MERCER
|
| John B. Walker | Michael E. Mercer |
|
Chief
Executive Officer of EV Management, LLC,
general
partner of EV Energy, GP, L.P.,
general partner of EV Energy Partners,
L.P.
|
Chief
Financial Officer of EV Management, LLC,
general partner of EV Energy GP, L.P.,
general partner of EV Energy Partners,
L.P.
|
Houston,
TX
March 12,
2009
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors of EV Management, LLC
and
Unitholders of EV Energy Partners, L.P. and Subsidiaries
Houston,
Texas
We have
audited the accompanying consolidated balance sheets of EV Energy Partners, L.P.
and subsidiaries (the "Partnership") as of December 31, 2008 and 2007, and the
related consolidated statements of operations, cash flows, and changes in
owners’ equity of the Partnership for the years ended December 31, 2008 and 2007
and three months ended December 31, 2006, and combined statement of
operations, cash flows, and changes in owners’ equity of the Combined
Predecessor Entities (the “Entities”) for the nine months ended
September 30, 2006. We also have audited the
Partnership's internal control over financial reporting as of December 31, 2008,
based on criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Partnership's management is responsible for these
financial statements, for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Management’s Report on Internal
Control Over Financial Reporting. Our responsibility is to express
an opinion on these financial statements and an opinion on the Partnership's
internal control over financial reporting based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. Our audit of internal control over financial reporting
included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on
the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe
that our audits provide a reasonable basis for our opinions.
A
company's internal control over financial reporting is a process designed by, or
under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control
over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.
Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our
opinion, the consolidated and combined financial statements referred to above
present fairly, in all material respects, the financial position of the
Partnership as of December 31, 2008 and 2007, and the results of their
operations and their cash flows for the years ended December 31, 2008 and 2007
and the three months ended December 31, 2006, and combined statements of
operations and their cash flows of the Entities for the nine months ended
September 30, 2006 in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, the
Partnership maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2008 based on the criteria
established in Internal
Control — Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
/s/DELOITTE
& TOUCHE LLP
Houston,
TX
March 12,
2009
EV
Energy Partners, L.P.
Consolidated
Balance Sheets
(In
thousands, except number of units)
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
ASSETS
|
||||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 41,628 | $ | 10,220 | ||||
|
Accounts
receivable:
|
||||||||
|
Oil,
natural gas and natural gas liquids revenues
|
17,588 | 18,658 | ||||||
|
Related
party
|
1,463 | 3,656 | ||||||
|
Other
|
3,278 | 15 | ||||||
|
Derivative
asset
|
50,121 | 1,762 | ||||||
|
Prepaid
expenses and other current assets
|
1,037 | 594 | ||||||
|
Total
current assets
|
115,115 | 34,905 | ||||||
|
Oil
and natural gas properties, net of accumulated depreciation, depletion and
amortization;
December
31, 2008, $69,958; December 31, 2007, $30,724
|
765,243 | 570,398 | ||||||
|
Other
property, net of accumulated depreciation and amortization;
December
31, 2008, $284; December 31, 2007, $239
|
180 | 225 | ||||||
|
Long–term
derivative asset
|
96,720 | – | ||||||
|
Other
assets
|
2,737 | 2,013 | ||||||
|
Total
assets
|
$ | 979,995 | $ | 607,541 | ||||
|
LIABILITIES
AND OWNERS’ EQUITY
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable and accrued liabilities
|
$ | 14,063 | $ | 12,113 | ||||
|
Deferred
revenues
|
4,120 | 1,122 | ||||||
|
Derivative
liability
|
2,115 | 5,232 | ||||||
|
Total
current liabilities
|
20,298 | 18,467 | ||||||
|
Asset
retirement obligations
|
33,787 | 19,463 | ||||||
|
Long–term
debt
|
467,000 | 270,000 | ||||||
|
Other
long-term liabilities
|
1,426 | 1,507 | ||||||
|
Long–term
derivative liability
|
– | 15,074 | ||||||
|
Commitments
and contingencies
|
||||||||
|
Owners’
equity:
|
||||||||
|
Common
unitholders – 13,027,062 units and 11,839,439 units issued and outstanding
as of
December
31, 2008 and 2007, respectively
|
432,031 | 282,676 | ||||||
|
Subordinated
unitholders – 3,100,000 units issued and outstanding as of December 31,
2008 and 2007
|
21,618 | (5,488 | ) | |||||
|
General
partner interest
|
3,835 | 4,245 | ||||||
|
Accumulated
other comprehensive income
|
– | 1,597 | ||||||
|
Total
owners’ equity
|
457,484 | 283,030 | ||||||
|
Total
liabilities and owners’ equity
|
$ | 979,995 | $ | 607,541 | ||||
See
accompanying notes to consolidated/combined financial statements.
EV
Energy Partners, L.P.
Statements
of Operations
(In
thousands, except per unit data)
|
Successor
|
Predecessors
|
|||||||||||||||
|
Year
Ended
|
Three
Months
Ended
|
Nine
Months
Ended
|
||||||||||||||
|
December
31,
|
December
31,
|
September
30,
|
||||||||||||||
|
2008
|
2007
|
2006
|
2006
|
|||||||||||||
|
(Consolidated)
|
(Combined)
|
|||||||||||||||
|
Revenues:
|
||||||||||||||||
|
Oil, natural gas and natural gas
liquids revenues
|
$ | 192,757 | $ | 89,422 | $ | 5,548 | $ | 34,379 | ||||||||
|
Gain on derivatives,
net
|
1,597 | 3,171 | 999 | 1,254 | ||||||||||||
|
Transportation and
marketing–related revenues
|
12,959 | 11,415 | 1,271 | 4,458 | ||||||||||||
|
Total revenues
|
207,313 | 104,008 | 7,818 | 40,091 | ||||||||||||
|
Operating
costs and expenses:
|
||||||||||||||||
|
Lease operating
expenses
|
42,681 | 21,515 | 1,493 | 6,085 | ||||||||||||
|
Cost of purchased natural
gas
|
9,849 | 9,830 | 1,153 | 3,860 | ||||||||||||
|
Production taxes
|
9,088 | 3,360 | 109 | 185 | ||||||||||||
|
Exploration
expenses
|
– | – | – | 1,061 | ||||||||||||
|
Dry hole costs
|
– | – | – | 354 | ||||||||||||
|
Impairment of unproved oil and
natural gas properties
|
– | – | – | 90 | ||||||||||||
|
Asset retirement obligations
accretion expense
|
1,434 | 814 | 89 | 129 | ||||||||||||
|
Depreciation, depletion and
amortization
|
38,032 | 19,759 | 1,180 | 4,388 | ||||||||||||
|
General and administrative
expenses
|
13,653 | 10,384 | 2,043 | 1,491 | ||||||||||||
|
Total operating costs and
expenses
|
114,737 | 65,662 | 6,067 | 17,643 | ||||||||||||
|
Operating
income
|
92,576 | 38,346 | 1,751 | 22,448 | ||||||||||||
|
Other
income (expense), net:
|
||||||||||||||||
|
Interest expense
|
(16,128 | ) | (8,009 | ) | (134 | ) | (573 | ) | ||||||||
|
Gain (loss) on mark–to–market
derivatives, net
|
148,713 | (19,906 | ) | 1,719 | – | |||||||||||
|
Other income,
net
|
559 | 813 | 31 | 344 | ||||||||||||
|
Total other income (expense),
net
|
133,144 | (27,102 | ) | 1,616 | (229 | ) | ||||||||||
|
Income
before income taxes and equity in income of affiliates
|
225,720 | 11,244 | 3,367 | 22,219 | ||||||||||||
|
Income
taxes
|
(235 | ) | (54 | ) | – | (5,809 | ) | |||||||||
|
Equity
in income of affiliates
|
– | – | – | 164 | ||||||||||||
|
Net
income
|
$ | 225,485 | $ | 11,190 | $ | 3,367 | $ | 16,574 | ||||||||
|
General
partner’s interest in net income, including incentive distribution
rights
|
$ | 54,643 | $ | 1,670 | $ | 67 | ||||||||||
|
Limited
partners’ interest in net income
|
$ | 170,842 | $ | 9,520 | $ | 3,300 | ||||||||||
|
Net
income per limited partner unit:
|
||||||||||||||||
|
Common units (basic and
diluted)
|
$ | 11.14 | $ | 0.74 | $ | 0.43 | ||||||||||
|
Subordinated units (basic and
diluted)
|
$ | 11.14 | $ | 0.74 | $ | 0.43 | ||||||||||
|
Weighted
average limited partner units outstanding:
|
||||||||||||||||
|
Common units (basic and
diluted)
|
12,240 | 9,815 | 4,495 | |||||||||||||
|
Subordinated units (basic and
diluted)
|
3,100 | 3,100 | 3,100 | |||||||||||||
See
accompanying notes to consolidated/combined financial statements.
EV
Energy Partners, L.P.
Statements
of Cash Flows
(In
thousands)
|
Successor
|
Predecessors
|
|||||||||||||||
|
Year
Ended
|
Three
Months
Ended
|
Nine
Months
Ended
|
||||||||||||||
|
December
31,
|
December
31,
|
September
30,
|
||||||||||||||
|
2008
|
2007
|
2006
|
2006
|
|||||||||||||
|
(Consolidated)
|
(Combined)
|
|||||||||||||||
|
Cash
flows from operating activities:
|
||||||||||||||||
|
Net income
|
$ | 225,485 | $ | 11,190 | $ | 3,367 | $ | 16,574 | ||||||||
|
Adjustments to reconcile net
income to net cash flows provided by operating
activities:
|
||||||||||||||||
|
Dry hole costs
|
– | – | – | 354 | ||||||||||||
|
Impairment of unproved oil and
natural gas properties
|
– | – | – | 90 | ||||||||||||
|
Asset retirement obligations
accretion expense
|
1,434 | 814 | 89 | 129 | ||||||||||||
|
Depreciation, depletion and
amortization
|
38,032 | 19,759 | 1,180 | 4,388 | ||||||||||||
|
Share–based compensation
cost
|
1,241 | 1,507 | – | – | ||||||||||||
|
Amortization of deferred loan
costs
|
370 | 155 | 22 | – | ||||||||||||
|
Unrealized (gain) loss on
mark–to–market derivatives
|
(164,867 | ) | 25,713 | (906 | ) | – | ||||||||||
|
Benefit for deferred income
taxes
|
– | – | – | (540 | ) | |||||||||||
|
Equity in income of affiliates,
net of distributions
|
– | – | – | 94 | ||||||||||||
|
Changes in operating assets and
liabilities:
|
||||||||||||||||
|
Accounts
receivable
|
327 | (8,926 | ) | (2,278 | ) | 1,258 | ||||||||||
|
Prepaid expenses and other
current assets
|
(151 | ) | 441 | – | – | |||||||||||
|
Accounts payable and accrued
liabilities
|
(233 | ) | 4,627 | 1,536 | (3,487 | ) | ||||||||||
|
Deferred
revenues
|
2,998 | 1,122 | – | |||||||||||||
|
Due to
affiliates
|
– | – | – | (2,089 | ) | |||||||||||
|
Income taxes
|
– | – | – | 2,993 | ||||||||||||
|
Other, net
|
(265 | ) | (288 | ) | (147 | ) | 350 | |||||||||
|
Net
cash flows provided by operating activities
|
104,371 | 56,114 | 2,863 | 20,114 | ||||||||||||
|
Cash
flows from investing activities:
|
||||||||||||||||
|
Acquisition of oil and natural
gas properties, net of cash acquired
|
(176,992 | ) | (456,513 | ) | (69,517 | ) | – | |||||||||
|
Development of oil and natural
gas properties
|
(33,017 | ) | (10,543 | ) | (1,171 | ) | (6,911 | ) | ||||||||
|
Investment in equity
investee
|
– | – | – | (130 | ) | |||||||||||
|
Net
cash flows used in investing activities
|
(210,009 | ) | (467,056 | ) | (70,688 | ) | (7,041 | ) | ||||||||
|
Cash
flows from financing activities:
|
||||||||||||||||
|
Long–term debt
borrowings
|
197,000 | 438,350 | 28,000 | – | ||||||||||||
|
Repayment of long–term debt
borrowings
|
– | (196,350 | ) | (10,350 | ) | – | ||||||||||
|
Proceeds from initial public
offering
|
– | – | 81,065 | – | ||||||||||||
|
Proceeds from private equity
offerings
|
– | 220,000 | – | – | ||||||||||||
|
Offering costs
|
– | (302 | ) | (4,448 | ) | – | ||||||||||
|
Distribution to the
Predecessors
|
– | – | (24,134 | ) | – | |||||||||||
|
Distributions related to
acquisitions
|
(13,918 | ) | (16,238 | ) | – | – | ||||||||||
|
Deferred loan
costs
|
(1,331 | ) | (1,046 | ) | (433 | ) | – | |||||||||
|
Contributions by
partners
|
601 | – | – | 16,000 | ||||||||||||
|
Distributions to partners and
dividends paid
|
(45,306 | ) | (25,127 | ) | – | (33,330 | ) | |||||||||
|
Net
cash flows provided by (used in) financing activities
|
137,046 | 419,287 | 69,700 | (17,330 | ) | |||||||||||
|
Increase
(decrease) in cash and cash equivalents
|
31,408 | 8,345 | 1,875 | (4,257 | ) | |||||||||||
|
Cash
and cash equivalents – beginning of period
|
10,220 | 1,875 | – | 7,159 | ||||||||||||
|
Cash
and cash equivalents – end of period
|
$ | 41,628 | $ | 10,220 | $ | 1,875 | $ | 2,902 | ||||||||
See
accompanying notes to consolidated/combined financial statements.
EV
Energy Partners, L.P.
Statements
of Changes in Owners’ Equity
(In
thousands)
|
Owners’
Equity Excluding Accumulated Other Comprehensive Income
(Loss)
|
Accumulated
Other Comprehensive Income (Loss)
|
Total
Owners’
Equity
|
||||||||||
|
Predecessors
(Combined):
|
||||||||||||
|
Balance, January 1,
2006
|
$ | 45,178 | $ | (4,268 | ) | $ | 40,910 | |||||
|
Comprehensive
income:
|
||||||||||||
|
Net income
|
16,574 | – | ||||||||||
|
Unrealized gain on
derivatives
|
– | 14,347 | ||||||||||
|
Reclassification adjustment
into earnings
|
– | (408 | ) | |||||||||
|
Total comprehensive
income
|
30,513 | |||||||||||
|
Contributions
|
19,315 | – | 19,315 | |||||||||
|
Distributions
|
(14,871 | ) | – | (14,871 | ) | |||||||
|
Dividends
|
(12,627 | ) | – | (12,627 | ) | |||||||
|
Balance, September 30,
2006
|
$ | 53,569 | $ | 9,671 | $ | 63,240 | ||||||
|
Common
Unitholders
|
Subordinated
Unitholders
|
General
Partner
Interest
|
Accumulated
Other Comprehensive Income
|
Total
Owners’
Equity
|
||||||||||||||||
|
Successor
(Consolidated):
|
||||||||||||||||||||
|
Balance at September 30,
2006
|
$ | – | $ | – | $ | – | $ | – | $ | – | ||||||||||
|
Proceeds from initial public
offering, net of
underwriter
discount
|
81,065 | – | – | - | 81,065 | |||||||||||||||
|
Offering costs
|
(4,448 | ) | – | – | – | (4,448 | ) | |||||||||||||
|
Acquisition of the
Predecessors
|
9,919 | 22,829 | 3,312 | 5,392 | 41,452 | |||||||||||||||
|
Distribution to the
Predecessors
|
(10,788 | ) | (13,346 | ) | – | – | (24,134 | ) | ||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||
|
Net income
|
1,953 | 1,347 | 67 | – | ||||||||||||||||
|
Reclassification adjustment
into earnings
|
– | – | – | (1,049 | ) | |||||||||||||||
|
Total comprehensive
income
|
2,318 | |||||||||||||||||||
|
Balance, December 31,
2006
|
77,701 | 10,830 | 3,379 | 4,343 | 96,253 | |||||||||||||||
|
Proceeds from private equity
offerings
|
215,600 | – | 4,400 | – | 220,000 | |||||||||||||||
|
Offering costs
|
(302 | ) | – | – | – | (302 | ) | |||||||||||||
|
Distributions in conjunction
with acquisitions
|
(695 | ) | (12,734 | ) | (2,809 | ) | – | (16,238 | ) | |||||||||||
|
Distributions
|
(18,226 | ) | (5,952 | ) | (949 | ) | – | (25,127 | ) | |||||||||||
|
Acquisition of derivative
instruments
|
– | – | – | 425 | 425 | |||||||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||
|
Net income
|
8,598 | 2,368 | 224 | |||||||||||||||||
|
Reclassification adjustment
into earnings
|
– | – | (3,171 | ) | ||||||||||||||||
|
Total comprehensive
income
|
8,019 | |||||||||||||||||||
|
Balance, December 31,
2007
|
282,676 | (5,488 | ) | 4,245 | 1,597 | 283,030 | ||||||||||||||
|
Conversion of 42,500 vested
phantom units
|
1,262 | – | – | – | 1,262 | |||||||||||||||
|
Contribution from general
partner
|
– | – | 601 | – | 601 | |||||||||||||||
|
Issuance of 1,145,123 common
units in conjunction
with
acquisition of oil and natural gas properties
|
7,927 | – | – | – | 7,927 | |||||||||||||||
|
Distributions in conjunction
with acquisitions
|
(5,453 | ) | (7,390 | ) | (1,075 | ) | – | (13,918 | ) | |||||||||||
|
Distributions
|
(32,582 | ) | (8,278 | ) | (4,446 | ) | – | (45,306 | ) | |||||||||||
|
Comprehensive
income:
|
||||||||||||||||||||
|
Net income
|
178,201 | 42,774 | 4,510 | – | ||||||||||||||||
|
Reclassification adjustment
into earnings
|
– | – | – | (1,597 | ) | |||||||||||||||
|
Total comprehensive
income
|
223,888 | |||||||||||||||||||
|
Balance, December 31,
2008
|
$ | 432,031 | $ | 21,618 | $ | 3,835 | $ | – | $ | 457,484 | ||||||||||
See
accompanying notes to consolidated/combined financial statements.
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements
NOTE
1. ORGANIZATION AND NATURE OF BUSINESS
EV Energy
Partners, L.P. (the “Partnership”) is a publicly held limited partnership that
engages in the acquisition, development and production of oil and natural gas
properties. The Partnership consummated the acquisition of its
predecessors and an initial public offering of its common units effective
October 1, 2006. The Partnership’s general partner is EV Energy GP,
L.P., a Delaware limited partnership, and the general partner of its general
partner is EV Management, LLC (“EV Management”), a Delaware limited liability
company.
The
Partnership’s predecessors (the “Predecessors”) were:
|
|
·
|
EV
Properties, L.P. (“EV Properties”), a limited partnership that owns oil
and natural gas properties and related assets in the Monroe field in
Northern Louisiana and in the Appalachian Basin in West Virginia,
and
|
|
|
·
|
CGAS
Exploration, Inc. (“CGAS Exploration”), a corporation that owns oil and
natural gas properties and related assets in the Appalachian Basin in
Ohio.
|
EV
Properties was formed on April 12, 2006 by EnerVest, Ltd. (“EnerVest”) and
investment funds affiliated with EnCap Investments, L.P. (“EnCap”) to acquire
the business of the following partnerships which were controlled by
EnerVest:
|
|
·
|
EnerVest
Production Partners, Ltd. (“EnerVest Production Partners”), which owned
oil and natural gas properties and related assets in the Monroe field in
Northern Louisiana, and
|
|
|
·
|
EnerVest
WV, L.P. (“EnerVest WV”), which owned oil and natural gas properties and
related assets in West
Virginia.
|
NOTE
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis
of Presentation
The
consolidated financial statements include the operations of the Partnership and
all of its subsidiaries (“we,” “our” or “us”) for periods beginning October 1,
2006. The combined financial statements of the Predecessors reflect
the operations of the following entities:
|
|
·
|
the
combined operations of EnerVest Production Partners, EnerVest WV and CGAS
Exploration for periods before May 12, 2006,
and
|
|
|
·
|
the
combined operations of EV Properties and CGAS Exploration from May 12,
2006 through September 30, 2006.
|
All
intercompany accounts and transactions have been eliminated in
consolidation/combination. In the Notes to Consolidated/Combined
Financial Statements, all dollar and share amounts in tabulations are in
thousands of dollars and shares, respectively, unless otherwise
indicated.
Use of Estimates
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and judgments that affect the reported amounts of assets and
liabilities, disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period. We base our estimates and judgments on
historical experience and on various other assumptions and information that are
believed to be reasonable under the circumstances. Estimates and
assumptions about future events and their effects cannot be perceived with
certainty and, accordingly, these estimates may change as new events occur, as
more experience is acquired, as additional information is obtained and as our
operating environment changes. While we believe that the estimates
and assumptions used in the preparation of the consolidated/combined financial
statements are appropriate, actual results could differ from those
estimates.
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
Cash
and Cash Equivalents
We
consider all highly liquid investments with an original maturity of three months
or less at the time of purchase to be cash equivalents.
Accounts
Receivable
Accounts
receivable from oil and natural gas sales are recorded at the invoiced amount
and do not bear interest. We routinely assess the financial strength
of our customers and bad debts are recorded based on an account–by–account
review after all means of collection have been exhausted, and the potential
recovery is considered remote.
As of
December 31, 2008 and 2007, we did not have any reserves for doubtful accounts,
and we did not incur any expense related to bad debts. We do not have
any off–balance sheet credit exposure related to our
customers.
Property
and Depreciation
Our oil
and natural gas producing activities are accounted for under the successful
efforts method of accounting. Under this method, exploration costs, other
than the costs of drilling exploratory wells, are charged to expense as
incurred. Costs that are associated with the drilling of successful
exploration wells are capitalized if proved reserves are found. Lease
acquisition costs are capitalized when incurred. Capitalized costs
associated with unproved properties totaled $0.2 million and $0.6 million as of
December 31, 2008 and December 31, 2007, respectively. Costs
associated with the drilling of exploratory wells that do not find proved
reserves, geological and geophysical costs and costs of certain non–producing
leasehold costs are expensed as incurred.
The
capitalized costs of our producing oil and natural gas properties are
depreciated and depleted by the units–of–production method based on the ratio of
current production to estimated total net proved oil and natural gas reserves as
estimated by independent petroleum engineers. Proved developed reserves
are used in computing unit rates for drilling and development costs and total
proved reserves are used for depletion rates of leasehold, platform, and
pipeline costs.
Other
property is stated at cost less accumulated depreciation, which is computed
using the straight–line method based on estimated economic lives ranging from
three to 25 years. We expense costs for maintenance and repairs
in the period incurred. Significant improvements and betterments are
capitalized if they extend the useful life of the asset.
Impairment
of Long–Lived Assets
We
evaluate our proved oil and natural gas properties and related equipment
and facilities for impairment whenever events or changes in circumstances
indicate that the carrying amounts of such properties may not be
recoverable. The determination of recoverability is made based upon
estimated undiscounted future net cash flows. The amount of
impairment loss, if any, is determined by comparing the fair value, as
determined by a discounted cash flow analysis, with the carrying value of the
related asset. For the years ended December 31, 2008, 2007 and 2006,
neither we nor the Predecessors recorded any impairments related to proved oil
and natural gas properties.
Unproved
oil and natural gas properties are assessed periodically on a
property–by–property basis, and any impairment in value is
recognized. For the years ended December 31, 2008 and 2007 and the
three months ended December 31, 2006, we recorded no impairments related to
unproved oil and natural gas properties. For the nine months ended
September 30, 2006, the Predecessors recorded $0.1 million of impairments
related to unproved oil and natural gas properties.
Asset
Retirement Obligations
We
account for our legal obligations associated with retirement of long–lived
assets in accordance with Statement of Financial Accounting Standards (“SFAS”)
No. 143, Accounting for Asset
Retirement Obligations. SFAS No. 143 requires that the fair
value of a liability associated with an asset retirement obligation (“ARO”) be
recognized in the period in which it is incurred if a reasonable estimate can be
made. The associated retirement costs are capitalized as part of the
carrying amount of the long–lived asset and subsequently depreciated over the
estimated useful life of the asset. The liability is eventually
extinguished when the asset is taken out of service.
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
Revenue
Recognition
Oil,
natural gas and natural gas liquids revenues are recognized when production is
sold to a purchaser at fixed or determinable prices, when delivery has occurred
and title has transferred and collectibility of the revenue is
probable. We follow the sales method of accounting for natural gas
revenues. Under this method of accounting, revenues are recognized
based on volumes sold, which may differ from the volume to which we are entitled
based on our working interest. An imbalance is recognized as a
liability only when the estimated remaining reserves will not be sufficient to
enable the under–produced owner(s) to recoup its entitled share through future
production. Under the sales method, no receivables are recorded where
we have taken less than our share of production. There were no
material gas imbalances at December 31, 2008 or 2007.
We own
and operate a network of natural gas gathering systems in the Monroe field in
Northern Louisiana which gather and transport owned natural gas and a small
amount of third party natural gas to intrastate, interstate and local
distribution pipelines. Natural gas gathering and transportation
revenue is recognized when the natural gas has been delivered to a custody
transfer point.
Income
Taxes
We are a
partnership that is not taxable for federal income tax purposes. As such,
we do not directly pay federal income tax. As appropriate, our taxable
income or loss is includable in the federal income tax returns of our
partners. We record our obligations under the Texas gross margin tax
as “Income taxes” in our consolidated statement of
operations.
One of
the Predecessors was a corporation subject to federal and state income
taxes. They used the liability method for determining their income
taxes, under which current and deferred tax liabilities and assets are recorded
in accordance with enacted tax laws and rates. Under this method, the
amounts of deferred tax liabilities and assets at the end of each period are
determined using the tax rate expected to be in effect when taxes are actually
paid or recovered. Future tax benefits are recognized to the extent
that realization of such benefits is more likely than not. Deferred
income taxes are provided for the estimated income tax effect of temporary
difference between financial and tax bases in assets and
liabilities. Deferred tax assets are also provided for certain tax
credit carryforwards. A valuation allowance to reduce deferred tax is
established when it is more likely than not that some portion of all of the
deferred tax assets will not be realized.
Net
Income per Limited Partner Unit
We
calculate net income per limited partner unit in accordance with Emerging Issues
Task Force 03–06, Participating Securities and the
Two–Class Method under FASB Statement No. 128 (“EITF
03–06”). The computation of net income per limited partner unit is
based on the weighted average number of common and subordinated units
outstanding during the period. Basic and diluted net income per
limited partner unit are determined by dividing net income, after deducting
the amount allocated to the general partner interest (including its incentive
distribution in excess of its 2% interest), by the weighted average number of
outstanding limited partner units during the period.
EITF
03–06 provides that in any accounting period where our aggregate net income
exceeds our aggregate distribution for such period, we are required to present
net income per limited partner unit as if all of the earnings for the periods
were distributed, regardless of whether those earnings would have actually been
distributed. EITF 03–06 does not impact our overall net income or
other financial results; however, for periods in which our aggregate net income
exceeds our aggregate distributions for such period, it will have the impact of
reducing the earnings per limited partner unit. This result occurs as
a larger portion of our aggregate earnings is allocated to the incentive
distribution rights held by EV Energy GP, as if distributed, even though we make
cash distributions on the basis of cash available for distributions, not
earnings, in any given accounting period. In accounting periods where
aggregate net income does not exceed aggregate distributions for such period,
EITF 03–06 does not have an impact on our net income per limited partner unit
calculation.
Fair Value of Financial
Instruments
Our
financial instruments consist of cash and cash equivalents, accounts receivable,
accounts payable and accrued liabilities, long–term debt and derivative
financial instruments. Commodity derivatives are recorded at fair value.
The carrying amount of our other financial instruments other than debt
approximates fair value because of the short–term nature of the
items. The carrying value of our debt approximates fair value because
our debt has variable interest rates.
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
Derivative Financial
Instruments
We
monitor our exposure to various business risks, including commodity price and
interest rate risks, and use derivative financial instruments to manage the
impact of certain of these risks. Our policies do not permit the use
of derivative financial instruments for speculative purposes. We use
energy derivatives for the purpose of mitigating risk resulting from
fluctuations in the market price of oil and natural gas.
The
Predecessors accounted for their derivative financial instruments as cash flows
hedges in accordance with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as
amended. Derivative financial instruments that had been
designated and qualified as cash flows hedging instruments were reported at fair
value. The change in fair value of the derivative financial
instrument was initially reported as a component of other comprehensive income
(“AOCI”). Amounts in AOCI were reclassified into net income (as a
component of revenues) in the same period in which the hedged forecasted
transaction affected earnings. In the event that a forecasted
transaction is no longer probable of occurrence, the amount deferred in AOCI for
such forecasted transaction would be reclassified into net income.
As of
October 1, 2006, we elected not to designate any of our derivative financial
instruments as hedging instruments as defined by SFAS No. 133. The amount in AOCI at
that date related to derivatives that previously were designated and accounted
for as cash flow hedges continued to be deferred until the underlying production
was produced and sold, at which time the amounts were reclassified from AOCI and
reflected as a component of revenues. Changes in the fair value of
derivatives that existed at October 1, 2006 and any derivatives entered
thereafter are no longer deferred in AOCI, but rather are recorded immediately
to net income as “Gain (loss) on mark–to–market derivatives, net” in our
consolidated statement of operations.
The
counterparties to our derivative financial instruments are major financial
institutions. The credit ratings and concentration of risk of these
financial institutions are monitored on a continuing basis.
Business
Segment Reporting
We
operate in one reportable segment engaged in the exploration, development and
production of oil and natural gas properties and all of our operations are
located in the United States.
Concentration
of Credit Risk
Our oil,
natural gas and natural gas liquids revenues are derived principally from
uncollateralized sales to numerous companies in the oil and natural gas
industry; therefore, our customers may be similarly affected by changes in
economic and other conditions within the industry. We have
experienced no material credit losses on such sales in the past.
In 2008,
three customers accounted for 11%, 10% and 10%, respectively, of our
consolidated oil, natural gas and natural gas liquids revenues. In
2007, one customer accounted for 15% of our consolidated oil, natural gas and
natural gas liquids revenues. In 2006, three customers accounted for
32%, 17% and 14%, respectively, of the combined oil, natural gas and natural gas
liquids revenues of us and our predecessors. We believe that the loss
of a major customer would have a temporary effect on our revenues but that over
time, we would be able to replace our major customers.
New
Accounting Standards
In
September 2006, the Financial Accounting Standards Board (“FASB”) issued
SFAS No. 157, Fair
Value Measurements, to provide guidance for using fair value to measure
assets and liabilities. SFAS No. 157 was to be effective for
financial statements issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years; however, in February 2008, the
FASB issued FASB Staff Position FAS 157–2, Effective Date of FASB Statement No.
157, which delayed the effective date of SFAS No. 157 for all
nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for
our financial assets and financial liabilities (see Note 6). We
adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and
nonfinancial liabilities, and the adoption did not have a material impact on our
consolidated financial statements.
In
February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities – Including an amendment of FASB Statement No.
115. SFAS No. 159 permits entities to choose to
measure
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
many
financial instruments and certain other items at fair value that are not
currently required to be measured at fair value. Unrealized
gains and losses on items for which the fair value option has been selected are
reported in earnings. SFAS No. 159 also establishes presentation and
disclosure requirements designed to facilitate comparisons between entities that
choose different measurement attributes for similar types of assets and
liabilities. SFAS No. 159 was effective for fiscal years beginning
after November 15, 2007. We have elected not to apply the provisions
of SFAS No. 159.
In
December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS
No. 141(R)”) to significantly change the accounting for business
combinations. Under SFAS No. 141(R), an acquiring entity will be
required to recognize all the assets acquired and liabilities assumed in a
transaction at the acquisition date fair value with limited exceptions and will
change the accounting treatment for certain specific items,
including:
|
|
·
|
acquisition
costs will generally be expensed as
incurred;
|
|
|
·
|
noncontrolling
interests will be valued at fair value at the date of acquisition;
and
|
|
|
·
|
liabilities
related to contingent consideration will be recorded at fair value at the
date of acquisition and subsequently remeasured each subsequent reporting
period.
|
SFAS No.
141(R) is effective for fiscal years beginning after December 15, 2008 and must
be applied prospectively to business combinations completed on or after that
date. We adopted SFAS No. 141(R) on January 1, 2009, and there was no
impact on our consolidated financial statements.
In
December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements – An Amendment of ARB No. 51, to
establish new accounting and reporting standards for the noncontrolling interest
in a subsidiary and for the deconsolidation of a subsidiary. SFAS No.
160 requires the recognition of a noncontrolling interest (minority interest) as
equity in the consolidated financial statements and separate from the parent’s
equity. The amount of net income attributable to the noncontrolling
interest will be included in consolidated net income on the face of the income
statement. SFAS No. 160 clarifies that changes in a parent’s
ownership interest in a subsidiary that do not result in deconsolidation are
equity transactions if the parent retains its controlling financial
interest. In addition, SFAS No. 160 requires that a parent recognize
a gain or loss in net income when a subsidiary is
deconsolidated. SFAS No. 160 also includes expanded disclosure
requirements regarding the interests of the parent and its noncontrolling
interest. SFAS No. 160 is effective for fiscal years beginning after
December 15, 2008. We adopted SFAS No. 160 on January 1, 2009, and
there was no impact on our consolidated financial statements.
In March 2008, the FASB
issued SFAS No. 161, Disclosures
about Derivative Instruments and Hedging Activities—an amendment of FASB
Statement No. 133. SFAS No. 161
requires enhanced disclosures about an entity’s derivative and hedging
activities and how they affect an entity’s financial position, financial
performance and cash flows. SFAS No. 161 is effective for fiscal years and
interim periods beginning after November 15, 2008. We adopted
the disclosure requirements of SFAS No. 161 on January 1,
2009.
In March
2008, the FASB issued Emerging Issues Task Force 07-04, Application of the Two–Class Method
under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships (“EITF 07–04”), to provide guidance as to how current period
earnings should be allocated between limited partners and a general partner when
the partnership agreement contains incentive distribution
rights. EITF 07–04 is to be applied retrospectively for all financial
statements presented and is effective for fiscal years beginning after December
15, 2008. We will adopt EITF 07–04 for the quarter ending March 31,
2009, and we have not yet determined the impact, if any, on our calculation of
net income per limited partner unit.
In May
2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles. SFAS No. 162 identifies the sources for accounting
principles and the framework for selecting the principles to be used in
preparing financial statements of nongovernmental entities that are presented in
conformity with generally accepted accounting principles (GAAP) in the United
States. SFAS No. 162 was effective on November 15, 2008.
In
December 2008, the SEC published Modernization of Oil and Gas
Reporting, a revision to its oil and natural gas reporting
disclosures. The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions
about reserves volumes. The new requirements also will allow companies to
disclose their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (i) report the independence and
qualifications
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
of its
reserves preparer or auditor; (ii) file reports when a third party is relied
upon to prepare reserves estimates or conducts a reserves audit; and (iii)
report oil and natural gas reserves using an average price based upon the prior
12 month period rather than year end prices. The new disclosure
requirements are effective for registration statements filed on or after January
1, 2010, and for annual reports on Forms 10–K and 20–F for fiscal years ending
on or after December 31, 2009. We will adopt the new disclosure
requirements when they become effective.
Reclassifications
Certain
reclassifications have been made to the prior year’s consolidated/combined
financial statements to conform with the current year’s
presentation.
NOTE
3. SHARE–BASED COMPENSATION
EV
Management has a long–term incentive plan (the “Plan”) for employees,
consultants and directors of EV Management and its affiliates who perform
services for us. The Plan, as amended, allows for the award of unit
options, phantom units, restricted units and deferred equity rights, and the
aggregate amount of our common units that may be awarded under the plan is 1.5
million units. Unless earlier terminated by us or unless all units
available under the Plan have been paid to participants, the Plan will terminate
as of the close of business on September 20, 2016. The
compensation committee or the board of directors administers the
Plan.
We
account for our share–based compensation in accordance with SFAS No. 123 –
Revised 2004, Share–Based
Payment (“SFAS 123(R)”). As of December 31, 2008, we had 0.4
million phantom units outstanding, which are subject to graded vesting over a
two to four year period. On satisfaction of the vesting requirement,
the holders of the phantom units are entitled, at our discretion, to either
common units or a cash payment equal to the current value of the
units. We account for these phantom units as liability awards, and
the fair value of the phantom units is remeasured at the end of each reporting
period based on the current market price of our common units until
settlement. Prior to settlement, compensation cost is recognized for
the phantom units based on the proportionate amount of the requisite service
period that has been rendered to date.
During
the years ended December 31, 2008 and 2007, we recognized compensation cost of
$1.2 million and $1.5 million, respectively, related to our phantom
units. This cost is included in “General and administrative expenses”
in our consolidated statement of operations. As of December 31, 2008,
there was $4.3 million of total unrecognized compensation cost related to
unvested phantom units which is expected to be recognized over a weighted
average period of 3.2 years.
In
January 2008, 42,500 phantom units vested and were converted to common units at
a fair value of $1.3 million.
NOTE
4. ACQUISITIONS
In May
2008, we acquired oil properties in South Central Texas for $17.4 million, and
in August 2008, we acquired oil and natural gas properties in Michigan, Central
and East Texas, the Mid-Continent area (Oklahoma, Texas Panhandle and Kansas)
and Eastland County, Texas for $58.8 million. These acquisitions were
primarily funded with borrowings under our credit facility.
In
September 2008, we issued 236,169 common units to EnerVest to acquire natural
gas properties in West Virginia. EnerVest and its affiliates have a
significant interest in our partnership through their 71.25% ownership of EV
Energy GP which, in turn, owns a 2% general partner interest in us and all of
our incentive distribution rights. As we acquired these natural gas
properties from EnerVest, we carried over the historical costs related to
EnerVest’s interest and assigned a value of $5.8 million to the common
units.
In
September 2008, we also acquired oil and natural gas properties in the San Juan
Basin (the “San Juan acquisition”) from institutional partnerships managed by
EnerVest for $114.7 million in cash and 908,954 of our common
units. As we acquired these oil and natural gas properties from
institutional partnerships managed by EnerVest, we carried over the historical
costs related to EnerVest’s interests in the institutional partnerships and
assigned a value of $2.1 million to the common units. We then applied
purchase accounting to the remaining interests acquired. As a result,
we recorded a deemed distribution of $13.9 million that represents the
difference between the purchase price allocation and the amount paid for the
acquisitions. We allocated this deemed distribution to the common
unitholders, subordinated unitholders and
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
the
general partner interest based on EnerVest’s relative ownership
interests. Accordingly, $5.4 million, $7.4 million and $1.1 million
was allocated to the common unitholders, subordinated unitholders and the
general partner, respectively.
The
allocation of the purchase price to the assets acquired and liabilities assumed
at the date of acquisition was as follows:
|
San
Juan
|
||||
|
Oil
and natural gas properties
|
$ | 105,770 | ||
|
Asset
retirement obligations
|
(2,858 | ) | ||
|
Allocation
of purchase price
|
$ | 102,912 | ||
In 2007,
we completed the following acquisitions:
|
|
·
|
in
January, we acquired natural gas properties in Michigan from an
institutional partnership managed by EnerVest for $69.5 million, net of
cash acquired;
|
|
|
·
|
in
March, we acquired additional natural gas properties in the Monroe Field
in Louisiana from an institutional partnership managed by EnerVest for
$95.4 million;
|
|
|
·
|
in
June, we acquired oil and natural gas properties in Central and East Texas
from Anadarko Petroleum Corporation for $93.6
million;
|
|
|
·
|
in
October, we acquired oil and natural gas properties in the Permian Basin
from Plantation Operating, LLC, a company sponsored by investment funds
formed by EnCap Investments, L.P. for $154.7 million;
and
|
|
|
·
|
in
December, we acquired oil and natural gas properties in the Appalachian
Basin from an institutional partnership managed by EnerVest for $59.6
million.
|
The
following table reflects unaudited pro forma revenues, net income and net income
per limited partner unit as if the San Juan acquisition and the acquisitions
completed in 2007 had taken place at the beginning of the period
presented. These unaudited pro forma amounts do not purport to be
indicative of the results that would have actually been obtained during the
periods presented or that may be obtained in the future.
|
Year
Ended
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Revenues
|
$ | 231,322 | $ | 190,456 | ||||
|
Net
income
|
233,728 | 30,749 | ||||||
|
Net
income per limited partner unit:
|
||||||||
|
Common units (basic and
diluted)
|
$ | 11.54 | $ | 2.03 | ||||
|
Subordinated units (basic and
diluted)
|
$ | 11.54 | $ | 2.03 | ||||
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
NOTE
5. RISK MANAGEMENT
Our
business activities expose us to risks associated with changes in the market
price of oil and natural gas. As such, future earnings are subject to
change due to changes in these market prices. We use derivative
agreements to reduce our risk of changes in the prices of oil and natural
gas. As of December 31, 2008, we had entered into derivative
agreements with the following terms:
|
Period
Covered
|
Index
|
Hedged
Volume
per
Day
|
Weighted
Average
Fixed
Price
|
Weighted
Average
Floor
Price
|
Weighted
Average
Ceiling
Price
|
|||||||||||||
|
Oil
(Bbls):
|
||||||||||||||||||
|
Swaps – 2009
|
WTI
|
1,781 | $ | 93.10 | $ | $ | ||||||||||||
|
Collar – 2009
|
WTI
|
125 | 62.00 | 73.90 | ||||||||||||||
|
Swaps – 2010
|
WTI
|
1,725 | 90.84 | |||||||||||||||
|
Swaps – 2011
|
WTI
|
480 | 109.38 | |||||||||||||||
|
Collar – 2011
|
WTI
|
1,100 | 110.00 | 166.45 | ||||||||||||||
|
Swaps – 2012
|
WTI
|
460 | 108.76 | |||||||||||||||
|
Collar – 2012
|
WTI
|
1,000 | 110.00 | 170.85 | ||||||||||||||
|
Swap – 2013
|
WTI
|
500 | 72.50 | |||||||||||||||
|
Natural
Gas (MMBtu):
|
||||||||||||||||||
|
Swaps – 2009
|
Dominion
Appalachia
|
6,400 | 9.03 | |||||||||||||||
|
Swaps – 2010
|
Dominion
Appalachia
|
5,600 | 8.65 | |||||||||||||||
|
Swap – 2011
|
Dominion
Appalachia
|
2,500 | 8.69 | |||||||||||||||
|
Collar – 2011
|
Dominion
Appalachia
|
3,000 | 9.00 | 12.15 | ||||||||||||||
|
Collar – 2012
|
Dominion
Appalachia
|
5,000 | 8.95 | 11.45 | ||||||||||||||
|
Swaps – 2009
|
NYMEX
|
9,000 | 8.05 | |||||||||||||||
|
Collars – 2009
|
NYMEX
|
7,000 | 7.79 | 9.50 | ||||||||||||||
|
Swaps – 2010
|
NYMEX
|
13,500 | 8.28 | |||||||||||||||
|
Collar – 2010
|
NYMEX
|
1,500 | 7.50 | 10.00 | ||||||||||||||
|
Swaps – 2011
|
NYMEX
|
12,500 | 8.53 | |||||||||||||||
|
Swaps - 2012
|
NYMEX
|
12,500 | 9.01 | |||||||||||||||
|
Swap – 2013
|
NYMEX
|
4,000 | 7.50 | |||||||||||||||
|
Swaps – 2009
|
MICHCON_NB
|
5,000 | 8.27 | |||||||||||||||
|
Swap – 2010
|
MICHCON_NB
|
5,000 | 8.34 | |||||||||||||||
|
Collar – 2011
|
MICHCON_NB
|
4,500 | 8.70 | 11.85 | ||||||||||||||
|
Collar – 2012
|
MICHCON_NB
|
4,500 | 8.75 | 11.05 | ||||||||||||||
|
Swaps – 2009
|
HOUSTON
SC
|
5,620 | 8.25 | |||||||||||||||
|
Collar – 2010
|
HOUSTON
SC
|
3,500 | 7.25 | 9.55 | ||||||||||||||
|
Collar - 2011
|
HOUSTON
SC
|
3,500 | 8.25 | 11.65 | ||||||||||||||
|
Collar – 2012
|
HOUSTON
SC
|
3,000 | 8.25 | 11.10 | ||||||||||||||
|
Swaps – 2009
|
EL
PASO PERMIAN
|
3,500 | 7.80 | |||||||||||||||
|
Swap – 2010
|
EL
PASO PERMIAN
|
2,500 | 7.68 | |||||||||||||||
|
Swap – 2011
|
EL
PASO PERMIAN
|
2,500 | 9.30 | |||||||||||||||
|
Swap – 2012
|
EL
PASO PERMIAN
|
2,000 | 9.21 | |||||||||||||||
|
Swap – 2013
|
EL
PASO PERMIAN
|
3,000 | 6.77 | |||||||||||||||
|
Swap – 2013
|
SAN
JUAN BASIN
|
3,000 | 6.66 | |||||||||||||||
In
addition, our floating rate credit facility exposes us to risks associated with
changes in interest rates and as such, future earnings are subject to change due
to changes in these interest rates. As of December 31, 2008, we had
entered into interest rate swaps with the following terms:
|
Period
Covered
|
Notional
Amount
|
Fixed
Rate
|
||||||
|
January
2009 – July 2012
|
$ | 35,000 | 4.043 | % | ||||
|
January
2009 – July 2012
|
40,000 | 4.050 | % | |||||
|
January
2009 – July 2012
|
70,000 | 4.220 | % | |||||
|
January
2009 – July 2012
|
20,000 | 4.248 | % | |||||
|
January
2009 – July 2012
|
35,000 | 4.250 | % | |||||
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
At
December 31, 2008, the fair value associated with these derivative agreements
and interest rate swaps was a net asset of $144.7 million.
During
the years ended December 31, 2008 and 2007 and three months ended December 31,
2006, we reclassified $1.6 million, $3.2 million and $1.0 million, respectively,
from AOCI to “Gain on derivatives, net.”
During
the years ended December 31, 2008 and 2007 and three months ended December 31,
2006, we recorded unrealized gains (losses) of $163.3 million, $(28.9) million
and $(0.1) million, respectively, on the change in fair value of our derivative
instruments in “Gain (loss) on mark–to–market derivatives, net.” In
addition, we recorded net realized (losses) gains of $(14.6) million, $9.0
million and $1.8 million in the years ended December 31, 2008 and 2007 and the
three months ended December 31, 2006, respectively, related to settlements of
our derivative instruments in “Gain (loss) on mark–to–market derivatives,
net.”
NOTE
6. FAIR VALUE MEASUREMENTS
SFAS 157
establishes a valuation hierarchy for disclosure of the inputs to valuation used
to measure fair value. This hierarchy prioritizes the inputs into the
following three levels:
|
|
·
|
Level
1 inputs are quoted prices (unadjusted) in active markets for identical
assets or liabilities.
|
|
|
·
|
Level
2 inputs are quoted prices for similar assets and liabilities in active
markets or inputs that are observable for the asset or liability, either
directly or indirectly through market
corroboration.
|
|
|
·
|
Level
3 inputs are unobservable inputs based on our own assumptions used to
measure assets and liabilities at fair
value.
|
A
financial asset or liability’s classification within the hierarchy is determined
based on the lowest level input that is significant to the fair value
measurement.
The
following table presents the fair value hierarchy table for our assets and
liabilities that are required to be measured at fair value on a recurring
basis:
|
Fair
Value Measurements at December 31, 2008 Using:
|
||||||||||||||||
|
Total
Carrying
Value
|
Quoted
Prices in Active Markets for Identical Assets
(Level
1)
|
Significant
Other Observable Inputs
(Level
2)
|
Significant
Unobservable Inputs
(Level
3)
|
|||||||||||||
|
Derivative
instruments
|
$ | 144,726 | $ | – | $ | 144,726 | $ | – | ||||||||
Our
derivative instruments consist of over–the–counter (“OTC”) contracts which are
not traded on a public exchange. These derivative instruments are
indexed to active trading hubs for the underlying commodity, and are OTC
contracts commonly used in the energy industry and offered by a number of
financial institutions and large energy companies.
As the
fair value of these derivative instruments is based on inputs using market
prices obtained from independent brokers or determined using quantitative models
that use as their basis readily observable market parameters that are actively
quoted and can be validated through external sources, including third-party
pricing services, brokers and market transactions, we have categorized these
derivative instruments as Level 2. We value these derivative instruments based
on observable market data for similar instruments. This observable data includes
the forward curve for commodity prices based on quoted market prices and
prospective volatility factors related to changes in the forward
curves.
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
NOTE
7. INCOME TAXES
We are a
partnership that is not taxable for federal income tax purposes. As such,
we do not directly pay federal income tax. As appropriate, our taxable
income or loss is includable in the federal income tax returns of our
partners.
During
the years ended December 31, 2008 and 2007, we recorded provisions of $0.2
million and $0.1 million, respectively, for income taxes relating to our
obligations under the Texas gross margin tax.
One of
the Predecessors was a corporate entity which was subject to federal and
state taxation. The provision for income taxes is comprised of the
following:
|
Nine
Months Ended
September
30,
|
||||
|
2006
|
||||
|
Current
|
$ | 6,348 | ||
|
Deferred
|
(539 | ) | ||
|
Provision
for income taxes
|
$ | 5,809 | ||
The
provision for income taxes differs from the amount computed by applying the U.S.
statutory income tax rate to income before income taxes and equity in income of
affiliates for the reasons set forth below:
|
Nine
Months Ended
September
30,
|
||||
|
2006
|
||||
|
Income
before income taxes and equity in income of affiliates
|
$ | 22,219 | ||
|
Less:
Income not subject to income taxes
|
(3,862 | ) | ||
|
Income
before income taxes and equity in income of affiliates subject to income
taxes
|
18,357 | |||
|
Statutory
rate
|
35 | % | ||
|
Income
tax expense at statutory rate
|
6,425 | |||
|
Reconciling
items:
|
||||
|
State income taxes, net of
federal benefit
|
656 | |||
|
Percentage depletion in excess
of basis
|
(1,225 | ) | ||
|
Other permanent
items
|
(47 | ) | ||
|
Provision
for income taxes
|
$ | 5,809 | ||
NOTE
8. ASSET RETIREMENT OBLIGATIONS
If a
reasonable estimate of the fair value of an obligation to perform site
reclamation, dismantle facilities or plug and abandon wells can be made, we
record an ARO and capitalize the asset retirement cost in oil and natural gas
properties in the period in which the retirement obligation is
incurred. After recording these amounts, the ARO is accreted to its
future estimated value using an assumed cost of funds and the additional
capitalized costs are depreciated on a unit–of–production basis. The
changes in the aggregate asset retirement obligations are as
follows:
|
Balance
as of December 31, 2006
|
$ | 5,188 | ||
|
Liabilities
incurred or assumed in acquisitions
|
13,579 | |||
|
Accretion
expense
|
814 | |||
|
Revisions
in estimated cash flows
|
14 | |||
|
Balance
as of December 31, 2007
|
19,595 | |||
|
Liabilities
incurred or assumed in acquisitions
|
13,098 | |||
|
Accretion
expense
|
1,434 | |||
|
Revisions
in estimated cash flows
|
514 | |||
|
Payments
to settle liabilities
|
(26 | ) | ||
|
Balance
as of December 31, 2008
|
$ | 34,615 |
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
As of
December 31, 2008 and December 31, 2007, $0.8 million and $0.1 million,
respectively, of our ARO is classified as current and is included in
“Accounts payable and accrued liabilities” on our consolidated balance
sheet.
NOTE
9. LONG–TERM DEBT
As of
December 31, 2008, our credit facility consists of a $700.0 million senior
secured revolving credit facility that expires in October
2012. Borrowings under the facility are secured by a first priority
lien on substantially all of our assets and the assets of our
subsidiaries. We may use borrowings under the facility for acquiring
and developing oil and natural gas properties, for working capital purposes, for
general corporate purposes and for funding distributions to
partners. We also may use up to $50.0 million of available borrowing
capacity for letters of credit. The facility contains certain
covenants which, among other things, require the maintenance of a current ratio
(as defined in the facility) of greater than 1.00 and a ratio of total debt to
earnings plus interest expense, taxes, depreciation, depletion and amortization
expense and exploration expense of no greater than 4.0 to 1.0. As of
December 31, 2008, we were in compliance with all of the facility
covenants.
Borrowings
under the facility bear interest at a floating rate based on, at our election, a
base rate or the London Inter–Bank Offered Rate plus applicable premiums based
on the percent of the borrowing base that we have outstanding (weighted average
effective interest rate of 4.74% and 7.16% at December 31, 2008 and 2007,
respectively).
Borrowings
under the facility may not exceed a “borrowing base” determined by the lenders
based on our oil and natural gas reserves. As of December 31, 2008,
the borrowing base was $525.0 million. The borrowing base is subject
to scheduled redeterminations as of April 1 and October 1 of each year with an
additional redetermination once per calendar year at our request or at the
request of the lenders and with one calculation that may be made at our request
during each calendar year in connection with material acquisitions or
divestitures of properties.
We had
$467.0 million and $270.0 million outstanding under the facility at December 31,
2008 and 2007, respectively.
NOTE
10. COMMITMENTS AND CONTINGENCIES
We are
involved in disputes or legal actions arising in the ordinary course of
business. We do not believe the outcome of such disputes or legal
actions will have a material adverse effect on our consolidated financial
statements.
NOTE
11. OWNERS’ EQUITY
Issuance
of Units
On
September 29, 2006, we closed our initial public offering of 3.9 million of our
common units, and on October 26, 2006, we closed the sale of an additional 0.4
million common units pursuant to the exercise of the underwriters’
over–allotment option. Upon the closing of our initial public offering
(and taking into account the underwriters’ exercise of their over–allotment
option), EnerVest and its affiliates received an aggregate of 136,304 common
units and 2,663,830 subordinated units.
In
February 2007 and June 2007, we entered into Common Unit Purchase Agreements and
Registration Rights Agreements for the issuance of 3.9 million common units and
3.4 million common units, respectively, to institutional investors in private
placements. We received net proceeds of $219.7 million, including
contributions of $4.4 million by our general partner to maintain its 2% interest
in us. Proceeds from these issuances were primarily used to repay
indebtedness outstanding under our credit facility.
In
September 2008, we issued a total of 1,145,123 common units to EnerVest in
conjunction with our acquisition of natural gas properties in West Virginia and
oil and natural gas properties in the San Juan Basin (see Note 4).
Units
Outstanding
At
December 31, 2008, owner’s equity consists of 13,027,062 common units
outstanding (including 737,785 common units held by affiliates of EV Management,
including executive officers), 3,100,000 subordinated units (including 1,836,596
held by affiliates of EV Management, including executive officers), collectively
representing a 98% limited partnership interest in us, and a 2% general
partnership interest.
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
Common
Units
During
the subordination period, the common units will have the right to receive
distributions of available cash from operating surplus (as defined in our
partnership agreement) each quarter in an amount equal to $0.40 per common
unit plus any arrearages in the payment of the minimum quarterly distribution on
the common units from prior quarters, before any distributions of available cash
from operating surplus may be made on the subordinated units. The purpose
of the subordinated units is to increase the likelihood that during the
subordination period there will be available cash to be distributed on the
common units.
The
subordination period will extend until the first day of any quarter beginning
after September 30, 2011 that each of the following tests are
met:
|
|
·
|
distributions
of available cash from operating surplus on each of the outstanding common
units, subordinated units and the 2% general partner interest equaled or
exceeded the minimum quarterly distribution for each of the three
consecutive, non–overlapping four quarter periods immediately
preceding that date;
|
|
|
·
|
the
“adjusted operating surplus” (as defined in our partnership agreement)
generated during each of the three consecutive, non–overlapping
four quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distributions on all of the
outstanding common and subordinated units and the 2% general partner
interest during those periods on a fully diluted basis during those
periods; and
|
|
|
·
|
there
are no arrearages in payment of the minimum quarterly distribution on the
common units.
|
If the
unitholders remove our general partner other than for cause and units held by
the general partner and its affiliates are not voted in favor of such
removal:
|
|
·
|
the
subordination period will end and each subordinated unit will immediately
convert into one common unit;
|
|
|
·
|
any
existing arrearages in payment of the minimum quarterly distribution on
the common units will be extinguished;
and
|
|
|
·
|
the
general partner will have the right to convert its 2% general partner
interest and its incentive distribution rights into common units or to
receive cash in exchange for those
interests.
|
The
common units have limited voting rights as set forth in our partnership
agreement.
Pursuant
to our partnership agreement, if at any time our general partner and its
affiliates own more than 80% of the common units outstanding, our general
partner has the right, but not the obligation, to “call” or acquire all, but not
less than all, of the common units held by unaffiliated persons at a price not
less than their then current market value. Our general partner may assign
this call right to any of its affiliates or to us.
Subordinated
Units
During
the subordination period, the subordinated units have no right to receive
distributions of available cash from operating surplus until the common units
receive distributions of available cash from operating surplus in an amount
equal to the minimum quarterly distribution of $0.40 per quarter, plus any
arrearages in the payment of the minimum quarterly distribution on the common
units from prior quarters. No arrearages will be paid to subordinated
units.
The
subordinated units may convert to common units on a one–for–one basis when
certain conditions as set forth in our partnership agreement are
met. Our partnership agreement also sets forth the calculation to be
used to determine the amount and priority of cash distributions that the common
unitholders, subordinated unitholders and our general partner will
receive.
The
subordinated units have limited voting rights as set forth in our partnership
agreement.
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
General
Partner Interest
Our
general partner owns a 2% interest in us. This interest entitles our
general partner to receive distributions of available cash from operating
surplus as discussed further below under Cash Distributions. Our
partnership agreement sets forth the calculation to be used to determine the
amount and priority of cash distributions that the common unitholders,
subordinated unitholders and general partner will receive.
The
general partner units have the management rights as set forth in our partnership
agreement.
Allocations
of Net Income
Net
income is allocated between our general partner and the common and subordinated
unitholders in accordance with the provisions of our partnership
agreement. Net income is generally allocated first to our general
partner and the common and subordinated unitholders in an amount equal to the
net losses allocated to our general partner and the common and subordinated
unitholders in the current and prior tax years under the partnership
agreement. The remaining net income is allocated to our general
partner and the common and subordinated unitholders in accordance with their
respective percentage interests of the general partner units, common units and
subordinated units.
Cash
Distributions
We intend
to continue to make regular cash distributions to unitholders on a quarterly
basis, although there is no assurance as to the future cash distributions since
they are dependent upon future earnings, cash flows, capital requirements,
financial condition and other factors. Our credit facility prohibits
us from making cash distributions if any potential default or event of default,
as defined in our credit facility, occurs or would result from the cash
distribution.
Within 45
days after the end of each quarter, we will distribute all of our available cash
(as defined in our partnership agreement) to our general partner and unitholders
of record on the applicable record date. The amount of available cash
generally is all cash on hand at the end of the quarter; less the amount of cash
reserves established by our general partner to provide for the proper conduct of
our business, to comply with applicable laws, any of our debt instruments, or
other agreements or to provide funds for distributions to unitholders and to our
general partner for any one or more of the next four quarters; plus all cash on
hand on the date of determination of available cash for the quarter resulting
from working capital borrowings made after the end of the
quarter. Working capital borrowings are generally borrowings that are
made under our credit facility and in all cases are used solely for working
capital purposes or to pay distributions to partners.
Our
partnership agreement requires that we make distributions of available cash from
operating surplus for any quarter during the subordination period in the
following manner:
|
|
·
|
first, 98% to the
common unitholders, pro rata, and 2% to the general partner, until we
distribute for each outstanding common unit an amount equal to the minimum
quarterly distribution for that
quarter;
|
|
|
·
|
second, 98% to the
common unitholders, pro rata, and 2% to the general partner, until we
distribute for each outstanding common unit an amount equal to any
arrearages in payment of the minimum quarterly distribution on the common
units for any prior quarters during the subordination
period;
|
|
|
·
|
third, 98% to the
subordinated unitholders, pro rata, and 2% to the general partner, until
we distribute for each subordinated unit an amount equal to the minimum
quarterly distribution for that
quarter; and
|
|
|
·
|
thereafter, cash in
excess of the minimum quarterly distributions is distributed to the
unitholders and the general partner based on the percentages
below.
|
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
Our
general partner is entitled to incentive distributions if the amount we
distribute with respect to one quarter exceeds specified target levels shown
below:
|
Marginal
Percentage Interest in Distributions
|
|||||||||||
|
Total
Quarterly Distributions
Target
Amount
|
Limited
Partner
|
General
Partner
|
|||||||||
|
Minimum
quarterly distribution
|
$0.40
|
98%
|
2
|
%
|
|||||||
|
First
target distribution
|
Up
to $0.46
|
98%
|
2
|
%
|
|||||||
|
Second
target distribution
|
Above
$0.46, up to $0.50
|
85%
|
15
|
%
|
|||||||
|
Thereafter
|
Above
$0.50
|
75%
|
25
|
%
|
|||||||
The
following sets forth the distributions we paid during the years ended
December 31, 2008 and 2007:
|
Date
Paid
|
Period
Covered
|
Distribution
per
Unit
|
Total
Distribution
|
|||||||
|
February
14, 2008
|
October
1, 2007 – December 31, 2007
|
$ | 0.60 | $ | 9,735 | |||||
|
May
15, 2008
|
January
1, 2008 – March 31, 2008
|
0.62 | 10,135 | |||||||
|
August
14, 2008
|
April
1, 2008 – June 30, 2008
|
0.70 | 11,732 | |||||||
|
November
14, 2008
|
July
1, 2008 – September 30, 2008
|
0.75 | 13,704 | |||||||
| $ | 45,306 | |||||||||
|
February
14, 2007
|
October
1, 2006 – December 31, 2006
|
$ | 0.40 | $ | 3,100 | |||||
|
May
15, 2007
|
January
1, 2007 – March 31, 2007
|
0.46 | 5,413 | |||||||
|
August
14, 2007
|
April
1, 2007 – June 30, 2007
|
0.50 | 7,713 | |||||||
|
November
14, 2007
|
July
1, 2007 – September 30, 2007
|
0.56 | 8,901 | |||||||
| $ | 25,127 | |||||||||
On
January 28, 2009, the board of directors of EV Management declared a $0.751 per
unit distribution for the fourth quarter of 2008 on all common and subordinated
units. The distribution was paid on February 13, 2009 to
unitholders of record at the close of business on February 6,
2009. The aggregate amount of the distribution was $13.8
million.
NOTE
12. NET INCOME PER LIMITED PARTNER UNIT
The
following sets forth the net income allocation in accordance with EITF
03–06:
|
Successor
|
||||||||||||
|
Year
Ended
December
31,
|
October
1, 2006
through
December
31,
|
|||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Net
income
|
$ | 225,485 | $ | 11,190 | $ | 3,367 | ||||||
|
Less:
|
||||||||||||
|
General partner incentive
distribution rights
|
(50,133 | ) | (1,476 | ) | – | |||||||
|
General partner’s 2% interest in
net income
|
(4,510 | ) | (194 | ) | (67 | ) | ||||||
|
Net
income available for limited partners
|
$ | 170,842 | $ | 9,520 | $ | 3,300 | ||||||
|
Weighted
average common units outstanding (basic and diluted)
|
||||||||||||
|
Common units (basic and
diluted)
|
12,240 | 9,815 | 4,495 | |||||||||
|
Subordinated units (basic and
diluted)
|
3,100 | 3,100 | 3,100 | |||||||||
|
Net
income per limited partner unit (basic and diluted)
|
$ | 11.14 | $ | 0.74 | $ | 0.43 | ||||||
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
NOTE
13. RELATED PARTY TRANSACTIONS
Successor
Pursuant
to the Omnibus Agreement, we paid EnerVest $5.5 million, $3.1 million and $0.3
million in the years ended December 31, 2008 and 2007 and the three months ended
December 31, 2006, respectively, in monthly administrative fees for providing us
general and administrative services. These fees are based on an
allocation of charges between EnerVest and us based on the estimated use of such
services by each party, and we believe that the allocation method employed by
EnerVest is reasonable and reflective of the estimated level of costs we would
have incurred on a standalone basis. These fees are included in
general and administrative expenses in our consolidated statement of
operations.
In
September 2008, we issued 236,169 common units to EnerVest to acquire natural
gas properties in West Virginia. In September 2008, we also acquired
oil and natural gas properties in the San Juan Basin from institutional
partnerships managed by EnerVest for $114.7 million in cash and 908,954 of our
common units (see Note 4).
On
January 31, 2007, we acquired natural gas properties in Michigan for $69.5
million, net of cash acquired, from certain institutional partnerships managed
by EnerVest, on March 30, 2007, we acquired additional natural gas properties in
the Monroe Field in Louisiana from an institutional partnership managed by
EnerVest for $95.4 million and on December 21, 2007, we acquired additional oil
and natural gas properties in the Appalachian Basin for $59.6 million from an
institutional partnership managed by EnerVest. On October 1, 2007, we
acquired oil and natural gas properties in the Permian Basin in New Mexico and
Texas from Plantation Operating, LLC, an EnCap sponsored company, for $154.4
million (see Note 4).
We have
entered into operating agreements with EnerVest whereby a subsidiary of EnerVest
acts as contract operator of the oil and natural gas wells and related gathering
systems and production facilities in which we own an interest. During
the years ended December 31, 2008 and 2007 and the three months ended December
31, 2006, we reimbursed EnerVest approximately $8.9 million, $6.1 million and
$0.6 million, respectively, for direct expenses incurred in the operation of our
wells and related gathering systems and production facilities and for the
allocable share of the costs of EnerVest employees who performed services on our
properties. As the vast majority of such expenses are charged to us
on an actual basis (i.e., no mark–up or subsidy is charged or received by
EnerVest), we believe that the aforementioned services were provided to us at
fair and reasonable rates relative to the prevailing market and are
representative of what the amounts would have been on a standalone
basis. These costs are included in lease operating expenses in our
consolidated statement of operations. Additionally, in its role as
contract operator, this EnerVest subsidiary also collects proceeds
from oil and natural gas sales and distributes them to us and other working
interest owners.
During
the three months ended March 31, 2007 and the three months ended December 31,
2006, we sold $1.3 million of natural gas to EnerVest Monroe Marketing, Ltd.
(“EnerVest Monroe Marketing”), a subsidiary of one of the EnerVest
partnerships. On March 30, 2007, we acquired EnerVest Monroe
Marketing in our acquisition of natural gas properties in the Monroe Field in
Louisiana (see Note 4).
Predecessors
Pursuant
to terms of certain agreements, the Predecessors paid $42,000 to EnerVest and
its subsidiaries for management, accounting and advisory services in the
nine months ended September 30, 2006. In addition, a subsidiary of EnerVest
served as operator of the Predecessors’ properties and received reimbursement
through Council of Petroleum Accountants Societies (“COPAS”) overhead
billings. The Predecessors paid this EnerVest subsidiary $1.0 million
in the nine months ended September 30, 2006 and these amounts are reflected in
lease operating expenses within the combined statements of
operations. As the vast majority of such expenses are charged to us
on an actual basis (i.e., no mark–up or subsidy is charged or received by
EnerVest), we believe that the aforementioned services were provided to us at
fair and reasonable rates relative to the prevailing market and are
representative of what the amounts would have been on a standalone
basis. Additionally, in its role as operator, this EnerVest
subsidiary also collected proceeds from oil and natural gas sales and
distributed them to the Predecessor and other working interest owners.
During
the nine months ended September 30, 2006, the Predecessors sold $4.3 million of
natural gas to EnerVest Monroe Marketing. The purchase price was spot
market price based on the average of two index prices for natural gas production
in the area, less a gathering fee of either $0.10 per Mcf or $0.75 per Mcf
depending upon whether compression
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
and
additional gathering services or facilities were provided. EnerVest Monroe
Marketing resold the natural gas and realized a profit of $0.3 million in the
nine months ended September 30, 2006.
In
connection with the formation of EV Properties in the second quarter of 2006,
EnerVest Production Partners and EnerVest WV sold certain non–material assets
not used in their oil and natural gas activities. These transactions
are described below:
|
|
·
|
The
Predecessors sold oil and natural gas properties totaling $0.4 million to
a wholly owned subsidiary of EnerVest. No loss was recognized
on the sale as the transaction was deemed to be a transfer of assets
between entities under common
control;
|
|
|
·
|
The
Predecessors sold other property totaling $0.2 million to a wholly owned
subsidiary of EnerVest. No loss was recognized on the sale as
the transaction was deemed to be a distribution to the general partner;
and
|
|
|
·
|
The
Predecessors sold investments in affiliated companies totaling $1.3
million to a wholly owned subsidiary of EnerVest. No loss was
recognized on the sale as the transaction was deemed to be a transfer of
assets between entities under common control. Prior to the
sale, the Predecessors recorded the proportionate share of net income from
the investments in affiliated companies under the equity method of
accounting.
|
In
addition, in connection with the contribution of the general partner and limited
partner interests in EnerVest Production Partners to EV Properties, accounts
payable of $3.2 million was forgiven by EnerVest and converted to owners’
equity.
NOTE 14. OTHER SUPPLEMENTAL
INFORMATION
Supplemental
cash flows and non–cash transactions were as follows:
|
Successor
|
Predecessors
|
|||||||||||||||
|
Year
Ended
December
31,
|
Three
Months Ended December 31,
|
Nine
Months Ended September 30,
|
||||||||||||||
|
2008
|
2007
|
2006
|
2006
|
|||||||||||||
|
Supplemental
cash flows information:
|
||||||||||||||||
|
Cash paid for
interest
|
$ | 15,822 | $ | 6,453 | $ | 16 | $ | 686 | ||||||||
|
Cash paid for income
taxes
|
171 | – | – | 3,357 | ||||||||||||
|
Non–cash
transactions:
|
||||||||||||||||
|
Issuance of common and
subordinated units in conjunction with the
acquisition
of the Predecessors
|
– | – | 36,060 | – | ||||||||||||
|
Costs for development of
oil and natural gas properties in accounts payable
and
accrued liabilities
|
924 | 1,653 | 557 | 241 | ||||||||||||
|
Increase in oil and
natural gas properties from purchase of limited
partnership
interest in EnerVest WV
|
– | – | – | 7,681 | ||||||||||||
|
Distribution/sale of
property and investments in affiliates to EnerVest
|
– | – | – | 1,849 | ||||||||||||
|
Reduction in debt through
partner contribution
|
– | – | – | 150 | ||||||||||||
|
Increase in due to
affiliates for the incurrence of offering costs on our
behalf
|
– | – | – | 4,000 | ||||||||||||
|
Conversion of accounts
payable to EnerVest to owners’ equity
|
– | – | – | 3,165 | ||||||||||||
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
NOTE 15. QUARTERLY DATA
(UNAUDITED)
|
Successor
|
||||||||||||||||
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
|||||||||||||
|
2008
|
||||||||||||||||
|
Revenues
|
$ | 47,757 | $ | 61,049 | $ | 57,404 | $ | 41,103 | ||||||||
|
Gross profit (1)
|
33,961 | 46,088 | 40,532 | 25,114 | ||||||||||||
|
Net income
(loss)
|
(24,672 | ) | (99,524 | ) | 204,139 | 145,542 | ||||||||||
|
Limited partners’ interest in
net income (loss)
|
(24,179 | ) | (97,533 | ) | 154,824 | 110,974 | ||||||||||
|
Net income (loss) per limited
partner unit
|
||||||||||||||||
|
Basic
|
$ | (1.61 | ) | $ | (6.51 | ) | $ | 10.14 | $ | 6.88 | ||||||
|
Diluted
|
$ | (1.61 | ) | $ | (6,51 | ) | $ | 10.14 | $ | 6.88 | ||||||
|
2007
|
||||||||||||||||
|
Revenues
|
$ | 12,007 | $ | 23,138 | $ | 29,429 | $ | 39,434 | ||||||||
|
Gross profit (1)
|
8,219 | 14,667 | 19,359 | 27,058 | ||||||||||||
|
Net income
(loss)
|
(2,602 | ) | 11,957 | 13,735 | (11,900 | ) | ||||||||||
|
Limited partners’ interest in
net income (loss)
|
(2,550 | ) | 11,718 | 12,014 | (11,662 | ) | ||||||||||
|
Net income (loss) per limited
partner unit
|
||||||||||||||||
|
Basic
|
$ | (0.28 | ) | $ | 0.93 | $ | 0.80 | $ | (0.78 | ) | ||||||
|
Diluted
|
$ | (0.28 | ) | $ | 0.93 | $ | 0.80 | $ | (0.78 | ) | ||||||
|
(1)
|
Represents
total revenues less lease operating expenses, cost of purchased natural
gas and production taxes.
|
NOTE
16. SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS ACTIVITIES
(UNAUDITED)
The
following disclosures of costs incurred related to oil and natural gas
activities are presented in accordance with SFAS No. 69, Disclosure about Oil and Gas Producing
Activities:
|
Successor
|
Predecessors
|
|||||||||||||||
|
Year
Ended December 31,
|
Three
Months Ended
December
31,
|
Nine
Months Ended
September
30,
|
||||||||||||||
|
2008
|
2007
|
2006
|
2006
|
|||||||||||||
|
Costs
incurred in oil and natural gas producing activities:
|
||||||||||||||||
|
Acquisition of proved
properties
|
$ | 186,345 | $ | 456,393 | $ | 112,952 | $ | – | ||||||||
|
Acquisition of unproved
properties
|
– | 446 | 173 | – | ||||||||||||
|
Development of oil and natural
gas properties
|
33,940 | 12,197 | 1,728 | 7,152 | ||||||||||||
|
Exploration
costs
|
– | – | – | 1,415 | ||||||||||||
|
Asset retirement costs incurred
and revised
|
13,794 | 13,593 | 712 | 11 | ||||||||||||
|
Total
|
$ | 234,079 | $ | 482,629 | $ | 115,565 | $ | 8,578 | ||||||||
|
December
31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Capitalized
costs related to oil and natural gas producing activities:
|
||||||||
|
Evaluated
properties:
|
||||||||
|
Proved
properties
|
$ | 835,040 | $ | 600,503 | ||||
|
Unproved
properties
|
161 | 619 | ||||||
|
Accumulated depreciation,
depletion and amortization
|
(69,958 | ) | (30,724 | ) | ||||
|
Net capitalized
costs
|
$ | 765,243 | $ | 570,398 | ||||
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
NOTE 17. ESTIMATED PROVED OIL,
NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES (UNAUDITED)
Our
estimated proved developed and estimated proved undeveloped reserves are all
located within the United States. We caution that there are many
uncertainties inherent in estimating proved reserve quantities and in projecting
future production rates and the timing of development expenditures.
Accordingly, these estimates are expected to change as further information
becomes available. Material revisions of reserve estimates may occur in
the future, development and production of the oil, natural gas and natural gas
liquids reserves may not occur in the periods assumed, and actual prices
realized and actual costs incurred may vary significantly from those used in
this estimate. Proved reserves represent estimated quantities of oil,
natural gas and natural gas liquids that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in future years from
known reservoirs under economic and operating conditions existing at the time
the estimates were made. Estimated proved developed reserves are estimated
proved reserves expected to be recovered through wells and equipment in place
and under operating methods in use at the time the estimates were made.
The estimates of our proved reserves as of December 31, 2008, 2007 and
2006 have been prepared by Cawley, Gillespie, & Associates, Inc.,
independent petroleum consultants.
The
following table sets forth changes in estimated proved and estimated proved
developed reserves for the periods indicated.
|
Oil
(MBbls)
(1)
|
Natural
Gas
(Mmcf)
(2)
|
Natural
Gas Liquids
(MBbls)
(1)
|
MMcfe
(3)
|
|||||||||||||
|
Predecessors:
|
||||||||||||||||
|
Proved reserves:
|
||||||||||||||||
|
Proved reserves, December 31,
2005
|
1,668 | 50,883 | – | 60,891 | ||||||||||||
|
Revision of previous
estimates
|
(139 | ) | (10,752 | ) | – | (11,590 | ) | |||||||||
|
Production
|
(147 | ) | (3,275 | ) | – | (4,157 | ) | |||||||||
|
Extension and
discoveries
|
47 | 1,157 | – | 1,440 | ||||||||||||
|
Proved reserves, September 30,
2006
|
1,429 | 38,013 | – | 46,584 | ||||||||||||
|
Proved developed
reserves:
|
||||||||||||||||
|
September 30,
2006
|
1,376 | 35,947 | – | 44,203 | ||||||||||||
|
Successor:
|
||||||||||||||||
|
Proved reserves:
|
||||||||||||||||
|
Proved reserves, September 30,
2006
|
– | – | – | – | ||||||||||||
|
Purchase of minerals in
place
|
1,992 | 49,050 | – | 61,002 | ||||||||||||
|
Revision of previous
estimates
|
– | 91 | – | 91 | ||||||||||||
|
Production
|
(18 | ) | (625 | ) | – | (733 | ) | |||||||||
|
Extensions and
discoveries
|
46 | 875 | – | 1,151 | ||||||||||||
|
Proved reserves, December 31,
2006
|
2,020 | 49,391 | – | 61,511 | ||||||||||||
|
Reclass of natural gas liquids
(4)
|
(18 | ) | – | 18 | – | |||||||||||
|
Purchase of minerals in
place
|
2,450 | 207,285 | 8,841 | 275,031 | ||||||||||||
|
Revision of previous
estimates
|
190 | 571 | 35 | 1,921 | ||||||||||||
|
Production
|
(225 | ) | (9,254 | ) | (199 | ) | (11,798 | ) | ||||||||
|
Extensions and
discoveries
|
87 | 2,017 | 24 | 2,683 | ||||||||||||
|
Proved reserves, December 31,
2007
|
4,504 | 250,010 | 8,719 | 329,348 | ||||||||||||
|
Purchase of minerals in
place
|
4,330 | 54,164 | 4,340 | 106,184 | ||||||||||||
|
Revision of previous
estimates
|
(2,568 | ) | (25,500 | ) | (2,919 | ) | (58,422 | ) | ||||||||
|
Production
|
(437 | ) | (14,578 | ) | (543 | ) | (20,458 | ) | ||||||||
|
Extensions and
discoveries
|
48 | 1,945 | 52 | 2,545 | ||||||||||||
|
Proved reserves, December 31,
2008
|
5,877 | 266,041 | 9,649 | 359,197 | ||||||||||||
|
Proved developed
reserves:
|
||||||||||||||||
|
December 31,
2006
|
1,920 | 45,906 | – | 57,425 | ||||||||||||
|
December 31,
2007
|
3,714 | 223,000 | 5,434 | 277,888 | ||||||||||||
|
December 31,
2008
|
5,666 | 253,088 | 8,966 | 340,883 | ||||||||||||
|
(1)
|
Thousand
of barrels.
|
|
(2)
|
Million
cubic feet.
|
|
(3)
|
Million
cubic feet equivalent; barrels are converted to Mcfe based on one barrel
of oil to six Mcf of natural gas
equivalent.
|
|
(4)
|
Reserves
for natural gas liquids were included with oil reserves in prior years as
the amounts were not material.
|
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
NOTE 18. STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL, NATURAL GAS AND NATURAL
GAS LIQUIDS RESERVES (UNAUDITED)
The
following tables, which present a standardized measure of discounted future net
cash flows and changes therein relating to estimated proved oil, natural
gas and natural gas liquids reserves, are presented pursuant to SFAS No.
69. In computing this data, assumptions other than those required by
SFAS No. 69 could produce different results. Accordingly, the data
should not be construed as representative of the fair market value of our
estimated proved oil, natural gas and natural gas liquids reserves.
The following assumptions have been made:
|
|
·
|
Future
revenues were based on year end oil, natural gas and natural gas
liquids prices. Future price changes were included only to the
extent provided by existing contractual
agreements.
|
|
|
·
|
Production
and development costs were computed using year end costs assuming no
change in present economic
conditions.
|
|
|
·
|
Future
net cash flows were discounted at an annual rate of
10%.
|
|
|
·
|
For
the nine months ended September 30, 2006, future income taxes were
computed only for CGAS Exploration using the approximate statutory tax
rate and giving effect to available net operating losses, tax credits and
statutory depletion. No future income taxes were computed for
EnerVest WV or EnerVest Production Partners in accordance with their
standing as non taxable entities. For the years ended
December 31, 2008 and 2007 and the three months ended December 31, 2006,
no future federal income taxes were computed in accordance with our
standing as non taxable entities. For the years ended December
31, 2008 and 2007, future obligations under the Texas gross margin tax
were computed.
|
The
standardized measure of discounted future net cash flows relating to estimated
proved oil, natural gas and natural gas liquids reserves is presented
below:
|
Successor
|
Predecessors
|
|||||||||||||||
|
Year
Ended December 31,
|
Three
Months Ended December 31,
|
Nine
Months Ended September 30,
|
||||||||||||||
|
2008
|
2007
|
2006
|
2006
|
|||||||||||||
|
Estimated
future cash inflows:
|
||||||||||||||||
|
Revenues from sales of oil,
natural gas and natural gas liquids
|
$ | 1,940,014 | $ | 2,541,295 | $ | 405,592 | $ | 263,003 | ||||||||
|
Production costs
|
(918,719 | ) | (937,764 | ) | (165,968 | ) | (113,414 | ) | ||||||||
|
Development
costs
|
(40,904 | ) | (100,113 | ) | (11,969 | ) | (5,666 | ) | ||||||||
|
Estimated future cash inflows
before future income taxes
|
980,391 | 1,503,418 | 227,655 | 143,923 | ||||||||||||
|
Future
income taxes
|
(1,711 | ) | (3,172 | ) | – | (31,222 | ) | |||||||||
|
Future
net cash inflows
|
978,680 | 1,500,246 | 227,655 | 112,701 | ||||||||||||
|
10%
annual timing discount
|
(536,748 | ) | (820,347 | ) | (122,652 | ) | (45,406 | ) | ||||||||
|
Standardized
measure of discounted future net cash flows
|
$ | 441,932 | $ | 679,899 | $ | 105,003 | $ | 67,295 | ||||||||
At
December 31, 2008, as specified by the SEC, the prices for oil, natural gas
and natural gas liquids used in this calculation were regional cash price quotes
on the last day of the year except for volumes subject to fixed price
contracts.
EV
Energy Partners, L.P.
Notes
to Consolidated/Combined Financial Statements (continued)
The
weighted average prices for the total estimated proved reserves at
December 31, 2008, 2007 and 2006 were $44.60 per Bbl of oil, $5.71 per
MMBtu of natural gas and $25.38 per Bbl of natural gas liquids, $95.95 per Bbl
of oil, $6.795 per MMBtu of natural gas and $57.50 per Bbl of natural gas
liquids and $60.85 per Bbl of oil and $5.635 per MMBtu of natural gas,
respectively. We do not include our oil and natural gas derivative
financial instruments, consisting of swaps and collars, in the determination of
our oil, natural gas and natural gas liquids reserves.
The
principal sources of changes in the standardized measure of future net cash
flows are as follows:
|
Predecessors:
|
||||
|
Standardized measure, December
31, 2005
|
$ | 182,409 | ||
|
Sales of oil, natural gas and
natural gas liquids, net of production costs
|
(28,109 | ) | ||
|
Extensions and
discoveries
|
6,499 | |||
|
Development costs
incurred
|
7,152 | |||
|
Changes in estimated future
development costs
|
2,776 | |||
|
Net changes in prices and
production costs
|
(147,324 | ) | ||
|
Revisions and
other
|
7,298 | |||
|
Changes in income
taxes
|
22,913 | |||
|
Accretion of 10% timing
discount
|
13,681 | |||
|
Standardized measure, September
30, 2006
|
$ | 67,295 | ||
|
Successor:
|
||||
|
Standardized measure, September
30, 2006
|
$ | – | ||
|
Sales of oil, natural gas and
natural gas liquids, net of production costs
|
(3,946 | ) | ||
|
Purchase of minerals in
place
|
84,265 | |||
|
Extensions and
discoveries
|
1,638 | |||
|
Development costs
incurred
|
10 | |||
|
Changes in estimated future
development costs
|
(7,372 | ) | ||
|
Net changes in prices and
production costs
|
22,300 | |||
|
Revisions and
other
|
6,574 | |||
|
Accretion of 10% timing
discount
|
1,534 | |||
|
Standardized measure, December
31, 2006
|
105,003 | |||
|
Sales of oil, natural gas and
natural gas liquids, net of production costs
|
(67,774 | ) | ||
|
Purchase of minerals in
place
|
519,578 | |||
|
Extensions and
discoveries
|
7,000 | |||
|
Development costs
incurred
|
12,528 | |||
|
Changes in estimated future
development costs
|
(4,092 | ) | ||
|
Net changes in prices and
production costs
|
55,419 | |||
|
Revisions and
other
|
19,176 | |||
|
Changes in income
taxes
|
(1,882 | ) | ||
|
Accretion of 10% timing
discount
|
34,943 | |||
|
Standardized measure, December
31, 2007
|
679,899 | |||
|
Sales of oil, natural gas and
natural gas liquids, net of production costs
|
(131,139 | ) | ||
|
Purchase of minerals in
place
|
249,945 | |||
|
Extensions and
discoveries
|
4,543 | |||
|
Development costs
incurred
|
33,940 | |||
|
Changes in estimated future
development costs
|
19,720 | |||
|
Net changes in prices and
production costs
|
(408,456 | ) | ||
|
Net changes in previous quantity
estimates
|
(75,040 | ) | ||
|
Changes in timing and
other
|
(11,354 | ) | ||
|
Changes in income
taxes
|
2,212 | |||
|
Accretion of 10% timing
discount
|
77,662 | |||
|
Standardized measure, December
31, 2008
|
$ | 441,932 | ||
None.
Evaluation of Disclosure Controls and
Procedures
In
accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and our Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief
Executive Officer and Chief Financial Officer concluded that our disclosure
controls and procedures were effective as of December 31, 2008 to provide
reasonable assurance that information required to be disclosed in our reports
filed or submitted under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission’s rules and forms. Our disclosure controls and procedures
include controls and procedures designed to provide reasonable assurance that
information required to be disclosed in reports filed or submitted under the
Exchange Act is accumulated and communicated to our management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.
Management’s
Report on Internal Control Over Financial Reporting
Pursuant
to Section 404 of the Sarbanes–Oxley Act of 2002, our management included a
report of their assessment of the design and effectiveness of our internal
controls over financial reporting as part of this Annual Report on Form 10–K for
the fiscal year ended December 31, 2008. Deloitte & Touche
LLP, our independent registered public accounting firm, has issued an
attestation report on the effectiveness of our internal control over financial
reporting. Management’s report and the independent registered public
accounting firm’s attestation report are included in Item 8 under the
caption entitled “Management’s Report on Internal Control Over Financial
Reporting” and “Report of Independent Registered Public Accounting Firm” and are
incorporated herein by reference.
Change
in Internal Controls Over Financial Reporting
There
have not been any changes in our internal controls over financial reporting that
occurred during the quarterly period ended December 31, 2008 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
None.
As is the
case with many publicly traded partnerships, we do not directly employ officers,
directors or employees. Our operations and activities are managed by
the general partner of our general partner, EV Management, a wholly owned
subsidiary of EnerVest. References to our officers, directors and
employees are references to the officers, directors and employees of EV
Management.
Our
general partner is not elected by our unitholders and will not be subject to
re–election on a regular basis in the future. Unitholders will not be
entitled to elect the directors of EV Management or directly or indirectly
participate in our management or operation. Our general partner is
owned 71.25% by EnerVest, 23.75% by EnCap and 5.00% by EV
Investors.
Our
general partner owes a fiduciary duty to our unitholders. Our general
partner will be liable, as general partner, for all of our debts (to the extent
not paid from our assets), except for indebtedness or other obligations that are
made expressly
nonrecourse
to it. Our general partner therefore may cause us to incur
indebtedness or other obligations that are nonrecourse to it.
Directors
and Executive Officers
All of
our executive management personnel, other than Messrs. Walker, Houser and Dwyer,
are employees of EV Management and devote all of their time to our business and
affairs. We estimate that Mr. Walker devotes approximately 25%
of his time to our business, Mr. Houser devotes approximately 40% of
his time to our business and Mr. Dwyer devotes approximately 30% of his time to
our business. The officers of EV Management will manage the
day–to–day affairs of our business. We also utilize a significant number
of employees of EnerVest to operate our properties and provide us with certain
general and administrative services. Under the omnibus agreement, we
pay EnerVest a fee for its operational personnel who perform services for our
benefit. During the year ended December 31, 2008, we paid EnerVest
$5.5 million for general and administrative services, which fee will increase or
decrease as we purchase or divest assets.
The
following table shows information as of March 2, 2009 regarding members of
our Board of Directors and executive officers of EV
Management. Members of our Board of Directors are elected for
one–year terms.
|
Name
|
Age
|
Position
with EV Management
|
||
|
John
B. Walker
|
63
|
Chairman
and Chief Executive Officer
|
||
|
Mark
A. Houser
|
47
|
President,
Chief Operating Officer and Director
|
||
|
Michael
E. Mercer
|
50
|
Senior
Vice President and Chief Financial Officer
|
||
|
Kathryn
S. MacAskie
|
52
|
Senior
Vice President of Acquisitions and Divestitures
|
||
|
Frederick
Dwyer
|
49
|
Controller
|
||
|
Victor
Burk (1)
(2)
|
59
|
Director
|
||
|
James
R. Larson (1)
|
59
|
Director
|
||
|
George
Lindahl III (1)
(2)
|
62
|
Director
|
||
|
Gary
R. Petersen (2)
|
62
|
Director
|
||
|
(1)
|
Member
of the audit committee and the conflicts
committee.
|
|
(2)
|
Member
of the compensation committee.
|
John B. Walker has
served as EV Management’s Chairman and Chief Executive Officer since 2006.
He has been the President and CEO of EnerVest, Ltd. since its formation in
1992. Prior to that, Mr. Walker was President and Chief Operating
Officer of Torch Energy Advisors Incorporated, a company which formed and
managed partnerships for institutional investors in the oil and natural gas
business, and Chief Executive Officer of Walker Energy Partners, a master
limited partnership engaged in the exploration and production business. He
was the Chairman of the Independent Petroleum Association of America from 2003
to 2005. Mr. Walker is currently a member of the National Petroleum
Council and serves or has served on the boards of the Houston Producers Forum,
Houston Petroleum Club, Offshore Energy Center, Texas Independent Producers and
Royalty Owners Association and as Chairman of the Board of the Sam Houston Area
Council of the Boy Scouts of America. He holds a BBA from Texas Tech
University and an MBA from New York University.
Mark A. Houser has served as
EV Management’s President, Chief Operating Officer and Director since
2006. He has been the Executive Vice President and Chief Operating
Officer of EnerVest, Ltd. since 1999. Prior to that, Mr. Houser
was Vice President, United States Exploration and Production, for Occidental
Petroleum Corporation, or Oxy, where he helped lead Oxy’s reorganization of its
domestic reserve base. Mr. Houser began his career as an engineer
with Kerr–McGee Corporation. He holds a petroleum engineering degree from
Texas A&M University and an MBA from Southern Methodist
University.
Michael E. Mercer has served
as our Senior Vice President and Chief Financial Officer since 2006. He
was a consultant to EnerVest, Ltd. from 2001 to 2006. Prior to that,
Mr. Mercer was an investment banker for twelve years. He was a
Director in the Energy Group at Credit Suisse First Boston in Houston and a
Director in the Energy Group at Salomon Smith Barney in New York and London.
He holds a BBA in Petroleum Land Management from the University of Texas
at Austin and an MBA from the University of Chicago Graduate School of
Business.
Kathryn S. MacAskie has
served as our Senior Vice President of Acquisitions and Divestitures since 2006.
She was President and co-owner of FlairTex Resources, Inc., a petroleum
engineering consulting and acquisition business from 2002
to 2006.
Prior to that, Ms. MacAskie was Vice President and Manager of
the Houston Office for Cawley, Gillespie & Associates Inc., a Petroleum
Engineering Consulting firm from 1999 to 2002 and Senior Vice President of
Acquisitions and Divestitures for EnerVest, Ltd. from 1994 to 1999. She
holds a BS in Engineering from Rice University and is a Licensed Professional
Engineer in the State of Texas.
Frederick Dwyer has served as
Controller of EV Management since 2006. Mr. Dwyer joined EnerVest in
September 2006 as Vice President and Corporate Controller. Prior to
that, he was employed by KCS Energy, Inc., a Houston–based oil and natural gas
exploration and production company, since 1986, where he held various management
and supervisory positions including Vice President, Controller and Corporate
Secretary. He began his career with Peat, Marwick, Mitchell &
Company. Mr. Dwyer holds a Bachelor of Science degree from Manhattan
College.
Victor Burk was appointed to
our Board of Directors in September 2006. Since 2005, Mr. Burk
has been the global energy practice leader for Spencer Stuart, a
privately owned executive recruiting firm. Prior to joining Spencer
Stuart, Mr. Burk served as managing partner of Deloitte & Touche’s
global oil and natural gas group from 2002 to 2005. He began his
professional career in 1972 with Arthur Andersen and served as managing partner
of Arthur Andersen’s global oil and natural gas group from 1989 until 2002.
Mr. Burk is a board member of the Houston Producers’ Forum, the
Independent Petroleum Association of America (Southeast Texas Region) and Sam
Houston Area Council of the Boy Scouts of America. He holds a BBA in
Accounting from Stephen F. Austin University, graduating with highest
honors.
James R. Larson was appointed
to our Board of Directors in September 2006. Since January 1, 2006,
Mr. Larson has been retired. From September 2005 until
January 1, 2006, Mr. Larson served as Senior Vice President of
Anadarko Petroleum Corporation. From December 2003 to September 2005,
Mr. Larson served as Senior Vice President, Finance and Chief Financial
Officer of Anadarko. From 2002 to 2003, Mr. Larson served as Senior
Vice President, Finance of Anadarko where he oversaw treasury, investor
relations, internal audits and acquisitions and divestitures. From 1995 to
2002, Mr. Larson served as Vice President and Controller of Anadarko where
he was responsible for accounting, financial reporting, budgeting, forecasting
and tax. Prior to that, he held various tax and financial positions within
Anadarko after joining the company in 1981. Mr. Larson is a current
member of the American Institute of Certified Public Accountants, Financial
Executives International and Tax Executives Institute. He holds a BBA in
Business from the University of Iowa.
George Lindahl III was
appointed to our Board of Directors in September 2006. From 2001 to
2007, he was a Managing Partner for Sandefer Capital Partners. From 2000
to 2001 he served as Vice Chairman of Anadarko Petroleum Corporation. From
1987 to 2000, he was with Union Pacific Resources, serving as President and
Chief Operating Officer from 1996 to 1999 and as Chairman, President and CEO
from 1999 to 2000. He holds a BS in Geology from the University of Alabama
and has completed the Advanced Management program at Harvard Business
School.
Gary R. Petersen was
appointed to our Board of Directors in September 2006. Since 1988,
Mr. Petersen has been Senior Managing Director of EnCap Investments L.P.,
an investment management firm which he co–founded. He had previously
served as Senior Vice President of the Corporate Finance Division of the Energy
Banking Group for RepublicBank Corporation. Prior to his position at
RepublicBank, he was Executive Vice President and a member of the Board of
Directors of Nicklos Oil & Gas Company from 1979 to 1984.
Mr. Petersen is on the board of directors of the general partner of
Plains All American Pipeline, L.P., a publicly traded partnership engaged in the
transportation and marketing of crude oil. He holds a BBA and an MBA from
Texas Tech University.
Composition
of the Board of Directors
EV
Management’s board of directors consists of six members, one of which, Mr.
Petersen, was appointed by EnCap and the remainder of which were appointed by
EnerVest.
EV
Management’s board of directors holds regular and special meetings at any time
as may be necessary. Regular meetings may be held without notice on
dates set by the board from time to time. Special meetings of the
board may be called with reasonable notice to each member upon request of the
chairman of the board or upon the written request of any three board
members. A quorum for a regular or special meeting will exist when a
majority of the members are participating in the meeting either in person or by
telephone conference. Any action required or permitted to be taken at
a board meeting may be taken without a meeting, without prior notice and without
a vote if all of the members sign a written consent authorizing the
action.
Unitholder
Communications
Interested
parties can communicate directly with non–management directors by mail in care
of EV Energy Partners, L.P., 1001 Fannin Street, Suite 800, Houston,
Texas 77002. Such communications should specify the
intended recipient or recipients. Commercial solicitations or
communications will not be forwarded.
Committees
of the Board of Directors
EV
Management’s board of directors established an audit committee, a compensation
committee and a conflicts committee. The charters for our audit and
compensation committees are posted under the “Investor Relations” section of our
website at www.evenergypartners.com. Our
conflicts committee was created in our partnership agreement and does not have a
charter.
Because
we are a limited partnership, the listing standards of the NASDAQ do not require
that we or our general partner have a majority of independent directors or a
nominating or compensation committee of the board of directors. We
are, however, required to have an audit committee, a majority of whose members
are required to be “independent” under NASDAQ standards as described
below.
Audit
Committee
The audit
committee is comprised of Messrs. Larson (Chairman), Burk and Lindahl, all of
whom meet the independence and experience standards established by the NASDAQ
and the Exchange Act. The board of directors has determined that each
of Messrs. Larson, Burk and Lindahl is an “audit committee financial expert” as
defined under SEC rules.
The audit
committee assists the board of directors in its oversight of the integrity of
our financial statements and our compliance with legal and regulatory
requirements and corporate policies and controls. The audit committee has
the sole authority and responsibility to retain and terminate our independent
registered public accounting firm, resolve disputes with such firm, approve all
auditing services and related fees and the terms thereof, and pre–approve any
non–audit services to be rendered by our independent registered public
accounting firm. The audit committee is also responsible for confirming
the independence and objectivity of our independent registered public accounting
firm. Our independent registered public accounting firm is given
unrestricted access to the audit committee and meets with the audit committee on
a regularly scheduled basis. During 2008, representatives of our
independent auditors attended all of our audit committee
meetings. The audit committee may also engage the services of
advisors and accountants as it deems advisable.
Compensation
Committee
Although
not required by the listing requirements of the NASDAQ, the board of directors
established and maintains a compensation committee comprised of non-employee
directors. The compensation committee is comprised of Messrs. Lindahl
(Chairman), Burk and Petersen. The compensation committee reviews the
compensation and benefits of our executive officers, establishes and reviews
general policies related to our compensation and benefits and administers our
Long–Term Incentive Plan.
Conflicts
Committee
The
conflicts committee is comprised of Messrs. Burk (Chairman), Larson and Lindahl,
all of whom meet the independence and experience standards established by the
NASDAQ and the Exchange Act. The conflicts committee reviews specific
matters that the board of directors believes may involve conflicts of interest.
The conflicts committee will then determine if the conflict of
interest has been
resolved in accordance with our partnership agreement. Any matters
approved by the conflicts committee will be conclusively deemed to be fair and
reasonable to us, approved by all of our partners, and not a breach by our
general partner of any duties it may owe us or our
unitholders.
Meetings
and Other Information
During
2008, the board of directors had eight regularly scheduled and special meetings,
the audit committee had four meetings, the compensation committee had one
meeting and the conflicts committee had five meetings. None of our
directors attended fewer than 75% of the aggregate number of meetings of the
board of directors and committees of the board on which the director
served.
Our
partnership agreement provides that the general partner manages and operates us
and that, unlike holders of common stock in a corporation, unitholders have only
limited voting rights on matters affecting our business or
governance. Accordingly, we do not hold annual meetings of
unitholders.
Section
16(a) Beneficial Ownership Reporting Compliance
Section
16(a) of the Exchange Act requires executive officers and directors of EV
Management and persons who beneficially own more than 10% of a class of our
equity securities registered pursuant to Section 12 of the Exchange Act to file
certain reports with the SEC and the NASDAQ concerning their beneficial
ownership of such securities.
Based
solely on a review of the copies of reports on Forms 3, 4 and 5 and amendments
thereto furnished to us and written representations from the executive officers
and directors of EV Management, we believe that during the year ended December
31, 2008, the officers and directors of EV Management and beneficial owners of
more than 10% of our equity securities registered pursuant to Section 12 were in
compliance with the applicable requirements of Section 16(a).
Code
of Ethics
The
corporate governance of EV Management is, in effect, the corporate governance of
our partnership, subject in all cases to any specific unitholder rights
contained in our partnership agreement.
EV
Management has adopted a code of business conduct that applies to all officers,
directors and employees of EV Management and its affiliates. A copy
of our code of business conduct is available on our website at www.evenergypartners.com. We
will provide a copy of our code of ethics to any person, without charge, upon
request to EV Management, LLC, 1001 Fannin, Suite 800, Houston, Texas 77002,
Attn: Corporate Secretary.
Audit
Committee Report
REPORT
OF THE AUDIT COMMITTEE FOR FISCAL YEAR 2008
Management
of EV Management is responsible for our internal controls and the financial
reporting process. Deloitte & Touche LLP, our independent
registered public accounting firm for the year ended December 31, 2008, is
responsible for performing an independent audit of our consolidated financial
statements in accordance with the standards of the Public Company Accounting
Oversight Board (PCAOB) and generally accepted auditing standards in the United
States of America and issuing a report thereon. The audit committee
monitors and oversees these processes and approves the selection and appointment
of our independent registered public accounting firm and recommends the
ratification of such selection and appointment to the board of
directors.
The audit
committee has reviewed and discussed our audited consolidated financial
statements with management and Deloitte & Touche LLP. The audit
committee has discussed with Deloitte & Touche LLP the matters required to
be discussed by Statement on Auditing Standards No. 114
“The Auditor’s Communication With Those Charged With
Goverance.” The audit committee has received written
confirmation of the firm’s independence from Deloitte & Touche LLP and has
discussed with Deloitte & Touche LLP that firm’s independence.
Based on
the foregoing review and discussions and such other matters the audit committee
deemed relevant and appropriate, the audit committee recommended to the board
that the audited consolidated financial statements of the partnership
be included in our Annual Report on Form 10-K for the year ended
December 31, 2008.
Members
of the Audit Committee:
James R.
Larson, Chairman
Victor
Burk
George
Lindahl III
Reimbursement of Expenses of
our General
Partner
Our
general partner does not receive any management fee or other compensation for
its management of our partnership. Under the terms of the omnibus
agreement, we pay EnerVest a fee for general and administrative services
undertaken for our benefit and for our allocable portion of the premiums on
insurance policies covering our assets. In addition, we reimburse EV
Management for the costs of employee, officer and director compensation and
benefits properly allocable to us, as well as for other expenses necessary or
appropriate to the conduct of our business and properly allocable to
us. Our partnership agreement provides that our general partner will
determine the expenses that are allocable to us in any reasonable manner
determined by our general partner in its sole discretion.
Compensation
Discussion and Analysis
Because
our general partner is a limited partnership, its general partner, EV
Management, manages our operations and activities. We do not directly
employ any of the persons responsible for managing our business. Mr.
Mercer and Ms. MacAskie are employees of EV Management, and we reimburse EV
Management for the costs of their compensation. Mr. Mercer and Ms.
MacAskie do not perform services for EnerVest or its
affiliates. Their compensation is set by the compensation committee
of EV Management’s board of directors, which we refer to as our compensation
committee
Messrs.
Walker, Houser and Dwyer are officers of EV Management and also are officers and
employees of subsidiaries of EnerVest. In these capacities, they
perform services for us as well as for EnerVest and its other
affiliates. Messrs. Walker, Houser and Dwyer receive their base
salary and short–term and long–term incentive compensation from
EnerVest. Our compensation committee discusses with EnerVest the
philosophy used by EnerVest in setting their salaries and bonus compensation,
but the compensation committee has no role in determining the base salary and
short–term and long–term incentive compensation paid to them by
EnerVest. We pay EnerVest a fee under the omnibus agreement which is
based in part on the compensation paid to EnerVest employees who perform work
for us, but we do not directly reimburse EnerVest for the costs of the
compensation of Messrs. Walker, Houser and Dwyer. In addition to the
compensation paid to them by EnerVest, Messrs. Walker, Houser and Dwyer
participate in our equity incentive plan. Awards made to Messrs.
Walker, Houser and Dwyer under the plan are determined by our compensation
committee.
Our
compensation committee has overall responsibility for the approval, evaluation
and oversight of all of our compensation plans. The committee’s
primary purpose is to assist the board of directors in the discharge of its
fiduciary responsibilities relating to fair and competitive
compensation. The compensation committee meets in the fourth quarter
of each year to review the compensation program and to determine compensation
levels for the ensuing fiscal year, and at other times as required.
Objectives
of Our Compensation Program
Our
executive compensation program is intended to align the interests of our
management team with those of our unitholders by motivating our executive
officers to achieve strong financial and operating results for us, which we
believe closely correlate to long–term unitholder value. In addition,
our program is designed to achieve the following objectives:
|
|
·
|
attract
and retain talented executive officers by providing reasonable total
compensation levels competitive with that of executives holding comparable
positions in similarly situated
organizations;
|
|
|
·
|
provide
total compensation that is justified by individual
performance;
|
|
|
·
|
provide
performance–based compensation that balances rewards for short–term and
long–term results and is tied to both individual and our performance;
and
|
|
|
·
|
encourage
the long–term commitment of our executive officers to us and our
unitholders’ long–term
interests.
|
What
Our Compensation Program is Designed to Reward
Our
compensation program is designed to reward performance that contributes to the
achievement of our business strategy on both a short–term and long–term
basis. In addition, we reward qualities that we believe help achieve
our strategy such as teamwork; individual performance in light of general
economic and industry specific conditions;
performance
that supports our core values; resourcefulness; the ability to manage our
existing assets; the ability to explore new avenues to increase oil and gas
production and reserves; level of job responsibility; and tenure.
Performance
Metrics
Our
compensation committee did not establish performance metrics for our executive
officers at the beginning of the year. Our compensation committee
does not intend to establish metrics, goals and target compensation levels for
2009 to remain flexible in our compensation practices during our first several
years as a public master limited partnership.
In
setting 2008 bonus and long–term incentives amounts, the compensation committee
considered the performance of our executive officers in causing us to achieve
the following milestones in 2008:
|
|
·
|
our
quarterly distributions increased from $0.60 per unit to $0.751 per
unit;
|
|
|
·
|
our
asset base increased over 32% from over $226 million in accretive
acquisitions; and
|
|
|
·
|
our
operating performance was within
budget.
|
Based on
this success, our compensation committee generally awarded bonuses and long–term
incentives that reflected good to excellent performance.
Elements
of Our Compensation Program and Why We Pay Each Element
To
accomplish our objectives, we seek to offer a total direct compensation program
to our executive officers that, when valued in its entirety, serves to attract,
motivate and retain executives with the character, experience and professional
accomplishments required for our growth and development. Our
compensation program is comprised of four elements:
|
|
·
|
base
salary;
|
|
|
·
|
cash
bonus;
|
|
|
·
|
long–term
equity–based compensation; and
|
|
|
·
|
benefits.
|
Base
Salary
We pay
base salary in order to recognize each executive officer's unique value and
historical contributions to our success in light of salary norms in the industry
and the general marketplace; to match competitors for executive talent; to
provide executives with sufficient, regularly–paid income; and to reflect
position and level of responsibility.
To
provide stability as well as incentivize appropriately, Mr. Mercer and Ms.
MacAskie are parties to employment agreements which set their minimum base
salaries per annum. In the compensation committee’s discretion,
however, these base salaries may be increased based upon performance and
subjective factors. For 2008, the compensation committee increased
the base salary of both Mr. Mercer and Ms. MacAskie by 2.9%, generally
representing a cost of living increase. Subjective factors the
compensation committee considered include individual achievements, the
partnership’s performance, level of responsibility, experience, leadership
abilities, increases or changes in duties and responsibilities and contributions
to our performance.
Cash
Bonus
We
include an annual cash bonus as part of our compensation program because we
believe this element of compensation helps to motivate management to achieve key
operational objectives by rewarding the achievement of these
objectives. The annual cash bonus also allows us to be competitive
from a total remuneration standpoint.
The cash
bonuses paid to Mr. Mercer and Ms. MacAskie reflect the belief of our
compensation committee that their efforts directly affected our success in
2008. Taking into account the achievement of the goals described
above at the good
or
excellent level, for 2008, the compensation committee awarded both Mr. Mercer
and Ms. MacAskie bonuses of $135,000 each, representing 60% of their 2008 base
salaries.
In
general, the compensation committee targets between 50% and 75% of base salary
for performance deemed by our compensation committee to be good (to generally
exceed expectations) and great (to significantly exceed expectations),
respectively, with the possibility of no bonus for poor performance and higher
for exceptional corporate or individual performance.
Long–term
Equity–based Compensation
Long–term
equity–based compensation is an element of our compensation policy because we
believe it aligns executives’ interests with the interests of our unitholders;
rewards long–term performance; is required in order for us to be competitive
from a total remuneration standpoint; encourages executive retention; and gives
executives the opportunity to share in our long–term performance.
The
compensation committee and/or our board of directors act as the manager of our
long–term incentive plan (the “Plan”) and performs functions that include
selecting award recipients, determining the timing of grants and assigning the
number of units subject to each award, fixing the time and manner in which
awards are exercisable, setting exercise prices and vesting and expiration
dates, and from time to time adopting rules and regulations for carrying out the
purposes of our plan. For compensation decisions regarding the grant
of equity compensation to executive officers, our compensation committee will
consider recommendations from our chief executive officer. Typically,
awards vest over multiple years, but the compensation committee maintains the
discretionary authority to vest the equity grant immediately if the individual
situation merits. In the event of a change of control, or upon the
death, disability, retirement or termination of a grantee’s employment without
good reason, all outstanding equity based awards will immediately
vest.
Awards
under the Plan may be unit options, phantom units, restricted units and deferred
equity rights, or DERs, and the aggregate amount of our common units that may be
awarded under the Plan is 1,500,000 units. As of December 31, 2008,
there are 1,045,200 units available for issuance. Unless earlier
terminated by us or unless all units available under the plan have been paid to
participants, the Plan will terminate as of the close of business on
September 20, 2016.
Although
the Plan generally provides for the grant of unit options, Internal Revenue Code
Section 409A and authoritative guidance thereunder provides that options can
generally only be granted to employees of the entity granting the option
and certain affiliates without being required to comply with Section 409A as
nonqualified deferred compensation. Until further guidance is issued by
the Treasury Department and Internal Revenue Service under Section 409A, we do
not intend to grant unit options.
In
addition, because we are a partnership, tax and accounting conventions make it
more costly for us to issue additional common units or options as incentive
compensation. Consequently, we have no outstanding options or
restricted units and have no plans to issue options or restricted units in the
future. Instead, we have issued phantom units to our executive
officers that are paid by issuance of units or, at the discretion of our
compensation committee, in cash based on the average closing price of our common
units for the 5 day trading period prior to vesting. The phantom
units typically vest two to four years from the date of grant. In
connection with the phantom unit awards, the committee also grants tandem DERs,
which entitle the holders to receive distributions equal to the distributions
paid on our common units. Through these awards, each executive
officer’s interest is aligned with those of our unitholders in increasing our
quarterly cash distributions, our unit price and maintaining a steady growth
profile.
In 2008,
Mr. Mercer and Ms. MacAskie were each granted 25,000 phantom units, taking into
account their achievement of the goals described above at the good or excellent
level. Except as set forth in the employment agreements, we have no
set formula for granting awards to our executives or employees. In
determining whether to grant awards and the amount of any awards, our
compensation committee takes into consideration discretionary factors such as
the individual’s current and expected future performance, level of
responsibilities, retention considerations, and the total compensation
package.
Because
Messrs. Walker, Houser and Dwyer commit less than half of their business time to
us, the compensation committee believes that it is appropriate to compensate
them only through long–term incentives that will reward them in accordance with
our long–term success. Messrs. Walker, Houser ware granted 30,000 and
27,000 phantom units, respectively, to reflect their leadership roles in causing
us to reach the goals described above at the good or excellent
level.
Benefits
We
believe in a simple, straight–forward compensation program and, as such, Mr.
Mercer and Ms. MacAskie are not provided unique perquisites or other personal
benefits. Consistent with this strategy, no perquisites or other
personal benefits have or are expected to exceed $10,000 for Mr. Mercer or Ms.
MacAskie.
Through
EnerVest, we provide company benefits that we believe are standard in the
industry. These benefits consist of a group medical and dental
insurance program for employees and their qualified dependents, group life
insurance for employees and their spouses, accidental death and dismemberment
coverage for employees, a company sponsored cafeteria plan and a 401(k) employee
savings and investment plan. We match employee deferral amounts,
including amounts deferred by named executive officers, up to a total of 6% of
the employee’s eligible salary, excluding annual cash bonuses, subject to
certain regulatory limitations.
How
Elements of Our Compensation Program are Related to Each Other
We view
the various components of compensation as related but distinct and emphasize
“pay for performance” with a significant portion of total compensation
reflecting a risk aspect tied to long–term and short–term financial and
strategic goals. Our compensation philosophy is to foster
entrepreneurship at all levels of the organization by making long–term
equity–based incentives, in particular unit grants, a significant component of
executive compensation. We determine the appropriate level for each
compensation component based in part, but not exclusively, on our view of
internal equity and consistency, and other considerations we deem relevant, such
as rewarding extraordinary performance.
Our
compensation committee, however, has not adopted any formal or informal policies
or guidelines for allocating compensation between long–term and currently paid
out compensation, between cash and non–cash compensation, or among different
forms of non–cash compensation.
Accounting
and Tax Considerations
We have
structured our compensation program to comply with Internal Revenue Code
Sections 162(m) and 409A. Under Section 162(m) of the Internal
Revenue Code, a limitation was placed on tax deductions of any publicly–held
corporation for individual compensation to certain executives of such
corporation exceeding $1,000,000 in any taxable year, unless the compensation is
performance–based. If an executive is entitled to nonqualified
deferred compensation benefits that are subject to Section 409A, and such
benefits do not comply with Section 409A, then the benefits are taxable in the
first year they are not subject to a substantial risk of
forfeiture. In such case, the service provider is subject to regular
federal income tax, interest and an additional federal income tax of 20% of the
benefit includible in income. We have no employees with
non–performance based compensation paid in excess of the Internal Revenue Code
Section 162(m) tax deduction limit. However, we reserve the right to
use our judgment to authorize compensation payments that do not comply with the
exemptions in Section 162(m) when we believe that such payments are appropriate
and in the best interest of the unitholders, after taking into consideration
changing business conditions or the executive’s individual performance and/or
changes in specific job duties and responsibilities.
When the
compensation committee makes awards under the Plan, they also review the effect
the awards will have on our consolidated financial statements.
Compensation
Committee Report
We have
reviewed and discussed with management the compensation discussion and analysis
required by Item 402(b) of Regulation S–K. Based on the review and
discussion referred to above, we recommend to the board of directors that the
compensation discussion and analysis be included in this Form 10–K.
Compensation
Committee:
George
Lindhal III (Chairman)
Victor
Burk
Gary R.
Petersen
Summary
Compensation Table
The
following table sets forth certain information with respect to compensation of
our named executive officers, except for Mr. Dwyer whose compensation paid by us
was less than $100,000. We reimburse EV Management for the costs of
Mr. Mercer’s and Ms. MacAskie’s salaries and bonuses. Messrs. Walker,
Houser and Dwyer are compensated by EnerVest. We pay EnerVest a fee
under the omnibus agreement, but we do not directly reimburse EnerVest for the
costs of their salaries and bonuses.
There was
no compensation awarded to, earned by or paid to any of the named executive
officers related to option awards or non–equity incentive compensation
plans. In addition, none of the named executive officers participate
in a defined benefit pension plan.
|
Name
and Principal Position
|
Year
|
Salary
|
Bonus
(1)
|
Unit
Awards (2)
|
All
Other Compensation (3)
|
Total
|
|||||||||||||||
|
John
B. Walker
|
2008
|
$ | – | $ | – | $ | 256,986 | $ | 115,050 | $ | 372,036 | ||||||||||
|
Chief
Executive Officer
|
2007
|
– | – | 308,907 | 75,300 | 384,207 | |||||||||||||||
|
2006
|
– | – | 450,000 | – | 450,000 | ||||||||||||||||
|
Mark
A. Houser
|
2008
|
– | – | 232,751 | 101,700 | 334,451 | |||||||||||||||
|
President,
Chief Operating Officer
|
2007
|
– | – | 306,711 | 75,300 | 382,011 | |||||||||||||||
|
2006
|
– | – | 450,000 | – | 450,000 | ||||||||||||||||
|
Michael
E. Mercer
|
2008
|
223,600 | 135,000 | 173,657 | 117,675 | 649,932 | |||||||||||||||
|
Senior
Vice President, Chief Financial Officer
|
2007
|
215,000 | 135,000 | 232,983 | 117,000 | 699,983 | |||||||||||||||
|
2006
|
50,000 | 200,000 | 1,200,000 | – | 1,450,000 | ||||||||||||||||
|
Kathryn
S. MacAskie
|
2008
|
223,600 | 135,000 | 239,336 | 121,425 | 719,361 | |||||||||||||||
|
Senior
Vice President ofAcquisitions and Divestitures
|
2007
|
215,000 | 135,000 | 383,945 | 113,000 | 846,945 | |||||||||||||||
|
2006
|
43,750 | 100,000 | 1,000,000 | – | 1,143,750 | ||||||||||||||||
|
(1)
|
Represents
amounts paid in December 2008 and 2007 as bonuses for services in 2008 and
2007, respectively.
|
|
(2)
|
Represents
the dollar amounts recognized for financial statement reporting purposes
in accordance with SFAS No. 123(R) for the grants of phantom
units.
|
|
(3)
|
Represents
cash distributions received on the unvested phantom units and on the
unvested subordinated units held by EV Investors and paid to the named
executive officer as discussed under “–EV Investors” below. Any
perquisites or other personal benefits received were less than
$10,000.
|
Narrative
Disclosure to the Summary Compensation Table
Mr.
Walker
Mr.
Walker received a grant of 30,000 phantom units in December
2008. This grant vests 1/4 each in January 2010, January 2011,
January 2012 and January 2013. Mr. Walker received grants of 20,000
phantom units and 25,000 phantom units in January 2007 and December 2007,
respectively. The January 2007 grant vested 50% in January 2008 and
50% in January 2009. The December 2007 grant vested 1/3 in January
2009, with 1/3 vesting in January 2010 and 1/3 vesting in January
2011. These phantom units will vest in full upon a change of control
or a termination without cause, with good reason or upon Mr. Walker’s death or
disability.
Mr.
Houser
Mr.
Houser received a grant of 27,000 phantom units in December
2008. This grant vests 1/4 each in January 2010, January 2011,
January 2012 and January 2013. Mr. Houser received grants of 20,000
phantom units and 20,000 phantom units in January 2007 and December 2007,
respectively. The January 2007 grant vested 50% in January 2008 and
50% in January 2009. The December 2007 grant vested 1/3 in January
2009, with 1/3 vesting in January 2010 and 1/3 vesting in January
2011. These phantom units will vest in full upon a change of control
or a termination without cause, with good reason or upon Mr. Houser’s death or
disability.
Mr.
Mercer
EV
Management entered into an employment agreement with Mr. Mercer that provides
that he will act as Senior Vice President and Chief Financial Officer of EV
Management until December 31, 2009, subject to automatic one year
renewals of the term if neither party submits a notice of termination at least
sixty days prior to the end of the then–current term.
This
agreement
may be terminated by either party, at any time, subject to severance obligations
in the event Mr. Mercer is terminated by EV Management without cause or he
dies or is disabled.
Mr. Mercer’s
employment agreement provides for a minimum base salary of $200,000, subject to
upward adjustment by the compensation committee or EV Management’s board of
directors, and an annual bonus equal to a percentage of his base salary based on
the achievement of performance criteria for the applicable period, all as
determined by the compensation committee.
Mr.
Mercer received a grant of 25,000 phantom units in December
2008. This grant vests 1/4 each in January 2010, January 2011,
January 2012 and January 2013. Mr. Mercer received grants of 7,500
phantom units, 7,500 phantom units and 15,000 phantom units in January 2007,
August 2007 and December 2007, respectively. The January 2007 and
August 2007 grants vested 50% in January 2008 and 50% in January
2009. The December 2007 grant vested 1/3 in January 2009, with 1/3
vesting in January 2010 and 1/3 vesting in January 2011. These
phantom units will vest in full upon a change of control or a termination
without cause, with good reason or upon Mr. Mercer’s death or
disability.
Ms.
MacAskie
EV
Management entered into an employment agreement with Ms. MacAskie that provides
that she will act as Senior Vice President of Acquisitions and Divestitures of
EV Management until December 31, 2009, subject to automatic one year
renewals of the term if neither party submits a notice of termination at least
sixty days prior to the end of the then–current term. This agreement may
be terminated by either party, at any time, subject to severance obligations in
the event Ms. MacAskie is terminated by EV Management without cause or he
dies or is disabled.
Ms. MacAskie’s
employment agreement provides for a minimum base salary of $175,000, subject to
upward adjustment by the compensation committee or EV Management’s board of
directors, and an annual bonus equal to a percentage of her base salary based on
the achievement of performance criteria for the applicable period, all as
determined by the compensation committee.
Ms.
MacAskie received a grant of 25,000 phantom units in December
2008. This grant vests 1/4 each in January 2010, January 2011,
January 2012 and January 2013. Ms. MacAskie received grants of 12,500
phantom units, 12,500 phantom units and 15,000 phantom units in January 2007,
August 2007 and December 2007, respectively. The January 2007 and
August 2007 grants vested 50% in January 2008 and 50% in January
2009. The December 2007 grant vested 1/3 in January 2009, with 1/3
vesting in January 2010 and 1/3 vesting in January 2011. These
phantom units will vest in full upon a change of control or a termination
without cause, with good reason or upon Ms. MacAskie’s death or
disability.
Grants
of Plan–Based Awards
The
following table sets forth certain information with respect to grants of phantom
units to our named executive officers in 2008. There were no grants
of non–equity incentives, equity incentives or option awards.
|
Name
|
Grant
Date
|
All
Other Unit Awards: Number of Units (1)
|
||||
|
John
B. Walker
|
December
2008
|
30,000 | ||||
|
Mark
A. Houser
|
December
2008
|
27,000 | ||||
|
Michael
E.
Mercer
|
December
2008
|
25,000 | ||||
|
Kathryn
S. MacAskie
|
December
2008
|
25,000 | ||||
|
(1)
|
Represents
the number of units granted to each named executive officer pursuant to
the Plan and terms of certain executives’ employment
agreements.
|
Outstanding
Equity Awards at Fiscal Year End
The
following table sets forth certain information with respect to outstanding
equity awards at December 31, 2008. There were no option awards or
equity incentive plan awards outstanding.
|
Name
|
Number
of Units That Have Not Yet Vested
|
Market
Value of Units That Have Not Yet
Vested
(1)
|
||||||
|
John
B. Walker
|
10,000 | (2) | $ | 953,550 | ||||
| 25,000 | (3) | |||||||
| 30,000 | (4) | |||||||
|
Mark
A. Houser
|
10,000 | (2) | 836,190 | |||||
| 20,000 | (3) | |||||||
| 27,000 | (4) | |||||||
|
Michael
E.
Mercer
|
3,750 | (2) | 696,825 | |||||
| 3,750 | (2) | |||||||
| 15,000 | (3) | |||||||
| 25,000 | (4) | |||||||
|
Kathryn
S. MacAskie
|
6,250 | (2) | 770,175 | |||||
| 6,250 | (2) | |||||||
| 15,000 | (3) | |||||||
| 25,000 | (4) | |||||||
|
(1)
|
Based
on the closing price of our common units on December 31, 2008 of
$14.67.
|
|
(2)
|
These
phantom units vested in January
2009.
|
|
(3)
|
These
phantom units vested 1/3 in January 2009, with 1/3 vesting in January 2010
and 1/3 vesting in January 2011.
|
|
(4)
|
These
phantom units vest 1/4 each in January 2010, January 2011, January 2012
and January 2013.
|
Option
Exercises and Units Vested
The
following table sets forth certain information with respect to phantom units
vested during the year ended December 31, 2008. There were no option
awards that vested.
|
Name
|
Number
of Units
Acquired
on Vesting
(#)
|
Value
Realized on Vesting
($)
|
||||||
|
John
B. Walker
|
10,000 | $ | 297,000 | |||||
|
Mark
A. Houser
|
10,000 | 297,000 | ||||||
|
Michael
E.
Mercer
|
7,500 | 222,750 | ||||||
|
Kathryn
S. MacAskie
|
12,500 | 371,250 | ||||||
Pension
Benefits
Nonqualified
Deferred Compensation
We do not
have a nonqualified deferred compensation plan and, as such, no compensation has
been deferred by our named executive officers.
Termination
of Employment and Change–in–Control Provisions
Mr.
Mercer and Ms. MacAskie are parties to employment agreements with EV Management
which provide them with post–termination benefits in a variety of
circumstances. The amount of compensation payable in some cases may
vary depending on the nature of the termination, whether as a result of
retirement/voluntary termination, involuntary not–for–cause termination,
termination following a change of control and in the event of disability or
death of the executive. The discussion below describes the varying
amounts payable in each of these situations. It assumes, in each
case, that the officer’s termination was effective as of December 31,
2008. In presenting this disclosure, we describe amounts earned
through December 31, 2008 and, in those cases where the actual amounts to
be paid out can only be determined at the time of such executive’s separation
from EV Management, our estimates of the amounts which would be paid out to the
executives upon their termination.
Provisions
Under the Employment Agreements
Under the
employment agreements, if the executive’s employment with EV Management and its
affiliates terminates, the executive is entitled to unpaid salary for the full
month in which the termination date occurred. However, if the
executive is terminated for cause, the executive is only entitled to receive
accrued but unpaid salary through the termination date. In addition,
if the executive’s employment terminates, the executive is entitled to unpaid
vacation days for that year which have accrued through the termination date,
reimbursement of reasonable business expenses that were incurred but unpaid as
of the termination date, and COBRA coverage as required by
law. Salary and accrued vacation days are payable in cash lump sum
less applicable withholdings. Business expenses are reimbursable in
accordance with normal procedures.
If the
executive's employment is involuntarily terminated by EV Management (except for
cause or due to the death of the executive) or if the executive's employment is
terminated due to disability or retirement, EV Management is obligated to pay as
additional compensation an amount in cash equal to 104 weeks of the executive’s
base salary in effect as of the termination date. Assuming
termination as of December 31, 2008, for both Mr. Mercer and Ms. MacAskie, this
amount would have been $447,200. In addition, the executive is
entitled to continued group health plan coverage following the termination date
for the executive and the executive’s eligible spouse and dependents for the
maximum period for which such qualified beneficiaries are eligible to receive
COBRA coverage. Executive shall not be required to pay more for COBRA
coverage than officers who are then in active service for EV Management and
receiving coverage under the plan. Assuming termination as of
December 31, 2008, for Mr. Mercer, this amount would have been $27,924, and for
Ms. MacAskie this amount would have been $18,647.
In the
event an executive’s employment terminates within the 12–month period
immediately following the effective date of a change in control other than by
reason of death, disability or for cause, the executive will be entitled to
receive payment of the compensation and benefits as set forth above and to
become 100% fully vested in all unvested shares or units of equity compensation
granted as of the effective date of the change in control. Assuming a
change in control as of December 31, 2008, for Mr. Mercer, this amount would
have been $447,200 representing 104 weeks of base salary, $696,825 representing
vesting of unvested units, and $27,924 representing COBRA
coverage. For Ms. MacAskie, this amount would have been $447,200
representing 104 weeks of base salary, $770,175 representing vesting of unvested
units, and $18,647 representing COBRA coverage.
If the
compensation is paid or benefits are provided under the employment agreement by
reason of a change in control, no additional compensation will be payable or
benefits provided by reason of a subsequent change in control during the term of
the agreement.
“Cause”
generally means:
|
·
|
the
executive’s conviction by a court of competent jurisdiction as to which no
further appeal can be taken of a felony or entering the plea of nolo
contendere to such crime by the
executive;
|
|
·
|
the
commission by the executive of a demonstrable act of fraud, or a
misappropriation of funds or property, of or upon the company or any
affiliate;
|
|
·
|
the
engagement by the executive without approval of the board of directors or
compensation committee in any material activity which directly competes
with the business of the company or any affiliate or which would directly
result in a material injury to the business or reputation of the company
or any affiliate; or
|
|
·
|
the
material breach by the executive of the employment agreement, or the
repeated nonperformance of executive’s duties to the company or any
affiliate (other than by reason of illness or
incapacity).
|
In some
cases, the executive has the opportunity to cure the breach or nonperformance
before being terminated for cause.
A “change
in control" generally means the occurrence of any of following
events:
|
·
|
a
corporation, person, or group acquires, directly or indirectly, beneficial
ownership of more than 50% of the equity interests in us then entitled to
vote generally in the election of the board of directors;
or
|
|
·
|
the
withdrawal, removal or resignation of EV Management as the general partner
of our general partner or the withdrawal, removal or resignation of our
general partner as the general partner of the partnership;
or
|
|
·
|
the
effective date of a merger, consolidation, or reorganization plan that is
adopted by the board of directors of EV Management involving EV Management
in which EV Management is not the surviving entity, or a sale of all or
substantially all of our assets; or
|
|
·
|
any
other transactions or series of related transactions which have
substantially the same effect as the
foregoing.
|
“Retirement”
means the termination of the executive’s employment for normal retirement at or
after attaining age sixty-five provided that executive has been with the company
for at least five years.
Provisions
Under Phantom Unit Award Agreements
The
phantom unit award agreements provide that any unvested units will vest upon the
executive’s death, disability, termination of employment other than for cause
and upon a change of control. Assuming termination of employment or
change of control as of December 31, 2008, for Mr. Mercer, the value of the
awards would have been $696,825, and for Ms. MacAskie, the value of the awards
would have been $770,175. If the executive resigns or his or her
employment or is terminated for cause, all unvested units are
forfeited. Upon vesting, the units may be paid in cash equal to the
fair market value of the units on the date immediately preceding the vesting
date, at the option of our general partner. The definitions of the
terms such as “cause” and “change in control” in the award agreements are
substantially similar to the definitions in the employment
agreements.
EV
Investors
When EV
Properties was formed in May 2006, EV Investors was issued a limited partnership
interest in one of our predecessors. The general partner of EV
Investors is EnerVest (with a nominal interest), and the limited partners of EV
Investors are Messrs. Walker, Houser and Mercer and Ms. MacAskie. The
predecessor issued the limited partnership interest to EV Investors as incentive
compensation to Messrs. Walker, Houser and Mercer and Ms.
MacAskie. In connection with the closing of our initial public
offering in September 2006, EV Investors transferred its limited partnership
interest in the predecessor to us in exchange for 155,000 subordinated
units. Under the partnership agreement of EV Investors, the limited
partners of EV Investors will be entitled to all of the distributions
attributable to the 155,000 subordinated units held by EV Investors. In
addition, because these limited partners did not forfeit their limited
partnership interests, they had distributed to them their share of the
subordinated units. The forfeiture period terminated as to half of the
limited partnership interest on September 30, 2007 and the other half on
September 30, 2008.
The
limited partner interests in EV Investors owned by the executive officers of EV
Management and the number of subordinated units with respect to which the
executive officer receives distributions is listed below:
|
Name
|
Percent
Interest
|
Subordinated
Units
|
||||||
|
John
B. Walker
|
14.5 | % | 22,500 | |||||
|
Mark
A. Houser
|
14.5 | % | 22,500 | |||||
|
Michael
E. Mercer
|
38.7 | % | 60,000 | |||||
|
Kathryn
S. MacAskie
|
32.3 | % | 50,000 | |||||
|
Total
|
100.0 | % | 155,000 | |||||
Compensation of
Directors
We use a
combination of cash and unit–based inventive compensation to attract and retain
qualified candidates to serve on EV Management’s board. In setting
director compensation, we consider the significant amount of time that directors
expend in fulfilling their duties to us as well as the skill level we require of
members of the board.
Directors
who are not officers or employees of EV Management, EnCap or their respective
affiliates receive an annual retainer of $25,000, with the chairman of the audit
committee receiving an additional annual fee of $4,000 and the chairmen of the
compensation committee and conflicts committee receiving an additional annual
fee of $2,000. In addition, each non–employee director receives
$1,000 per committee meeting attended ($500 if by phone) and is reimbursed for
his out of pocket expenses in connection with attending
meetings. We indemnify each director for his actions associated with
being a director to the fullest extent permitted under Delaware
law.
Each of
the independent directors was awarded 2,000 phantom units in December
2008. Mr. Petersen, who is not an independent director because of his
affiliations with EnCap, was awarded 1,500 phantom units in December
2008. These phantom units vest 25% each on January 15, 2010, January
15, 2011, January 15, 2012 and January 15, 2013.
The
following table discloses the cash unit awards and other compensation earned,
paid or awarded to each of EV Management’s directors during year ended December
31, 2008:
|
Name (1)
|
Fees
Earned or
Paid
in Cash
($)
|
Unit
Awards (2)
($)
|
All
Other
Compensation
(3)
($)
|
Total
|
||||||||||||
|
Victor
Burk
|
$ | 36,000 | $ | 19,220 | $ | 5,674 | $ | 60,894 | ||||||||
|
James
R. Larson
|
37,500 | 19,220 | 5,674 | 62,394 | ||||||||||||
|
George
Lindahl III
|
35,500 | 19,220 | 5,674 | 60,394 | ||||||||||||
|
Gary
R. Petersen
|
– | 17,368 | 5,006 | 22,374 | ||||||||||||
|
(1)
|
Messrs.
Walker and Houser are not included in this table as they are employees of
EnerVest and receive no compensation for their services as
directors. Mr. Petersen is not an independent director because
of his affiliations with EnCap and does not receive a cash director’s
fee.
|
|
(2)
|
Reflects
the dollar amount recognized for financial statement reporting purposes
for the year ended December 31, 2008 in accordance with SFAS No. 123(R)
for the grants of phantom units.
|
|
(3)
|
Reflects
the dollar amount of compensation recognized for financial statement
reporting purposes for the year ended December 31, 2008 for distributions
paid on the unvested phantom units.
|
Compensation
Committee Interlocks and Insider Participation
None of
our executive officers serves as a member of the board of directors or
compensation committee of any entity that has one or more of its executive
officers serving as a member of EV Management’s board of directors or
compensation committee.
None of
the members of the compensation committee have served as an officer or employee
of us, our general partner or its general partner. Furthermore,
except for compensation arrangements discussed in this Form 10–K, we have
not
participated
in any contracts, loans, fees, awards or financial interests, direct or
indirect, with any committee member, nor are we aware of any means, directly or
indirectly, by which a committee member could receive a material benefit from
us.
Security
Ownership of Certain Beneficial Owners
Based
solely on a review of the copies of reports on Schedule 13G and amendments
thereto furnished to us, we believe that there were no beneficial owners of more
than 5% of our common or subordinated units as of March 2,
2009.
Security
Ownership of Management
The
following table sets forth the beneficial ownership of our units as of March 2,
2009 held by:
|
·
|
each
member of the Board of Directors of EV
Management
|
|
·
|
each
named executive officer of EV Management;
and
|
|
·
|
all
directors and executive officers of EV Management as a
group.
|
|
Name
of Beneficial Owner (1)
|
Common
Units Beneficially Owned
|
Percentage
of Common Units Beneficially Owned
|
Subordinated
Units Beneficially Owned
|
Percentage
of Subordinated Units Beneficially Owned
|
Percentage
of Common Units and Subordinated Units Beneficially Owned
|
|||||||||||||||
|
Officers
and Directors:
|
||||||||||||||||||||
|
John B. Walker (2)
|
584,364 | 4.5 | % | 1,806,596 | 58.3 | % | 14.7 | % | ||||||||||||
|
Mark A. Houser (3)
|
144,921 | 1.1 | % | 45,000 | 1.5 | % | 1.2 | % | ||||||||||||
|
Michael E. Mercer (4)
|
28,000 | * | 65,000 | 2.1 | % | * | ||||||||||||||
|
Kathryn S. MacAskie (5)
|
43,000 | * | 51,000 | 1.6 | % | * | ||||||||||||||
|
Frederick Dwyer
|
3,333 | * | 1,500 | * | * | |||||||||||||||
|
Victor Burk
|
4,000 | * | 1,000 | * | * | |||||||||||||||
|
James R. Larson
|
3,000 | * | – | – | * | |||||||||||||||
|
George Lindahl
III
|
49,700 | * | 4,000 | * | * | |||||||||||||||
|
Gary R. Petersen (6)
|
25,571 | * | 436,170 | 14.1 | % | 2.8 | % | |||||||||||||
|
All directors andexecutive
officers as agroup (9 persons)
|
885,889 | 6.7 | % | 2,277,666 | 73.5 | % | 19.5 | % | ||||||||||||
* Less
than 1%
|
(1)
|
Unless
otherwise indicated, the address for all beneficial owners in this table
is 1001 Fannin Street, Suite 800, Houston, TX
77002.
|
|
(2)
|
Includes
67,923 common units and 1,611,596 subordinated units owned by EnerVest and
155,000 subordinated units owned by EV
Investors. Mr. Walker, by virtue of his direct and
indirect ownership of the limited liability company that acts as
EnerVest’s general partner, may be deemed to beneficially own the common
and subordinated units beneficially owned by EnerVest, and EnerVest may be
deemed to be the beneficial owner of the subordinated units owned by EV
Investors. EnerVest, as the general partner of EV Investors,
has the power to direct the voting and disposition of the subordinated
units owned by EV Investors, and may therefore be deemed to beneficially
own such units. Mr. Walker disclaims beneficial ownership
of the units in which he does not have a pecuniary
interest.
|
|
(3)
|
Includes
22,500 subordinated units owned by EV Investors. As a limited
partner of EV Investors, Mr. Houser is entitled to distributions made
with respect to the subordinated units, and may be entitled to receive a
distribution of the subordinated units in the
future. Mr. Houser disclaims beneficial ownership of the
subordinated units owned by EV
Investors.
|
|
(4)
|
Includes
60,000 subordinated units owned by EV Investors. As a limited
partner of EV Investors, Mr. Mercer is entitled to distributions made
with respect to the subordinated units, and may be entitled to receive a
distribution of the subordinated units in the
future. Mr. Mercer disclaims beneficial ownership of the
subordinated units owned by EV
Investors.
|
|
(5)
|
Includes
1,000 common units held by a family trust of which Ms. MacAskie is a
trustee and 50,000 subordinated units owned by EV
Investors. As a limited partner of EV Investors,
Ms. MacAskie is entitled to distributions made with respect to the
subordinated units, and may be entitled to receive a distribution of the
subordinated units in the future. Ms. MacAskie disclaims
beneficial ownership of the common units held by the trust and the
subordinated units owned by EV
Investors.
|
|
(6)
|
Includes
14,279 common units and 243,350 subordinated units owned by EnCap Energy
Capital Fund V, L.P. and 11,292 common units and 192,820 subordinated
units owned by EnCap Energy Capital Fund V–B, L.P. EnCap
Equity Fund V GP, L.P., as the general partner of each of EnCap
Energy Capital Fund V, L.P. and EnCap Energy Capital Fund V–B,
L.P., EnCap Investments L.P., as the general partner of EnCap Equity
Fund V GP, L.P., EnCap Investments GP, L.L.C., as the general partner
of EnCap Investments L.P., RNBD GP LLC, as the sole member of EnCap
Investments GP, L.L.C., and David B. Miller, Gary R. Petersen, D. Martin
Phillips, and Robert L. Zorich, as the members of RNBD GP LLC may be
deemed to share voting and dispositive control over the subordinated units
and common units owned by EnCap Energy Capital Fund V, L.P. and EnCap
Energy Capital Fund V–B, L.P. Each of EnCap Equity
Fund V GP, L.P., EnCap Investments L.P., EnCap Investments GP,
L.L.C., RNBD GP LLC, David B. Miller, Gary R. Petersen, D. Martin
Phillips, and Robert L. Zorich disclaim beneficial ownership of the
reported securities in excess of such entity’s or person’s respective
pecuniary interest in the
securities.
|
Beneficial
Ownership of Our General Partner
EV
Management, the general partner of our general partner, is a limited liability
company wholly–owned by EnerVest, a limited partnership. Messrs. Jon
Rex Jones and A.V. Jones and members of EnerVest’s executive management team,
including Mr. Walker and Mr. Houser, own substantially all of the partnership
interests in EnerVest. The address for Mr. Jon Rex Jones and Mr. A.V.
Jones, and the members of EnerVest’s executive management team which own
interests in EnerVest, is 1001 Fannin Street, Suite 800, Houston, Texas
70002.
Securities
Authorized for Issuance under Equity Compensation Plans
The
following table summarizes information about our equity compensation plans as of
December 31, 2008:
|
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights
(a)
|
Weighted
average exercise price of outstanding options, warrants and
rights
(b)
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column
(a))
(c)
|
||||||||||
|
Equity
compensation plans approved by security holders
|
412,300 | – | 1,045,200 | |||||||||
|
Equity
compensation plans not approved by security holders
|
– | – | – | |||||||||
|
Total
|
412,300 | – | 1,045,200 | |||||||||
For a
description of our equity compensation plan, please see the discussion under
Item 11 above.
Ownership
in Our General Partner by the Management of EV Management and EnCap
Our
general partner, EV Energy GP, is owned 71.25% by EnerVest, 23.75% by EnCap and
5% by EV Investors. Our general partner has a 2% interest in us and
owns the incentive distribution rights, which entitle our general partner to a
portion of the distributions we make. The distributions we will make
to our general partner are described under Item 5. While
EnerVest and EV Investors are under common control with us, EnCap is
deemed our affiliate because EnCap has designated a director to the board of
directors of EV Management.
Contracts
with EnerVest and Its Affiliates
EnerVest
owns all of the limited liability interests in EV Management, the general
partner of our general partner. Messrs. Walker and Houser own
partnership interests in EnerVest. In addition, some of the employees
of EnerVest who perform services for us under the administrative services
agreement and operating agreement described below are owners of
EnerVest.
We have
entered into agreements with EnerVest. The following is a description
of those agreements.
Omnibus
Agreement
In
connection with our initial public offering, we entered into an omnibus
agreement with EnerVest, our general partner and others that addressed the
following matters:
|
·
|
our
obligation to pay EnerVest a monthly fee for providing us general and
administrative and all other services with respect to our existing
business and operations;
|
|
·
|
our
obligation to reimburse EnerVest for any insurance coverage expenses it
incurs with respect to our business and
operations; and
|
|
·
|
EnerVest’s
obligation to indemnify us for certain liabilities and our obligation to
indemnify EnerVest for certain
liabilities.
|
Pursuant
to the omnibus agreement, EnerVest performs certain centralized corporate
functions for us, such as accounting, treasury, insurance administration and
claims processing, risk management, health, safety and environmental,
information technology, human resources, credit, payroll, internal audit, taxes
and engineering and senior management oversight.
Any or
all of the provisions of the omnibus agreement, other than the indemnification
provisions described below, will be terminable by EnerVest at its option if our
general partner is removed without cause and units held by our general partner
and its affiliates are not voted in favor of that removal. The omnibus
agreement will also terminate in the event of a change of control of us, our
general partner or the general partner of our general
partner.
Under the
omnibus agreement, EnerVest indemnified us for losses attributable to title
defects, retained assets and liabilities (including any preclosing litigation
relating to assets contributed to us) and income taxes attributable to
pre–closing operations. EnerVest’s maximum liability for these
indemnification obligations will not exceed $1.5 million and EnerVest will
not have any obligation under this indemnification until our aggregate losses
exceed $200,000. We also will indemnify EnerVest for all losses
attributable to the operations of the assets contributed to us after September
29, 2006, to the extent not subject to EnerVest’s indemnification
obligations.
During
the year ended December 31, 2008, we paid EnerVest $5.5 million in monthly
administrative fees under the omnibus agreement. These fees are based
on an allocation of charges between EnerVest and us based on the estimated use
of such services by each party, and we believe that the allocation method
employed by EnerVest is reasonable and reflective of the estimated level of
costs we would have incurred on a standalone basis. The initial term
of the omnibus agreement expired on December 31, 2008. In December
2008, EV Management and EnerVest extended the term of the omnibus agreement
through 2009.
Operating
Agreements
We are
party to operating agreements under which a subsidiary of EnerVest acts as
contract operator of all wells in which we own an interest and are entitled to
appoint the operator. As contract operator, EnerVest designs and
manages the drilling and completion of our wells, and manages the day–to–day
operating and maintenance activities of our wells and facilities.
Under the
operating agreements, EnerVest establishes a joint account for each well in
which we have an interest. The joint account is charged with all
direct expenses incurred in the operation of our wells and related gathering
systems and production facilities, and we are required to pay our working
interest share of amounts charged to the joint
account. The
determination
of which direct expenses can be charged to the joint account and the manner of
charging direct expenses to the joint account for our wells is done in
accordance with the COPAS model form of accounting procedure.
Under the
COPAS model form, direct expenses include the costs of third party services
performed on our properties and well, gathering and other equipment used on our
properties. In addition, direct expenses will include the allocable
share of the cost of the EnerVest employees who perform services on our
properties. The allocation of the cost of EnerVest employees who
perform services on our properties are based on time sheets maintained by
EnerVest’s employees. Direct expenses charged to the joint account
will also include an amount determined by EnerVest to be the fair rental value
of facilities owned by EnerVest and used in the operation of our
properties.
During
the year ended December 31, 2008, we reimbursed EnerVest approximately $8.9
million for direct expenses incurred in the operation of our wells and related
gathering systems and production facilities and for the allocable share of the
costs of EnerVest employees who performed services on our
properties. As the vast majority of such expenses are charged to us
on an actual basis (i.e., no mark–up or subsidy is charged or received by
EnerVest), we believe that the aforementioned services were provided to us at
fair and reasonable rates relative to the prevailing market and are
representative of what the amounts would have been on a standalone
basis.
Purchase
of Oil and Natural Gas Properties from EnerVest and Its
Affiliates
In
September 2008, we issued 236,169 common units to EnerVest to acquire natural
gas properties in West Virginia. In September 2008, we also acquired
oil and natural gas properties in the San Juan Basin from certain institutional
partnerships managed by EnerVest for $117.4 million in cash and 908,954 of our
common units.
Director
Independence
All
members of the board of directors of EV Management, other than Messrs. Walker,
Houser and Petersen, are independent as defined under the independence standards
established by the NASDAQ. The NASDAQ does not require a listed
limited partnership like us to have a majority of independent directors on the
board of directors of our general partner.
The audit
committee of EV Management selected Deloitte & Touche LLP, an independent
registered public accounting firm, to audit our consolidated financial
statements for the year ended December 31, 2008. The audit
committee’s charter requires the audit committee to approve in advance all audit
and non–audit services to be provided by our independent registered public
accounting firm. All services reported in the audit, audit–related,
tax and all other fees categories below with respect to this Annual Report on
Form 10–K for the year ended December 31, 2008 were approved by the audit
committee.
Fees paid
to Deloitte & Touche LLP are as follows:
|
2008
|
2007
|
|||||||
|
Audit
fees (1)
|
$ | 1,025,500 | $ | 1,243,560 | ||||
|
Audit–related
fees
|
43,700 | 95,268 | ||||||
|
Tax
fees
|
– | – | ||||||
|
All
other fees
|
– | – | ||||||
|
Total
|
$ | 1,069,200 | $ | 1,338,828 | ||||
|
(1)
|
Represents
fees for professional services provided in connection with the audit of
our annual financial statements, review of our quarterly financial
statements and audits performed as part of our registration
filings.
|
|
(a)
|
List
of Documents filed as part of this
Report
|
|
|
(1)
|
Financial
Statements
|
All
financial statement of the Registrant as set forth under Item 8 of this Annual
Report on Form 10–K.
|
|
(2)
|
Financial
Statement Schedules
|
Financial
statement schedules have been omitted because they are either not required, not
applicable or the information required to be presented is included in our
consolidated financial statements and related notes.
|
|
(3)
|
Exhibits
|
The
exhibits listed below are filed or furnished as part of this
report:
|
|
2.1
|
Purchase
and Sale Agreement by and among EV Properties, L.P. and Five States Energy
Company, LLC dated November 10, 2006 (Incorporated by reference from
Exhibit 2.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed
with the SEC on November 17, 2006).
|
|
|
|
|
|
2.2
|
Purchase
and Sale Agreement by and among EV Properties, L.P. and Five States Energy
Company, LLC dated November 10, 2006 (Incorporated by reference from
Exhibit 2.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed
with the SEC on November 17, 2006).
|
|
|
2.3
|
Purchase
and Sale Agreement between EV Properties, L.P. and EnerVest Energy
Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund IX–WI,
L.P. dated January 9, 2007 (Incorporated by reference from Exhibit 2.1 to
EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC
on January 16, 2007).
|
|
|
2.4
|
Agreement
of Sale and Purchase by and among EnerVest Monroe Limited Partnership,
EnerVest Monroe Pipeline GP, L.C. and EnerVest Monroe Gathering, Ltd., as
Seller, and EnerVest Production Partners, Ltd, as Buyer, dated March 7,
2007 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners
L.P.’s current report on Form 8–K filed with the SEC on March 14,
2007).
|
|
|
2.5
|
First
Amendment to Agreement of Sale and Purchase by and among EnerVest Monroe
Limited Partnership, EnerVest Monroe Pipeline GP, L.C., EnerVest
Production Partners, Ltd and EVPP GP, LLC dated March 29, 2007
(Incorporated by reference from Exhibit 2.1 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on April 4,
2007).
|
|
|
2.6
|
Purchase
and Sale Agreement between Anadarko E&P Company LP and Kerr–McGee Oil
and Gas Onshore LP, as Seller, and EnerVest Energy Institutional Fund X–A,
L.P., EnerVest Energy Institutional Fund X–WI, L.P., EnerVest Energy
Institutional Fund XI–A, L.P., EnerVest Energy Institutional Fund XI–WI,
L.P., EnerVest Management Partners, Ltd., Wachovia Investment Holdings,
LLC and EV Properties, L.P. dated April 13, 2007 (Incorporated by
reference from Exhibit 2.3 to EV Energy Partners, L.P.’s quarterly report
on Form 10–Q filed with the SEC on August 14,
2007).
|
|
|
2.7
|
Asset
Purchase and Sale Agreement between Plantation Operating, LLC, as Seller,
and EV Properties, L.P., as Buyer, dated July 17, 2007 (Incorporated by
reference from Exhibit 2.5 to EV Energy Partners, L.P.’s quarterly report
on Form 10–Q filed with the SEC of November 14,
2007).
|
|
|
2.8
|
Agreement
of Sale and Purchase between EnerVest Appalachia, L.P., as Seller, and
EnerVest Production Partners, Ltd., as Buyer, dated November 16, 2007
(Incorporated by reference from Exhibit 2.8 to EV Energy Partners, L.P.’s
annual report on Form 10–K filed with the SEC on March 14,
2008).
|
|
|
2.9
|
Purchase
and Sale Agreement between EV Properties, L.P. and EnerVest Energy
Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund IX-WI,
L.P. dated August 11, 2008 (Incorporated by reference from Exhibit 2.1 to
EV Energy Partners L.P.’s current report on Form 8–k filed with the SEC on
November 10, 2008).
|
|
|
3.1
|
First
Amended and Restated Partnership Agreement EV Energy Partners, L.P.
(Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on October 5,
2006).
|
|
|
3.2
|
First
Amended and Restated Partnership Agreement of EV Energy GP, L.P.
(Incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on October 5,
2006).
|
|
|
3.3
|
Amended
and Restated Limited Liability Company Agreement of EV Management, LLC.
(Incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on October 5,
2006).
|
|
|
3.4
|
First
Amendment dated April 15, 2008 to First Amended and Restated Partnership
Agreement of EV Energy Partners, L.P., effective as of January 1, 2007
(Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on April 18,
2008).
|
|
|
10.1
|
Omnibus
Agreement, dated September 29, 2006, by and among EnerVest Management
Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy
Partners, L.P., and EV Properties, L.P. (Incorporated by reference from
Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K
filed with the SEC on October 5,
2006).
|
|
|
10.2
|
Contract
Operating Agreement, dated September 29, 2006, by and among EnerVest
Operating, L.L.C. and EnerVest Production Partners, L.P. (Incorporated by
reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report
on Form 8–K filed with the SEC on October 5,
2006).
|
|
|
10.3
|
Contract
Operating Agreement, dated September 29, 2006, by and among EnerVest
Operating, L.L.C. and CGAS Properties, L.P. (Incorporated by reference
from Exhibit 10.3 to EV Energy Partners, L.P.’s current report on Form 8–K
filed with the SEC on October 5, 2006).
|
| *10.4 | EV Energy Partners, L.P. Long–Term Incentive Plan (Incorporated by reference from Exhibit 10.4 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006). |
|
|
10.5
|
Contribution
Agreement, dated September 29, 2006, by and among EnerVest Management
Partners, Ltd., EVEC Holdings, LLC, EnerVest Operating, L.L.C., CGAS
Exploration, Inc., EV Investors, L.P., , EVCG GP LLC, CGAS Properties,
L.P., CGAS Holdings, LLC, EnCap Energy Capital Fund V, L.P., EnCap V-B
Acquisitions, L.P., EnCap Fund V, EV Management, LLC, EV Energy GP, L.P.,
and EV Energy Partners, L.P. (Incorporated by reference from Exhibit 10.5
to EV Energy Partners, L.P.’s current report on Form 8–K filed with the
SEC on October 5, 2006).
|
|
|
10.6
|
Credit
Agreement, dated September 29, 2006, by and among EV Properties, L.P. and
JPMorgan Chase Bank, N.A., as administrative agent for the lenders named
therein. (Incorporated by reference from Exhibit 10.6 to EV Energy
Partners, L.P.’s current report on Form 8–K filed with the SEC on October
5, 2006).
|
| *10.7 | Employment Agreement, dated October 1, 2006, by and between EV Management, LLC and Michael E. Mercer. (Incorporated by reference from Exhibit 10.7 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006). | |
| *10.8 | Employment Agreement, dated October 1, 2006, by and between EV Management, LLC and Kathryn S. MacAskie. (Incorporated by reference from Exhibit 10.8 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006). |
|
|
10.9
|
Purchase
Agreement, dated February 27, 2007, by and among EV Energy Partners, L.P.
and the Purchasers named therein (Incorporated by reference from Exhibit
10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with
the SEC on February 28, 2007).
|
| 10.10 | Registration Rights Agreement, dated February 27, 2007, by and among EV Energy Partners, L.P. and the Purchasers named therein (Incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on February 28, 2007). | |
| 10.11 | Purchase Agreement, dated June 1, 2007, by and among EV Energy Partners, L.P. and the Purchasers named therein (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on June 4, 2007). | |
| 10.12 | Registration Rights Agreement, dated June 1, 2007, by and among EV Energy Partners, L.P. and the Purchasers named therein (Incorporated by reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on June 4, 2007). | |
| 10.13 | Amended and Restated Credit Agreement dated as of October 1, 2007, among EV Energy Partners, L.P., as Parent, EV Properties, L.P., as Borrower, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders named therein (Incorporated by reference from Exhibit 10.13 to EV Energy Partners, L.P.’s annual report on Form 10–K filed with the SEC on March 14, 2008). | |
| 10.14 | First Amendment dated August 28, 2008 to Amended and Restated Credit Agreement (Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on September 4, 2008). | |
| +10.15 | Omnibus Agreement Extension, dated December 17, 2008, by and between EnerVest, Ltd. and EV Energy GP, L.P. | |
| +21.1 | Subsidiaries of EV Energy Partners, L.P. | |
| +23.1 | Consent of Cawley, Gillespie & Associates, Inc. | |
| +23.2 | Consent of Deloitte & Touche LLP. | |
| +31.1 | Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. | |
| +31.2 | Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. | |
| +32 .1 | Section 1350 Certification of Chief Executive Officer | |
| +32.2 | Section 1350 Certification of Chief Financial Officer | |
|
*
|
Management
contract or compensatory plan or
arrangement
|
|
+
|
Filed
herewith
|
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, as amended, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
EV
Energy Partners, L.P.
(Registrant)
Date: March
12, 2009
By:
/s/ MICHAEL E. MERCER
Michael
E. Mercer
Senior
Vice President and Chief Financial Officer
Pursuant
to the requirement of the Securities Exchange Act of 1934, as amended, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
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Signature
|
Title
|
Date
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||
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/s/JOHN
B. WALKER
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Chairman
and Chief Executive Officer
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March
12, 2009
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||
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John
B. Walker
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(principal
executive officer)
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|||
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/s/MARK
A. HOUSER
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President,
Chief Operating Officer and Director
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March
12, 2009
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||
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Mark
A. Houser
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||||
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/s/MICHAEL
E. MERCER
|
Senior
Vice President and Chief Financial Officer
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March
12, 2009
|
||
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Michael
E. Mercer
|
(principal
financial officer)
|
|||
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/s/FREDERICK
DWYER
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Controller
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March
12, 2009
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||
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Frederick
Dwyer
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(principal
accounting officer)
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|||
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/s/VICTOR
BURK
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Director
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March
12, 2009
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||
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Victor
Burk
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||||
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/s/JAMES
R. LARSON
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Director
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March
12, 2009
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||
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James
R. Larson
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||||
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/s/GEORGE
LINDAHL III
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Director
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March
12, 2009
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||
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George
Lindahl, III
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||||
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/s/GARY
R. PETERSEN
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Director
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March
12, 2009
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||
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Gary
R. Petersen
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||||
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2.1
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Purchase
and Sale Agreement by and among EV Properties, L.P. and Five States Energy
Company, LLC dated November 10, 2006 (Incorporated by reference from
Exhibit 2.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed
with the SEC on November 17, 2006).
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2.2
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Purchase
and Sale Agreement by and among EV Properties, L.P. and Five States Energy
Company, LLC dated November 10, 2006 (Incorporated by reference from
Exhibit 2.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed
with the SEC on November 17, 2006).
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2.3
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Purchase
and Sale Agreement between EV Properties, L.P. and EnerVest Energy
Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund IX–WI,
L.P. dated January 9, 2007 (Incorporated by reference from Exhibit 2.1 to
EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC
on January 16, 2007).
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2.4
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Agreement
of Sale and Purchase by and among EnerVest Monroe Limited Partnership,
EnerVest Monroe Pipeline GP, L.C. and EnerVest Monroe Gathering, Ltd., as
Seller, and EnerVest Production Partners, Ltd, as Buyer, dated March 7,
2007 (Incorporated by reference from Exhibit 2.1 to EV Energy Partners
L.P.’s current report on Form 8–K filed with the SEC on March 14,
2007).
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2.5
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First
Amendment to Agreement of Sale and Purchase by and among EnerVest Monroe
Limited Partnership, EnerVest Monroe Pipeline GP, L.C., EnerVest
Production Partners, Ltd and EVPP GP, LLC dated March 29, 2007
(Incorporated by reference from Exhibit 2.1 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on April 4,
2007).
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2.6
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Purchase
and Sale Agreement between Anadarko E&P Company LP and Kerr–McGee Oil
and Gas Onshore LP, as Seller, and EnerVest Energy Institutional Fund X–A,
L.P., EnerVest Energy Institutional Fund X–WI, L.P., EnerVest Energy
Institutional Fund XI–A, L.P., EnerVest Energy Institutional Fund XI–WI,
L.P., EnerVest Management Partners, Ltd., Wachovia Investment Holdings,
LLC and EV Properties, L.P. dated April 13, 2007 (Incorporated by
reference from Exhibit 2.3 to EV Energy Partners, L.P.’s quarterly report
on Form 10–Q filed with the SEC on August 14,
2007).
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2.7
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Asset
Purchase and Sale Agreement between Plantation Operating, LLC, as Seller,
and EV Properties, L.P., as Buyer, dated July 17, 2007 (Incorporated by
reference from Exhibit 2.5 to EV Energy Partners, L.P.’s quarterly report
on Form 10–Q filed with the SEC of November 14,
2007).
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2.8
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Agreement
of Sale and Purchase between EnerVest Appalachia, L.P., as Seller, and
EnerVest Production Partners, Ltd., as Buyer, dated November 16, 2007
(Incorporated by reference from Exhibit 2.8 to EV Energy Partners, L.P.’s
annual report on Form 10–K filed with the SEC on March 14,
2008).
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2.9
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Purchase
and Sale Agreement between EV Properties, L.P. and EnerVest Energy
Institutional Fund IX, L.P. and EnerVest Energy Institutional Fund IX-WI,
L.P. dated August 11, 2008 (Incorporated by reference from Exhibit 2.1 to
EV Energy Partners L.P.’s current report on Form 8–k filed with the SEC on
November 10, 2008).
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3.1
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First
Amended and Restated Partnership Agreement EV Energy Partners, L.P.
(Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on October 5,
2006).
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3.2
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First
Amended and Restated Partnership Agreement of EV Energy GP, L.P.
(Incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on October 5,
2006).
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3.3
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Amended
and Restated Limited Liability Company Agreement of EV Management, LLC.
(Incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on October 5,
2006).
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3.4
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First
Amendment dated April 15, 2008 to First Amended and Restated Partnership
Agreement of EV Energy Partners, L.P., effective as of January 1, 2007
(Incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on April 18,
2008).
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10.1
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Omnibus
Agreement, dated September 29, 2006, by and among EnerVest Management
Partners, Ltd., EV Management, LLC, EV Energy GP, L.P., EV Energy
Partners, L.P., and EV Properties, L.P. (Incorporated by reference from
Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K
filed with the SEC on October 5,
2006).
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10.2
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Contract
Operating Agreement, dated September 29, 2006, by and among EnerVest
Operating, L.L.C. and EnerVest Production Partners, L.P. (Incorporated by
reference from Exhibit 10.2 to EV Energy Partners, L.P.’s current report
on Form 8–K filed with the SEC on October 5,
2006).
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10.3
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Contract
Operating Agreement, dated September 29, 2006, by and among EnerVest
Operating, L.L.C. and CGAS Properties, L.P. (Incorporated by reference
from Exhibit 10.3 to EV Energy Partners, L.P.’s current report on Form 8–K
filed with the SEC on October 5,
2006).
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|
*10.4
|
EV
Energy Partners, L.P. Long–Term Incentive Plan (Incorporated by reference
from Exhibit 10.4 to EV Energy Partners, L.P.’s current report on Form 8–K
filed with the SEC on October 5,
2006).
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10.5
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Contribution
Agreement, dated September 29, 2006, by and among EnerVest Management
Partners, Ltd., EVEC Holdings, LLC, EnerVest Operating, L.L.C., CGAS
Exploration, Inc., EV Investors, L.P., , EVCG GP LLC, CGAS Properties,
L.P., CGAS Holdings, LLC, EnCap Energy Capital Fund V, L.P., EnCap V-B
Acquisitions, L.P., EnCap Fund V, EV Management, LLC, EV Energy GP, L.P.,
and EV Energy Partners, L.P. (Incorporated by reference from Exhibit 10.5
to EV Energy Partners, L.P.’s current report on Form 8–K filed with the
SEC on October 5, 2006).
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10.6
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Credit
Agreement, dated September 29, 2006, by and among EV Properties, L.P. and
JPMorgan Chase Bank, N.A., as administrative agent for the lenders named
therein. (Incorporated by reference from Exhibit 10.6 to EV Energy
Partners, L.P.’s current report on Form 8–K filed with the SEC on October
5, 2006).
|
|
*10.7
|
Employment
Agreement, dated October 1, 2006, by and between EV Management, LLC and
Michael E. Mercer. (Incorporated by reference from Exhibit 10.7 to EV
Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on
October 5, 2006).
|
|
*10.8
|
Employment
Agreement, dated October 1, 2006, by and between EV Management, LLC and
Kathryn S. MacAskie. (Incorporated by reference from Exhibit 10.8 to EV
Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on
October 5, 2006).
|
|
10.9
|
Purchase
Agreement, dated February 27, 2007, by and among EV Energy Partners, L.P.
and the Purchasers named therein (Incorporated by reference from Exhibit
10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with
the SEC on February 28, 2007).
|
|
10.10
|
Registration
Rights Agreement, dated February 27, 2007, by and among EV Energy
Partners, L.P. and the Purchasers named therein (Incorporated by reference
from Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8–K
filed with the SEC on February 28,
2007).
|
|
10.11
|
Purchase
Agreement, dated June 1, 2007, by and among EV Energy Partners, L.P. and
the Purchasers named therein (Incorporated by reference from Exhibit 10.1
to EV Energy Partners, L.P.’s current report on Form 8–K filed with the
SEC on June 4, 2007).
|
|
10.12
|
Registration
Rights Agreement, dated June 1, 2007, by and among EV Energy Partners,
L.P. and the Purchasers named therein (Incorporated by reference from
Exhibit 10.2 to EV Energy Partners, L.P.’s current report on Form 8–K
filed with the SEC on June 4,
2007).
|
|
10.13
|
Amended
and Restated Credit Agreement dated as of October 1, 2007, among EV Energy
Partners, L.P., as Parent, EV Properties, L.P., as Borrower, and JPMorgan
Chase Bank, N.A., as administrative agent for the lenders named therein
(Incorporated by reference from Exhibit 10.13 to EV Energy Partners,
L.P.’s annual report on Form 10–K filed with the SEC on March 14,
2008).
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10.14
|
First
Amendment dated August 28, 2008 to Amended and Restated Credit Agreement
(Incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s
current report on Form 8–K filed with the SEC on September 4,
2008).
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| +10.15 | Omnibus Agreement Extension, dated December 17, 2008, by and between EnerVest, Ltd. and EV Energy GP, L.P. |
|
Subsidiaries
of EV Energy Partners, L.P.
|
|
Consent
of Cawley, Gillespie & Associates,
Inc.
|
|
Consent
of Deloitte & Touche LLP.
|
|
Rule 13a-14(a)/15d-14(a)
Certification of Chief Executive
Officer.
|
|
Rule 13a-14(a)/15d-14(a)
Certification of Chief Financial
Officer.
|
|
Section 1350
Certification of Chief Executive
Officer
|
|
Section
1350 Certification of Chief Financial
Officer
|
|
|
|
|
*
|
Management
contract or compensatory plan or
arrangement
|
|
+
|
Filed
herewith
|