ITEM 1. BUSINESS
Overview
EV
Energy Partners, L.P. (“we,” “our,” “us” or the “Partnership”) is a publicly held
Delaware limited partnership formed in 2006. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware
limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware
limited liability company. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited
partnership. EnerVest and its affiliates have a significant interest in us through their 71.25% ownership of EV Energy GP which,
in turn, owns a 2% general partner interest in us and all of our incentive distribution rights (“IDRs”).
Our common units are
traded on the NASDAQ Global Market under the symbol “EVEP.” Our business activities are primarily conducted through
wholly owned subsidiaries.
As
of December 31, 2016, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian
Basin (which includes the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Monroe Field in Northern
Louisiana, the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin.
Oil,
natural gas and natural gas liquids reserve information is derived from our reserve reports prepared by Cawley, Gillespie &
Associates, Inc. (“Cawley Gillespie”) and Wright & Company, Inc. (“Wright”), our independent reserve
engineers. All of our proved reserves are located in the United States. The following table summarizes information about our proved
reserves by geographic region as of December 31, 2016:
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Estimated Net Proved
Reserves
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Natural Gas
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|
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Oil
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Natural Gas
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Liquids
|
|
|
|
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PV10
(1)
|
|
|
|
(MMBbls)
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|
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(Bcf)
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(MMBbls)
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|
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Bcfe
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($ in millions)
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Barnett Shale
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|
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0.4
|
|
|
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239.1
|
|
|
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21.0
|
|
|
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367.8
|
|
|
$
|
128.6
|
|
San Juan Basin
|
|
|
1.1
|
|
|
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94.9
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|
|
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7.1
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|
|
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144.0
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|
|
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46.3
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Appalachian Basin
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|
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7.2
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91.7
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|
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0.3
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|
|
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136.4
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|
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98.4
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Michigan
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-
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74.7
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0.4
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|
|
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77.8
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|
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29.1
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Central Texas
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2.4
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20.5
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2.4
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49.1
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|
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44.0
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Monroe Field
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-
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27.9
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-
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27.9
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|
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(1.2
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)
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Mid–Continent area
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1.1
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|
|
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18.9
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|
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0.4
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|
|
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27.8
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18.9
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Permian Basin
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0.4
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7.6
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1.8
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20.4
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9.5
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Total
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12.6
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|
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575.3
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33.4
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|
|
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851.2
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|
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$
|
373.6
|
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_____________
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(1)
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At December 31, 2016,
our standardized measure of discounted future net cash flows was $371.1 million. Because
we are a limited partnership, we made no provision for federal income taxes in the calculation
of standardized measure; however, we made a provision for future obligations under the
Texas gross margin tax. The present value of future net pre–tax cash flows attributable
to estimated net proved reserves, discounted at 10% per annum (“PV–10”),
is a computation of the standardized measure of discounted future net cash flows on a
pre–tax basis. PV–10 is computed on the same basis as standardized measure
but does not include a provision for federal income taxes or the Texas gross margin tax.
PV–10 is considered a non–GAAP financial measure under the regulations of
the Securities and Exchange Commission (the “SEC”). We believe PV–10
to be an important measure for evaluating the relative significance of our oil and natural
gas properties. We further believe investors and creditors may utilize our PV–10
as a basis for comparison of the relative size and value of our reserves to other companies.
PV–10, however, is not a substitute for the standardized measure. Our PV–10
measure and the standardized measure do not purport to present the fair value of our
reserves.
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The table
below provides a reconciliation of PV–10 to the standardized measure at December 31, 2016 (dollars in millions):
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Standardized measure
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$
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371.1
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|
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Future Texas gross margin taxes, discounted at 10%
|
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2.5
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PV-10
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$
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373.6
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Current Developments
Oil, natural gas and
natural gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been
volatile, and we expect them to remain volatile. In late 2014, prices for oil, natural gas and natural gas liquids declined precipitously,
and prices remained low through 2015 and most of 2016. While prices showed some improvement during the second half of 2016 and
the beginning of 2017, they have continued to fluctuate.
Factors contributing
to lower oil prices include real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle
East; lower forecasted levels of global economic growth combined with excess global supply; actions taken by the Organization
of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. Factors contributing
to lower natural gas prices include increased supplies of natural gas due to greater exploration and development activities; higher
levels of natural gas in storage; and competition from other energy sources. Prices for natural gas liquids generally correlate
to the price of oil and, accordingly, prices remain lower than historical levels and are likely to continue to directionally follow
the market for oil.
In 2016, these low
prices negatively affected our revenues, earnings and cash flows, and continued volatility in prices for oil, natural gas and
natural gas liquids could have a material adverse effect on our liquidity. Continued volatility or further declines in prices
could also have a significant adverse impact on the value and quantities of our reserves, assuming no other changes in our development
plans.
In 2016, in response
to continued lower prices, we took a number of actions to preserve our liquidity and financial flexibility, including:
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·
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repurchased
$82.7 million of our outstanding senior notes due April 2019 for $35.0 million;
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·
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reduced
the amount of capital spending we dedicated to the development of our reserves by approximately
75%;
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·
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continued
to reduce operating and capital costs;
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·
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amended
our credit facility to, among other things, ease the leverage covenants until 2018;
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continued
to evaluate strategic divestitures such as our recent Barnett Shale divestiture described
below and acquisitions of long-life, producing oil and natural gas properties; and
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·
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reevaluated
our common unit distribution policy and suspended our common unit distribution to conserve
excess cash.
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As a result of the
steps above, as of December 31, 2016, we have over $205 million of liquidity between our borrowing base capacity, cash on hand
and restricted cash. However, given current forward oil and natural gas prices and the fact that we have less production hedged
at lower prices in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve
our liquidity and financial flexibility. These steps include:
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·
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focusing
on managing and enhancing our base business through continued reductions in operating
costs;
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·
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increasing
our capital spending budget to $30 - $45 million from $10.7 million in 2016, in an effort
to maintain current production levels;
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·
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maintaining
a sufficient liquidity position to manage through the current environment, which includes
continuing to assess the appropriate distribution levels every quarter;
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·
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continuing
to evaluate strategic acquisitions of long–life, producing oil and natural gas
properties such as our Eagle Ford Acquisition described below; and
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·
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further
realizing the value of our undeveloped acreage through either alternative sources of
capital, including farmouts, production payments and joint ventures, or potential monetization
of acreage.
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During 2016, the board
of directors of EV Management announced that it had elected to suspend distributions for the first three quarters of 2016. The
board of directors also elected to suspend distributions for the fourth quarter of 2016. The company continues to generate positive
distributable cash flow, albeit at significantly lower levels than previous years. The board of directors continues to evaluate
the distribution on a quarterly basis and may elect to reinstate the distribution at the appropriate time when commodity prices
and operating cash flows have increased to a level that can support a sustainable distribution in compliance with the covenants
in our credit agreement. In order to reinstate distributions, we must be in compliance with the covenants contained in our credit
agreement. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit
agreement and expect to be in compliance through the end of 2017. Absent a rebound in commodity prices or an amendment to our
credit facility, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter
of 2018. See Item 1A. Risk Factors
- Covenants in our credit agreement may restrict our ability to resume and sustain distributions.
In December 2016,
we sold a portion of our Barnett Shale natural gas properties for $52.1 million (before post-closing adjustments),
which proceeds were deposited with a qualified intermediary to facilitate a like-kind exchange transaction pursuant to Section
1031 of the Internal Revenue Code. On January 31, 2017, we acquired a 5.8% working interest in 9,151 gross acres (529 net
acres) in Karnes County, TX for $58.7 million (before post-closing purchase price adjustments) with the proceeds and $6.6 million
of borrowings under our credit facility (the “Eagle Ford Acquisition”). Certain EnerVest institutional partnerships
own an 87% working interest in, and EnerVest acts as operator of, the properties.
Long–Term Business Strategy
One
of our primary business objectives is to manage our oil and natural gas properties for the purpose of generating sufficient excess
cash flow that will allow us to reinstate a stable distribution, which we will be able to grow over time. To meet this objective,
we intend to execute the following business strategies:
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Maximize
asset value and cash flow stability through our operating and technical expertise
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We
seek to maintain an inventory of drilling and development projects to maintain and grow our production from our capital development
program. EnerVest operates properties representing approximately 94% of our estimated net proved reserves as of December 31, 2016.
Our development program is focused on lower–risk, repeatable drilling opportunities to maintain and grow cash flow.
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·
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Maintain
focus on controlling the costs of our operations
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We focus on
controlling the operating costs of our properties. We manage our operating costs by using advanced technologies and integrating
the knowledge, expertise and experience of our management teams as well as the managerial and technical staff of EnerVest. Regarding
our non–operated properties, we proactively engage with the operators to ensure disciplined and cost focused operations
are being implemented.
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·
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Maintain
conservative levels of indebtedness to reduce risk and facilitate acquisition opportunities
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Since our
initial public offering in 2006, we have financed approximately 52% of our $2.3 billion of acquisitions with free cash flow and
the issuance of common units in public and private offerings. We seek to maintain sufficient liquidity not only for our operating
positions but also to maintain flexibility in financing our acquisitions.
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·
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Pursue
alternatives to optimize the value of our assets
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We continue to pursue a range
of alternatives to optimize the value of our assets, and we cannot at this time predict the type of transaction or transactions
into which we may enter. We may not be successful in our efforts or it may take longer to complete a transaction than we expect.
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·
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Pursue
acquisitions of long–lived producing oil and natural gas properties with relatively
low decline rates, predictable production profiles, and low– risk development opportunities
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Our acquisition
program targets oil and natural gas properties that we believe will generate attractive risk-adjusted expected rates of return
and that will be financially accretive. These acquisitions are characterized by long–lived production, relatively low decline
rates and predictable production profiles, as well as low–risk development opportunities. As part of this strategy, we continually
seek to optimize our asset portfolio, which may include the divestiture of noncore assets.
Our acquisition
efforts may involve our participation in auction processes, as well as situations in which we are the only party or one of a very
limited number of potential buyers in negotiations with the potential seller. We finance acquisitions with a combination of cash
flow from operations, borrowings under our credit facility and funds from equity and debt offerings. We also acquire interests
in properties alongside the institutional partnerships managed by EnerVest, which has allowed us to participate in much larger
acquisitions than would otherwise be available to us, and directly from institutional partnerships managed by EnerVest.
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·
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Reduce
cash flow volatility and exposure to commodity price and interest rate risk through commodity
price and interest rate derivatives
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Changes in
oil, natural gas and natural gas liquids prices may cause our revenues and cash flows to be volatile. We enter into various derivative
contracts intended to achieve more predictable cash flow and to reduce our exposure to fluctuations in the prices of oil, natural
gas and natural gas liquids. We currently maintain derivative contracts for a portion of our oil and natural gas production.
Our commodity
derivatives are primarily in the form of swaps that are designed to provide a fixed price that we will receive. Without the use
of these commodity derivatives, we would be exposed to the full range of price fluctuations. In addition, we enter into interest
rate swaps to minimize the effects of fluctuations in interest rates.
Competitive Strengths
We
believe that we are well positioned to achieve our primary business objectives and to execute our strategies because of the following
competitive strengths:
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·
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Geographically
diversified asset base characterized by long–life reserves and predictable decline
rates
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Our properties
are located in eight producing basins with an average reserve life of 15.3 years as of December 31, 2016. The majority of our
properties have been producing for many years, resulting in predictable decline rates.
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·
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Significant
inventory of low–risk development opportunities
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We have a significant inventory
of development projects in our core areas of operation. At December 31, 2016, we had 3,014 identified gross drilling locations,
of which approximately 144 were proved undeveloped drilling locations and the remainder were unproved drilling locations. In 2016,
we drilled a total of 9 gross (2.6 net) development wells with a 100% gross success rate. Our development program is focused on
lower risk drilling opportunities to maintain and increase production.
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·
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Relationship
with EnerVest
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Our relationship
with EnerVest provides us with a wide breadth of operational, financial, technical, risk management and other expertise across
a broad geographical range, which assists us in evaluating acquisition and development opportunities. In addition, we believe
that our relationship with EnerVest allows us to participate in much larger acquisitions that would not otherwise be available
to us.
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·
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Experienced
management, operating and technical teams
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Our executive
officers and key employees have on average over 25 years of experience in the oil and natural gas industry and over ten years
of experience acquiring and managing oil and natural gas properties for EnerVest partnerships.
Our Relationship
with EnerVest
Our
general partner is EV Energy GP, and its general partner is EV Management, which is a wholly owned subsidiary of EnerVest. Through
our omnibus agreement, EnerVest agrees to make available its personnel to permit us to carry on our business. We therefore benefit
from the technical expertise of EnerVest, which we believe would generally not otherwise be available to a company of our size.
EnerVest’s
principal business is to act as general partner or manager of EnerVest partnerships, formed to acquire, explore, develop and produce
oil and natural gas properties. A primary investment objective of the EnerVest partnerships is to make periodic cash distributions.
EnerVest was formed in 1992 and is one of the 25 largest oil and natural gas companies in the United States, with more than 40,000
wells across 15 states, 6.5 million acres under lease and 5.4 Tcfe of proved reserves under management.
While our relationship
with EnerVest is a significant attribute, it is also a source of potential conflicts. For example, we have acquired oil and natural
gas properties from partnerships formed by EnerVest and partnerships in which EnerVest has an interest, and we may do so in the
future. We have also acquired interests in oil and natural gas properties in conjunction with institutional partnerships managed
by EnerVest. In these acquisitions, we and the institutional partnerships managed by EnerVest each acquire an interest in all
of the properties subject to the acquisition. The purchase is allocated among us and the institutional partnerships managed by
EnerVest based on the interest acquired. In the future, it is possible that we would vary the manner in which we jointly acquire
oil and natural gas properties with the institutional partnerships managed by EnerVest.
EnerVest currently
operates oil and natural gas properties representing 94% of our proved oil and gas reserves as of December 31, 2016. The EnerVest
partnerships own interests in oil and gas properties in which we own interests. The properties are primarily located in the Barnett
Shale, Central Texas and the Appalachian Basin, and these properties represent approximately 65% of our net proved reserves at
December 31, 2016. The investment strategy of the EnerVest partnerships is to typically divest their properties in three to five
years, while our strategy contemplates holding such properties for a longer term. If the EnerVest partnerships were to sell their
interests in these properties to an entity not affiliated with EnerVest, we may not have a sufficient working interest to cause
EnerVest to remain operator of the property. The EnerVest partnerships are under no obligation to us with respect to their sale
of the properties they own.
EnerVest is not restricted
from competing with us. It may acquire, develop or dispose of oil and natural gas properties or other assets in the future without
any obligation to offer us the opportunity to purchase or participate in the development of those assets. In addition, the principal
business of the EnerVest partnerships is to acquire and develop oil and natural gas properties. The agreements for certain of
our EnerVest partnerships, however, provide that if EnerVest becomes aware, other than in its capacity as an owner of our general
partner, of acquisition opportunities that are suitable for purchase by the EnerVest partnerships during their investment periods,
EnerVest must first offer those opportunities to those EnerVest partnerships, in which case we would be offered the opportunities
only if the EnerVest partnerships chose not to pursue the acquisition. EnerVest’s obligation to offer acquisition opportunities
to its existing EnerVest partnership will not apply to acquisition opportunities which we generate internally, and EnerVest has
agreed with us that for so long as it controls our general partner it will not enter into any agreements which would limit our
ability to pursue acquisition opportunities that we generate internally.
Oil and Natural
Gas Producing Activities
At
December 31, 2016, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin
(which includes the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Monroe Field in Northern
Louisiana, the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin.
Barnett
Shale
Our
properties are primarily located in Denton, Montague, Parker, Tarrant and Wise counties in Northern Texas. Our estimated net proved
reserves as of December 31, 2016 were 367.8 Bcfe, 65% of which is natural gas. During 2016, we drilled 9 gross wells in the
Barnett Shale, which was successfully completed. EnerVest operates wells representing 98% of our estimated net proved reserves
in this area, and we own an average 26% working interest in 1,560 gross productive wells.
San Juan Basin
Our
properties are primarily located in Rio Arriba County, New Mexico and La Plata County in Colorado. Our estimated net proved reserves
as of December 31, 2016 were 144.0 Bcfe, 66% of which is natural gas. During 2016, we did not drill any wells in the
San Juan Basin. EnerVest operates wells representing 97% of our estimated net proved reserves in this area, and we own an average
77% working interest in 519 gross productive wells.
Appalachian
Basin (including the Utica Shale)
Our activities are
concentrated in the Ohio and West Virginia areas of the Appalachian Basin. Our Ohio area properties are producing primarily from
the Knox and Clinton formations and other Devonian age sands in 40 counties in Eastern Ohio and 8 counties in Western Pennsylvania.
Our West Virginia area properties are producing primarily from the Balltown, Benson and Big Injun formations in 22 counties in
North Central West Virginia. Our estimated net proved reserves as of December 31, 2016 were 136.4 Bcfe, 67% of which is natural
gas. During 2016, we did not drill any wells in the Appalachian Basin. EnerVest operates wells representing 88% of our estimated
net proved reserves in this area, and we own an average 71% working interest in 11,238 gross productive wells.
Michigan
Our properties are
located in the Antrim Shale reservoir in Otsego and Montmorency counties in northern Michigan. Our estimated net proved reserves
as of December 31, 2016 were 77.8 Bcfe, 96% of which is natural gas. During 2016, we did not drill any wells in Michigan. EnerVest
operates wells representing 99% of our estimated net proved reserves in this area, and we own an average 60% working interest
in 1,586 gross productive wells.
Central
Texas
Our
properties produce primarily from the Austin Chalk formation and are located in 16 counties in Central Texas. Our portion of the
estimated net proved reserves as of December 31, 2016 was 49.1 Bcfe, 42% of which is natural gas. During 2016, we did not drill
any wells in Central Texas. EnerVest operates wells representing 97% of our estimated net proved reserves in this area, and we
own an average 22% working interest in 1,462 gross productive wells.
Monroe Field
Our
properties are primarily located in two parishes in Northeast Louisiana. Our estimated net proved reserves as of December 31,
2016 were 27.9 Bcfe, 100% of which is natural gas. During 2016, we did not drill any wells in the Monroe Field. EnerVest operates
wells representing 100% of our estimated net proved reserves in this area, and we own an average 100% working interest in 3,244
gross productive wells.
Mid–Continent Area
Our
properties are primarily located in 43 counties in Oklahoma, 22 counties in Texas, four parishes in North Louisiana, two counties
in Kansas and six counties in Arkansas. Our estimated net proved reserves as of December 31, 2016 were 27.8 Bcfe, 68%
of which is natural gas. During 2016, we did not drill any wells in the Mid-Continent area. EnerVest operates wells representing
16% of our estimated net proved reserves in this area, and we own an average 24% working interest in 1,748 gross productive
wells.
Permian
Basin
Our
properties are primarily located in the Yates, Seven Rivers, Queen, Morrow, Clear Fork and Wichita Albany formations in four counties
in New Mexico and Texas. Our estimated net proved reserves as of December 31, 2016 were 20.4 Bcfe, 37% of which is natural gas.
During 2016, we did not drill any wells in the Permian Basin. EnerVest operates wells representing 99% of our estimated net proved
reserves in this area, and we own an average 96% working interest in 136 gross productive wells.
Our Oil, Natural
Gas and Natural Gas Liquids Data
Our Reserves
The
following table presents our estimated net proved reserves at December 31, 2016:
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|
Oil (MMBbls)
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|
|
Natural Gas
(Bcf)
|
|
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Natural Gas
Liquids
(MMBbls)
|
|
|
Bcfe
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Developed
|
|
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12.0
|
|
|
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523.1
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|
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28.2
|
|
|
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764.1
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Undeveloped
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0.6
|
|
|
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52.2
|
|
|
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5.2
|
|
|
|
87.1
|
|
Total
|
|
|
12.6
|
|
|
|
575.3
|
|
|
|
33.4
|
|
|
|
851.2
|
|
Proved
developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating
methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for recompletion. See “Glossary of Oil and Natural
Gas Terms.” All proved undeveloped locations conform to the SEC rules defining proved undeveloped locations. We do not have
any reserves that would be classified as synthetic oil or synthetic natural gas.
Our estimates of proved
reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering
data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs,
and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic
or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production
performance and material balance methods. Certain new producing properties with little production history were forecast using
a combination of production performance and analogy to offset production, both of which are believed to provide accurate forecasts.
Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or
analogy methods. These methods are believed to provide accurate forecasts due to the mature nature of the properties targeted
for development and an abundance of subsurface control data.
The
data in the above table represents estimates only. Oil, natural gas and natural gas liquids reserve engineering is inherently
a subjective process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be measured
exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation
and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and natural gas liquids that are
ultimately recovered. Please read “Item 1A. Risk Factors.”
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, without giving effect to non–property related expenses such as
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 Proved Undeveloped Reserves
We annually review
all PUDs to ensure an appropriate plan for development exists. As of December 31, 2016, none of our PUDs have remained part of
our PUD inventory for more than five years following the date they were initially classified as PUDs, except for 3.5% of our PUDs
that require sidetracks of existing producing wells, in which case the development will occur when existing production ceases.
We plan to convert our PUDs as of December 31, 2016 to proved developed reserves within five years of the date they were included
as part of our PUD inventory of drilling locations, except for the sidetracks mentioned above, by drilling 144 gross wells
at
a total estimated capital cost of $61.9 million.
At December 31, 2016,
we had 87.1 Bcfe of PUDs compared with 187.7 Bcfe of PUDs at December 31, 2015. The following table describes the changes
in our PUDs during 2016:
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|
Bcfe
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PUDs as of December 31, 2015
|
|
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187.7
|
|
Revisions of previous estimates
|
|
|
(94.8
|
)
|
Sales of minerals in place
|
|
|
(18.2
|
)
|
Extensions and discoveries
|
|
|
13.7
|
|
Converted to proved developed reserves
|
|
|
(1.3
|
)
|
PUDs as of December 31, 2016
|
|
|
87.1
|
|
The following describes
the material changes to our PUDs during 2016:
Revisions of previous
estimates
. The annual review of our PUDs for 2016 resulted in a negative revision of 94.8 Bcfe. This change from prior estimates
results from the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2016 reserve estimates
from prices used in our December 31, 2015 reserve estimates.
Sales of minerals
in place
. In December 2016, we sold oil and natural gas properties in the Barnett Shale and Austin Chalk areas. Of the 18.2
Bcfe of PUDs sold in 2016, 17.2 Bcfe were located in the Barnett Shale and the remaining 1.0 Bcfe were located in the Austin Chalk.
Extensions and
discoveries
. As we drill wells on our leases, reserves attributable to wells adjacent to the newly drilled wells may be added
as extensions and discoveries to the PUD category. Extensions and discoveries were primarily due to increases in PUDs associated
with our successful drilling activity in 2016 in the Barnett Shale and Austin Chalk. PUD additions in the Barnett Shale and Austin
Chalk totaled 13.0 Bcfe and 0.7 Bcfe, respectively. We plan to drill these new PUDs within five years of January 1, 2017.
Converted to proved
developed reserves
.
In 2016, we developed approximately 1% of our
PUD volume and 1% of our PUD locations booked as of December 31, 2015 through the drilling of 2 gross (0.6 net) development wells.
Of these reserves and wells, 1.3 Bcfe and 1 gross well are located in the Barnett Shale and the additional well and reserves are
located in the Mid-Continent area. Costs incurred relating to the development of PUDs were approximately $0.4 million during 2016.
Internal Controls Applicable to
our Reserve Estimates
Our policies and procedures
regarding internal controls over the recording of our reserves is structured to objectively and accurately estimate our reserves
quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s
regulations. Compliance with these rules and regulations is the responsibility of Terry Wagstaff, our Vice President of Acquisitions
and Engineering, who is also our principal engineer. Mr. Wagstaff has over 35 years of experience in the oil and natural gas industry,
with exposure to reserves and reserve related valuations and issues during most of this time, and is a qualified reserves estimator
(“QRE”), as defined by the standards of the Society of Petroleum Engineers. Further professional qualifications include
a Bachelor of Science in Petroleum Engineering, extensive internal and external reserve training, asset evaluation and management,
and he is a registered professional engineer in the state of Texas. In addition, our principal engineer is an active participant
in industry reserve seminars, professional industry groups, and is a member of the Society of Petroleum Engineers.
Our controls over
reserve estimates included retaining Cawley Gillespie and Wright as our independent petroleum engineers. We provided information
about our oil and natural gas properties, including production profiles, prices and costs, to Cawley Gillespie and Wright, and
they prepared their own estimates of 89% and 11%, respectively, of our reserves attributable to our properties. All of the information
regarding reserves in this annual report on Form 10–K is derived from the reports of Cawley Gillespie and Wright, which
are included as exhibits to this annual report on Form 10–K.
The principal engineer
at Cawley Gillespie responsible for preparing our reserve estimates is W. Todd Brooker, a President and Principal with Cawley
Gillespie. Mr. Brooker is a licensed professional engineer in the state of Texas (license #83462) with over 25 years of experience
in petroleum engineering. The principal engineer at Wright responsible for preparing our reserve estimates is D. Randall Wright,
the President of Wright. Mr. Wright is a licensed professional engineer in the state of Texas (license #43291) with over 43 years
of experience in petroleum engineering.
We and EnerVest maintain
an internal staff of petroleum engineers, geoscience professionals and petroleum landmen who work closely with Cawley Gillespie
and Wright to ensure the integrity, accuracy and timeliness of data furnished to Cawley Gillespie and Wright in their reserves
estimation process. Our Vice President of Acquisitions and Engineering reviews and approves the reserve information compiled by
our internal staff. Our technical team meets regularly with representatives of Cawley Gillespie and Wright to review properties
and discuss the methods and assumptions used by Cawley Gillespie and Wright in their preparation of the year end reserves estimates.
Our technical team and Vice President of Acquisitions and Engineering also meet regularly to review the methods and assumptions
used by Cawley Gillespie and Wright in their preparation of the year end reserves estimates.
The audit committee
of our board of directors meets with management, including the Vice President of Acquisitions and Engineering, to discuss matters
and policies related to our reserves.
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,
2016. 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 productive wells in which we have a working interest, 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. Operated wells are the wells operated by EnerVest in
which we own an interest.
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
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
Barnett Shale:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
12
|
|
|
|
1,301
|
|
|
|
1,313
|
|
|
|
4
|
|
|
|
385
|
|
|
|
389
|
|
Non–operated
|
|
|
12
|
|
|
|
235
|
|
|
|
247
|
|
|
|
1
|
|
|
|
10
|
|
|
|
11
|
|
San Juan Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
19
|
|
|
|
421
|
|
|
|
440
|
|
|
|
19
|
|
|
|
370
|
|
|
|
389
|
|
Non–operated
|
|
|
23
|
|
|
|
56
|
|
|
|
79
|
|
|
|
2
|
|
|
|
7
|
|
|
|
9
|
|
Appalachian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
1,798
|
|
|
|
8,299
|
|
|
|
10,097
|
|
|
|
1,732
|
|
|
|
5,982
|
|
|
|
7,714
|
|
Non–operated
|
|
|
99
|
|
|
|
1,042
|
|
|
|
1,141
|
|
|
|
30
|
|
|
|
192
|
|
|
|
222
|
|
Michigan:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
1
|
|
|
|
1,226
|
|
|
|
1,227
|
|
|
|
1
|
|
|
|
933
|
|
|
|
934
|
|
Non–operated
|
|
|
29
|
|
|
|
330
|
|
|
|
359
|
|
|
|
1
|
|
|
|
17
|
|
|
|
18
|
|
Central Texas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
614
|
|
|
|
611
|
|
|
|
1,225
|
|
|
|
158
|
|
|
|
144
|
|
|
|
302
|
|
Non–operated
|
|
|
21
|
|
|
|
216
|
|
|
|
237
|
|
|
|
1
|
|
|
|
14
|
|
|
|
15
|
|
Monroe Field:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
-
|
|
|
|
3,244
|
|
|
|
3,244
|
|
|
|
-
|
|
|
|
3,244
|
|
|
|
3,244
|
|
Non–operated
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Mid–Continent area:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
38
|
|
|
|
77
|
|
|
|
115
|
|
|
|
29
|
|
|
|
58
|
|
|
|
87
|
|
Non–operated
|
|
|
611
|
|
|
|
1,022
|
|
|
|
1,633
|
|
|
|
47
|
|
|
|
288
|
|
|
|
335
|
|
Permian Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated
|
|
|
1
|
|
|
|
132
|
|
|
|
133
|
|
|
|
1
|
|
|
|
129
|
|
|
|
130
|
|
Non–operated
|
|
|
3
|
|
|
|
-
|
|
|
|
3
|
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
Total
(1)
|
|
|
3,281
|
|
|
|
18,212
|
|
|
|
21,493
|
|
|
|
2,027
|
|
|
|
11,773
|
|
|
|
13,800
|
|
_____________
|
(1)
|
In addition, we own
small royalty interests in over 1,000 wells.
|
Our Developed
and Undeveloped Acreage
The
following table sets forth information relating to our leasehold acreage as of December 31, 2016:
|
|
Developed Acreage
|
|
|
Undeveloped Acreage
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Barnett Shale
|
|
|
146,360
|
|
|
|
38,465
|
|
|
|
14,834
|
|
|
|
3,382
|
|
San Juan Basin
|
|
|
167,064
|
|
|
|
74,193
|
|
|
|
41,222
|
|
|
|
30,339
|
|
Appalachian Basin
|
|
|
3,018,837
|
|
|
|
538,450
|
|
|
|
1,934,201
|
|
|
|
322,963
|
|
Michigan
|
|
|
103,441
|
|
|
|
67,536
|
|
|
|
4,437
|
|
|
|
1,169
|
|
Central Texas
|
|
|
792,379
|
|
|
|
106,883
|
|
|
|
13,447
|
|
|
|
2,303
|
|
Monroe Field
(1)
|
|
|
6,134
|
|
|
|
6,134
|
|
|
|
171,375
|
|
|
|
146,696
|
|
Mid–Continent area
|
|
|
392,483
|
|
|
|
57,072
|
|
|
|
10,315
|
|
|
|
493
|
|
Permian Basin
|
|
|
11,415
|
|
|
|
10,868
|
|
|
|
520
|
|
|
|
385
|
|
Total
|
|
|
4,638,113
|
|
|
|
899,601
|
|
|
|
2,190,351
|
|
|
|
507,730
|
|
_____________
|
(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 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. The acreage in which we hold interests that are not held by production are not significant to our overall
undeveloped acreage.
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 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 properties and believe that we have satisfactory title to our producing properties in
accordance with standards generally accepted in the oil and natural gas 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.
Production
by Field
The following table
sets forth our production for 2016, 2015 and 2014 from the Barnett Shale, the Appalachian Basin and the San Juan Basin, which
are the only fields during those years for which our estimated net proved reserves at December 31, 2016 attributable to the field
represented 15% or more of our total estimated net proved reserves at December 31, 2016:
|
|
Year Ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Natural
|
|
|
Gas
|
|
|
|
|
|
Natural
|
|
|
Gas
|
|
|
|
|
|
Natural
|
|
|
Gas
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Liquids
|
|
|
Oil
|
|
|
Gas
|
|
|
Liquids
|
|
|
Oil
|
|
|
Gas
|
|
|
Liquids
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBbls)
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBbls)
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale
|
|
|
39
|
|
|
|
19,936
|
|
|
|
1,320
|
|
|
|
65
|
|
|
|
22,249
|
|
|
|
1,593
|
|
|
|
100
|
|
|
|
22,569
|
|
|
|
1,642
|
|
Appalachian Basin
|
|
|
611
|
|
|
|
12,097
|
|
|
|
59
|
|
|
|
420
|
|
|
|
7,553
|
|
|
|
43
|
|
|
|
332
|
|
|
|
7,254
|
|
|
|
32
|
|
San Juan Basin
|
|
|
75
|
|
|
|
3,751
|
|
|
|
405
|
|
|
|
53
|
|
|
|
1,949
|
|
|
|
203
|
|
|
|
50
|
|
|
|
1,780
|
|
|
|
124
|
|
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 2016, 2015 and 2014,
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.
|
|
Year Ended December 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Gross wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
9.0
|
|
|
|
62.0
|
|
|
|
186.0
|
|
Dry
|
|
|
-
|
|
|
|
-
|
|
|
|
2.0
|
|
Total
|
|
|
9.0
|
|
|
|
62.0
|
|
|
|
188.0
|
|
Net wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
2.6
|
|
|
|
14.6
|
|
|
|
38.6
|
|
Dry
|
|
|
-
|
|
|
|
-
|
|
|
|
0.2
|
|
Total
|
|
|
2.6
|
|
|
|
14.6
|
|
|
|
38.8
|
|
As of December 31,
2016, we were participating in the drilling of 1 gross (0.3 net) development well.
We did not drill any
exploratory wells in 2016. We drilled three gross (1.7 net) exploratory wells in 2015, all of which were successfully completed
as producers. We drilled six gross (2.7 net) exploratory wells in 2014, four of which were successfully completed as producers.
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, Marketing Arrangements
and Delivery Commitments
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 2016, Energy
Transfer Partners, L.P., EnLink Midstream Partners, L.P. and Ergon Oil Purchasing, Inc. accounted for 18.5%,
13.4% and 10.4%, respectively, of our consolidated oil, natural gas and natural gas liquids revenues. In 2015, Energy Transfer
Partners, L.P. and EnLink Midstream Partners, L.P. accounted for 17.1% and 10.8%, respectively, of our consolidated oil,
natural gas and natural gas liquids revenues. In 2014, no customer accounted for greater than 10% of our consolidated oil,
natural gas and natural gas liquids revenues. We believe that the loss of a major customer would have a temporary effect on
our revenues but that over time, we would be able to replace our major customers.
Information regarding
our delivery commitments is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations — Contractual Obligations” contained herein.
Competition
The
oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from
major oil and natural gas 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 have delayed development drilling
and other exploitation activities and have 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 there can
be no assurances 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 primarily in certain
areas of the Appalachian Basin, the San Juan 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 drilling objectives and increase competition for equipment, supplies
and personnel during the drilling season, which could lead to shortages and increased costs or delay our operations. Generally
demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage
facilities and purchase some of their anticipated winter natural gas requirements during off–peak months. This can also
lessen seasonal demand fluctuations.
Environmental,
Health and Safety 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:
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require
the acquisition of various permits before drilling commences;
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require
the installation of pollution control equipment in connection with operations and place
other conditions on our operations;
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place
restrictions or regulations upon the use or disposal of the material utilized in our
operations;
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restrict
the types, quantities and concentrations of various substances that can be released into
the environment or used in connection with drilling, production and transportation activities;
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limit
or prohibit drilling activities on lands lying within wilderness, wetlands and other
protected areas;
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govern
gathering, transportation and marketing of oil and natural gas and pipeline and facilities
construction;
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require
remedial measures to mitigate pollution from former and ongoing operations, such as site
restoration, pit closure and plugging of abandoned wells; and
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require
the expenditure of significant amounts in connection with worker health and safety.
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These laws,
rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible.
The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently
affects profitability. Additionally, Congress and federal, 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. In general, the oil and natural
gas industry has recently been the subject of increased legislation and regulatory attention with respect to environmental matters.
The US Environmental Protection Agency (the “EPA”) has identified environmental compliance by the energy extraction
sector as one of its enforcement initiatives for fiscal years 2017 and 2019 although it is unclear about the outlook for this
initiative with the incoming administration.
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, or 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 waste generated in our operations are regulated as non–hazardous solid waste rather
than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the
handling of non–hazardous or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future.
For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several
non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria
regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent
decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March
15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination
that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the
Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt
waste is subject to more rigorous and costly disposal requirements. Any such change could result in an increase in our costs to
manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.
Comprehensive
Environmental Response, Compensation and Liability Act
The Comprehensive
Environmental Response, Compensation and Liability Act, or 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. 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 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 our 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. Comparable state statutes may not provide a comparable exemption for petroleum.
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.
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 offsite 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 CERCLA,
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.
Clean Water
Act
The Federal Water
Pollution Control Act, also known as the “Clean Water Act” and analogous state laws impose restrictions and strict
controls with respect to the discharge of pollutants, including discharges, spills and leaks of produced water and other oil and
natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited,
except in accordance with the terms of a permit issued by 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.
The EPA has issued final rules outlining
its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute
an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit
Court of Appeals in October 2015 as that appellate court and several other courts hear lawsuits opposing implementation of the
rule. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with
the federal district or appellate courts. Litigation surrounding this rule is ongoing.
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 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 cleanup and response costs.
Safe Drinking
Water Act and Hydraulic Fracturing
Hydraulic fracturing
involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate
production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level,
as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except for fracturing activities
involving the use of diesel). Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater
quality, there have been recent developments at the federal, state, regional and local levels that could result in regulation
of hydraulic fracturing becoming more stringent and costly. In December 2016, the EPA released its final report on the potential
impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with
hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for
fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or
produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids
directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or
storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it
more difficult to perform hydraulic fracturing and increase our costs of compliance and business.
Legislation was introduced
in prior sessions of Congress to provide for federal regulation of hydraulic fracturing by eliminating the current exemption in
the Safe Drinking Water Act, and, further, to require disclosure of the chemicals used in the fracturing process, but did not
pass. Also, some states and local or regional regulatory bodies have adopted, or are considering adopting, regulations that could
restrict or ban hydraulic fracturing in certain circumstances or that require disclosure of chemical in the fracturing fluids.
For example, New York has imposed a ban on hydraulic fracturing. Further, Pennsylvania has adopted a variety of regulations limiting
how and where fracturing can be performed, and Wyoming and Texas have adopted legislation requiring drilling operators conducting
hydraulic fracturing activities in that state to publicly disclose the chemicals used in the fracturing process. States have also
considered or adopted other restrictions on drilling and completion operations, including requirements regarding casing and cementing
of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical
additives that may be used in hydraulic fracturing operations. Further, the EPA has published guidance on hydraulic fracturing
using diesel and has published an advanced notice of public rulemaking under the Toxic Substances Control Act to develop regulations
governing the disclosure and evaluation of hydraulic fracturing chemicals. Further, in June 2016, the EPA published an effluent
limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction
facilities to publicly owned wastewater treatment plants. The Bureau of Land Management (“BLM”) published a final
rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but,
in June 2016 a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule,
and that decision is currently being appealed by the federal government. This litigation remains on appeal.
State and federal
regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for oil
and gas wastewater and an observed increase in minor seismic activity and tremors. When caused by human activity, such events
are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced
injection volumes or suspended operations, often voluntarily. Some state regulatory agencies have modified their regulations to
account for induced seismicity. For example, the Texas Railroad Commission rules allow it to modify, suspend, or terminate a permit
based on a determination that the permitted activity is likely to be contributing to seismic activity. Regulatory agencies are
continuing to study possible linkage between injection activity and induced seismicity.
If new laws or regulations
imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where we conduct business,
we could incur substantial compliance costs and such requirements could adversely delay or restrict our ability to conduct fracturing
activities on our assets.
Oil Pollution
Act
The primary federal
law for oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the Clean Water
Act and 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, we may be liable for costs and damages.
Air Emissions
Our operations are
subject to the federal Clean Air Act, or CAA, and analogous state laws and local ordinances governing the control of emissions
from sources of air pollution. The CAA and analogous 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 (or 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 seek injunctive relief, requiring us to forego construction, modification or operation
of certain air emission sources.
On
April 17, 2012, the EPA issued final rules to subject oil and natural gas production, storage, processing and transmission operations
to regulation under the New Source Performance Standards, or NSPS, and the National Emission Standards for Hazardous Air Pollutants,
or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS
standards for completions of hydraulically fractured natural gas wells. Beginning January 1, 2015, operators have been required
to capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The
standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized
regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators,
storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including
the installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business.
The EPA has adopted
rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing
and transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources, The
status of future regulation remains unclear but if adopted could require changes to our operations, including the installation
of new emission control equipment. Simultaneously with the methane rules, EPA adopted new rules governing the aggregating of multiple
surface sites into a single-source of air quality permitting purposes, a change which could impact the applicability of permitting
requirement to our operations and subject certain operations to additional regulatory requirements. We continuously evaluate the
effect of these rules on our operations. In late 2016, BLM adopted rules governing flaring and venting on public and tribal lands,
which could require additional equipment and emissions controls as well as inspection requirements. These rules have been challenged
in court and remain in litigation. Additionally, the US House of Representatives has passed a resolution under the Congressional
Review Act disapproving the rules; Senate action remains pending. If allowed to stand, these additional regulations on our air
emissions is likely to result in increased compliance costs and additional operating restrictions on our business.
National Environmental
Policy Act
Oil and natural gas
exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or 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. Depending on the mitigation strategies recommended
in the Environmental Assessment or Environmental Impact Statement, we could incur added costs, which may be significant. Reviews
and decisions under NEPA are also subject to protest or appeal, any or all of which may delay or halt projects. 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. In the absence of comprehensive federal legislation on GHG emission control,
the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements,
it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. Some
states, regions and localities have adopted or have considered programs to address GHG emissions. In addition, both houses of
Congress previously considered legislation to reduce emissions of greenhouse gases and many states have adopted or considered
measures to establish GHG emissions reduction levels, often involving the planned development of GHG emission inventories and/or
GHG cap and trade programs. Most of these cap and trade programs would work by requiring major sources of emissions or major producers
of fuels to acquire and surrender emission allowances. Federal efforts at a cap and trade program appear to not be moving forward
in Congress. Some members of Congress have publicly indicated an intention to introduce legislation to curb EPA’s regulatory
authority over GHGs. Depending on the regulatory reach of new CAA legislation implementing regulations or new EPA and/or state,
regional or local rules restricting the emission of GHGs, we could incur significant costs to control our emissions and comply
with regulatory requirements. In addition, the EPA has adopted a mandatory GHG emissions reporting program which imposes reporting
and monitoring requirements on various industries, including onshore and offshore oil and natural gas production facilities and
onshore oil and natural gas processing, transmission, storage and distribution facilities. Compliance with these requirements
has and is anticipated to require us to make investments in monitoring and recordkeeping equipment. We do not believe, however,
that our compliance with applicable monitoring, recordkeeping and reporting requirements under GHG reporting program as recently
amended will have a material adverse effect on our results of operations or financial position. We have submitted annual reports
for emissions starting with our 2012 GHG emissions.
The EPA has adopted
rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing
and transmission sources. Further EPA has announced its intention to regulate methane emissions from existing oil and gas sources
but the status of future regulation on existing sources remains unclear; if adopted, it could require changes to our operations,
including the installation of new emission control equipment. Simultaneously with the methane rules for new and modified sources,
EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes,
a change which could impact the applicability of permitting requirement to our operations and subject certain operations to additional
regulatory requirements. We continuously evaluate the effect of these rules on our operations.
Because of the lack
of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation
of GHGs might take place. Moreover, the federal, regional, state and local regulatory initiatives also could adversely affect
the marketability of the oil, natural gas and natural gas liquids 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.
Endangered Species
Act
The
Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed
as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect
that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct
operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered
under the act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect
the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material
restrictions to our use of the land and may materially delay or prohibit land access for oil and natural gas development. It also
may adversely impact the value of the affected leases.
OSHA and Other
Laws and Regulation
To the extent not
preempted by other applicable laws, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA,
and comparable state statutes, where applicable. 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, where applicable, 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 state statute 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, 2016, 2015 and 2014. Additionally, we are not aware of any environmental issues or claims that will require
material capital expenditures during 2017 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 or 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, local and tribal authorities. Rules and regulations affecting
the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden
and the potential for financial sanctions for noncompliance. 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.
Drilling
and Production
Statutes,
rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted,
making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes.
The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its
profitability. Our drilling and production 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:
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the
method of drilling, completing and operating wells;
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the
surface use and restoration of properties upon which wells are drilled;
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the
venting or flaring of natural gas;
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the
plugging and abandoning of wells;
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notice
to surface owners and other third parties; and
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produced
water and disposal of waste water, drilling fluids and other liquids and solids utilized
or produced in the drilling and extraction process.
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State and federal
regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural
gas between owners in a common reservoir or formation, control the amount of oil and natural gas produced by assigning allowable
rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies
that provide midstream services to us are also subject to the jurisdiction of various federal, state and local authorities, which
can affect our operations. State laws also regulate the size and shape of drilling and spacing units or proration units governing
the pooling of oil and natural gas properties and impose bonding requirements in order to drill and operate wells. Some states
have taken up consideration of forced pooling. Other states rely on voluntary pooling of lands and leases.
States generally impose
a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their respective
jurisdictions. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there
can be no assurance they will not do so in the future.
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.
If we conduct operations
on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including
various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be
conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management
(the “BLM”), Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs,
tribal or other appropriate federal, state and/or Indian tribal agencies.
The Mineral Leasing
Act of 1920 (the “Mineral Act”) prohibits ownership of any direct or indirect interest in federal onshore oil and
natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed
under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their
country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these
restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney
General. We qualify as an entity formed under the laws of the United States or of any U.S. State or territory. Although the
regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non–reciprocal
countries, there are presently no such designations in effect. It is possible that our unitholders may be citizens of foreign
countries and do not own their units in a U.S corporation or even if such interest held through a U.S. corporation, their country
of citizenship may be determined to be a non–reciprocal country under the Mineral Act. In such event, any federal onshore
oil and natural gas leases held by us could be subject to cancellation based on such determination.
Federal Regulation
of Oil, Natural Gas and Natural Gas Liquids, including Regulation of Transportation
The availability,
terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale
of natural gas are 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
as well as under Section 311 of the Natural Gas Policy Act.
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.
Sales
of our oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms,
and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC
under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate
oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of
an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates.
The
pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department
of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the
Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”)
has established a risk–based approach to determine which gathering pipelines are subject to regulation and what safety standards
regulated gathering pipelines must meet. In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline
safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas.
Transportation
of our oil, natural gas liquids and purity components (ethane, propane, butane, iso–butane, and natural gasoline) by rail
is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”)
under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and
new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation
of flammable liquids.
In addition, the U.S.
federal government has recently ended its decades–old prohibition of exports of oil produced in the lower–48 states
of the U.S. It is too recent an event to determine the impact this regulatory change may have on our operations or our sales of
oil.
Although natural gas
sales 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 oil and natural gas liquids are not currently regulated and are made at market prices.
Hydraulic Fracturing
Most of our oil and
natural gas properties are subject to hydraulic fracturing to economically develop the properties. The hydraulic fracturing process
is integral to our drilling and completion costs in these areas and typically represent up to 60% of the total drilling/completion
costs per well.
We diligently review
best practices and industry standards, and comply with all regulatory requirements in the protection of these potable water sources.
Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources
and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time,
and disposing of all non–commercially produced fluids in certified disposal wells at depths below the potable water sources.
In compliance with
laws enacted in various states, we will disclose hydraulic fracturing data to the appropriate chemical registry. These laws generally
require disclosure for each chemical ingredient that is subject to the requirements of OSHA regulations, as well as the total
volume of water used in the hydraulic fracturing treatment.
There have not been
any material incidents, citations or suits related to our hydraulic fracturing activities involving violations of environmental
laws and regulations.
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 our
unitholders.
Insurance
In accordance with
industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We
currently have insurance policies that include coverage for control of well, general liability (includes sudden and accidental
pollution), physical damage to our oil and gas natural properties, auto liability, worker's compensation and employer's liability,
among other things.
Currently, we have
general liability insurance coverage up to $1.0 million per occurrence, which includes sudden and accidental environmental liability
coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy
limits and in most cases, deductibles that must be met prior to recovery. These insurance policies are subject to certain customary
exclusions and limitations. In addition, we maintain $100.0 million in excess liability coverage, which is in addition to and
triggered if the general liability per occurrence limit is reached.
We do not currently
have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing
operations. However, we believe our general liability and excess liability insurance policies would cover third party claims related
to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.
We re–evaluate
the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry
could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable
in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain
insurance in the future at rates that we consider reasonable, and we may elect to self–insure or maintain only catastrophic
coverage for certain risks in the future.
Employees
EV
Management, the general partner of our general partner, has seven full time employees who spend a significant amount of their
time on our operations. At December 31, 2016, EnerVest, the sole member of EV Management, had approximately 1,100 full–time
employees, including over 103 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 relationship with its
employees to be good.
Offices
We do not have any
material owned or leased property (other than our interests in oil and gas properties). Under our omnibus agreement, EnerVest
provides us office space for our executive officers and other employees at EnerVest’s offices in Houston, Texas.
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.
ITEM 1A. RISK FACTORS
Limited
partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we
are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks
were actually to occur, our business, financial condition or results of operations or cash flows could be materially adversely
affected.
Risks Related
to Our Business
We may
not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including
cost reimbursements to our general partner, to enable us to resume cash distributions to holders of our common units.
We
have suspended cash distributions to the holders of our common units in order to conserve cash and improve our liquidity.
We
may not have sufficient available cash from operating surplus each quarter to enable us to resume making cash distributions under
our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we
generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
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the
amount of oil, natural gas and natural gas liquids we produce;
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the
prices at which we sell our 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 collectability of receivables; and
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prevailing
economic conditions.
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As
a result of these factors, we may not have sufficient available cash to resume our quarterly cash distributions to our common
unitholders. Even if we were able to resume a quarterly cash distribution, the amount of available cash that we
could distribute may fluctuate significantly from quarter to quarter. In order to reinstate distributions, we must be in
compliance with the covenants contained in our credit agreement. We are currently in compliance with all of the covenants
contained in the most recent ninth amendment of our credit agreement and expect to be in compliance through the end of 2017.
Absent a rebound in commodity prices or an amendment to our credit facility, we currently project that we will not be in
compliance with our leverage covenant at the end of the first quarter of 2018. See Item 1A. Risk Factors
- Covenants in
our credit agreement may restrict our ability to resume and sustain distributions
.
Covenants
in our credit agreement may restrict our ability to resume and sustain distributions.
The terms of our
credit agreement may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.
Prior to reinstating distributions, we will ensure that we are, and will continue to be, in compliance with the covenants
contained in our credit agreement. We are currently in compliance with all of the covenants contained in the most recent ninth
amendment of our credit agreement and, at current forward prices, expect to be in compliance through the end of 2017. At the end
of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to
a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we may have a total
debt to EBITDAX ratio higher than the level prescribed in the most recent ninth amendment of our credit agreement. Absent a rebound
in commodity prices, we currently project that we will not be in compliance with our leverage covenant at the end of the first
quarter of 2018, and this may require us to make payments on our debt facilities or require us to work with our bank syndicate
to amend our credit agreement. Our inability to amend our credit agreement or otherwise comply with the covenants in our credit
agreement could have a material, adverse effect on our business, including our ability to resume and sustain distributions.
Oil, natural
gas and natural gas liquids prices are highly volatile and depressed prices can significantly and adversely affect our cash flows
from operations and our ability to service our debt obligations and resume distributions on our common units.
Our
revenue, profitability and cash flow depend upon the prices for oil, natural gas and natural gas liquids. Prices for these commodities
have been depressed when compared with historical prices. The prices we receive for our production are volatile and a drop in
prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our
borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, all of which
can affect our ability to pay distributions. Changes in prices have a significant impact on the value of our reserves and on our
cash flows. Prices may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a
variety of additional factors that are beyond our control, such as:
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the
domestic and foreign supply of and demand for oil, natural gas and natural gas liquids;
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the
amount of added production from development of unconventional natural gas reserves;
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the
price and quantity of foreign imports of oil, natural gas and natural gas liquids;
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the
level of consumer product demand;
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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
recent change in federal regulations removing the longstanding prohibition of the export
of oil produced in the U.S.;
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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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Low
prices will decrease our revenues, but may also reduce the amount of oil, natural gas or natural gas liquids that we can economically
produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs,
or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting
rules may require us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties
for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to
a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be
recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future,
which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under
our credit facility, which may adversely affect our ability to make cash distributions to our unitholders and service our debt
obligations.
Low commodity prices or further
declines would have a material adverse effect on our business.
Our financial position,
results of operations, access to capital and the quantities of oil and natural gas that may be economically produced would be
negatively impacted if oil and natural gas prices decrease further or remain depressed for an extended period of time. The ways
in which such price decreases could have a material negative effect include:
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a
significant decrease in the number of wells we drill on our acreage, thereby reducing
our production and cash flows;
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a
reduction in cash flow, which would decrease funds available for capital expenditures
employed to replace reserves and maintain or increase production;
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a
decrease in future undiscounted and discounted net cash flows from producing properties,
possibly resulting in impairment expense that may be significant;
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lower
proved reserves, production and cash flow as certain reserves may no longer be economic
to produce;
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access
to sources of capital, such as equity or long–term debt markets could be severely
limited or unavailable; and
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a
reduction in the borrowing base on our credit facility.
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Future oil and natural gas price
declines may result in a write-down of our asset carrying values.
Accounting rules require
us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties in the event
we have impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in
circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated
future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write–down. During 2016,
we recorded impairment charges of approximately $131.3 million. The impairment charges during 2016 included $89.5 million related
to oil and natural gas properties in the Barnett Shale that were written down to their fair value as determined based on the sale
of these properties during December 2016. We also may incur impairment charges in the future, which could have a material adverse
effect on our results of operations in the period incurred. Since December 31, 2016, commodity prices have continued to fluctuate.
If commodity prices significantly decrease before March 31, 2017, or in future quarters, we could have additional impairments
of our oil and natural gas properties.
We may be limited in our ability
to maintain or book additional proved undeveloped reserves under the SEC’s rules.
Our estimates of our
proved reserves as of December 31, 2016 have been prepared in a manner consistent with our interpretation of the SEC rules relating
to reserve estimation and disclosure requirements for oil and natural gas companies, as well as the interpretation of our independent
petroleum consultants performing an audit of our reserve estimates. Included within these SEC reserve rules is a general requirement
that, subject to limited exceptions, PUD’s may only be classified as such if a development plan has been adopted indicating
that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional
PUD’s as we pursue our drilling program. Further, if we postpone drilling of PUD’s beyond this five-year development
horizon, whether in response to a continued depressed commodity price environment or otherwise, we may have to write off reserves
previously recognized as PUD’s. Our long–term plans may change based on commodity prices, costs or our liquidity in
a manner that would require us to reduce our proved reserve estimate in the future due to the five year development rule or otherwise.
Our identified potential drilling
locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter
the occurrence or timing of their drilling and result in changes to the amount of our proved undeveloped reserves.
As of December 31,
2016, we had over 3,014 gross identified potential drilling locations, of which approximately 1,400 were located in the Barnett
Shale and approximately 1,000 were located in the Appalachian Basin. This inventory was developed using data gathered from our
appraisal efforts and development drilling, along with offset operators drilling activities. As of December 31, 2016, we included
reserves attributable to 144 of our gross identified potential drilling locations in our proved undeveloped reserves category,
of which approximately 90 were located in the Barnett Shale. These drilling locations, including those without proved undeveloped
reserves, represent a part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties,
including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil
and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations
are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial
additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will
yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. Because
of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will
be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities
may materially differ from those presently identified, which could adversely affect our business.
The development of our proved undeveloped
reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Future development
of proved undeveloped reserves attributable to our interests in properties EnerVest does not operate will be subject to decisions
of the operator which will be beyond our control.
Approximately 10%
of our total estimated proved reserves as of December 31, 2016 were proved undeveloped reserves and may not be ultimately developed
or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations.
The reserve data included in the reserve reports of our independent petroleum engineers assume that we will have the financing
to make the substantial capital expenditures required to develop such reserves. We cannot be certain that the estimated costs
of the development of these reserves are accurate, that our projections of the ability to finance these future costs will be realized,
that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development
of our reserves, increases in costs to drill and develop such reserves or decreases in oil, natural gas or natural gas liquids
prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming
uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as
unproved reserves. In addition, the decision of the operators to develop the proved undeveloped reserves attributable to our properties
that EnerVest does not operate will be subject to the business plans and constraints of the operators of these properties, and
be beyond our control.
We currently own
interests in oil and natural gas properties in which partnerships managed by EnerVest also own an interest and we may acquire
properties in which the EnerVest managed partnerships own an interest in the future. If the EnerVest partnerships elect to sell
their interest in these properties, we would own a minority interest in the properties, and EnerVest may lose the ability to operate
the properties.
We own interests in
oil and natural gas properties in which partnerships managed by EnerVest also own interests, and we expect to make acquisitions
of properties jointly with EverVest partnerships in the future. These properties are primarily in the Barnett Shale and Central
Texas, and these properties represent approximately 49% of our estimated net proved reserves as of December 31, 2016. The EnerVest
partnerships generally have an investment strategy to typically divest properties in three to five years, while our strategy is
to hold properties for the longer term. We own less than a majority working interest in the properties in which the EnerVest partnerships
also own an interest. If the EnerVest partnerships were to sell their interest in these properties to an entity not affiliated
with EnerVest, our working interest would not be large enough that we could control the selection of the operator and EnerVest
may lose the ability to operate the properties on our behalf. Loss of operations would mean that EnerVest would no longer control
decisions regarding the development and production of those properties, and any replacement operator could make decisions regarding
development or production activities that make it difficult to implement our strategy.
We depend on EnerVest
to provide us services necessary to operate our business. If EnerVest were unable or unwilling to provide these services, it would
result in disruption in our business which could have an adverse effect on our ability to resume cash distributions to our unitholders
and service our debt obligations.
Under an omnibus agreement,
EnerVest provides services to us such as accounting, human resources, office space and other administrative services, and under
an operating agreement, EnerVest operates our properties for us. If EnerVest were to become unable or unwilling to provide such
services, we would need to develop these services internally or arrange for the services from another service provider. Developing
the capabilities internally or by retaining another service provider could have an adverse effect on our ability to resume cash
distributions to our unitholders and our business, and the services, when developed or retained, may not be of the same quality
as provided to us by EnerVest.
Our hedging transactions may limit
our gains and expose us to counterparty credit risk.
We enter into derivative
contracts from time to time to manage our exposure to fluctuations in oil, natural gas and natural gas liquids prices. These derivative
contracts limit our potential gains if prices rise above the fixed prices established by the derivative contracts. These derivative
contracts may also expose us to other risks of financial losses, for example, if our production is less than we anticipated at
the time we entered into the derivatives contract. Similarly, during periods of falling commodity prices, our derivative contracts
expose us to risk of financial loss if the counterparty to the derivative contract fails to perform its obligations under the
derivative contract (e.g., our counterparty fails to perform its obligation to make payments to us under the derivative contract
when the market (floating) price under such derivative contract falls below the specified fixed price). To mitigate counterparty
credit risk, we conduct our hedging activities with financial institutions who are lenders under our credit facility. Disruptions
in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to
perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness
or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending
upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could
incur a significant loss.
Our hedging
activities could result in financial losses or could reduce our net income, which may adversely affect our ability to pay cash
distributions to our unitholders and service our debt obligations.
To achieve more predictable
cash flows and to reduce our exposure to fluctuations in the prices of oil, natural gas and natural gas liquids, we have and may
continue to enter into hedging arrangements for a significant portion of our production. If we experience a sustained material
interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit
of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.
Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not
perform under the instrument and that we will not realize the benefit of the hedge.
Our ability to use
hedging transactions to protect us from future price declines will be dependent upon oil and natural gas prices at the time we
enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more
sensitive to commodity price changes.
Our policy has been to hedge a significant
portion of our near–term estimated production. However, our price hedging strategy and future hedging transactions will
be determined at the discretion of our general partner, which is not under an obligation to hedge a specific portion of our production.
The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these
transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging
strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely,
our hedging strategy may limit our ability to realize cash flows from commodity price increases. Relative to previous years, we
have less volumes hedged at lower prices. This makes our near-term oil, natural gas and natural gas liquids revenues more sensitive
to changes in commodity prices.
Our limited ability to hedge our
natural gas liquids production could adversely impact our net cash provided by operating activities and results of operations.
A liquid, readily
available and commercially viable market for hedging natural gas liquids has not developed in the same way that exists for oil
and natural gas. The current direct natural gas liquids hedging market is constrained in terms of price, volume, duration and
number of counterparties, which limits our ability to hedge our natural gas liquids production effectively or at all. As a result,
our net cash provided by operating activities and results of operations could be adversely impacted by fluctuations in the market
prices for natural gas liquids.
The adoption
of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge
risks associated with our business.
Title
VII of the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and
requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting
derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market.
Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant
definitions and/or exemptions still remain to be finalized.
In
one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016, a re-proposed rule
imposing position limits for certain futures and option contracts in various commodities (including crude oil and natural gas)
and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions
are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s
requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued.
Similarly, on December 2, 2016, the CFTC has re-issued a proposed rule regarding the capital a swap dealer or major swap participant
is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.
The
CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption
from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge
commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise
applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to
trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in
order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain
interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types
of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions
and other regulatory compliance obligations.
All
of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate
our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this
time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability
to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these
rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements
in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued,
the Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into
uncleared financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives
transactions. The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in
financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities
may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current
business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the
ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure
to commodity price volatility.
As
a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts
(including through requirements to post cash collateral), which could adversely affect our capital available for other commercial
operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial
derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.
If
we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile
and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally,
the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some
legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural
gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower
commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results
of operations or cash flows.
Should we fail to comply with all
applicable statutes, rules, regulations and orders administered by the CFTC or the Federal Energy Regulatory Commission (“FERC”),
we could be subject to substantial penalties and fines.
Under the Energy Policy
Act of 2005, FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the
ability to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation.
While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that
may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements.
We also must comply with the anti-market manipulation rules enforced by FERC under the NGA. Under the Commodity Exchange
Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market
manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures,
and swaps. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress,
the FERC, or the CFTC from time to time. Failure to comply with those statutes, regulations, rules and orders could subject
us to civil penalty liability.
The distressed financial conditions
of customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services
we provide.
Some of our customers
may experience, in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.
We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to
us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results
of operations or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding
or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed
by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use
of our products and services, which could have a material adverse effect on our results of operations and financial condition.
We may
be unable to integrate successfully the operations of our recent or future acquisitions with our operations and we may not realize
all the anticipated benefits of the recent acquisitions or any future acquisition.
Integration of our
recent acquisitions with our business and operations has been a complex, time consuming and costly process. Failure to successfully
assimilate our past or future acquisitions could adversely affect our financial condition and results of operations.
Our acquisitions involve
numerous risks, including:
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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 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.
Properties
that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated
with the properties or obtain protection from sellers against such liabilities, which could adversely affect our cash available
for distribution and for servicing our debt obligations.
One
of our growth strategies is to capitalize on opportunistic acquisitions of oil, natural gas and natural gas liquids reserves.
Any future acquisition will require an assessment of recoverable reserves, title, future oil, natural gas and natural gas liquids
prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar
factors. Ordinarily, our review efforts are focused on the higher valued properties and are inherently incomplete because it generally
is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and
properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar
with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and
potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity
of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material
liabilities and costs that negatively impact our financial conditions and results of operations and our ability to resume and
sustain cash distributions to our unitholders and service our debt obligations.
Additional
potential risks related to acquisitions include, among other things:
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incorrect
assumptions regarding the future prices of oil, natural gas and natural gas liquids or
the future operating or development costs of properties acquired;
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incorrect
estimates of the 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.
Unless
we replace the reserves we produce, our revenues and production will decline, which would adversely affect our cash flows from
operations and our ability to resume or sustain distributions to our unitholders or service our debt obligations.
Producing
reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors.
Our decline rate may change when we drill additional wells, make acquisitions or under other circumstances. Our future cash flows
and income and our ability to resume, maintain and increase distributions to unitholders are highly dependent on our success in
efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.
We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable
costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability
to acquire additional reserves include competition, access to capital, prevailing oil, natural gas and natural gas liquids prices
and the number and attractiveness of properties for sale.
Our estimated reserve quantities
and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these
reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.
Numerous
uncertainties are inherent in estimating quantities of our reserves. Our estimates of our net proved reserve quantities are based
upon reports from Cawley Gillespie and Wright, independent petroleum engineering firms used by us. The process of estimating oil,
natural gas and natural gas liquids reserves is complex, requiring significant decisions and assumptions in the evaluation of
available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including
assumptions regarding future oil, natural gas and natural gas liquids prices, production levels, and operating and development
costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development
expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the
results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect
our estimates of reserves, the economically recoverable quantities of oil, natural gas and natural gas liquids attributable to
any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net
cash flows. In addition, our wells are characterized by low production rates per well. As a result, changes in future production
costs assumptions could have a significant effect on our proved reserve quantities.
The
standardized measure of discounted future net cash flows of our estimated net proved reserves is not necessarily the same as the
current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net
proved reserves on average prices for the 12 months preceding the date of the estimate. Actual prices received for production
and actual costs of such production will be different than these assumptions, perhaps materially.
The
timing of both our production and our incurrence of expenses in connection with the development and production of our properties
will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition,
the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value
of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make
cash distributions to our unitholders.
Our acquisition
and development operations will require substantial capital expenditures, which will reduce our cash available for distribution.
We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production
and reserves.
The oil and natural
gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for
the development, production and acquisition of reserves. As part of our exploration and development operations, we have expanded,
and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques.
The utilization of these techniques requires substantially greater capital expenditures as compared to the drilling of a vertical
well, sometimes more than three times the cost. The incremental capital expenditures are the result of greater measured depths
and additional hydraulic fracture stages in horizontal wellbores.
Our capital expenditures
will be deducted from our revenues in determining our cash available for distribution. We intend to finance our future capital
expenditures with cash flows from operations, borrowings under our credit facility and the issuance of debt and equity securities.
The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal
on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our
cash flows from operations and access to capital are subject to a number of variables, including:
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the
estimated quantities of our reserves;
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the
amount of oil, natural gas and natural gas liquids 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, and could adversely affect our business, results of operation, financial conditions and ability
to make distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and
businesses.
We rely
on development drilling to assist in maintaining our levels of production. If our development drilling is unsuccessful, our cash
available for distributions and for servicing our debt obligations and financial condition will be adversely affected.
Part
of our business strategy has focused on maintaining production levels by drilling development wells. Although we were successful
in development drilling in the past, we cannot assure you that we will continue to maintain production levels through development
drilling, particularly in the current commodity price environment. Our drilling involves numerous risks, including the risk that
we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and
complete wells. Additionally, seismic technology does not allow us to know conclusively, prior to drilling a well, that oil or
natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible
that we will make substantial expenditures on development drilling and not discover reserves in commercially viable quantities.
These expenditures will reduce cash available for distribution to our unitholders and for servicing our debt obligations.
Our drilling operations
may be curtailed, delayed or cancelled as a result of a variety of factors, including:
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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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unusual
or unexpected geological formations;
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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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Our business strategy involves
the use of the latest available horizontal drilling, completion and production technology, which involve risks and uncertainties
in their application.
Our
operations involve the use of the latest horizontal drilling, completion and production technologies, as developed by us and our
service providers, in an effort to improve efficiencies in recovery of hydrocarbons. Use of these new technologies may not prove
successful and could result in significant cost overruns or delays or reduction in production, and in extreme cases, the abandonment
of a well. The difficulties we face drilling horizontal wells include:
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landing our
wellbore in the desired drilling zone;
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staying in
the desired drilling zone while drilling horizontally through the formation;
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running our
production casing the entire length of the wellbore; and
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running tools
and other equipment consistently through the horizontal wellbore.
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Difficulties
that we face while completing our wells include the following:
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designing and
executing the optimum fracture stimulation program for a specific target zone;
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running tools
the entire length of the wellbore during completion operations; and
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cleaning out
the wellbore after completion of the fracture stimulation.
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In addition,
certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being
shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the application
of technology developed in drilling, completing and producing in one productive formation may not be successful in other prospective
formations with little or no horizontal drilling history. If our use of the latest technologies does not prove successful, our
drilling and production results may be less than anticipated or we may experience cost overruns, delays in obtaining production
or abandonment of a well. As a result, the return on our investment will be adversely affected, we could incur material write-downs
of unevaluated properties or undeveloped reserves and the value of our undeveloped acreage and reserves could decline in the future.
We could experience periods of
higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in our area of operations. Higher
costs could reduce our profitability, cash flow and ability to pursue our drilling program as planned
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Historically,
our capital and operating costs typically rise during periods of sustained increasing oil, natural gas and NGL prices. These cost
increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of
electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that
we and our vendors rely upon; and the cost of services and labor especially those required in horizontal drilling and completion.
Since late 2014, oil and natural gas prices declined substantially resulting in decreased levels of drilling activity in the U.S.
oil and natural gas industry, including in our area of operations. This led to significantly lower costs of some drilling and
completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases
in our area of operations, these lower cost levels may not be sustainable over long periods. As a result, such costs may rise
thereby negatively impacting our profitability, cash flow and causing us to possibly reconfigure or reduce our drilling program.
We may be unable to compete effectively
with larger companies, which may adversely affect our ability to generate sufficient revenue and our ability to pay distributions
to our unitholders and service our debt obligations.
The oil and natural
gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to
acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select
suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only
drill for and produce oil, natural gas and natural gas liquids, but also carry on refining operations and market petroleum and
other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties
and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these
companies may have a greater ability to continue drilling activities during periods of low prices, to contract for drilling equipment,
to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations.
The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which
has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has
been strong in hiring experienced personnel, particularly in the accounting and financial reporting, tax and land departments.
In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and
undeveloped leases and drilling rights. We may be often outbid by competitors in our attempts to acquire properties or companies.
Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial
condition and results of operations.
Our business
is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial
condition or results of operations and, as a result, our ability to pay distributions to our unitholders and service our debt
obligations.
Our
business activities are subject to operational risks, including:
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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;
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uncontrollable
flows of oil or natural gas or well fluids; and
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surface
spillage and surface or ground water contamination from petroleum constituents or hydraulic
fracturing chemical additives.
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In
addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that are owned
by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and
processing facilities. These alternative facilities may not be available, which could cause us to shut–in our natural gas
production, or the alternative facilities could be more expensive than the facilities we currently use.
Any of these events
could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life,
damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of
wells, regulatory penalties, suspension of operations, and attorneys’ fees and other expenses incurred in the prosecution
or defense of litigation.
As is customary in
the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance
if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore
occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that
is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results
of operations and ability to pay distributions to our unitholders and service our debt obligations.
Our business depends on gathering
and compression facilities owned by third parties and transportation facilities owned by third-party transporters and we rely
on third parties to gather and deliver our oil, natural gas and NGLs to certain designated interconnects with third-party transporters.
Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere
with our ability to market the oil, natural gas and natural gas liquids we produce and could reduce our revenues and cash available
for distribution.
The marketability
of our oil, natural gas and natural gas liquids production depends in part on the availability, proximity and capacity of pipeline
systems owned by third parties in the respective operating areas. The amount of oil and natural gas that can be produced and sold
is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance,
excessive pressure, physical damage to the gathering, compression or transportation system, or lack of contracted capacity on
such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many
cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition,
some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and
transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we
may not be able to sell the oil and natural gas production from these wells until the necessary gathering and transportation systems
are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction
of necessary gathering, compression and transportation facilities, could reduce our revenues and cash available for distribution.
The third parties on whom we rely
for gathering, compression and transportation services are subject to complex federal, state and other laws and regulations that
could adversely affect the cost, manner or feasibility of doing business.
The operations of
the third parties on whom we rely for gathering, compression and transportation services are subject to complex and stringent
laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal,
state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws
and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new
laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services.
Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse
effect on our business, financial condition, results of operations and ability to resume distributions to our unitholders.
Our financial
condition and results of operations may be materially adversely affected if we incur costs and liabilities due to a failure to
comply with environmental regulations or a release of hazardous substances into the environment.
We may incur
significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering
systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental
laws and regulations, including, for example:
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the
CAA and comparable state laws and regulations that impose obligations related to emissions
of air pollutants;
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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
Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose
requirements for the handling and disposal of waste from our facilities;
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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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the
Safe Drinking Water Act and state or local laws and regulations related to hydraulic
fracturing;
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the
OPA which subjects responsible parties to liability for removal costs and damages arising
from an oil spill in waters of the U.S.;
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EPA
community right to know regulations under the Title III of CERCLA and similar state statutes
require that we organize and/or disclose information about hazardous materials used or
produced in our operations; and
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the
Endangered Species Act, which may restrict or prohibit operations in protected area.
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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, OPA and analogous state laws and regulations, impose strict joint
and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have
been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change and greenhouse
gases, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the
environment.
We are
subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility
of conducting our operations.
Our
operations are subject to complex and stringent laws and regulations, which are continuously being reviewed for amendment and/or
expansion. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous
permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining
and maintaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties,
and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding
resource conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil,
natural gas and natural gas liquids we may produce and sell.
We
are subject to, and may incur liabilities under, federal, state and local laws and regulations as interpreted and enforced by
governmental authorities possessing jurisdiction over various aspects of the exploration and production of oil, natural gas and
natural gas liquids.
For
example, several states have enacted Surface Damage Acts (“SDAs”) that are designed to compensate surface owners/users
for damages caused by mineral owners. Most SDAs contain entry notification and negotiation requirements to facilitate contact
between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users
in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness
and increase development costs. In addition, many states, including Texas, impose a production, ad valorem or severance tax with
respect to the production and sale of oil and gas within their jurisdiction.
Other
activities subject to regulation are:
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the location and spacing of wells;
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the method of drilling and completing and operating
wells;
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the rate and method of production;
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the surface use and restoration of properties upon
which wells are drilled and other exploration activities;
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notice to surface owners and other third parties;
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the venting or flaring of natural gas;
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the plugging and abandoning of wells;
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the discharge of contaminants into water and the emission
of contaminants into air;
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the disposal of fluids used or other wastes obtained
in connection with operations;
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the marketing, transportation and reporting of production;
and
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the valuation and payment of royalties.
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While
the cost of compliance with these laws has not been material to our operations in the past, the possibility exists that new laws,
regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able
to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to our unitholders and
service our debt obligations could be adversely affected.
Climate change legislation or regulations
restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil, natural gas and natural
gas liquids we produce.
The EPA requires the
reporting of GHG emissions from specified large GHG emission sources, including onshore and offshore oil and natural gas production
facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities
we operate. We began reporting emissions in 2012 for emissions occurring in 2011 and continue to report as required on an annual
basis.
More
stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses
to comply.
Both houses of Congress
previously considered legislation to reduce emissions of GHGs and many states have adopted or considered measures to reduce GHG
emission reduction levels, often involving the planned development of GHG emission inventories and/or cap and trade programs.
Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender
emission allowances. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations
on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs
associated with our operations or could adversely affect demand for the oil, natural gas and natural gas liquids that we produce.
Federal efforts at a cap and trade program appear to not be moving forward in Congress. Some members of Congress have publicly
indicated an intention to introduce legislation to curb EPA’s regulatory authority over GHGs.
In the absence of
comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although
the Supreme Court struck down the permitting requirements, it upheld EPA’s authority to control GHG emissions when a permit
is required due to emissions of other pollutants. The EPA has adopted rules to regulate methane emissions, including from new
and modified oil and gas production sources and natural gas processing and transmission sources, and has announced its intention
to regulate methane emissions from existing oil and gas sources, although it remains unclear the status of future rulemaking under
the new administration, This rule is also the subject of pending appeals. In late 2016, BLM adopted rules governing flaring and
venting on public and tribal lands, which could require additional equipment and emissions controls as well as inspection requirements.
These rules have been challenged in court and remain in litigation. Additionally, the US House of Representatives has passed a
resolution under the Congressional Review Act disapproving the rules; Senate action remains pending.
Significant physical effects of
climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant
costs in preparing for or responding to those effects.
In an interpretative
guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather
(including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects
were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects
could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production
activities either because of climate related damages to our facilities in our costs of operation potentially arising from such
climatic effects, less efficient or non–routine operating practices necessitated by climate effects or increased costs for
insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect
effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies,
service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some
or any of the damages, losses or costs that may result from potential physical effects of climate change.
Federal legislation and state and
local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating
restrictions or delays.
Hydraulic fracturing
is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from dense
rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the
formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in most
of our drilling and completion programs. Hydraulic fracturing is typically regulated by state oil and natural gas commissions
but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing
activities involving the use of diesel. In addition, in past sessions, legislation was introduced before Congress to provide for
federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in
the fracturing process. At the state level, some states, including Pennsylvania, Louisiana and Texas, where we operate, have adopted,
and other states are considering adopting, requirements that could impose more stringent permitting, public disclosure or well
construction requirements on hydraulic fracturing activities including such things as restrictions on drilling and completion
operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access
to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations.
Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit,
and in some cases impose a moratorium on, hydraulic fracturing. In the event that new or more stringent federal, state, or local
legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially
significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development,
or production activities, and perhaps even be precluded from drilling wells.
In addition, certain
governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.
The EPA has issued final rules outlining its position on the federal
jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute an expansion of federal jurisdiction
over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 as
that appellate court and several other courts hear lawsuits opposing implementation of the rule. In January 2017, the United States
Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts.
Litigation surrounding this rule is ongoing
. Further, the EPA has published guidance on hydraulic fracturing using diesel
and has published an advanced notice of public rulemaking under the Toxic Substances Control Act to develop regulations governing
the disclosure and evaluation of hydraulic fracturing chemicals. Further, in June 2016, the EPA published an effluent limit guideline
final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly
owned wastewater treatment plants. This ongoing scrutiny of hydraulic fracturing, depending on the degree of pursuit and any meaningful
results obtained, could result in further regulation of hydraulic fracturing under the federal Safe Drinking Water Act or other
regulatory programs.
We are now subject to regulation
under NSPS and NESHAPS programs, which could result in increased operating costs.
On April 17, 2012,
the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation
under the NSPS and the NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural
gas wells. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can
be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that
are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions
from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules
may require changes to our operations, including the installation of new equipment to control emissions. We continuously evaluate
the effect of new rules on our business.
Changes
in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.
Interest
rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase
accordingly. As with other yield oriented securities, our unit price is impacted by the level of our cash distributions and implied
distribution yield. The distribution yield is often used by investors to compare and rank related yield oriented securities for
investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements
of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and
our ability to issue additional equity to make acquisitions, incur debt or for other purposes.
We may
encounter obstacles to marketing our oil, natural gas and natural gas liquids, which could adversely impact our revenues.
The
marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines
and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize
is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies
that have priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and
state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.
The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be
substantial and could adversely affect our ability to produce and market oil, natural gas and natural gas liquids, the value of
our units and our ability to pay distributions on our units and service our debt obligations.
We may
experience a temporary decline in revenues and production if we lose one of our significant customers.
To the extent any
significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption
in sales of, or a lower price for, our production and our revenues and cash available for distribution could decline which could
adversely affect our ability to make cash distributions to our unitholders and service our debt obligations.
Our ability
to make cash distributions depends on our ability to successfully drill and complete wells on our properties. Seasonal weather
conditions and lease stipulations may adversely affect our ability to conduct drilling and production activities in some of the
areas where we operate.
Drilling
and producing operations in the Appalachian Basin, the San Juan Basin and Michigan are adversely affected by seasonal weather
conditions, primarily in the spring. Many municipalities in Appalachia impose weight restrictions on the paved roads that lead
to our jobsites due to the muddy conditions caused by spring thaws. In addition, our Monroe Field properties in Louisiana are
subject to flooding. This limits our access to these jobsites and our ability to service wells in these areas on a year around
basis.
The amount
of cash we have available for distribution to holders of our common units depends primarily on our cash flows and not our profitability.
The
amount of cash that we have available for distribution depends primarily upon our cash flows, including financial reserves and
cash flows from working capital, or other borrowings, and not solely on profitability, which is affected by noncash items. As
a result, we may be unable to resume the payment of distributions even when we record net income and we may be able to resume
the payment of distributions during periods when we incur net losses.
Any significant reduction in our
borrowing base under our credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively
impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our credit facility
if required as a result of a borrowing base redetermination.
Availability under
our credit facility is currently subject to a borrowing base of $450.0 million. The borrowing base is subject to scheduled semiannual
and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined
by the lenders under our credit facility, and other factors deemed relevant by our lenders. Additional declines in prices for
oil, natural gas and natural gas liquids may cause our banks to further reduce the borrowing base under our credit facility. As
of December 31, 2016, we had outstanding borrowings of $265.0 million which bore a weighted average effective interest rate of
3.75%. We intend to continue borrowing under our credit facility in the future. Any significant reduction in our borrowing base
as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our
operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow.
Further, if the outstanding borrowings under our credit facility were to exceed the borrowing base as a result of any such redetermination,
we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient
funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant
assets. Any such sale could have a material adverse effect on our business and financial results.
We have
significant indebtedness under our credit facility and our 8% senior notes due April 2019. Restrictions in our credit facility
and our 8% senior notes due April 2019 may limit our ability to resume and sustain distributions to our unitholders and may limit
our ability to capitalize on acquisitions and other business opportunities.
Our
credit facility and 8% senior notes due April 2019 contain covenants limiting our ability to make distributions, incur indebtedness,
grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates, as well as containing
covenants requiring us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may
materially adversely affect our ability to make distributions to our unitholders, react to changes in market conditions, take
advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand
a continued or future downturn in our business. We are currently in compliance with all of the covenants contained in the most
recent ninth amendment of our credit agreement and expect to be in compliance through the end of 2017. Absent a rebound in commodity
prices or an amendment to our credit facility, we currently project that we will not be in compliance with our leverage covenant
at the end of the first quarter of 2018. See Item 1A. Risk Factors –
Covenants in our credit agreement may restrict our
ability to resume and sustain distributions.
We may
incur substantial debt in the future to enable us to maintain or increase our production levels and to otherwise pursue our business
plan. This debt may restrict our ability to resume or sustain distributions to our unitholders and service our debt obligations.
Our business requires
a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile,
and we cannot predict the prices we will receive in the future. If prices were to decline for an extended period of time, if the
costs of our acquisition and development operations were to increase substantially, or if other events were to occur which reduced
our revenues or increased our costs, we may be required to borrow significant amounts in the future to enable us to finance the
expenditures necessary to replace the reserves we produce. The cost of the borrowings and our obligations to repay the borrowings
will reduce amounts otherwise available for distributions to our unitholders.
Oil and gas exploration and production
activities are complex and involves risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.
Like many oil and
gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course our business, such
as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the
ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless
of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other
personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability,
penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could
materially and adversely affect our business, operating results and financial condition. Accruals for such liabilities, penalties
or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other
proceedings could change from one period to the next, and such changes could be material.
Loss of our information and computer
systems could adversely affect our business.
We are heavily dependent
on our information systems and computer based programs, including our well operations information, seismic data, electronic data
processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware
or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce,
process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated
or computerized business activities. Any such consequence could have a material adverse effect on our business.
Cyber–attacks targeting systems
and infrastructure used by the oil and natural gas industry may adversely impact our operations.
Our business has become
increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities.
We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating
data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access
to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption,
or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and
natural gas distribution systems in the U.S. and abroad, which are necessary to transport our production to market. A cyber–attack
directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment,
delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and
settle transactions.
While we have not
experienced cyber–attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future.
Further, as cyber–attacks continue to evolve, we may be required to expend significant additional resources to continue
to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.
Risks Inherent in an Investment in
Us
The price of our units could be
subject to wide fluctuations and unitholders could lose a significant part of their investment.
From the beginning
of 2015 through the fourth quarter of 2016, the quoted market prices of our common units fluctuated from a high of $21.38 to a
low of $1.51. The market prices of our common units are subject to fluctuations in response to a number of factors, most of which
we cannot control, including, but not limited to:
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fluctuations in broader securities
market prices and volumes, particularly among securities of oil and natural gas companies
and securities of publically traded limited partnerships and limited liability companies;
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changes in general conditions
in the U.S. economy, financial markets or the oil and natural gas industry, including
fluctuations in commodity prices;
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changes in securities analysts’
recommendations and their estimates of our financial performance;
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the public’s reaction
to our press releases, announcements and our filings with the SEC;
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changes in market valuations
of similar companies;
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departures of key personnel;
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commencement of or involvement
in litigation;
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variations in our quarterly
results of operations or those of other oil and natural gas companies;
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variations in the amount
of our quarterly cash distributions; and
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future issuances and sales
of our units.
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In recent years, the
securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market
price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market
fluctuations may result in a lower price of our common units.
We do not have the same flexibility
as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.
Unlike a corporation,
our limited partnership agreement requires us to make distributions to our unitholders of all available cash reduced by any amounts
of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value
of our units may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience
a liquidity problem in the future, we may have difficulty issuing more equity to recapitalize.
EnerVest controls our general partner,
which has sole responsibility for conducting our business and managing our operations. EnerVest, EV Investors, L.P. (“EV
Investors”) and EnCap Investments, L.P. (“EnCap”), which are limited partners of our general partner, will have
conflicts of interest, which may permit them to favor their own interests to your detriment.
EnerVest
owns and controls our general partner and EnCap owns a 23.75% limited partnership interest in our general partner. Conflicts of
interest may arise between EnerVest, EnCap and their respective affiliates, including our general partner, on the one hand, and
us, our unitholders and the holders of our debt obligations, on the other hand. In resolving these conflicts of interest, our
general partner may favor its own interests and the interests of its owners over the interests of our unitholders and the holders
of our debt obligations. These conflicts include, among others, the following situations:
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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 and used to service our debt obligations;
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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. John B. Walker is Executive Chairman of EV Management and Chief Executive Officer
of EnerVest, which is in the business of acquiring oil and natural gas properties and managing the EnerVest partnerships that
are in that business. Mr. Kenneth Mariani, a director of EV Management, is also President of EnerVest. We cannot assure you
that these conflicts will be resolved in our favor. Mr. Gary R. Petersen, a director of EV Management, is also a senior managing
director of EnCap, which is in the business of investing in oil and natural gas companies with independent management which in
turn is in the business of acquiring oil and natural gas properties. Mr. Petersen is also a director of several oil and natural
gas producing entities that are in the business of acquiring oil and natural gas properties. The existing positions of these directors
and officers may give rise to fiduciary obligations that are in conflict with fiduciary obligations owed to us. The EV Management
officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as the
other entities with which they are or may be affiliated. Due to these existing and potential future affiliations with these and
other entities, they may have fiduciary obligations to present potential business opportunities to those entities prior to presenting
them to us, which could cause additional conflicts of interest. They may also decide that the opportunities are more appropriate
for other entities which they serve and elect not to present them to us.
Neither
EnerVest nor EnCap is limited in its ability to compete with us for acquisition or drilling opportunities. This could cause conflicts
of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our ability
to replace reserves, results of operations and cash available for distribution to our unitholders and for servicing our debt obligations.
Neither our partnership
agreement nor the omnibus agreement between EnerVest and us prohibits EnerVest, EnCap and their affiliates from owning assets
or engaging in businesses that compete directly or indirectly with us. For instance, EnerVest, EnCap and their respective affiliates
may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any obligation
to offer us the opportunity to purchase or develop any of those assets. Each of these entities is a large, established participant
in the energy business, and each has significantly greater resources and experience than we have, which factors may make it more
difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As
a result, competition from these entities could adversely impact our results of operations and accordingly cash available for
distribution and for servicing our debt obligations.
Cost reimbursements
due to our general partner and its affiliates for services provided may be substantial and will reduce our cash available for
distribution to our unitholders and for servicing our debt obligations.
Pursuant
to the omnibus agreement between EnerVest and us, EnerVest will receive reimbursement for the provision of various general and
administrative services for our benefit. In addition, we entered into contract operating agreements with a subsidiary of EnerVest
pursuant to which the subsidiary will be the contract operator of all of the wells for which we have the right to appoint an operator.
Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders.
In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts
and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general
partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If
we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to
make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for
distribution to our unitholders.
Our partnership
agreement limits our general partner’s fiduciary duties to holders of our common units.
Although
our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers
of EV Management, the general partner of our general partner, have a fiduciary duty to manage our general partner in a manner
beneficial to its owners. Our partnership agreement contains provisions that reduce the standards to which our general partner
and its affiliates would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general
partner and its affiliates to make a number of decisions either in their individual capacities, as opposed to in its capacity
as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner and
its affiliates to consider only the interests and factors that they desire, and they have no duty or obligation to give any consideration
to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:
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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 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.
This may result in lower distributions to holders of our common units in certain situations.
Our
general partner has the right to reset the cash target distribution levels at higher levels based on the distribution at the time
of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount
will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately
preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the
target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum
quarterly distribution amount.
In
connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B
units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible
into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units
whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive
distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order
to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common
unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when
it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive
distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions
from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the
initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the
amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner
in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights.
Holders
of our common units have limited voting rights and are not entitled to elect our general partner or the board of directors of
its general partner.
Unlike the holders
of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore,
limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner,
its general partner or the members of its board of directors, and will have no right to elect our general partner, its general
partner or its board of directors on an annual or other continuing basis. The board of directors of EV Management is chosen by
EnerVest, the sole member of EV Management. Furthermore, if the unitholders were dissatisfied with the performance of our general
partner, they will have only a limited ability to remove our general partner. As a result of these limitations, the price at which
the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Even if
holders of our common units are dissatisfied, they will have difficulty removing our general partner without its consent.
The
vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general
partner. EnerVest owns and controls our general partner, and as of February 15, 2017, officers and directors of EV Management
owned an aggregate of 10.5% of our outstanding common units. Accordingly, it may be difficult for holders of our common units
to remove our general partner.
Our partnership
agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’
voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns
20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons
who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our
partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information
about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction
of management.
Control
of our general partner may be transferred to a third party without unitholder consent.
Our
general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all
of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of
the owners of our general partner or EV Management, from transferring all or a portion of their respective ownership interest
in our general partner or EV Management to a third party. The new owners of our general partner or EV Management would then be
in a position to replace the board of directors and officers of EV Management with its own choices and thereby influence the decisions
taken by the board of directors and officers.
We may issue additional units without
your approval, which would dilute your existing ownership interests.
Our
partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without
the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank
will have the following effects:
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our
unitholders’ proportionate ownership interest in us will decrease;
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the
amount of cash available for distribution on each unit may decrease;
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the
ratio of taxable income to distributions may increase;
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the
relative voting strength of each previously outstanding unit may be diminished; and
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the
market price of the common units may decline.
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We have
the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions.
Our
partnership agreement allows us to borrow to make distributions. We may make short term borrowings under our credit facility,
which we refer to as working capital borrowings, to make distributions. The primary purpose of these borrowings would be to mitigate
the effects of short term fluctuations in our working capital that would otherwise cause volatility in our quarter to quarter
distributions.
Our partnership agreement requires
that we distribute all of our available cash, which could limit our ability to grow our reserves and production and service our
debt obligations.
Our partnership agreement
provides that we will distribute all of our available cash to our unitholders each quarter. As a result, we will be dependent
on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of
factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings,
including:
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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, natural gas and natural gas liquids.
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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 our common units, our general partner will have the right,
but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common
units held by unaffiliated persons at a price not less than their then current market price. As a result, you may be required
to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur
a tax liability upon a sale of your units.
Your liability may not be limited
if a court finds that unitholder action constitutes control of our business.
A
general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual
obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under
Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner
interests for the obligations of a limited partnership have not been clearly established in some of the other states in which
we do business. You could be liable for any and all of our obligations as if you were a general partner if:
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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 sales of our production, less operating expenditures, such as production
costs and taxes, and less estimated maintenance capital, which are generally amounts we estimate we will need to spend in the
future to maintain our production levels over the long term. Capital surplus generally means amounts we receive from non–operating
sources, such as sales of properties and issuances of debt and equity securities. Cash representing capital surplus, therefore,
is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion
to their percentage interests in us, or 98 percent to our unitholders and two percent to our general partner, and will result
in a decrease in our minimum quarterly distribution and a lower threshold for distributions on the incentive distribution rights
held by our general partner.
Our partnership agreement
allows us to add to operating surplus up to two times the amount of our most recent minimum quarterly distribution. As a result,
a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates,
as holders of incentive distribution rights, rather than to holders of common units as a return of capital.
If we
fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent
fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business
and the trading price of our units.
Effective internal
controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company.
If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot
be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls
over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under
Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered
in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting
obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information,
which would likely have a negative effect on the trading price of our units.
Tax Risks
to Common Unitholders
Our tax
treatment depends on our status as a partnership for federal income tax purposes and not being subject to a material amount of
entity–level taxation by individual states. If the Internal Revenue Service treats us as a corporation or we become subject
to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution
to our unitholders.
The anticipated after–tax
economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income
tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to
as the IRS, on this or any other tax matter affecting us.
If
we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at
the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions
to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through
to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially
reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flows and after–tax
return to the unitholders, likely causing a substantial reduction in the value of our common units.
Current
law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to
entity–level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating
ways to subject partnerships to entity–level taxation through the imposition of state income, franchise and other forms
of taxation. For example, in Texas, we are now subject to an entity level tax at a maximum effective rate of 0.7% on the portion
of our income that is apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash
available for distribution to a unitholder.
The
partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us
to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes,
the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law
on us.
An IRS
contest of our U.S. federal income tax positions may adversely affect the market for our common units, and the cost of any IRS
contest will reduce our cash available for distribution to our unitholders.
We
have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any
other matter affecting us. It may be necessary to resort to administrative or court proceedings to sustain some or all of our
counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or positions
we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they
trade. In addition, costs incurred in any contest with the IRS will be borne indirectly by our unitholders and our general partner
because the costs will reduce our cash available for distribution.
You may be required to pay taxes
on income from us even if you do not receive any cash distributions from us.
Because
our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the
cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your
share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us
equal to your share of our taxable income or even equal to the tax liability that results from that income.
Tax gain
or loss on disposition of common units could be more or less than expected.
If
you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax
basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common
unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is
sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial
portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units,
you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax–exempt
entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment
in common units by tax–exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and
non–U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations
that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income
and will be taxable to them. Distributions to non–U.S. persons will be reduced by withholding taxes at the highest
applicable effective tax rate, and non–U.S. persons will be required to file U.S. federal tax returns and pay tax on
their share of our taxable income.
We will
treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.
The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because
we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization
positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions
could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the
amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit
adjustments to your tax returns.
The sale
or exchange of 50% or more of our capital and profits interests during any twelve–month period will result in the termination
of our partnership for federal income tax purposes.
We
will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or
more of the total interests in our capital and profits within a twelve–month period. For example, an exchange of 50% of
our capital and profits could occur if, in any twelve–month period, holders of our common units sell at least 50% of the
interests in our capital and profits. Our termination would, among other things, result in the closing of our taxable year for
all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.
Unitholders
may be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing
in our common units.
In
addition to federal income taxes, you will likely be subject to other taxes, including Medicare, state and local taxes, unincorporated
business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business
or own property, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income
tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties
for failure to comply with those requirements. We own assets and do business in the states of Texas, Louisiana, Oklahoma, Arkansas,
New Mexico, Colorado, Kansas, Michigan, Ohio, West Virginia and Pennsylvania. Each of these states, other than Texas, currently
imposes a personal income tax. As we make acquisitions or expand our business, we may own assets or do business in additional
states that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns.
The tax treatment of publicly traded
partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes
and differing interpretations, possibly on a retroactive basis.
The present federal
income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative,
judicial or administrative changes and differing interpretations at any time. Specifically, from time to time, members of Congress
propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If
successful, such a proposal could eliminate the qualifying income exception to the treatment of all publicly traded partnerships
as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, it is
anticipated that the Trump administration will pass tax reform, and it is possible that such legislation could negatively impact
our U.S. federal income taxation. Any modification to the U.S. federal income tax laws may be applied retroactively and could
make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships
for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately
be enacted. Any such changes could negatively impact the value of an investment in our common units.