e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2006
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Commission File
No. 001-33016
EAGLE ROCK ENERGY PARTNERS,
L.P.
(Exact Name of Registrant as
Specified in Its Charter)
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Delaware
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68-0629883
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification Number)
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16701 Greenspoint Park Drive, Suite 200
Houston, Texas 77060
(Address of principal executive
offices, including zip code)
(281) 408-1200
(Registrants telephone
number, including area code)
14950 Heathrow Forest Parkway, Suite 111
Houston, Texas 77032
(Former name, former address and
former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Units of Limited Partner
Interests
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NASDAQ Stock Market LLC
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Exchange
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated
filer o Accelerated
Filer o Non-accelerated
Filer þ
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
As of March 29, 2007, the aggregate market value of the
registrants common units held by non-affiliates of the
registrant was $381,052,602 based on the closing sale price as
reported on NASDAQ Global Market.
The issuer had 20,691,495 common units and 21,536,046
subordinated and general partner units outstanding as of
March 30, 2007.
DOCUMENTS
INCORPORATED BY REFERENCE:
None
PART I
Our
Partnership
We are a growth-oriented Delaware limited partnership formed in
March 2006 and are engaged in the business of gathering,
compressing, treating, processing, transporting and selling
natural gas and fractionating and transporting natural gas
liquids, or NGLs. Our assets are strategically located in three
significant natural gas producing regions in the Texas
Panhandle, southeast Texas and Louisiana. We intend to acquire
and construct additional assets, and we have an experienced
management team dedicated to growing and maximizing the
profitability of our assets.
On October 24, 2006, we completed our initial public
offering, or IPO. We issued 12,500,000 common units to the
public, representing a 29.6% limited partner interest. Eagle
Rock Holdings, L.P., upon contribution of certain assets and
ownership of operating subsidiaries, received 3,459,236 common
units and 20,691,495 subordinated units, totaling an aggregate
initially of 57.2% limited partner interest (which reduced to
54.0% after the exercise of the overallotment option and
including restricted common units issued to employees in
connection with our IPO), and all of the equity interests in the
Partnerships general partner, Eagle Rock Energy GP, L.P.,
which owns a 2% general partner interest. Additional private
investors, after conversion of their ownership in Eagle Rock
Pipeline, L.P., received 4,732,259 common units, representing
initially an 11.2% limited partner interest in the Partnership
(which reduced to 10.7% after the exercise of the overallotment
option and including restricted common units issued to employees
in connection with our IPO). On November 21, 2006,
1,463,785 common units were redeemed as part of the exercise of
the underwriters overallotment option we granted in
conjunction with our IPO. In connection with the IPO, Eagle Rock
Pipeline, L.P. was merged with and into our newly formed
subsidiary with Eagle Rock Pipeline, L.P. being the surviving
entity.
The net proceeds from the offering of approximately
$219.1 million, after deducting underwriting discounts and
fees and offering expenses, were used for the following:
(i) to replenish approximately $35.0 million of
working capital distributed prior to the consummation of the
offering to the existing equity owners of Eagle Rock Pipeline,
L.P., (ii) to satisfy our obligation to reimburse Eagle
Rock Holdings and certain private investors for approximately
$173.1 million of capital expenditures incurred prior to
the IPO related to the assets contributed to the Partnership and
as partial consideration for the contribution of those assets,
and (iii) to distribute approximately $11.0 million to
Eagle Rock Holdings as a cash distribution from Eagle Rock
Pipeline, L.P. in respect of arrearages on the existing
subordinated and general partner units of Eagle Rock Pipeline,
L.P. owned by Eagle Rock Holdings. In addition, a portion of the
proceeds were used to reimburse the Partnership for transaction
costs of the offering.
As a result of the initial public offering, our current
partnership structure is such that Eagle Rock Energy G&P,
LLC is the general partner of Eagle Rock Energy GP, L.P., which
is the general partner of Eagle Rock Energy Partners, L.P. Eagle
Rock Holdings, L.P., which is owned by members of management and
private equity funds controlled by Natural Gas Partners, is the
sole member of Eagle Rock G&P, LLC.
Our Texas Panhandle operations cover ten counties in Texas and
one county in Oklahoma, consisting of our East Panhandle System
and our West Panhandle System (collectively, Texas
Panhandle Systems). The facilities that comprise our East
Panhandle System are primarily located in Wheeler, Hemphill and
Roberts Counties in the eastern Texas Panhandle and consist of:
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approximately 773 miles of natural gas gathering pipelines,
ranging from two inches to 12 inches in diameter, with
35,289 horsepower of associated pipeline compression;
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three active natural gas processing plants with an aggregate
capacity of 90 MMcf/d; and
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two natural gas treating facilities with an aggregate capacity
of 75 MMcf/d.
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The facilities that comprise our West Panhandle System are
primarily located in Moore, Potter, Hutchinson, Carson, Roberts,
Gray, Wheeler and Collingsworth Counties in the western Texas
Panhandle and consist of:
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approximately 2,736 miles of natural gas gathering
pipelines, ranging from two inches to 12 inches in
diameter, with 81,473 horsepower of associated pipeline
compression;
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four active natural gas processing plants with an aggregate
capacity of 101 MMcf/d;
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three natural gas treating facilities with an aggregate capacity
of 65 MMcf/d;
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a propane fractionation facility with capacity of
1,000 Bbls/d; and
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a condensate collection facility.
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Our southeast Texas and Louisiana operations (Texas and
Louisiana System) are primarily located in Polk, Tyler,
Jasper and Newton counties, Texas and Vernon Parish, Louisiana.
The facilities that comprise our southeast Texas and Louisiana
System consist of:
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approximately 1,049 miles of natural gas gathering
pipelines, ranging from four inches to 12 inches in
diameter, with 5,200 horsepower of associated pipeline
compression;
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a 100 MMcf/d cryogenic processing plant;
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a 150 MMcf/d cryogenic processing plant, in which we own a
25% undivided interest; and
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a 19-mile
NGL pipeline.
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We commenced operations in 2002 when certain members of our
management team formed Eagle Rock Energy, Inc., an affiliate of
our predecessor, to provide midstream services to natural gas
producers. Since 2002, we have grown through a combination of
organic growth and acquisitions. In connection with the
acquisition in 2003 of the Dry Trail plant, a
CO2
tertiary recovery plant located in the Oklahoma panhandle,
members of our management team formed Eagle Rock Holdings, L.P.,
the successor to Eagle Rock Energy, Inc., to own, operate,
acquire and develop complementary midstream energy assets. Eagle
Rock Holdings, L.P., has benefited from the equity sponsorship
of Natural Gas Partners, one of the largest private equity fund
sponsors of companies in the energy sector, which since 2003 has
provided us with significant support in pursuing acquisitions.
Business
Strategies
Our primary business objective is to increase our cash
distributions per unit over time. We intend to accomplish this
objective by continuing to execute the following business
strategies:
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Maximizing the profitability of our existing
assets. We intend to maximize the profitability
of our existing assets by adding new volumes of natural gas and
undertaking additional initiatives to enhance utilization and
improve operating efficiencies. We plan to:
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market our midstream services and provide superior customer
service to producers in our areas of operation to connect new
wells to our gathering and processing systems, increase
gathering volumes from existing wells and more fully utilize
excess capacity on our systems; and
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improve the operations of our existing assets by relocating idle
processing plants to areas experiencing increased processing
demand, reconfiguring compression facilities, improving
processing plant efficiencies and capturing lost and unaccounted
for natural gas.
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Expanding our operations through organic growth
projects. We intend to leverage our existing
infrastructure and customer relationships by expanding our
existing asset base to meet new or increased demand for
midstream services. We completed the construction of our Tyler
County pipeline in the March 2006 quarter and will complete a
16-mile
extension in the first half of 2007 that will allow for the
delivery of dedicated natural gas volumes to our Brookeland
processing plant. We will complete in
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the second quarter of 2007 the refurbishment project of
restarting the Red Deer plant in our Texas Panhandle Systems
which will provide needed additional gas processing capacity.
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Pursuing complementary acquisitions. We have
grown significantly through acquisitions and will continue to
employ a disciplined acquisition strategy that capitalizes on
the operational experience of our management team as well as
bring new expertise to the Partnership. We believe that the
extensive experience of our management team in acquiring and
operating natural gas gathering and processing assets will
enable us to continue to successfully identify and complete
acquisitions that will enhance our profitability and increase
our operating capacity.
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Continuing to reduce our exposure to commodity price
risk. We intend to continue to operate our
business in a manner that reduces our exposure to commodity
price risk. We instituted a hedging program related to our NGL
business and have hedged substantially all of our share of
expected NGL volumes through 2007 through the purchase of NGL
put contracts, costless collar contracts and swap contracts, and
substantially all of our share of expected NGL volumes related
to our
percentage-of-proceeds
contracts from 2008 through 2010 through a combination of direct
NGL hedging as well as indirect hedging through crude oil
costless collars. We have also hedged substantially all of our
share of our short natural gas position for 2006 and 2007. We
anticipate that after 2007, our short natural gas position will
become a long natural gas position because of our increased
volumes in the Texas Panhandle and the volumes contributed from
our acquisition of the Brookeland and Masters Creek systems. In
addition, where market conditions permit, we intend to pursue
fee-based arrangements and to increase retained percentages of
natural gas and NGLs under
percent-of-proceeds
arrangements.
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Maintaining a disciplined financial policy. We
will continue to pursue a disciplined financial policy by
maintaining a prudent capital structure, managing our exposure
to interest rate and commodity price risk and conservatively
managing our cash reserves. We are committed to maintaining a
balanced capital structure, which will allow us to use our
available capital to selectively pursue accretive investment
opportunities.
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Competitive
Strengths
We believe that we are well positioned to execute our business
strategies successfully because of the following competitive
strengths:
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Our assets are strategically located in major natural gas
supply areas. Our assets are strategically
located in the Texas Panhandle, southeast Texas and Louisiana.
Our Texas Panhandle Systems are located in areas that produce
natural gas with high NGL content, especially in the West
Panhandle System. Our East Panhandle System is experiencing
significant drilling activity related to the Granite Wash play
and our West Panhandle System is connected to wells that
generally have long lives with predictable, steady flow rates
and minimal decline. Additionally, our southeast Texas and
Louisiana assets, specifically in Tyler and Polk Counties, are
located in areas characterized by high volumes of natural gas
and significant drilling activity, which provides us with
attractive opportunities to access newly developed natural gas
supplies. We believe that our extensive existing presence in
these regions, together with our available capacity and the
limited alternatives available to local producers, provide us
with a competitive advantage in capturing new supplies of
natural gas.
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We provide a distinct and integrated package of midstream
services. We provide a broad range of midstream
services to natural gas producers, including gathering,
compressing, treating, processing, transporting and selling
natural gas and fractionating and transporting NGLs. For
example, in the Texas Panhandle, we treat natural gas to extract
impurities such as carbon dioxide and hydrogen sulfide and we
fractionate NGLs to extract propane. Our competitors in this
area do not provide these services. Additionally, many of our
gathering systems, including our Texas Panhandle Systems,
operate at lower inlet pressures, which allow us to provide
gathering services to customers at a lower cost and on a more
timely basis than our competitors, who are often required to add
compression to provide gathering services to new wells.
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We have the financial flexibility to pursue growth
opportunities. We currently have approximately a
$500.0 million amended and restated credit facility, under
which we have approximately $80.0 million unused capacity,
with $24.0 million available capacity at year end. We
believe the available capacity under this credit facility,
combined with our expected ability to access the capital
markets, will provide us with a flexible financial structure
that will facilitate our strategic expansion and acquisition
strategies.
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We have an experienced, knowledgeable management team with a
proven record of performance. Our management team
has a proven record of enhancing value through the investment
in, and the acquisition, exploitation and integration of,
natural gas midstream assets. Our senior management team has an
average of over 25 years of industry-related experience.
Our teams extensive experience and contacts within the
midstream industry provide a strong foundation for managing and
enhancing our operations, accessing strategic acquisition
opportunities and constructing new assets. Members of our senior
management team have a substantial economic interest in us.
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We are affiliated with Natural Gas Partners, a leading
private equity capital source for the energy
industry. Natural Gas Partners, a leading private
equity firm focused on the energy industry, owns a significant
equity position in Eagle Rock Holdings, L.P., which owns
2,187,871 common and 20,691,495 subordinated units and all of
the equity interests in our general partner. We expect that our
relationship with Natural Gas Partners will provide us with
several significant benefits, including increased exposure to
acquisition opportunities and access to a significant group of
transactional and financial professionals with a successful
track record of investing in midstream assets. Founded in 1988,
Natural Gas Partners is among the oldest of the private equity
firms that specialize in the energy industry. Through its family
of eight institutionally-backed investment funds, Natural Gas
Partners has sponsored over 100 portfolio companies and has
controlled invested capital and additional commitments totaling
$2.9 billion.
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An investment in our common units involves risks associated with
our business, regulatory and legal matters, our limited
partnership structure and the tax characteristics of our common
units. Please read carefully the risks described under
Item 1A. Risk Factors.
Industry
Overview
The midstream natural gas industry is the link between
exploration and production of natural gas and the delivery of
its components to end-use markets, and consists of the
gathering, compressing, treating, processing, transporting and
selling of natural gas, and the transporting and selling of NGLs.
Natural Gas Demand and Production. Natural gas
is a critical component of energy consumption in the United
States. According to the Energy Information Administration, or
the EIA, total annual domestic consumption of natural gas is
expected to increase from approximately 22.2 trillion cubic
feet, or Tcf, in 2005 to approximately 23.35 Tcf in 2010. The
industrial and electricity generation sectors are the largest
users of natural gas in the United States. During the last three
years, these sectors accounted for approximately 56% of the
total natural gas consumed in the United States. In 2005,
natural gas represented approximately 36% of all end-user
domestic energy requirements. During the last three years, the
United States has on average consumed approximately 22.3 Tcf per
year, with average annual domestic production of approximately
18.5 Tcf during the same period. Driven by growth in natural gas
demand and high natural gas prices, domestic natural gas
production is projected to increase from 18.1 Tcf per year to
20.4 Tcf per year between 2005 and 2015.
Midstream Natural Gas Industry. Once natural
gas is produced from wells, producers then seek to deliver the
natural gas and its components to end-use markets. The process
of natural gas gathering, processing, fractionation, storage and
transportation ultimately results in natural gas and its
components being delivered to end-users.
Natural Gas Gathering and Treating. The
natural gas gathering process begins with the drilling of wells
into gas-bearing rock formations. Once the well is completed,
the well is connected to a gathering system.
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Onshore gathering systems generally consist of a network of
small diameter pipelines that collect natural gas from points
near producing wells and transport it to larger pipelines for
further transmission.
Natural gas has a varied composition depending on the field, the
formation and the reservoir from which it is produced. Natural
gas from certain formations can be high in carbon dioxide or
hydrogen sulfide. Natural gas with high carbon dioxide or
hydrogen sulfide levels may cause significant damage to
pipelines and is generally not acceptable to end-users. To
alleviate the potential adverse effects of these contaminants,
many pipelines regularly inject corrosion inhibitors into the
gas stream.
Natural Gas Compression. Gathering systems are
operated at pressures that will maximize the total throughput
from all connected wells. Since wells produce at progressively
lower field pressures as they age, it becomes increasingly
difficult to deliver the remaining production from the ground
against a higher pressure that exists in the connecting
gathering system. Natural gas compression is a mechanical
process in which a volume of wellhead gas is compressed to a
desired higher pressure, allowing gas flow into a higher
pressure downstream pipeline to be brought to market. Field
compression is typically used to lower the pressure of a
gathering system to operate at a lower pressure or provide
sufficient pressure to deliver gas into a higher pressure
downstream pipeline. If field compression is not installed, then
the remaining natural gas in the ground will not be produced
because it cannot overcome the higher gathering system pressure.
In contrast, if field compression is installed, then a well can
continue delivering production that otherwise would not be
produced.
Natural Gas Processing. Natural gas is
described as lean or rich depending on its content of heavy
components or liquids content. These are relative terms, but as
generally used, rich natural gas may contain as much as five to
six gallons or more of NGLs per Mcf, whereas lean natural gas
usually contains one to two gallons of NGLs per Mcf. NGLs have
economic value and are utilized as a feedstock in the
petrochemical and oil refining industries or directly as
heating, engine or industrial fuels. Long-haul natural gas
pipelines have specifications as to the maximum NGL content of
the gas to be shipped. In order to meet quality standards for
long-haul pipeline transportation, natural gas collected through
a gathering system must be processed to separate hydrocarbon
liquids that can have higher values as mixed NGLs from the
natural gas.
The principal component of natural gas is methane, but most
natural gas also contains varying amounts of NGLs including
ethane, propane, normal butane, isobutane and natural gasoline.
NGLs are typically recovered by cooling the natural gas until
the mixed NGLs become separated through condensation. Cryogenic
recovery methods are processes where this is accomplished at
temperatures lower than
−150o.
These methods provide higher NGL recovery yields. After being
extracted from natural gas, the mixed NGLs are typically
transported via NGL pipelines or trucks to a fractionator for
separation of the NGLs into their component parts.
In addition to NGLs, natural gas collected through a gathering
system may also contain impurities, such as water, sulfur
compounds, nitrogen or helium. As a result, a natural gas
processing plant will typically provide ancillary services such
as dehydration and condensate separation prior to processing.
Dehydration removes water from the natural gas stream, which can
form ice when combined with natural gas and cause corrosion when
combined with carbon dioxide or hydrogen sulfide. Condensate
separation involves the removal of hydrocarbons from the natural
gas stream. Once the condensate has been removed, it may be
stabilized for transportation away from the processing plant.
Natural gas with a carbon dioxide or hydrogen sulfide content
higher than permitted by pipeline quality standards requires
treatment with chemicals called amines at a separate treatment
plant prior to processing.
Natural Gas Fractionation. Fractionation is
the process by which NGLs are further separated into individual,
more valuable components. NGL fractionation facilities separate
mixed NGL streams into discrete NGL products: ethane, propane,
isobutane, normal butane and natural gasoline. Ethane is
primarily used in the petrochemical industry to produce
ethylene, one of the basic building blocks for a wide range of
plastics and other chemical products. Propane is used in the
production of ethylene and propylene and as a heating fuel, an
engine fuel and an industrial fuel. Isobutane is used
principally to enhance the octane content of motor gasoline.
Normal butane is used in the production of ethylene, butadiene
(a key ingredient in synthetic rubber), motor gasoline and
isobutane. Natural gasoline, a mixture of pentanes and heavier
hydrocarbons, is used primarily to produce motor gasoline and
petrochemicals.
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Fractionation takes advantage of the differing boiling points of
the various NGL products. NGLs are fractionated by heating mixed
NGL streams and passing them through a series of distillation
towers. As the temperature of the NGL stream is increased, the
lightest (lowest boiling point) NGL product boils off the top of
the tower where it is condensed and routed to storage. The
mixture from the bottom of the first tower is then moved into
the next tower where the process is repeated, and a different
NGL product is separated and stored. This process is repeated
until the NGLs have been separated into their components.
Because the fractionation process uses large quantities of heat,
energy costs are a major component of the total cost of
fractionation.
Natural Gas and NGL Transportation. Natural
gas transportation pipelines receive natural gas from other
mainline transportation pipelines and gathering systems and
deliver the processed natural gas to industrial end-users and
utilities and to other pipelines. NGLs are transported to market
by means of pipelines, pressurized barges, rail car and tank
trucks. The method of transportation utilized depends on, among
other things, the existing resources of the transporter, the
locations of the production points and the delivery points,
cost-efficiency and the quantity of NGLs being transported.
Pipelines are generally the most cost-efficient mode of
transportation when large, consistent volumes of NGLs are to be
delivered.
Formation
and Acquisitions
We are a Delaware limited partnership formed in March 2006, to
own and operate the assets that have historically been owned and
operated by Eagle Rock Holdings, L.P. and its subsidiaries. In
2002, certain members of our management team formed Eagle Rock
Energy, Inc. to provide midstream services to natural gas
producers. In connection with the acquisition in 2003, of the
Dry Trail plant, a
CO2
tertiary recovery plant located in the Oklahoma panhandle,
members of our management team and Natural Gas Partners formed
Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy,
Inc., to own, operate, acquire and develop complementary
midstream energy assets. Natural Gas Partners is one of the
largest private equity fund sponsors of companies in the energy
sector and, since 2003, has provided us with significant support
in pursuing acquisitions.
Acquisition
of Camp Ruby Gathering System and Indian Spring Processing Plant
and Expansion of System
On July 28, 2004, we acquired certain minority-owned,
non-operated undivided interests in natural gas gathering and
processing assets from Black Stone Minerals for approximately
$20.0 million. The assets consisted of a 20% undivided
interest in the Camp Ruby gathering system and a 25% undivided
interest in its related Indian Springs processing facility, both
located in Southeast Texas. An affiliate of Enterprise Products
Partners, L.P. currently owns the remaining interests in the
facilities and is the operator of each of the facilities.
We began the construction of the Tyler County pipeline in
September 2005. During the construction phase, we were able to
secure large dedication areas from three additional producers in
the vicinity of the Tyler County pipeline increasing our
expected volumes from 15 MMcf/d to approximately an average
of 30 MMcf/d. The Tyler County pipeline reached the first
producer and began flowing natural gas on December 30,
2005. Construction of the pipeline was finished on
February 28, 2006, at a cost of approximately
$8.6 million. We are currently constructing an extension to
the Tyler County pipeline which should be flowing gas by mid
2007. This line provides additional supply capacity and
flexibility in addition to providing us the opportunity to take
advantage of processing plant efficiencies for our customers, as
well as a reduction in third-party processing fees.
Acquisition
of Panhandle Assets
On December 1, 2005, we completed the purchase of ONEOK
Texas Field Services, L.P., or ONEOK or predecessor, for
approximately $528.0 million of cash. The assets acquired
in the transaction consist of gathering and processing assets
located in a ten county area in the Texas Panhandle and
represent the majority of our assets in the Texas Panhandle.
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In the first few months after the acquisition, we attracted
20 MMcf/d of new volumes at attractive processing margins.
We are in the process of expanding our processing capacity in
this area by beginning to refurbish and will restart an idle
20 MMcf/d processing plant, and by connecting the East
Panhandle System with the West Panhandle System, where excess
capacity currently exists. We also intend to expand our
processing capacity by relocating and restarting a
24.5 MMcf/d facility in the latter part of 2007. In July,
2006, we began flowing gas across the
10-mile
pipeline constructed to connect the gas in the east to the
surplus plant capacity in the west.
Acquisition
of Brookeland Assets
On March 31, 2006, we purchased an 80% interest in the
Brookeland gathering and processing facility, a 76.3% interest
in the Masters Creek gathering system and 100% of the Jasper NGL
line from Duke Energy Field Services, L.P. and on April 7,
2006, we purchased the remaining interest owned by Swift Energy
Corporation in those same assets for an approximate total
purchase price of $95.7 million. The acquired assets are
located in southeast Texas and complement our existing southeast
Texas assets. To motivate Swift Energy Corporation to enhance
their drilling program, we have negotiated an incentive on all
new well production. As such, they have resumed their drilling
program.
We began the construction of a
16-mile
extension to our Tyler County pipeline to reach the Brookeland
processing plant, which as of April 30, 2006, operated with
72.2 MMcf/d of excess capacity. This extension will allow
us to deliver the Tyler County pipeline volumes to our
wholly-owned Brookeland processing facility which will enable us
to avoid the processing fee we currently pay at the Indian
Springs processing facility on these volumes. We also expect by
delivering these volumes to our Brookeland processing facility
we will achieve higher NGL recoveries as the Brookeland
processing facility is more efficient than the Indian Springs
processing facility.
Acquisition
of MGS
In June 2006, we purchased all of the partnership interests in
Midstream Gas Services, L.P., which we refer to as MGS, for
approximately $4.7 million in cash and 1,125,416 common
units in Eagle Rock Pipeline from a group of private investors,
including Natural Gas Partners VII, L.P. We issued 798,155 of
our common units (pre-IPO common units), which we refer to as
the Deferred Common Units, to Natural Gas Partners VII, L.P.,
the primary equity owner of MGS, as a contingent earn-out
payment if MGS achieves certain financial objectives for the
year ending December 31, 2007. Prior to the acquisition,
Natural Gas Partners VII, L.P. owned a 95% limited partnership
interest in MGS and a 95% interest in its general partner, which
owned a 1% general partner interest in MGS. We refer to the
private investors who received common units in Eagle Rock
Pipeline as partial consideration for the MGS acquisition as the
June 2006 Private Investors. The March 2006 Private Investors
and the June 2006 Private Investors are collectively referred to
in the Annual Report as the Private Investors. Each
of the Private Investors common units in Eagle Rock
Pipeline was converted into common units in the Partnership upon
consummation of our initial public offering on approximately a
1-for-0.719
common unit basis.
Our
Assets
We own strategically positioned natural gas gathering and
processing assets in two significant natural gas producing
regions, the Texas Panhandle and the southeast Texas
western Louisiana region.
Texas
Panhandle Operations
Our Texas Panhandle operations cover ten counties in Texas and
one county in Oklahoma and consist of our East Panhandle System
and our West Panhandle System. Through these systems, we offer
producers a complete set of midstream
wellhead-to-market
services, including gathering, compressing, treating,
processing, transporting and selling of natural gas and
fractionating and transporting NGLs.
Our Texas Panhandle Systems are located in the Texas Railroad
Commission, or the TRRC, District 10, which has experienced
significant growth activity since 2002. According to the EIA,
there were approximately
7
5.4 Tcf of total proved natural gas reserves at year-end 2006 in
District 10. This area has experienced significant drilling
activity during the last three years, and more than 550 new
wells were completed in the counties served by our Texas
Panhandle Systems during 2006.
Our Texas Panhandle Systems collectively include
3,509 miles of gathering pipeline, six active gas
processing plants with an aggregate capacity of approximately
166 MMcf/d, and four inactive plants with an aggregate
capacity of approximately 70 MMcf/d. Our Texas Panhandle
Systems had an average throughput of 146 MMcf/d and an
average NGL and condensate production of approximately
13,900 Bbls/d for the twelve months ended December 31,
2006.
East
Panhandle System
The East Panhandle System gathers and processes natural gas
produced in the Morrow and Granite Wash reservoirs of the
Anadarko basin in Wheeler, Hemphill and Roberts Counties, an
area in the eastern portion of the Texas Panhandle that has
experienced substantial drilling and reserve growth since 2002.
The processing plants in our East Panhandle System are rapidly
reaching capacity. In order to provide additional processing
capacity to our East Panhandle System, we constructed in early
2006 a
10-mile
pipeline from the West Panhandle System to the East Panhandle
System, to activate inactive processing plants located in the
West Panhandle System and relocate those processing plants in
the East Panhandle System or connect the processing plants to
existing pipeline connections, and to utilize unused capacity at
existing processing plants.
System Description. The East Panhandle System
consists of:
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approximately 773 miles of natural gas gathering pipelines,
ranging from two inches to 12 inches in diameter, with
35,289 horsepower of associated pipeline compression;
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three active natural gas processing plants with an aggregate
capacity of 90 MMcf/d; and
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two natural gas treating facilities with an aggregate capacity
of 75 MMcf/d.
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The average throughput of the gathering system was approximately
93.4 MMcf/d for the twelve months ended December 31,
2006.
The Arrington processing plant is a refrigerated, lean oil
absorption facility located in Hemphill County, Texas. The
processing plant has seven compressors with an aggregate of
approximately 6,000 horsepower and approximately 40 MMcf/d
of processing capacity. During the twelve months ended
December 31, 2006, the facility processed approximately
28.6 MMcf/d of natural gas and produced approximately
1,520 Bbls/d of NGLs. The Arrington processing plant was
built in 1974.
The Canadian processing plant is a turbo expander cryogenic
facility located in Hemphill County, Texas. The plant has eleven
compressors with an aggregate of approximately 10,720 horsepower
and approximately 25 MMcf/d of processing capacity. During
the twelve months ended December 31, 2006, the facility
processed approximately 36 MMcf/d of natural gas and
produced approximately 2,300 Bbls/d of NGLs. As part of our
Canadian processing plant, we own a 25 MMcf/d treating
facility that removes carbon dioxide and small amounts of
hydrogen sulfide from the natural gas. The Canadian processing
plant was built in 1977.
Our Goad treating facility is a 50 MMcf/d treating facility
that removes carbon dioxide and hydrogen sulfide from the
natural gas.
In addition, we purchased Midstream Gas Services, L.P. in June
2006, which consists of facilities located in Roberts County
within our East Panhandle System. The facilities consist of
approximately four miles of natural gas gathering pipelines with
associated pipeline compression and an active natural gas
processing plant with aggregate capacity of 25 MMcf/d. The
processing plant was constructed in late 2005 and early 2006,
and was successfully started in the second quarter of 2006. The
plant is currently processing approximately 3 MMcf/d of
natural gas. This facility is connected to our East Panhandle
System, allowing additional natural gas supply from nearby
Hemphill County to be processed through this facility. The
residue gas is currently being delivered to the ANR pipeline.
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Natural Gas Supply. As of December 31,
2006, 592 wells and central delivery points were connected
to our East Panhandle System. There are approximately 73
producers with the primary producers connected to the East
Panhandle System being Devon Energy Production Company, L.P.,
Peak Operating of Texas LLC, Prize Operating Company and
ChevronTexaco Exploration & Production. The Anadarko
basin, from where this gas is produced, extends from the western
portion of the Texas Panhandle through most of central Oklahoma.
Natural gas production from wells located within the area served
by the East Panhandle System generally has steep rates of
decline during the first few years of production. Approximately
64% of the natural gas that is gathered on our East Panhandle
System is processed to recover the NGL content, which generally
ranges from 4.0 to 5.0 gpm for this processed natural gas.
Approximately 36% of the natural gas gathered in the East
Panhandle System is not processed but is treated for removal of
carbon dioxide and hydrogen sulfide to make the natural gas
marketable. This natural gas can be isolated and sent to the
treating facilities while the remaining system is used to gather
the natural gas into the processing plants.
The East Panhandle System is located in an area characterized by
significant growth in drilling activity and production. In 2006,
approximately 744 wells have been permitted and
472 wells have been drilled in the area. On the East
Panhandle System, natural gas is purchased at the wellhead
primarily under
percent-of-proceeds
and fee-based arrangements that primarily range from one to five
years in term. As of December 31, 2006, approximately 77%,
22% and 1% of our total throughput in the East Panhandle System
was under
percent-of-proceeds,
fee-based and keep-whole arrangements, respectively. For a more
complete discussion of our natural gas purchase contracts,
please read Item 7. Managements Discussion and
Analysis of Financial Condition and Results of
Operations Our Operations.
Markets. We marketed the residue natural gas
and the NGLs on the East Panhandle System to approximately six
purchasers. Interconnects exist with Northern Natural Gas Co. at
the Canadian processing plant and Southern Star Central Gas
Pipeline, Inc.
Pursuant to an exchange agreement, the NGLs from our East
Panhandle System are currently transported to the ONEOK NGL
pipeline at Mont Belvieu, Texas or Conway, Kansas, where the
NGLs are being marketed by ONEOK. During 2006, we began
marketing these NGLs, which we believe enhanced the netback to
us and the producers because of better market pricing and
improved marketing fee arrangements. With the December 2005
Panhandle acquisition, a significant portion of the residue
natural gas and NGLs were purchased by ONEOK Energy Services in
the first half of 2006. The exchange agreement with ONEOK Energy
Services expired on May 31, 2006.
The condensate from the East Panhandle System is transported by
truck to central tank facilities and injected for sale into the
ConocoPhillips Y-2 system.
Competition. Our primary competitor in this
area is Enbridge, Inc.
West
Panhandle System
The West Panhandle System gathers and processes natural gas
produced from the Anadarko basin in Moore, Potter, Hutchinson,
Carson, Roberts, Gray, Wheeler and Collingsworth Counties
located in the western part of the Texas Panhandle.
System Description. The West Panhandle System
consists of:
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approximately 2,736 miles of natural gas gathering
pipelines, ranging from two inches to 12 inches in
diameter, with 81,473 horsepower of associated pipeline
compression;
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four active natural gas processing plants with an aggregate
capacity of 101 MMcf/d;
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three natural gas treating facilities with an aggregate capacity
of 65 MMcf/d;
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a propane fractionation facility with capacity of
1,000 Bbls/d; and
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a condensate collection facility.
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9
The average throughput of the gathering system was approximately
50.8 MMcf/d for the twelve months ended December 31,
2006.
The Cargray processing plant is a turbo expander cryogenic
facility located in Carson County, Texas. The plant has seven
compressors with an aggregate of approximately 7,000 horsepower
and approximately 30 MMcf/d of processing capacity. In
addition to the cryogenic plant, the processing facility also
includes a 30 MMcf/d dehydration unit, a 12 MMcf/d
deoxygenation unit and a 1,000 Bbls/d propane fractionator,
which also includes a deethanizer, a depropanizer, 136,000
gallons of storage capacity, loading pumps and a truck loading
rack. During the twelve months ended December 31, 2006, the
facility processed approximately 14 MMcf/d of natural gas
and produced approximately 2,400 Bbls/d of NGLs. In
addition, approximately 3.6 MMcf/d of the natural gas
gathered by the Cargray plant is treated for the removal of
hydrogen sulfide and carbon dioxide at the Shaefer treating
facility in Carson County, Texas. The Cargray plant was built in
1974.
The Gray processing plant is a turbo expander cryogenic facility
located in Gray County, Texas. The plant has seven compressors
with an aggregate of approximately 2,000 horsepower and
approximately 20 MMcf/d of processing capacity. During the
twelve months ended December 31, 2006, the facility
processed approximately 14.4 MMcf/d of natural gas and
produced approximately 1,940 Bbls/d of NGLs. This plant
includes an inactive 12 gpm treating facility and a
20 MMcf/d dehydration unit. The Gray plant was built in
1984.
The condensate collection facility, which is located near the
Gray processing plant, serves as a central collection point for
the condensate produced on the West Panhandle System. The
facility includes several horizontal feed tanks, a
1,500 Bbls/d condensate stabilizer, horizontal make tanks,
truck loading and unloading facilities and a pipeline connection
to ConocoPhillips. Condensate is transported by a pipeline from
the Gray processing plant and by truck from other parts of the
West Panhandle System.
The Lefors processing plant is a cryogenic processing facility
located in Gray County, Texas. The plant has an aggregate of
1,225 horsepower of inlet compression and 400 horsepower of
refrigeration compression and approximately 11 MMcf/d of
processing capacity. The processing facility also includes a 5
gpm amine product treater. During the twelve months ended
December 31, 2006, the facility processed approximately
7.6 MMcf/d of natural gas and produced approximately
1,700 Bbls/d of NGLs. The Lefors plant was originally
constructed in 1928, converted in 1970 and was replaced in 1995.
The Stinnett processing plant is a turbo expander cryogenic
facility located in Moore County, Texas. The plant has five
compressors with an aggregate of approximately 6,300 horsepower
and approximately 40 MMcf/d of processing capacity. The
processing facility also includes a 14 gpm treating facility, a
40 MMcf/d dehydration unit, a 40 MMcf/d dehydrator and
a condensate stabilizer. During the twelve months ended
December 31, 2006, the facility processed approximately
14.1 MMcf/d of natural gas and produced approximately
1,550 Bbls/d of NGLs. The Stinnett plant was built in 1984.
We believe we have opportunities to increase the profitability
of the West Panhandle System primarily by utilizing excess
processing capacity on this system to process natural gas
transported from our East Panhandle System as well as by
rationalizing assets, reducing fuel expense and other operating
costs and improving NGL recovery efficiency. Additionally,
opportunities exist to capture additional natural gas production
associated with the re-completion of existing wells that were
not developed using advanced technology and infill drilling.
Natural Gas Supply. As of December 31,
2006, 1,737 wells and central delivery points were
connected to the West Panhandle System. There are 195 producers
connected to the West Panhandle System with Chesapeake, Excel
Energy, Chevron, XTO Energy, Questa Energy Corporation, and
James Reneau Seed Corp. being the primary producers.
Wells located in the West Panhandle System produce natural gas
associated with the crude oil production from the wells. These
wells generally have long production lives with predictable
production base decline rates of approximately 6% per year.
These wells generally produce natural gas having an NGL content
of between 6.5 and 13.0 gpm, a level that is considered
extremely high in comparison to average levels of NGL content of
between 1.0 and 2.0 gpm related to natural gas production that
is not associated with crude oil production.
10
Significant compression horsepower and significantly more
pipeline capacity are required to move this natural gas to the
processing facilities because of the high NGL content. Because
of the complex level of service and high quality of the natural
gas, the value of the natural gas produced and the margins
associated with our services are typically higher for the West
Panhandle System as compared to the East Panhandle System.
The West Panhandle System is located in a mature drilling area
that produces high NGL content natural gas. New drilling
activity around the West Panhandle System has been less active
over the past several years. However, producers are continually
re-working their existing properties to maintain productive
reserves, which has resulted in a low natural gas production
decline rate.
On the West Panhandle System, 40% of the natural gas is
purchased at the wellhead primarily under keep-whole
arrangements with a $3.0 million per year gathering demand
fee. The remaining 60% of the natural gas purchased is primarily
under
percent-of-proceeds
contracts. The natural gas from this system is dedicated under
long-term contracts. For a more complete discussion of our
natural gas purchase contracts, please read Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations Our Operations.
Markets. Our primary purchaser of the residue
gas and NGLs on the West Panhandle System for 2005 was ONEOK
Energy Services, which represented approximately 80% of revenues
on the system for the twelve months ended December 31,
2006. Our exchange with ONEOK Energy Services ended May 31,
2006, and we have expanded our purchasers, including ONEOK
Energy Services, to six portfolios of marketing outlets. In
addition, condensate produced on the system is trucked and
purchased by SemCrude, L.P. and Petro Source Partners, LP.
Competition. Our primary competition in this
area is Duke Energy Field Services, L.P.
Southeast
Texas and Louisiana Operations
Our southeast Texas and Louisiana operations are located
primarily in Polk, Tyler, Jasper and Newton Counties, Texas and
Vernon Parish, Louisiana. Through our southeast Texas and
Louisiana System, we offer producers natural gas gathering,
treating, processing and transportation and NGL transportation.
Systems Description. The facilities that
comprise our southeast Texas and Louisiana operations consist of:
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approximately 1,049 miles of natural gas gathering
pipelines, ranging from four inches to 12 inches in
diameter, with 5,200 horsepower of associated pipeline
compression;
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a 100 MMcf/d cryogenic processing plant;
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a 150 MMcf/d cryogenic processing plant, in which we own a
25% undivided interest; and
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a 19-mile
NGL pipeline.
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The Brookeland System is located in Jasper and Newton Counties,
Texas and consists of approximately 650 miles of natural
gas gathering pipelines, ranging from 4 inches to
12 inches in diameter, and the Brookeland processing plant.
The gathering system has capacity of approximately
120 MMcf/d. The gathering system utilizes approximately
1,100 horsepower to gather the natural gas from 156 wells
and central delivery points. This system was acquired in second
quarter 2006.
The Masters Creek System is located in Vernon, Beauregard and
Rapides Parishes, Louisiana and consists of approximately
250 miles of natural gas gathering pipelines, ranging from
two inches to 16 inches in diameter. The gathering system
has capacity of approximately 200 MMcf/d. The gathering
system utilizes approximately 4,000 horsepower to gather natural
gas from 52 wells and central delivery points. This system
was acquired in second quarter 2006.
The Brookeland processing plant is a cryogenic natural gas
processing and treating facility located in Jasper County,
Texas. The plant processes the gas delivered from the Brookeland
and Masters Creek systems. The plant has processing capacity of
approximately 100 MMcf/d. This system was acquired in
second quarter
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2006. For the period since the Partnership acquired the
facilities, approximately 27.1 MMcf/d of natural gas was
processed for 2006 and produced approximately 1,900 Bbls/d
of NGLs.
The Camp Ruby System is located in Polk, Hardin and Tyler
Counties, Texas and consists of approximately 126 miles of
natural gas gathering pipelines, ranging from two inches to
eight inches in diameter, and the Indian Springs processing
plant. The gathering system average throughput was approximately
71 MMcf/d for December 2006. The system delivers all of the
natural gas to the Indian Springs processing plant. We own a 20%
undivided interest in the Camp Ruby System and a subsidiary of
Enterprise Products Partners, L.P., owns the remaining 80% and
operates the system.
The Indian Springs processing plant is a cryogenic natural gas
processing and treating plant located in Polk County, Texas. The
Indian Springs processing plant is comprised of two cryogenic
plants with total operational capacity of 150 MMcf/d.
During December 2006, the facility processed approximately
100 MMcf/d of natural gas and produced approximately
6,900 Bbls/d of NGLs. We own a 25% undivided interest in
the Indian Springs processing plant and a subsidiary of
Enterprise Products Partners, L.P., owns the remaining 75% and
operates the facility.
On February 28, 2006, we completed construction on our
Tyler County pipeline, a
23-mile,
10-inch
diameter natural gas pipeline that is the first segment of a
natural gas gathering system that crosses Tyler County, Texas.
As of December 2006, the Tyler County gathering system had a
capacity of 60 MMcf/d, with an average throughput of
approximately 28.4 MMcf/d. Construction of an extension of
the Tyler County gathering system to the Brookeland System is
expected to be in service by the end of the first half of 2007,
at a cost of approximately $16.0 million, which will
increase capacity of the existing pipeline to 45 MMcf/d and
allows existing gas on the Tyler County Pipeline to be processed
at the Brookeland processing plant which is owned 100% by us.
The Jasper NGL pipeline is a
19-mile,
6-inch
diameter pipeline that is located in Jasper and Newton Counties,
Texas. The pipeline capacity is 18 MBbl/d and delivers NGLs
from the Brookeland plant to the Black Lake Pipeline which is
jointly owned by Duke Energy Field Services, L.P. and BP America
Production Company, for ultimate delivery of the NGLs to a
fractionation plant located in Mont Belvieu, Texas.
The Live Oak gathering system is located in Live Oak County,
Texas. It gathers gas from Zinergy and redelivers it to the
nearby Copano pipeline system for a fixed fee. This system was
built and put in service in November 2005. Zinergy had drilled
and completed three wells on this system by December 2006.
Volumes were averaging 3.4 MMcf/d as of December 2006.
Natural Gas Supply. As of December 31,
2006, approximately 209 wells and central delivery points
were connected to our systems in the southeast Texas and
Louisiana regions. Our southeast Texas and Louisiana operations
are located in an area experiencing an increase in drilling
activity and production. The Texas Railroad Commission and the
Louisiana Department of Natural Resources have issued 179
drilling permits in Tyler, Polk, Jasper and Newton Counties,
Texas and Vernon, Beauregard and Rapides Parish, Louisiana from
January 2006 through December 2006. We have secured areas of
dedication from Ergon Exploration Inc. (Ergon),
Black Stone Minerals Co., Delta Petroleum Corp., B.W.O.C. Inc.
(B.W.O.C.) and Pogo Producing Company. Each of the
entities has at least five additional locations identified as
drilling locations on this acreage. The Ergon and B.W.O.C. gas
was connected to our Tyler County pipeline in March 2006. As of
December 31, 2006, the gas on the Tyler County pipeline was
producing at a combined rate of approximately 28.4 MMcf/d.
The natural gas supplied to us under our southeast Texas and
Louisiana System is generally dedicated to us under individually
negotiated long-term and life of lease contracts. Contracts
associated with this production are generally
percent-of-proceeds
and
percent-of-liquids
arrangements. Natural gas is purchased at the wellhead from the
producers under
percent-of-proceeds
contracts or keep-whole contracts or is gathered for a fee and
redelivered at the plant tailgates. For a more complete
discussion of our natural gas purchase contracts, please read
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations Our
Operations.
12
Markets. Residue gas remaining after
processing is primarily taken in kind by the producer customers
into the markets available at the tailgates of the plants. Some
of the available markets are Houston Pipeline Company, Natural
Gas Pipeline Company and Tennessee Gas Pipeline. Our NGLs are
sold to Duke Energy Field Services, L.P. and our condensate
production is sold to SemCrude, L.P.
Competition. Our primary competition in this
area includes Anadarko Petroleum and Enterprise Products
Partners, L.P.
Safety
and Maintenance Regulation
We are subject to a number of federal and state laws and
regulations, including the federal Occupational Safety and
Health Act of 1970, referred to as OSHA, and comparable state
statutes, whose purpose is to protect the health and safety of
workers, both generally and within the pipeline industry. In
addition, the OSHA hazard communication standard, the EPA
community
right-to-know
regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes
require that information be maintained concerning hazardous
materials used or produced in our operations and that this
information be provided to employees, state and local government
authorities and citizens. We and the entities in which we own an
interest are also subject to OSHA Process Safety Management
regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive,
flammable or explosive chemicals. These regulations apply to any
process which involves a chemical at or above the specified
thresholds or any process which involves flammable liquid or
gas, pressurized tanks, caverns and wells in excess of 10,000
pounds at various locations. Flammable liquids stored in
atmospheric tanks below their normal boiling point without the
benefit of chilling or refrigeration are exempt. We have an
internal program of inspection and auditing designed to monitor
and enforce compliance with worker safety requirements. We
believe that we are in material compliance with all applicable
laws and regulations relating to worker health and safety. Our
east Texas and Louisiana assets have not experienced a lost-time
accident since June 2005. Our Texas Panhandle assets have not
experienced a lost-time accident since early 2004. Since our
inception, we have not experienced a lost-time accident.
Regulation
of Operations
Regulation of pipeline gathering and transportation services,
natural gas sales and transportation of NGLs may affect certain
aspects of our business and the market for our products and
services.
Gathering Pipeline
Regulation. Section 1(b) of the Natural Gas
Act exempts natural gas gathering facilities from the
jurisdiction of the Federal Energy Regulatory Commission
(FERC) under the Natural Gas Act. We believe that
the natural gas pipelines in our gathering systems meet the
traditional tests FERC has used to establish a pipelines
status as a gatherer not subject to FERC jurisdiction. However,
the distinction between FERC-regulated transmission services and
federally unregulated gathering services is the subject of
substantial, on-going litigation, so the classification and
regulation of our gathering facilities are subject to change
based on future determinations by FERC and the courts. State
regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances,
nondiscriminatory take requirements, and in some instances
complaint-based rate regulation.
Our Camp Ruby gathering system does provide limited interstate
transportation services pursuant to Section 311 of the
Natural Gas Policy Act (Section 311). The
rates, terms and conditions of such transportation service are
subject to FERC jurisdiction. Under Section 311, intrastate
pipelines providing interstate service may avoid jurisdiction
that would otherwise apply under the Natural Gas Act.
Section 311 regulates, among other things, the provision of
transportation services by an intrastate natural gas pipeline on
behalf of a local distribution company or an interstate natural
gas pipeline. Under Section 311, rates charged for
transportation must be fair and equitable, and amounts collected
in excess of fair and equitable rates are subject to refund with
interest. Additionally, the terms and conditions of service set
forth in the intrastate pipelines Statement of Operating
Conditions are subject to FERC approval. Failure to observe the
service limitations applicable to transportation services
provided under Section 311, failure to comply with the
rates approved by FERC for Section 311 service, and failure
to comply with the terms and conditions of service
13
established in the pipelines FERC-approved Statement of
Operating Conditions could result in the assertion of federal
Natural Gas Act jurisdiction by FERC
and/or the
imposition of administrative, civil and criminal penalties.
Louisianas Pipeline Operations Section of the Department
of Natural Resources Office of Conservation is generally
responsible for regulating gathering facilities in Louisiana,
and has authority to review and authorize the construction,
acquisition, abandonment and interconnection of physical
pipeline facilities. Historically, apart from pipeline safety,
it has not acted to exercise this jurisdiction respecting
gathering facilities.
The majority of our gathering systems in Texas have been deemed
non-utilities by the TRRC. Under Texas law, non-utilities are
not subject to rate regulation by the TRRC. Should the status of
these non-utility facilities change, they would become subject
to rate regulation by the TRRC, which could adversely affect the
rates that our facilities are allowed to charge their customers.
Texas also administers federal pipeline safety standards under
the Pipeline Safety Act of 1968. The rural gathering
exemption under the Natural Gas Pipeline Safety Act of
1968 presently exempts most of our gathering facilities from
jurisdiction under that statute, including those portions
located outside of cities, towns or any area designated as
residential or commercial, such as a subdivision or shopping
center. The rural gathering exemption, however, may
be restricted in the future. With respect to recent pipeline
accidents in other parts of the country, Congress and the
Department of Transportation, or DOT, have passed or are
considering heightened pipeline safety requirements. We operate
our facilities in full compliance with local, state and federal
regulations, including DOT 192 and 195.
Eleven miles of our Turkey Creek gathering system is regulated
as a utility by the TRRC. To date, there has been no adverse
affect to our system due to this regulation. In addition, the
four miles of gathering system that we recently purchased from
MGS is regulated by the TRRC.
Our purchasing and gathering operations are subject to ratable
take and common purchaser statutes. The ratable take statutes
generally require gatherers to take, without undue
discrimination, natural gas production that may be tendered to
the gatherer for handling. Similarly, common purchaser statutes
generally require gatherers to purchase without undue
discrimination as to source of supply or producer. These
statutes are designed to prohibit discrimination in favor of one
producer over another producer or one source of supply over
another source of supply. These statutes have the effect of
restricting our right as an owner of gathering facilities to
decide with whom we contract to purchase or transport natural
gas. Texas and Louisiana have adopted a complaint-based
regulation of natural gas gathering activities, which allows
natural gas producers and shippers to file complaints with state
regulators in an effort to resolve grievances relating to
natural gas gathering access and rate discrimination.
Natural gas gathering may receive greater regulatory scrutiny at
both the state and federal levels now that FERC has taken a more
light-handed approach to regulation of the gathering activities
of interstate pipeline transmission companies and a number of
such companies have transferred gathering facilities to
unregulated affiliates. Many of the producing states have
adopted some form of complaint-based regulation that generally
allows natural gas producers and shippers to file complaints
with state regulators in an effort to resolve grievances
relating to natural gas gathering access and rate
discrimination. Our gathering operations could be adversely
affected should they be subject in the future to the application
of state or federal regulation of rates and services. Our
gathering operations also may be or become subject to safety and
operational regulations relating to the design, installation,
testing, construction, operation, replacement and management of
gathering facilities. Additional rules and legislation
pertaining to these matters are considered or adopted from time
to time. We cannot predict what effect, if any, such changes
might have on our operations, but the industry could be required
to incur additional capital expenditures and increased costs
depending on future legislative and regulatory changes.
Sales of Natural Gas. The price at which we
buy and sell natural gas currently is not subject to federal
regulation and, for the most part, is not subject to state
regulation. Our sales of natural gas are affected by the
availability, terms and cost of pipeline transportation. As
noted above, the price and terms of access to pipeline
transportation are subject to extensive federal and state
regulation. The FERC is continually proposing and
14
implementing new rules and regulations affecting those segments
of the natural gas industry, most notably interstate natural gas
transmission companies that remain subject to the FERCs
jurisdiction. These initiatives also may affect the intrastate
transportation of natural gas under certain circumstances. The
stated purpose of many of these regulatory changes is to promote
competition among the various sectors of the natural gas
industry, and these initiatives generally reflect more
light-handed regulation. We cannot predict the ultimate impact
of these regulatory changes to our natural gas marketing
operations, and we note that some of the FERCs more recent
proposals may adversely affect the availability and reliability
of interruptible transportation service on interstate pipelines.
We do not believe that we will be affected by any such FERC
action materially differently than other natural gas marketers
with whom we compete.
Intrastate NGL Pipeline Regulation. We do not
own any NGL pipelines subject to FERCs regulation. We do
own and operate an intrastate common carrier NGL pipeline
subject to the regulation of the TRRC. The TRRC requires that
intrastate NGL pipelines file tariff publications that contain
all the rules and regulations governing the rates and charges
for service performed. The applicable Texas statutes require
that NGL pipeline rates provide no more than a fair return on
the aggregate value of the pipeline property used to render
services. State commissions have generally not been aggressive
in regulating common carrier pipelines and have generally not
investigated the rates or practices of NGL pipelines in the
absence of shipper complaints. Complaints to state agencies have
been infrequent and are usually resolved informally. Although we
cannot assure that our intrastate rates would ultimately be
upheld if challenged, we believe that, given this history, the
tariffs now in effect are not likely to be challenged or, if
challenged, are not likely to be ordered to be reduced.
Environmental
Matters
We operate pipelines, plants, and other facilities for
gathering, compressing, treating, processing, fractionating, or
transporting natural gas, NGLs, and other products that are
subject to stringent and complex federal, state, and local laws
and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection.
These laws and regulations can impair our operations that affect
the environment in many ways, such as requiring the acquisition
of permits to conduct regulated activities; restricting the
manner in which we can release materials into the environment;
requiring remedial activities or capital expenditures to
mitigate pollution from former or current operations; and
imposing substantial liabilities on us for pollution resulting
from our operations. The costs of planning, designing,
constructing and operating pipelines, plants and other
facilities must incorporate compliance with environmental laws
and regulations and safety standards. Failure to comply with
these laws and regulations may result in the assessment of
administrative, civil and criminal penalties, the imposition of
remedial obligations, and the issuance of injunctions limiting
or prohibiting our activities.
The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus, any changes in environmental laws and
regulations that result in more stringent and costly waste
handling, storage, transport, disposal, or remediation
requirements could have a material adverse effect on our
operations and financial position. Moreover, accidental releases
or spills are associated with our operations, and we cannot
assure that we will not incur significant costs and liabilities
as a result of such releases or spills, including those relating
to claims for damage to property and persons. In the event of
future increases in costs, we may be unable to pass on those
increases to our customers. While we believe that we are in
substantial compliance with existing environmental laws and
regulations and that continued compliance with current
requirements would not have a material adverse effect on us,
there is no assurance that this trend will continue in the
future.
The Comprehensive Environmental Response, Compensation and
Liability Act, as amended, also known as CERCLA or
Superfund, and comparable state laws impose
liability without regard to fault or the legality of the
original conduct, on certain classes of persons who are
considered to be responsible for the release of a hazardous
substance into the environment. Under CERCLA, these
responsible persons may be subject to joint and
several, strict liability for the costs of cleaning up the
hazardous substances that have been released into the
environment, for damages to natural resources, and for the costs
of certain health studies, and it is not uncommon for
neighboring landowners and other third parties to file claims
for personal injury and
15
property damage allegedly caused by the release of hazardous
substances into the environment. While we generate materials in
the course of our operations that may be regulated as hazardous
substances, we have not received notification that we may be
potentially responsible for cleanup costs under CERCLA.
We also may incur liability under the Resource Conservation and
Recovery Act, as amended, also known as RCRA, which
imposes requirements related to the handling and disposal of
solid and hazardous wastes. While there exists an exclusion from
the definition of hazardous wastes for certain materials
generated in the exploration, development, or production of
crude oil and natural gas, in the course of our operations we
may generate petroleum product wastes and ordinary industrial
wastes such as paint wastes, waste solvents, and waste
compressor oils that may be regulated as hazardous wastes.
We currently own or lease, and have in the past owned or leased,
properties that for many years have been used for midstream
natural gas and NGL activities. Although we used operating and
disposal practices that were standard in the industry at the
time, petroleum hydrocarbons or wastes may have been disposed of
or released on or under the properties owned or leased by us or
on or under other locations where such wastes have been taken
for disposal. In addition, some of these properties have been
operated by third parties whose treatment and disposal or
release of petroleum hydrocarbons and wastes was not under our
control. These properties and the materials disposed or released
on them may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, we could be required to remove or remediate
previously disposed wastes or property contamination, or to
perform remedial activities to prevent future contamination. We
intend to conduct environmental investigations at 11 properties,
the aggregate cost of which is estimated to range between
$0.2 million and $0.4 million and for which we have
accrued reserves in the amount of $0.3 million as of
December 31, 2006. Depending on the findings made during
these investigations, and in anticipation of implementing
amended SPCC plans at multiple locations as well as performing
selected cavern closures, we estimate that an additional
$1.2 million to $2.5 million in costs could be
incurred in resolving environmental issues at those properties.
Separately, (1) we are entitled to indemnification with
respect to certain environmental liabilities retained by prior
owners of these properties, and (2) we purchased an
environmental pollution liability insurance policy.
The Clean Air Act, as amended, and comparable state laws
restrict the emission of air pollutants from many sources,
including processing plants and compressor stations. These laws
and any implementing regulations may require us to obtain
pre-approval for the construction or modification of certain
projects or facilities expected to produce air emissions, impose
stringent air permit requirements, or utilize specific equipment
or technologies to control emissions. While we may be required
to incur certain capital expenditures in the next few years for
air pollution control equipment in connection with maintaining
or obtaining operating permits addressing other air
emission-related issues, we do not believe that such
requirements will have a material adverse affect on our
operations.
The Federal Water Pollution Control Act of 1972, as amended,
also known as the Clean Water Act, and analogous
state laws impose restrictions and controls on the discharge of
pollutants into federal and state waters. These laws also
regulate the discharge of stormwater in process areas. Pursuant
to these laws and regulations, we are required to obtain and
maintain approvals or permits for the discharge of wastewater
and stormwater and develop and implement spill prevention,
control and countermeasure plans, also referred to as SPCC
plans, in connection with
on-site
storage of greater than threshold quantities of oil. The EPA
issued revised SPCC rules in July 2002 whereby SPCC plans are
subject to more rigorous review and certification procedures.
Pursuant to these revised rules, SPCC plans must be amended, if
necessary to assure compliance, and implemented by no later than
October 31, 2007. We believe that our operations are in
substantial compliance with applicable Clean Water Act and
analogous state requirements, including those relating to
wastewater and stormwater discharges and SPCC plans.
Title to
Properties and
Rights-of-Way
Our real property falls into two categories: (1) parcels
that we own in fee and (2) parcels in which our interest
derives from leases, easements,
rights-of-way,
permits or licenses from landowners or governmental authorities
permitting the use of such land for our operations. Portions of
the land on which our plants and
16
other major facilities are located are owned by us in fee title,
and we believe that we have satisfactory title to these lands.
The remainder of the land on which our plant sites and major
facilities are located are held by us pursuant to ground leases
between us, as lessee, and the fee owner of the lands, as
lessors. We, or our predecessors, have leased these lands for
many years without any material challenge known to us relating
to the title to the land upon which the assets are located, and
we believe that we have satisfactory leasehold estates to such
lands. We have no knowledge of any challenge to the underlying
fee title of any material lease, easement,
right-of-way,
permit or license held by us or to our title to any material
lease, easement,
right-of-way,
permit or lease, and we believe that we have satisfactory title
to all of our material leases, easements,
rights-of-way,
permits and licenses.
Employees
To carry out our operations, Eagle Rock Energy G&P, LLC, the
general partner of our general partner, employs approximately
163 people who provide direct support for our operations.
None of these employees are covered by collective bargaining
agreements.
Legal
Proceedings
Our operations are subject to a variety of risks and disputes
normally incident to our business. As a result, we are and may,
at any given time, be a defendant in various legal proceedings
and litigation arising in the ordinary course of business.
However, we are not currently a party to any material litigation.
We maintain insurance policies with insurers in amounts and with
coverage and deductibles that we, with the advice of our
insurance advisors and brokers, believe are reasonable and
prudent. We cannot, however, assure that this insurance will be
adequate to protect us from all material expenses related to
potential future claims for personal and property damage or that
these levels of insurance will be available in the future at
economical prices.
Available
Information
We file annual, quarterly and other reports and other
information with the Securities and Exchange Commission
(SEC), under the Securities Exchange Act of 1934
(the Exchange Act). Materials that we file with the
SEC at the SECs Public Reference Room at 100 F Street, NE,
Washington, DC 20549, may be read and copied. Additional
information about the Public Reference Room may be obtained by
calling the SEC at
1-800-SEC-0330.
In addition, the SEC maintains an Internet site
(http://www.sec.gov) that contains reports, proxy and
information statements, and other information regarding issuers
that file electronically with the SEC, including us.
We also make available free of charge on or through our Internet
website (http://www.eaglerockenergy.com) or through our Investor
Relations group
(281-408-1200),
our Annual Reports on
Form 10-K,
Quarterly Reports on
Form 10-Q,
Current Reports on
Form 8-K,
and other information statements and, if applicable, amendments
to those reports filed or furnished pursuant to
Section 13(a) of the Exchange Act as soon as reasonably
practicable after we electronically file such material with, or
furnish it to, the SEC.
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 could be
materially adversely affected. In that case, we might not be
able to pay the minimum quarterly distribution on our common
units and the trading price of our common units could
decline.
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Risks
Related to Our Business
Because
of the natural decline in production from existing wells, our
success depends on our ability to obtain new sources of supplies
of natural gas and NGLs, which are dependent on certain factors
beyond our control. Any decrease in supplies of natural gas or
NGLs could adversely affect our business and operating
results.
Our gathering and transportation pipeline systems are connected
to or dependent on the level of production from natural gas
wells, from which production will naturally decline over time.
As a result, our cash flows associated with these wells will
also decline over time. In order to maintain or increase
throughput levels on our gathering and transportation pipeline
systems and NGL pipelines and the asset utilization rates at our
natural gas processing plants, we must continually obtain new
supplies of natural gas. The primary factors affecting our
ability to obtain new supplies of natural gas and NGLs and
attract new customers to our assets include: (1) the level
of successful drilling activity by producers near our systems
and (2) our ability to compete for volumes from successful
new wells.
The level of drilling activity is dependent on economic and
business factors beyond our control. The primary factor that
impacts drilling decisions is natural gas prices. Currently,
natural gas prices are high in relation to historical prices.
For example, the rolling twelve-month average NYMEX daily
settlement price of natural gas has increased from
$5.49 per MMBtu as of December 31, 2003 to
$7.23 per MMBtu as of December 31, 2006. If the high
price for natural gas were to decline, the level of drilling
activity could decrease. A sustained decline in natural gas
prices could result in a decrease in exploration and development
activities in the fields served by our gathering and pipeline
transportation systems and our natural gas treating and
processing plants, which would lead to reduced utilization of
these assets. Other factors that impact production decisions
include producers capital budgets, the ability of
producers to obtain necessary drilling and other governmental
permits, and regulatory changes. Because of these factors, even
if new natural gas reserves are discovered in areas served by
our assets, producers may choose not to develop those reserves.
If we are not able to obtain new supplies of natural gas to
replace the natural decline in volumes from existing wells due
to reductions in drilling activity or competition, throughput on
our pipelines and the utilization rates of our treating and
processing facilities would decline, which could have a material
adverse effect on our business, results of operations, financial
condition and ability to make cash distributions.
Natural
gas, NGLs and other commodity prices are volatile, and a
reduction in these prices could adversely affect our cash flow
and our ability to make distributions.
We are subject to risks due to frequent and often substantial
fluctuations in commodity prices. NGL prices generally fluctuate
on a basis that correlates to fluctuations in crude oil prices.
In the past, the prices of natural gas and crude oil have been
extremely volatile, and we expect this volatility to continue.
The NYMEX daily settlement price for natural gas for the prompt
month contract in 2006 ranged from a high of $9.87 per
MMBtu to a low of $3.63 per MMBtu. The NYMEX daily
settlement price for crude oil for the prompt month contract in
2006 ranged from a high of $77.03 per barrel to a low of
$55.81 per barrel. The markets and prices for natural gas and
NGLs depend upon factors beyond our control. These factors
include demand for oil, natural gas and NGLs, which fluctuate
with changes in market and economic conditions and other
factors, including:
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the impact of weather on the demand for oil and natural gas;
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the level of domestic oil and natural gas production;
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the availability of imported oil and natural gas;
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actions taken by foreign oil and gas producing nations;
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the availability of local, intrastate and interstate
transportation systems;
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the availability and marketing of competitive fuels;
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the impact of energy conservation efforts; and
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the extent of governmental regulation and taxation.
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Our natural gas gathering and processing businesses operate
under two types of contractual arrangements that expose our cash
flows to increases and decreases in the price of natural gas and
NGLs:
percentage-of-proceeds
and keep-whole arrangements. Under
percentage-of-proceeds
arrangements, we generally purchase natural gas from producers
and retain an agreed percentage of the proceeds (in cash or
in-kind) from the sale at market prices of pipeline-quality gas
and NGLs or NGL products resulting from our processing
activities. Under keep-whole arrangements, we receive the NGLs
removed from the natural gas during our processing operations as
the fee for providing our services in exchange for replacing the
thermal content removed as NGLs with a like thermal content in
pipeline-quality gas or its cash equivalent. Under these types
of arrangements our revenues and our cash flows increase or
decrease as the prices of natural gas and NGLs fluctuate. The
relationship between natural gas prices and NGL prices may also
affect our profitability. When natural gas prices are low
relative to NGL prices, under keep-whole arrangements it is more
profitable for us to process natural gas. When natural gas
prices are high relative to NGL prices, it is less profitable
for us and our customers to process natural gas both because of
the higher value of natural gas and of the increased cost
(principally that of natural gas as a feedstock and a fuel) of
separating the mixed NGLs from the natural gas. As a result, we
may experience periods in which higher natural gas prices
relative to NGL prices reduce our processing margins or reduce
the volume of natural gas processed at some of our plants. For a
detailed discussion of these arrangements, please read
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations Our
Operations.
Our
hedging activities may have a material adverse effect on our
earnings, profitability, cash flows and financial
condition.
We are exposed to risks associated with fluctuations in
commodity prices. The extent of our commodity price risk is
related largely to the effectiveness and scope of our hedging
activities. In order to reduce our exposure to commodity price
risk, we directly hedged substantially all of our share of
expected NGL volumes in 2006 and 2007 under
percent-of-proceed
and keep-whole contracts. This has been accomplished primarily
through the purchase of NGL put contracts but also through
executing NGL costless collar contracts and swap contracts. We
have also hedged substantially all of our share of expected NGL
volumes from 2008 through 2010 under
percent-of-proceed
contracts through a combination of direct NGL hedging as well as
indirect hedging through crude oil costless collars.
Additionally, to mitigate the exposure to natural gas prices
from keep-whole volumes, we have purchased natural gas calls
from 2006 to 2007 to cover our short natural gas position. For
periods after 2010, our management will evaluate whether to
enter into any new hedging arrangements, but there can be no
assurance that we will enter into any new hedging arrangement or
that our future hedging arrangements will be on terms similar to
our existing hedging arrangements.
To the extent we hedge our commodity price and interest rate
risk, we will forego the benefits we would otherwise experience
if commodity prices or interest rates were to change in our
favor. Furthermore, because we have entered into derivative
transactions related to only a portion of the volume of our
expected natural gas supply and production of NGLs and
condensate from our processing plants, we will continue to have
direct commodity price risk to the unhedged portion. Our actual
future supply and production may be significantly higher or
lower than we estimate at the time we entered into the
derivative transactions for that period. If the actual amount is
higher than we estimate, we will have less commodity price risk
than we intended. If the actual amount is lower than the amount
that is subject to our derivative financial instruments, we
might be forced to satisfy all or a portion of our derivative
transactions without the benefit of the underlying physical
commodity, resulting in a reduction of our liquidity.
As a result of these factors, our hedging activities may not be
as effective as we intend in reducing the volatility of our cash
flows, and in certain circumstances may actually increase the
volatility of our cash flows. In addition, even though our
management monitors our hedging activities, these activities can
result in substantial losses. Such losses could occur under
various circumstances, including if a counterparty does not
perform its obligations under the applicable hedging
arrangement, the hedging arrangement is imperfect or
19
ineffective, or our hedging policies and procedures are not
properly followed or do not work as planned. The steps we take
to monitor our hedging activities may not detect and prevent
violations of our risk management policies and procedures,
particularly if deception or other intentional misconduct is
involved.
As a result of our hedging activities and our practice of
marking to market the value of our hedging instruments, we will
also experience significant variations in our unrealized
derivative gains/(losses) from period to period. These
variations from period to period will follow variations in the
underlying commodity prices and interest rates. As this item is
of a non-cash nature, it will not impact our cash flows or our
ability to make our distributions. However, it will impact our
earnings and other profitability measures. To illustrate, during
the twelve months ended December 31, 2006, we experienced
positive movements in our underlying commodities prices
which led to an unrealized derivative loss of
$26.3 million. This $26.3 million loss had a direct
impact on our net income (loss) line resulting in a net loss of
$23.1 million. For additional information regarding our
hedging activities, please read Item 7A. Quantitative and
Qualitative Disclosures about Market Risk.
We
typically do not obtain independent evaluations of natural gas
reserves dedicated to our gathering and pipeline systems;
therefore, volumes of natural gas on our systems in the future
could be less than we anticipate.
We typically do not obtain independent evaluations of natural
gas reserves connected to our systems due to the unwillingness
of producers to provide reserve information as well as the cost
of such evaluations. Accordingly, we do not have independent
estimates of total reserves dedicated to our systems or the
anticipated life of such reserves. If the total reserves or
estimated life of the reserves connected to our gathering
systems is less than we anticipate and we are unable to secure
additional sources of natural gas, then the volumes of natural
gas on our systems in the future could be less than we
anticipate. A decline in the volumes of natural gas on our
systems could have a material adverse effect on our business,
results of operations, financial condition and our ability to
make cash distributions.
We
depend on certain natural gas producer customers for a
significant portion of our supply of natural gas. The loss of
any of these customers could result in a decline in our volumes,
revenues and cash available for distribution.
We rely on certain natural gas producer customers for a
significant portion of our natural gas and NGL supply. Our two
largest suppliers for the year ended December 31, 2005,
affiliates of Chesapeake Energy Corporation and Devon Energy
Corporation, accounted for approximately 19% and 9%,
respectively, of our 2005 natural gas supply. The
make-up of
gas suppliers can change from time to time based upon a number
of reasons, some of which are success of the producers
drilling programs, additions or cancellations of new agreements,
and acquisition of new systems. As of December 31, 2006,
our two largest suppliers were affiliates of Chesapeake Energy
Corporation and Prize Operating Company, accounting for
approximately 12% and 10% respectively, of our natural gas
supply. We may be unable to negotiate long-term contracts or
extensions or replacements of existing contracts, on favorable
terms, if at all. The loss of all or even a portion of the
natural gas volumes supplied by these customers, as a result of
competition or otherwise, could have a material adverse effect
on our business, results of operations and financial condition,
unless we were able to acquire comparable volumes from other
sources.
We may
not successfully balance our purchases and sales of natural gas,
which would increase our exposure to commodity price
risks.
We purchase from producers and other customers a substantial
amount of the natural gas that flows through our natural gas
gathering, processing and transportation systems for resale to
third parties, including natural gas marketers and end-users. We
may not be successful in balancing our purchases and sales. A
producer or supplier could fail to deliver contracted volumes or
deliver in excess of contracted volumes, or a purchaser could
purchase less than contracted volumes. Any of these actions
could cause our purchases and sales to be unbalanced. If our
purchases and sales are unbalanced, we will face increased
exposure to commodity price risks and could have increased
volatility in our operating income and cash flows.
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If
third-party pipelines and other facilities interconnected to our
systems become unavailable to transport or produce natural gas
and NGLs, our revenues and cash available for distribution could
be adversely affected.
We depend upon third-party pipelines and other facilities that
provide delivery options to and from our pipelines and
facilities for the benefit of our customers. Since we do not own
or operate any of these pipelines or other facilities, their
continuing operation is not within our control. If any of these
third-party pipelines and other facilities become unavailable to
transport or produce natural gas and NGLs, our revenues and cash
available for distribution could be adversely affected.
Our
industry is highly competitive, and increased competitive
pressure could adversely affect our business and operating
results.
We compete with similar enterprises in our respective areas of
operation. Some of our competitors are large oil and natural gas
companies that have greater financial resources and access to
supplies of natural gas and NGLs than we do. Some of these
competitors may expand or construct gathering, processing and
transportation systems that would create additional competition
for the services we provide to our customers. In addition, our
customers who are significant producers of natural gas may
develop their own gathering, processing and transportation
systems in lieu of using ours. Likewise, our customers who
produce NGLs may develop their own processing facilities in lieu
of using ours. Our ability to renew or replace existing
contracts with our customers at rates sufficient to maintain
current revenues and cash flows could be adversely affected by
the activities of our competitors and our customers. All of
these competitive pressures could have a material adverse effect
on our business, results of operations, financial condition and
ability to make cash distributions.
A
change in the jurisdictional characterization of some of our
assets by federal, state or local regulatory agencies or a
change in policy by those agencies may result in increased
regulation of our assets, which may cause our revenues to
decline and operating expenses to increase.
Our natural gas gathering and intrastate transportation
operations are generally exempt from Federal Energy Regulatory
Commission, or FERC, regulation under the Natural Gas Act of
1938, or NGA, except for Section 311 as discussed below,
but FERC regulation still affects these businesses and the
markets for products derived from these businesses. FERCs
policies and practices across the range of its oil and natural
gas regulatory activities, including, for example, its policies
on open access transportation, ratemaking, capacity release and
market center promotion, indirectly affect intrastate markets.
In recent years, FERC has pursued pro-competitive policies in
its regulation of interstate oil and natural gas pipelines.
However, FERC may not continue this approach as it considers
matters such as pipeline rates and rules and policies that may
affect rights of access to oil and natural gas transportation
capacity. In addition, the distinction between FERC-regulated
transmission services and federally unregulated gathering
services has been the subject of regular litigation, so, in such
a circumstance, the classification and regulation of some of our
gathering facilities and intrastate transportation pipelines may
be subject to change based on future determinations by FERC and
the courts.
Other state and local regulations also affect our business.
Common purchaser statutes generally require gatherers to
purchase without undue discrimination as to source of supply or
producer. These statutes restrict our right as an owner of
gathering facilities to decide with whom we contract to purchase
or transport oil or natural gas. Federal law leaves any economic
regulation of natural gas gathering to the states. The states in
which we operate have adopted complaint-based regulation of oil
and natural gas gathering activities, which allows oil and
natural gas producers and shippers to file complaints with state
regulators in an effort to resolve grievances relating to oil
and natural gas gathering access and rate discrimination. Other
state regulations may not directly regulate our business, but
may nonetheless affect the availability of natural gas for
purchase, processing and sale, including state regulation of
production rates and maximum daily production allowable from gas
wells. While our proprietary gathering lines currently are
subject to limited state regulation, there is a risk that state
laws will be changed, which may give producers a stronger basis
to challenge proprietary
21
status of a line, or the rates, terms and conditions of a
gathering line providing transportation service. Please read
Item 1. Business Regulation of Operations.
We are
subject to compliance with stringent environmental laws and
regulations that may expose us to significant costs and
liabilities.
Our operations are subject to stringent and complex federal,
state and local environmental laws and regulations governing the
discharge of materials into the environment or otherwise to
environmental protection. These laws and regulations may impose
numerous obligations that are applicable to our operations
including the acquisition of permits to conduct regulated
activities, the incurrence of capital expenditures to limit or
prevent releases of materials from our pipelines and facilities,
and the imposition of substantial liabilities for pollution
resulting from our operations. Numerous governmental
authorities, such as the U.S. Environmental Protection
Agency, also known as the EPA, and analogous state
agencies, have the power to enforce compliance with these laws
and regulations and the permits issued under them, oftentimes
requiring difficult and costly actions. Failure to comply with
these laws, regulations, and permits may result in the
assessment of administrative, civil, and criminal penalties, the
imposition of remedial obligations, and the issuance of
injunctions limiting or preventing some or all of our operations.
There is inherent risk of incurring significant environmental
costs and liabilities in connection with our operations due to
our handling of petroleum hydrocarbons and wastes, air emissions
and water discharges related to our operations, and historical
industry operations and waste disposal practices. Joint and
several, strict liability may be incurred under these
environmental laws and regulations in connection with discharges
or releases of petroleum hydrocarbons and wastes on, under or
from our properties and facilities, many of which have been used
for midstream activities for a number of years, oftentimes by
third parties not under our control. Private parties, including
the owners of properties through which our gathering systems
pass and facilities where our petroleum hydrocarbons or wastes
are taken for reclamation or disposal, may also have the right
to pursue legal actions to enforce compliance as well as to seek
damages for non-compliance with environmental laws and
regulations or for personal injury or property damage. In
addition, changes in environmental laws and regulations occur
frequently, and any such changes that result in more stringent
and costly waste handling, storage, transport, disposal, or
remediation requirements could have a material adverse effect on
our operations or financial position. We may not be able to
recover some or any of these costs from insurance. See
Item 1. Business Environmental Matters.
Our
construction of new assets may not result in revenue increases
and is subject to regulatory, environmental, political, legal
and economic risks, which could adversely affect our results of
operations and financial condition.
One of the ways we intend to grow our business is through the
construction of new midstream assets. The construction of
additions or modifications to our existing systems and the
construction of new midstream assets involve numerous
regulatory, environmental, political and legal uncertainties
beyond our control and may require the expenditure of
significant amounts of capital. If we undertake these projects,
they may not be completed on schedule or at the budgeted cost,
or at all. Moreover, our revenues may not increase immediately
upon the expenditure of funds on a particular project. For
instance, if we expand a pipeline, the construction may occur
over an extended period of time, and we will not receive any
material increases in revenues until the project is completed.
Moreover, we may construct facilities to capture anticipated
future growth in production in a region in which such growth
does not materialize. Since we are not engaged in the
exploration for and development of natural gas and oil reserves,
we often do not have access to third-party estimates of
potential reserves in an area prior to constructing facilities
in such area. To the extent we rely on estimates of future
production in our decision to construct additions to our
systems, such estimates may prove to be inaccurate because there
are numerous uncertainties inherent in estimating quantities of
future production. As a result, new facilities may not be able
to attract enough throughput to achieve our expected investment
return, which could adversely affect our results of operations
and financial condition. In addition, the construction of
additions to our existing gathering and transportation assets
may require us to obtain new
rights-of-way
prior to constructing new pipelines. We may be unable to obtain
such
rights-of-way
to connect new natural gas
22
supplies to our existing gathering lines or capitalize on other
attractive expansion opportunities. Additionally, it may become
more expensive for us to obtain new
rights-of-way
or to renew existing
rights-of-way.
If the cost of renewing or obtaining new
rights-of-way
increases, our cash flows could be adversely affected.
If we
do not make acquisitions on economically acceptable terms, our
future growth will be limited.
Our ability to grow depends, in part, on our ability to make
acquisitions that result in an increase in the cash generated
from operations per unit. If we are unable to make these
accretive acquisitions either because we are: (1) unable to
identify attractive acquisition candidates or negotiate
acceptable purchase contracts with them, (2) unable to
obtain financing for these acquisitions on economically
acceptable terms, or (3) outbid by competitors, then our
future growth and ability to increase distributions will be
limited. Furthermore, even if we do make acquisitions that we
believe will be accretive, these acquisitions may nevertheless
result in a decrease in the cash generated from operations per
unit.
Any acquisition involves potential risks, including, among other
things:
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mistaken assumptions about volumes, revenues and costs,
including synergies;
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an inability to integrate successfully the businesses we acquire;
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inadequate expertise for new geographic areas, operations or
products and services;
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the assumption of unknown liabilities;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt;
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the diversion of managements and employees attention
from other business concerns;
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unforeseen difficulties operating in new product areas or new
geographic areas;
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customer or key employee losses at the acquired
businesses; and
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establishment of internal controls and procedures that we are
required to maintain under the Sarbanes-Oxley Act of 2002.
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If we consummate any future acquisitions, our capitalization and
results of operations may change significantly, and the limited
partners will not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider
in determining the application of these funds and other
resources.
Our acquisition strategy is based, in part, on our expectation
of ongoing divestitures of energy assets by industry
participants. A material decrease in such divestitures would
limit our opportunities for future acquisitions and could
adversely affect our operations and cash flows available for
distribution to our unitholders.
We do
not own all of the land on which our pipelines and facilities
are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and
facilities have been constructed, and we are therefore subject
to the possibility of more onerous terms
and/or
increased costs to retain necessary land use if we do not have
valid rights of way or if such rights of way lapse or terminate.
We obtain the rights to construct and operate our pipelines on
land owned by third parties and governmental agencies for a
specific period of time. Our loss of these rights, through our
inability to renew
right-of-way
contracts or otherwise, could have a material adverse effect on
our business, results of operations and financial condition and
our ability to make cash distributions.
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Our
business involves many hazards and operational risks, some of
which may not be fully covered by insurance. If a significant
accident or event occurs that is not fully insured, our
operations and financial results could be adversely
affected.
Our operations are subject to many hazards inherent in the
gathering, compressing, treating, processing and transporting of
natural gas and NGLs, including:
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damage to pipelines and plants, related equipment and
surrounding properties caused by hurricanes, tornadoes, floods,
fires and other natural disasters and acts of terrorism;
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inadvertent damage from construction, farm and utility equipment;
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leaks of natural gas, NGLs and other hydrocarbons or losses of
natural gas or NGLs as a result of the malfunction of equipment
or facilities;
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fires and explosions; and
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other hazards that could also result in personal injury and loss
of life, pollution and suspension of operations.
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These risks could result in substantial losses due to personal
injury
and/or loss
of life, severe damage to and destruction of property and
equipment and pollution or other environmental damage and may
result in curtailment or suspension of our related operations. A
natural disaster or other hazard affecting the areas in which we
operate could have a material adverse effect on our operations.
We are not fully insured against all risks inherent to our
business. For example, we do not have any property insurance on
any of our underground pipeline systems that would cover damage
to the pipelines. We are not insured against all environmental
accidents that might occur which may include toxic tort claims,
other than those considered to be sudden and accidental. If a
significant accident or event occurs that is not fully insured,
it could adversely affect our operations and financial
condition. In addition, we may not be able to maintain or obtain
insurance of the type and amount we desire at reasonable rates.
As a result of market conditions, premiums and deductibles for
certain of our insurance policies have increased substantially,
and could escalate further. In some instances, certain insurance
could become unavailable or available only for reduced amounts
of coverage. Additionally, we may be unable to recover from
prior owners of our assets, pursuant to our indemnification
rights, for potential environmental liabilities.
Our
debt levels may limit our flexibility in obtaining additional
financing and in pursuing other business
opportunities.
In December 2005, we entered into up to a $475.0 million
senior secured credit facility, consisting of up to a
$400.0 million term loan facility and up to a
$75.0 million revolving credit facility for our acquisition
of the ONEOK Texas natural gas gathering and processing assets.
The revolver facility was increased to $100.0 million in
June 2006. On August 31, 2006, we entered into an amended
and restated credit facility that provides for an aggregate of
approximately $500.0 million borrowing capacity, of which
we have the ability to incur up to $80.0 million of
additional debt, subject to limitations in our credit facility.
Our level of debt could have important consequences to us,
including the following:
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our ability to obtain additional financing, if necessary, for
working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available
on favorable terms;
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we will need a portion of our cash flow to make interest
payments on our debt, reducing the funds that would otherwise be
available for operations, future business opportunities and
distributions to unitholders;
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our debt level will make us more vulnerable to competitive
pressures or a downturn in our business or the economy
generally; and
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our debt level may limit our flexibility in responding to
changing business and economic conditions.
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Our ability to service our debt will depend upon, among other
things, our future financial and operating performance, which
will be affected by prevailing economic conditions and
financial, business, regulatory and other factors, some of which
are beyond our control. In addition, our ability to service debt
under our amended and restated credit facility will depend on
market interest rates, since we anticipate that the interest
rates applicable to our borrowings will fluctuate with movements
in interest rate markets. If our operating results are not
sufficient to service our current or future indebtedness, we
will be forced to take actions such as reducing distributions,
reducing or delaying our business activities, acquisitions,
investments or capital expenditures, selling assets,
restructuring or refinancing our debt, or seeking additional
equity capital. We may not be able to effect any of these
actions on satisfactory terms, or at all.
Restrictions
in our amended and restated credit facility limit our ability to
make distributions and limit our ability to capitalize on
acquisitions and other business opportunities.
Our amended and restated credit facility contains covenants
limiting our ability to make distributions, incur indebtedness,
grant liens, make acquisitions, investments or dispositions and
engage in transactions with affiliates. Furthermore, our amended
and restated credit facility contains covenants requiring us to
maintain certain financial ratios and tests. Any subsequent
replacement of our credit facility or any new indebtedness could
have similar or greater restrictions.
Increases
in interest rates, which have recently experienced record lows,
could adversely impact our unit price and our ability to issue
additional equity, to incur debt to make acquisitions or for
other purposes or to make cash distributions at our intended
levels.
The credit markets recently have experienced record lows in
interest rates over the past several years. As the overall
economy strengthens, it is likely that monetary policy will
continue to tighten further, resulting in higher interest rates
to counter possible inflation. 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
incur debt to make acquisitions or for other purposes or to make
cash distributions at our intended levels.
Due to
our lack of industry and geographic diversification, adverse
developments in our midstream operations or operating areas
would reduce our ability to make distributions to our
unitholders.
We rely on the revenues generated from our midstream energy
businesses, and as a result, our financial condition depends
upon prices of, and continued demand for, natural gas, NGLs and
condensate. Furthermore, all of our assets are located in the
Texas Panhandle, southeast Texas and Louisiana. Due to our lack
of diversification in industry type and location, an adverse
development in one of these businesses or operating areas would
have a significantly greater impact on our financial condition
and results of operations than if we maintained more diverse
assets and operating areas.
We are
exposed to the credit risks of our key producer customers, and
any material nonpayment or nonperformance by our key producer
customers could reduce our ability to make distributions to our
unitholders.
We are subject to risks of loss resulting from nonpayment or
nonperformance by our producer customers. Any material
nonpayment or nonperformance by our key producer customers could
reduce our ability to make distributions to our unitholders.
Furthermore, some of our producer customers may be highly
leveraged and subject to their own operating and regulatory
risks, which could increase the risk that they may default on
their obligations to us.
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Terrorist
attacks, and the threat of terrorist attacks, have resulted in
increased costs to our business. Continued hostilities in the
Middle East or other sustained military campaigns may adversely
impact our results of operations.
The long-term impact of terrorist attacks, such as the attacks
that occurred on September 11, 2001, and the threat of
future terrorist attacks on our industry in general, and on us
in particular, is not known at this time. Increased security
measures taken by us as a precaution against possible terrorist
attacks have resulted in increased costs to our business.
Uncertainty surrounding continued hostilities in the Middle East
or other sustained military campaigns may affect our operations
in unpredictable ways, including disruptions of crude oil
supplies and markets for refined products, and the possibility
that infrastructure facilities could be direct targets of, or
indirect casualties of, an act of terror.
Changes in the insurance markets attributable to terrorist
attacks may make certain types of insurance more difficult for
us to obtain. Moreover, the insurance that may be available to
us may be significantly more expensive than our existing
insurance coverage. Instability in the financial markets as a
result of terrorism or war could also affect our ability to
raise capital.
If we
fail to develop or maintain an effective system of internal
controls, we may not be able to report our financial results
accurately or prevent fraud.
Prior to our initial public offering, which was completed on
October 24, 2006, we have been a private company and have
not filed reports with the SEC. We produce our consolidated
financial statements in accordance with the requirements of
GAAP, but our internal accounting controls may not currently
meet all standards applicable to companies with publicly traded
securities. Effective internal controls are necessary for us to
provide reliable financial reports to prevent fraud and to
operate successfully as a publicly traded partnership. Our
efforts to develop and maintain our internal controls may not be
successful, and we may be unable to maintain effective controls
over our financial processes and reporting in the future,
including compliance with the obligations under Section 404
of the Sarbanes-Oxley Act of 2002, which we refer to as
Section 404. For example, Section 404 will require us,
among other things, annually to review and report on, and our
independent registered public accounting firm to attest to, our
internal control over financial reporting. We must comply with
Section 404 for our fiscal year ending December 31,
2007. Any failure to develop or maintain effective controls, or
difficulties encountered in their implementation or other
effective improvement of our internal controls could harm our
operating results or cause us to fail to meet our reporting
obligations. Given the difficulties inherent in the design and
operation of internal controls over financial reporting, we can
provide no assurance as to our, or our independent registered
public accounting firms, conclusions about the
effectiveness of our internal controls and we may incur
significant costs in our efforts to comply with
Section 404. Ineffective internal controls subject us to
regulatory scrutiny and a loss of confidence in our reported
financial information, which could have an adverse effect on our
business and would likely have a negative effect on the trading
price of our common units.
Risks
Inherent in an Investment in Us
We may
not have sufficient cash from operations following the
establishment of cash reserves and payment of fees and expenses,
including cost reimbursements to our general partner, to enable
us to make cash distributions to holders of our common units and
subordinated units at the initial distribution rate under our
cash distribution policy.
In order to make our cash distributions at our initial
distribution rate of $0.3625 per common unit per complete
quarter, or $1.45 per unit per year, we will require
available cash of approximately $15.3 million per quarter,
or $61.2 million per year, based on the common units and
subordinated units outstanding as of the date of this report. We
may not have sufficient available cash from operating surplus
each quarter to enable us to make cash distributions at the
initial distribution rate under our cash distribution policy.
The amount of cash we can distribute on our units principally
depends upon the amount of cash we generate from our operations,
which will fluctuate from quarter to quarter based on, among
other things:
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the fees we charge and the margins we realize for our services;
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the prices of, level of production of, and demand for, natural
gas, NGLs and condensate;
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the volume of natural gas we gather, treat, compress, process,
transport and sell, and the volume of NGLs we transport and sell;
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the producers drilling activities and success of such
programs;
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the level of competition from other midstream energy companies;
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the level of our operating and maintenance and general and
administrative costs;
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the relationship between natural gas and NGL prices; and
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prevailing economic conditions.
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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 level of capital expenditures we make;
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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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restrictions contained in our debt agreements; and
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the amount of cash reserves established by our general partner.
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The
amount of cash we have available for distribution to holders of
our common units and subordinated units depends primarily on our
cash flow and not solely on profitability.
The amount of cash we have available for distribution depends
primarily upon our cash flow and not solely on profitability,
which will be affected by non-cash items. As a result, we may
make cash distributions during periods when we record losses for
financial accounting purposes and may not make cash
distributions during periods when we record net earnings for
financial accounting purposes.
The amount of available cash we need to pay the minimum
quarterly distribution for four quarters on our common units is
$30.0 million and $1.2 million as a full distribution
on our general partner units and a full distribution on our
subordinated units is $30.0 million, totaling
$61.2 million. The amount of our pro forma available cash
generated during the year ended December 31, 2005 and the
twelve months ended December 31, 2006 would not have been
sufficient to allow us to pay the full minimum quarterly
distribution on our common units and subordinated units for
those periods; however, it would have been sufficient to allow
us to pay the full minimum quarterly distribution on all of our
common units. For the February 15, 2007, cash distribution,
the common units received their full distribution for the
December 2006 quarter on an adjusted basis to reflect the timing
on the initial public offering. No distributions were made to
the general partner or subordinated units for the period.
We may not have sufficient available cash from operating surplus
each quarter to enable us to make cash distributions at the
initial distribution rate under our cash distribution policy.
Eagle
Rock Holdings, L.P., owns a 54.0% limited partner interest in us
and will control our general partner, which has sole
responsibility for conducting our business and managing our
operations. Our general partner has conflicts of interest, which
may permit it to favor its own interests.
Eagle Rock Holdings, L.P, owns and controls our general partner.
Holdings is owned and controlled by the NGP Investors. 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 our general partner have a fiduciary duty to manage
our general partner in a manner beneficial to its owners, the
NGP Investors. Conflicts of interest may arise
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between the NGP Investors and their affiliates, including our
general partner, on the one hand, and us and our unitholders, on
the other hand. In resolving these conflicts of interest, our
general partner may favor its own interests and the interests of
its affiliates over the interests of our unitholders. These
conflicts include, among others, the following situations:
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neither our partnership agreement nor any other agreement
requires the NGP Investors to pursue a business strategy that
favors us;
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our general partner is allowed to take into account the
interests of parties other than us in resolving conflicts of
interest;
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The NGP Investors and its affiliates are not limited in their
ability to compete with us;
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our general partner has limited its liability and reduced its
fiduciary duties, and has also restricted the remedies available
to our unitholders for actions that, without the limitations,
might constitute breaches of fiduciary duty;
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our general partner determines the amount and timing of asset
purchases and sales, borrowings, issuance of additional
partnership securities and reserves, each of which can affect
the amount of cash that is distributed to unitholders;
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our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is a
maintenance capital expenditure, which reduces operating
surplus, or an expansion capital expenditure, which does not
reduce operating surplus. This determination can affect the
amount of cash that is distributed to our unitholders and the
ability of the subordinated units to convert to common units;
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our general partner determines which costs incurred by it and
its affiliates are reimbursable by us;
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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 intends to limit its liability regarding our
contractual and other obligations and, in some circumstances, is
entitled to be indemnified by us;
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our general partner may exercise its limited right to call and
purchase common units if it and its affiliates own more than 80%
of the common units;
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our general partner controls the enforcement of obligations owed
to us by our general partner and its affiliates; and
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our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
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Affiliates
of our general partner are not limited in their ability to
compete with us, which could cause conflicts of interest and
limit our ability to acquire additional assets or businesses
which in turn could adversely affect our results of operations
and cash available for distribution to our
unitholders.
Affiliates of our general partner are not prohibited from owning
assets or engaging in businesses that compete directly or
indirectly with us. In addition, affiliates of our general
partner may acquire, construct or dispose of additional
midstream or other assets in the future, without any obligation
to offer us the opportunity to purchase or construct any of
those assets.
Cost
reimbursements due to our general partner and its affiliates for
services provided, which will be determined by our general
partner, will be substantial and will reduce our cash available
for distribution.
Prior to making distribution on our common units, we will
reimburse our general partner and its affiliates for all
expenses they incur on our behalf. These expenses will include
all costs incurred by our general partner and its affiliates in
managing and operating us, including costs for rendering
corporate staff and support
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services to us, and there is no limit on the amount of expenses
for which our general partner and its affiliates may be
reimbursed. Our partnership agreement provides that our general
partner will determine the expenses that are allocable to us in
good faith. 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
general partner intends to limit its liability regarding our
obligations.
Our general partner intends to limit its liability under
contractual arrangements so that the other party has recourse
only to our assets, and not against our general partner or its
assets. Our general partner therefore may cause us to incur
indebtedness or other obligations that are nonrecourse to it.
The partnership agreement provides that any action taken by our
general partner to limit its liability is not a breach of our
general partners fiduciary duties, even if we could have
obtained more favorable terms without the limitation on
liability.
Our
partnership agreement requires that we distribute all of our
available cash, which could limit our ability to grow and make
acquisitions.
We expect that we will distribute all of our available cash to
our unitholders. As a result, we expect that we will rely
primarily upon external financing sources, including commercial
bank borrowings and the issuance of debt and equity securities,
to fund our acquisitions and expansion capital expenditures. As
a result, to the extent we are unable to finance growth
externally, our cash distribution policy will significantly
impair our ability to grow.
In addition, because we distribute all of our available cash,
our growth may not be as fast as businesses that reinvest their
available cash to expand ongoing operations. To the extent we
issue additional units in connection with any acquisitions or
expansion capital expenditures, the payment of distributions on
those additional units may increase the risk that we will be
unable to maintain or increase our per unit distribution level.
There are no limitations in our partnership agreement or our
amended and restated credit facility on our ability to issue
additional units, including units ranking senior to the common
units. The incurrence of additional commercial borrowings or
other debt to finance our growth strategy would result in
increased interest expense, which in turn may impact the
available cash that we have to distribute to our unitholders.
Our
partnership agreement limits our general partners
fiduciary duties to holders of our common units and subordinated
units.
Although our general partner has a fiduciary duty to manage us
in a manner beneficial to us and our unitholders, the directors
and officers of 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 would otherwise be held
by state fiduciary duty laws. For example, our partnership
agreement permits our general partner to make a number of
decisions in its individual capacity, as opposed to in its
capacity as our general partner or otherwise free of fiduciary
duties to us and our unitholders, including determining how to
allocate corporate opportunities among us and our affiliates.
This entitles our general partner to consider only the interests
and factors that it desires, and it has no duty or obligation to
give any consideration to any interest of, or factors affecting,
us, our affiliates or any limited partner. Examples include:
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its limited call right;
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its voting rights with respect to the units it owns;
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its registration rights; and
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and its determination whether or not to consent to any merger or
consolidation of the partnership or amendment to the partnership
agreement.
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Our
partnership agreement restricts the remedies available to
holders of our common units and subordinated units for actions
taken by our general partner that might otherwise constitute
breaches of fiduciary duty.
Our partnership agreement contains provisions that modify and
limit our general partners fiduciary duties to our
unitholders. Our partnership agreement also contains provisions
that restrict the remedies available to unitholders for actions
taken by our general partner that might otherwise constitute
breaches of fiduciary duty. For example, our partnership
agreement:
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provides that whenever our general partner makes a determination
or takes, or declines to take, any other action in its capacity
as our general partner, our general partner is required to make
such determination, or take or decline to take such other action
in good faith, and our general partner will not be subject to
any other or different standard imposed by our partnership
agreement, Delaware law or any other law, rule or regulation or
at equity;
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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, and our
partnership agreement specifies that the satisfaction of this
standard requires that our general partner must believe that the
decision is in the best interests of our partnership;
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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; and
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provides that our general partner will not be in breach of its
obligations under the partnership agreement or its fiduciary
duties to us or our unitholders if the resolution of a conflict
is:
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approved by the conflicts committee of our general partner,
although our general partner is not obligated to seek such
approval;
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approved by the vote of a majority of the outstanding common
units, excluding any common units owned by our general partner
or any of its affiliates;
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on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
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fair and reasonable to us, taking into account the totality of
the relationships among the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
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In connection with a situation involving a conflict of interest,
any determination by our general partner involving the
resolution of the conflict of interest must be made in good
faith, provided that, if our general partner does not seek
approval from the conflicts committee and its board of directors
determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the
standards set forth in the third and fourth bullet points above,
then it will be presumed that, in making its decision, the board
of directors acted in good faith, and in any proceeding brought
by or on behalf of any limited partner or the partnership, the
person bringing or prosecuting such proceeding will have the
burden of overcoming such presumption.
Holders
of our common units have limited voting rights and are not
entitled to elect our general partner or its
directors.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence
managements decisions regarding our business. Unitholders
will not elect our general partner or its board of directors,
and will have no right to elect our general partner or its board
of directors on an annual or other continuing basis. The board
of directors of Eagle Rock Energy G&P, LLC, the general
partner of our general partner, has been and will be
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chosen by the members of Eagle Rock Energy G&P, LLC.
Furthermore, if the unitholders were dissatisfied with the
performance of our general partner, they will have little
ability to remove our general partner. As a result of these
limitations, the price at which the common units will trade
could be diminished because of the absence or reduction of a
takeover premium in the trading price.
Even
if holders of our common units are dissatisfied, they cannot
initially remove our general partner without its
consent.
The unitholders will be unable initially to remove our general
partner without its consent because our general partner and its
affiliates own sufficient units to be able to prevent its
removal. The vote of the holders of at least
662/3%
of all outstanding units voting together as a single class is
required to remove the general partner. Our general partner and
its affiliates own 55.1% of our aggregate outstanding common and
subordinated units. Also, if our general partner is removed
without cause during the subordination period (which in general
is expected to end in late 2009, unless we distribute at least
$2.175 for the period ending September 30, 2007) and
units held by our general partner and its affiliates are not
voted in favor of that removal, all remaining subordinated units
will automatically convert into common units and any existing
arrearages on our common units will be extinguished. A removal
of our general partner under these circumstances would adversely
affect our common units by prematurely eliminating their
distribution and liquidation preference over our subordinated
units, which would otherwise have continued until we had met
certain distribution and performance tests. Cause is narrowly
defined to mean that a court of competent jurisdiction has
entered a final, non-appealable judgment finding the general
partner liable for actual fraud or willful or wanton misconduct
in its capacity as our general partner. Cause does not include
most cases of charges of poor management of the business, so the
removal of the general partner because of the unitholders
dissatisfaction with our general partners performance in
managing our partnership will most likely result in the
termination of the subordination period and conversion of all
subordinated units to common units.
Our
partnership agreement restricts the voting rights of unitholders
owning 20% or more of our common units.
Unitholders voting rights are further restricted by the
partnership agreement provision providing that any units held by
a person that owns 20% or more of any class of units then
outstanding, other than our general partner, its affiliates,
their transferees and persons who acquired such units with the
prior approval of the board of directors of our general partner,
cannot vote on any matter. Our partnership agreement also
contains provisions limiting the ability of unitholders to call
meetings or to acquire information about our operations, as well
as other provisions limiting the unitholders ability to
influence the manner or direction of management.
Control
of our general partner may be transferred to a third party
without unitholder consent.
Our general partner may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the
ability of the owners of our general partner or Eagle Rock
Energy G&P, LLC, from transferring all or a portion of their
respective ownership interest in our general partner or Eagle
Rock Energy G&P, LLC to a third party. The new owners of our
general partner or Eagle Rock Energy G&P, LLC would then be
in a position to replace the board of directors and officers of
Eagle Rock Energy G&P, LLC with its own choices and thereby
influence the decisions taken by the board of directors and
officers.
We may
issue additional units without limited partner approval, which
would dilute 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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31
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because a lower percentage of total outstanding units will be
subordinated units, the risk that a shortfall in the payment of
the minimum quarterly distribution will be borne by our common
unitholders will increase;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit
may be diminished; and
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the market price of the common units may decline.
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Affiliates
of our general partner, certain private investors, and
employees, may sell common units in the public markets, which
sales could have an adverse impact on the trading price of the
common units.
Management of Eagle Rock Energy G&P, LLC, the general
partner of our general partner and the NGP Investors and their
affiliates (both through their interests in Eagle Rock
Holdings), certain private investors, including the selling
unitholders, and certain employees of Eagle Rock Energy G&P,
LLC hold an aggregate of 6,851,960 common units, including
122,450 common units which are subject to an overall three-year
vesting requirement, and 20,691,495 subordinated units. All of
the subordinated units will convert into common units at the end
of the subordination period and some may convert earlier. The
sale of these units in the public markets could have an adverse
impact on the price of the common units or on any trading market
that may develop. In addition, we have entered into a
registration rights agreement with Eagle Rock Holdings, which
requires us to file with the SEC a registration statement within
90 days of our receipt of a request from Eagle Rock
Holdings to file a registration statement and to have such
registration statement become effective within 180 days of
receipt of such request. Following the effective date of the
registration statement and the expiration of any
lock-up
agreements applicable to the selling unitholders and Eagle Rock
Holding, these holders may sell their common units into the
public markets.
Our
general partner has a limited call right that may require
limited partners to sell their units at an undesirable time or
price.
If at any time our general partner and its affiliates own more
than 80% of the common units, our general partner will have the
right, but not the obligation, which it may assign to any of its
affiliates or to us, to acquire all, but not less than all, of
the common units held by unaffiliated persons at a price not
less than their then-current market price. As a result, the
limited partners may be required to sell their common units at
an undesirable time or price and may not receive any return on
their investment. Limited partners may also incur a tax
liability upon a sale of units. Our general partner and its
affiliates will own approximately 10.5% of our outstanding
common units. At the end of the subordination period, assuming
no additional issuances of common units, our general partner and
its affiliates will own approximately 55.1% of our outstanding
common units.
Liability
of a limited partner 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.
Limited partners could be liable for any and all of our
obligations as a general partner if:
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a court or government agency determined that we were conducting
business in a state but had not complied with that particular
states partnership statute; or
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the 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 constitute control of our business.
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32
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 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.
The
price of our common units may fluctuate
significantly.
Prior to October 24, 2006, there was no public market for
the common units. The lack of a liquid market in our common
units may result in wide bid-ask spreads, contribute to
significant fluctuations in the market price of the common units
and limit the number of investors who are able to buy the common
units.
The market price of our common units may be influenced by many
factors, some of which are beyond our control, including:
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our quarterly distributions;
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our quarterly or annual earnings or those of other companies in
our industry;
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loss of a large customer;
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announcements by us or our competitors of significant contracts
or acquisitions;
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changes in accounting standards, policies, guidance,
interpretations or principles;
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general economic conditions;
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the failure of securities analysts to cover our common units or
changes in financial estimates by analysts;
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future sales of our common units; and
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other factors described in these Risk Factors.
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We
will incur increased costs as a result of being a publicly
traded partnership.
We have little history operating as a publicly traded
partnership. As a publicly traded partnership, we will incur
significant legal, accounting and other expenses that we did not
incur as a private company. In addition, the Sarbanes-Oxley Act
of 2002, as well as new rules subsequently implemented by the
SEC and the NASDAQ Global Market, have required changes in
corporate governance practices of publicly traded companies. We
expect these new rules and regulations to increase our legal and
financial compliance costs and to make activities more
time-consuming and costly. For example, as a result of becoming
a publicly traded partnership, we are required to have at least
three independent directors, create additional board committees
and adopt policies regarding internal controls and disclosure
controls and procedures, including the preparation of reports on
internal controls over financial reporting. In addition, we will
incur additional costs associated with our publicly traded
company reporting requirements. We also expect these new rules
and regulations to make it more difficult and more expensive for
our general partner to obtain director and officer liability
insurance and it may be required to accept reduced policy limits
and coverage or incur substantially higher costs to obtain the
same or similar coverage. As a result, it may be more difficult
for our general partner to attract and retain qualified persons
to serve on its board of directors or as executive officers. We
have included approximately $2.5 million of estimated
incremental costs per year associated with being a publicly
traded
33
partnership for purposes of our financial forecast range;
however, it is possible that our actual incremental costs of
being a publicly traded partnership will be higher than we
currently estimate.
Tax Risks
to Common Unitholders
The
tax efficiency of our partnership structure depends on our
status as a partnership for federal income tax purposes, as well
as our not being subject to a material amount of entity-level
taxation by individual states. If the Internal Revenue Service
were to treat us as a corporation or if 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.
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the
Internal Revenue Service, which we refer to as the IRS, on this
or any other tax matter affecting us.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of 35%
and would likely pay state income tax at varying rates.
Distributions would generally be taxed again as corporate
distributions, and no income, gains, losses or deductions would
flow through to the limited partners. Because a tax would be
imposed upon us as a corporation, our cash available for
distribution would be substantially reduced. Therefore,
treatment of us as a corporation would result in a material
reduction in the anticipated cash flow and after-tax return to
the unitholders, likely causing a substantial reduction in the
value of our common units.
Current law may change so as to cause us to be treated as a
corporation for federal income tax purposes or otherwise subject
us to entity-level taxation. In addition, because of widespread
state budget deficits and other reasons, several states are
evaluating ways to subject partnerships to entity-level taxation
through the imposition of state income, franchise and other
forms of taxation. We will, for example, be subject to a new
entity level tax on the portion of our income that is generated
in Texas beginning in our tax year ending December 31,
2007. Specifically, the Texas tax will be imposed at a maximum
effective rate of 1.0% of our gross income apportioned to Texas.
Imposition of such a tax on us by Texas, or any other state,
will reduce the cash available for distribution. 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 amounts will be adjusted to reflect the impact of
that law on us.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely impacted and the
cost of any IRS contest will reduce our cash available for
distribution.
We have not requested a ruling from the IRS with respect to our
treatment as a partnership for federal income tax purposes or
any other matter affecting us. The IRS may adopt positions that
differ from the conclusions of our counsel expressed in this
report or from the positions we take. It may be necessary to
resort to administrative or court proceedings to sustain some or
all of our counsels conclusions or the positions we take.
A court may not agree with some or all of our counsels
conclusions or positions we take. Any contest with the IRS may
materially and adversely impact the market for our common units
and the price at which they trade. In addition, our costs of any
contest with the IRS will be borne indirectly by our unitholders
and our general partner because the costs will reduce our cash
available for distribution.
Limited
partners may be required to pay taxes on their share of our
income even if they do not receive any cash distributions from
us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income which could be different in amount
than the cash we distribute, limited partners will be required
to pay any federal income taxes and, in some cases, state and
local income taxes on their share of our taxable income even if
no cash distributions were received from us. Limited partners
may not receive cash distributions from us equal to their share
of our taxable income or even equal to the actual tax liability
that results from that income.
34
Tax
gain or loss on disposition of our common units could be more or
less than expected.
If a limited partner sells common units, the limited partner
will recognize a gain or loss equal to the difference between
the amount realized and the tax basis in those common units.
Prior distributions to a limited partner in excess of the total
net taxable income allocated for a common unit, which decreased
the limited partners tax basis in that common unit, will,
in effect, become taxable income to the limited partner if the
common unit is sold at a price greater than their tax basis in
that common unit, even if the price received is less than the
original cost. A substantial portion of the amount realized,
whether or not representing gain, may be ordinary income. In
addition, if a limited partner sells units, the limited partner
may incur a tax liability in excess of the amount of cash
received from the sale.
Tax-exempt
entities and foreign persons face unique tax issues from owning
common units that may result in adverse tax consequences to
them.
Investment in common units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), other retirement
plans and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal
income tax, including IRAs and other retirement plans, will be
unrelated business taxable income and will be taxable to them.
Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file United States federal tax returns and
pay tax on their share of our taxable income. If a limited
partner is a tax-exempt entity or a foreign person, the limited
partner should consult a tax advisor before investing in our
common units.
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 adopt 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 the limited partners. It also could affect
the timing of these tax benefits or the amount of gain from
sales of common units and could have a negative impact on the
value of our common units or result in audit adjustments to tax
returns of our limited partners.
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. 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.
Limited
partners will likely be subject to state and local taxes and
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, a limited partner will
likely be subject to other taxes, including foreign, 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
the limited partner does not live in any of those jurisdictions.
A limited partner will likely be required to file foreign, state
and local income tax returns and pay state and local income
taxes in some or all of these various jurisdictions. Further, a
limited partner may be subject to penalties for failure to
comply with those requirements. We own assets and conduct
business in the States of Louisiana, Texas and Oklahoma. 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 conduct business in additional states that
impose a personal income tax. It is a limited partners
35
responsibility to file all United States federal, foreign, state
and local tax returns. Our counsel has not rendered an opinion
on the foreign, state or local tax consequences of an investment
in our common units.
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Item 1B.
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Unresolved
Staff Comments.
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This item is not applicable to us.
A description of our properties is contained in Item 1.
Business of this Annual Report. Substantially all of our
pipelines are constructed on
rights-of-way
granted by the apparent record owners of the property. Lands
over which pipeline
rights-of-way
have been obtained may be subject to prior liens that have been
subordinated to the
rights-of-way
grants. We have obtained, where necessary, license or permit
agreements from public authorities and railroad companies to
cross over or under, or to lay facilities in or along,
waterways, county or parish roads, municipal streets, railroad
properties and state highways, as applicable. In some cases,
property on which our pipeline was built was purchased in fee.
Some of our leases, easements,
rights-of-way,
permits, licenses and franchise ordinances require the consent
of the current landowner to transfer these rights, which in some
instances is a governmental entity. We believe that we have
obtained sufficient third-party consents, permits and
authorizations for the transfer of the assets necessary for us
to operate our business in all material respects. With respect
to any consents, permits or authorizations that have not been
obtained, we believe that the failure to obtain these consents,
permits or authorizations will have no material adverse effect
on the operation of our business.
We believe that we have satisfactory title to our assets. Title
to property may be subject to encumbrances. We believe that none
of these encumbrances will materially detract from the value of
our properties or from our interest in these properties nor will
they materially interfere with their use in the operation or our
business.
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Item 3.
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Legal
Proceedings.
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We and our subsidiaries may become party to legal proceedings
which arise from time to time in the ordinary course of
business. While the outcome of these proceedings cannot be
predicted with certainty, we do not expect these matters to have
a material adverse effect on the financial statements.
We carry insurance with coverage and coverage limits consistent
with our assessment of risks in our business and of an
acceptable level of financial exposure. Although there can be no
assurance such insurance will be sufficient to mitigate all
damages, claims or contingencies, we believe our insurance
provides reasonable coverage for known asserted or unasserted
claims. In the event we sustain a loss from a claim and the
insurance carrier disputed coverage or coverage limits, we may
record a charge in a different period than the recovery, if any,
from the insurance carrier.
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Item 4.
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Submission
of Matters to a Vote of Security Holders.
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None.
36
PART II
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Item 5.
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Market
for Registrants Common Equity, Related Unitholder Matters
and Issuer Purchases of Equity Securities.
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Our common units have been listed on the NASDAQ Global Market
under the symbol EROC. The following table sets
forth the high and low sales prices of our common units as
reported by the NASDAQ Global Market, as well as the amount of
cash distributions paid per quarter from our initial public
offering date, October 24, 2006, through December 31,
2006.
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Distributions
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per Common
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Quarter Ended
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High
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Low
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Unit(1)
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Record Date(2)
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Payment Date(2)
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Through December 2006
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$
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20.70
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$
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17.50
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$
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0.27
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Feb. 7, 2007
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Feb. 15, 2007
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(1) |
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Represents a prorated distribution to the common unitholders
from the IPO date of October 24, 2006 through
December 31, 2006. |
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(2) |
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Approved by the Board of the Partnership on January 24,
2007. |
We have also issued 20,691,495 subordinated units, for which
there is no established market. There is one holder of record of
our subordinated units as of the date of this report.
The last reported sale price of our common units on the NASDAQ
Global Market on March 30, 2007, was $20.36. As of that date,
there were 21 holders of record and approximately 8,000
beneficial owners of our common units.
Cash
Distribution Policy
We will distribute to our unitholders, on a quarterly basis, all
of our available cash in the manner described below. Available
cash generally means, for any quarter ending prior to
liquidation, all cash on hand at the end of that quarter less
the amount of cash reserves that are necessary or appropriate in
the reasonable discretion of the general partner to:
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provide for the proper conduct of our business;
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comply with applicable law or any partnership debt instrument or
other agreement; or
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provide funds for distributions to unitholders and the general
partner in respect of any one or more of the next four quarters.
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In addition to distributions on its 2% general partner interest,
our general partner is entitled to receive incentive
distributions if the amount we distribute with respect to any
quarter exceeds levels specified in our partnership agreement.
Under the quarterly incentive distribution provisions, our
general partner is entitled, without duplication, to 15% of
amounts we distribute in excess of $0.4169 per unit, 25% of
the amounts we distribute in excess of $0.4531 per unit and
50% of amounts we distribute in excess of $0.5438 per unit.
Under the terms of the agreements governing our debt, we are
prohibited from declaring or paying any distribution to
unitholders if a default or event of default (as defined in such
agreements) exists. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Amended and Restated Credit Agreement.
37
Sales of
Unregistered Securities
On May 25, 2006, in connection with the formation of Eagle
Rock Energy Partners, L.P. (the Partnership), the
Partnership issued to (i) its general partner the 2%
general partner interest in the Partnership for $20 and
(ii) Eagle Rock Holdings, L.P., the 98% limited partner
interest in the Partnership for $980. The issuance was exempt
from registration under Section 4(2) of the Securities Act.
There have been no other sales of unregistered securities within
the past three years.
On March 27, 2006, certain private investors contributed
$98.3 million to Eagle Rock Pipeline, L.P., which became
our operating partnership, in exchange for 5,455,050 common
units in Eagle Rock Pipeline, L.P. In June 2006, we purchased
all of the partnership interests in Midstream Gas Services, L.P.
for approximately $4.7 million in cash and 1,125,416 common
units in Eagle Rock Pipeline, L.P. In addition, if Midstream Gas
Services, L.P. achieves certain financial objectives for the
year ending December 31, 2007, we will issue up to 798,155
of our common units as a contingent earn-out payment to Natural
Gas Partners VII, L.P., as the primary equity owner of Midstream
Gas Services. Upon completion of the initial public offering,
the 6,580,466 common units in Eagle Rock Pipeline, L.P. were
converted into common units in Eagle Rock Energy Partners, L.P.
on approximately a
1-for-0.719
common unit basis. All of these interests in Eagle Rock Pipeline
were converted into common units in us upon consummation of the
initial public offering.
38
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Item 6.
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Selected
Financial Data.
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The financial data should be read in conjunction with our
audited consolidated financial statements included in the Index
to Consolidated Financial Statements on
page F-1
of this Report. See also Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
The following table includes selected financial data for the
Partnership or its predecessor for the years ended
December 31, 2006, 2005 and 2004.
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Eagle Rock Energy Partners, L.P.
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For the Year Ended December 31,
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2006
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2005
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2004
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($ in thousands)
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Statement of Operations
Data:
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Operating revenues
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$
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502,394
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$
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66,382
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$
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10,636
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Unrealized derivative
gains/(losses)
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(26,306
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)
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7,308
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Realized derivative gains
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2,302
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Total operating revenues
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478,390
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73,690
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10,636
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Cost of natural gas and NGLs
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377,580
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55,272
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8,811
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Operating and maintenance expense
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32,905
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2,955
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34
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General and administrative expense
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13,161
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4,765
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2,406
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Advisory termination fee
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6,000
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Depreciation and amortization
expense
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43,220
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4,088
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619
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Operating Income
(loss)
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5,524
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6,610
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(1,234
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)
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Interest and other (income)
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(996
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)
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(171
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)
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|
|
(24
|
)
|
Interest and other expense
|
|
|
28,604
|
|
|
|
4,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income
taxes
|
|
|
(22,084
|
)
|
|
|
2,750
|
|
|
|
(1,210
|
)
|
Income tax provision
|
|
|
1,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing
operations
|
|
|
(23,314
|
)
|
|
|
2,750
|
|
|
|
(1,210
|
)
|
Income from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
22,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(23,314
|
)
|
|
$
|
2,750
|
|
|
$
|
20,982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per unit from
continuing operations
basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
(1.26
|
)
|
|
$
|
0.11
|
|
|
$
|
(0.05
|
)
|
Subordinated units
|
|
$
|
(0.43
|
)
|
|
$
|
|
|
|
$
|
|
|
General partner
|
|
$
|
(0.80
|
)
|
|
$
|
4.06
|
|
|
$
|
(0.05
|
)
|
Balance Sheet Data (at period
end):
|
|
|
|
|
|
|
|
|
|
|
|
|
Property plant and equipment, net
|
|
$
|
554,063
|
|
|
$
|
441,588
|
|
|
$
|
19,564
|
|
Total assets
|
|
|
779,901
|
|
|
|
700,659
|
|
|
|
28,017
|
|
Long-term debt
|
|
|
405,731
|
|
|
|
408,466
|
|
|
|
|
|
Net equity
|
|
|
291,987
|
|
|
|
208,096
|
|
|
|
27,655
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by (used
in):
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
54,992
|
|
|
$
|
(1,667
|
)
|
|
$
|
3,652
|
|
Investing activities
|
|
|
(134,873
|
)
|
|
|
(543,501
|
)
|
|
|
16,918
|
|
Financing activities
|
|
|
71,088
|
|
|
|
556,304
|
|
|
|
(13,955
|
)
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit(1)
|
|
$
|
100,810
|
|
|
$
|
18,418
|
|
|
$
|
1,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(2)
|
|
$
|
81,192
|
|
|
$
|
3,390
|
|
|
$
|
(615
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Defined as operating revenues minus the cost of natural gas and
NGLs and other cost of sales. Operating revenues include both
realized and unrealized risk management activities. |
|
(2) |
|
Defined as net income (loss) plus income tax, interest-net,
depreciation and amortization expense, other non-cash operating
expenses less non realized revenues risk management loss (gain)
activities and less net income from discontinued operations. |
39
GAAP to
Non GAAP Reconciliations for the Years 2006, 2005 and
2004
Segment
Profit reconciliation to Net Income (Loss)
The following table reconciles Segment Profit to Net Income
(loss) on a
year-to-year
basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ending December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
($ in thousands)
|
|
|
Segment Profit:
|
|
$
|
100,810
|
|
|
$
|
18,418
|
|
|
$
|
1,825
|
|
Less
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
32,905
|
|
|
|
2,955
|
|
|
|
34
|
|
General and administrative expense
|
|
|
13,161
|
|
|
|
4,765
|
|
|
|
2,406
|
|
Depreciation and amortization
expense
|
|
|
43,220
|
|
|
|
4,088
|
|
|
|
619
|
|
Interest-net
including realized risk management instrument
|
|
|
30,383
|
|
|
|
5,459
|
|
|
|
(24
|
)
|
Unrealized risk management
interest related instrument
|
|
|
(2,775
|
)
|
|
|
(1,599
|
)
|
|
|
|
|
Advisory termination fee
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
Income tax provision
|
|
|
1,230
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
22,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income as
reported
|
|
$
|
(23,314
|
)
|
|
$
|
2,750
|
|
|
$
|
20,982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA reconciliation to Net Income (Loss)
The following table reconciles Adjusted EBITDA to Net Income
(loss) on a
year-to-year
basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ending December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
($ in thousands)
|
|
|
Adjusted EBITDA:
|
|
$
|
81,192
|
|
|
$
|
3,390
|
|
|
$
|
(615
|
)
|
Less
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision
|
|
|
1,230
|
|
|
|
|
|
|
|
|
|
Interest-net
including realized risk management instrument
|
|
|
30,383
|
|
|
|
5,459
|
|
|
|
(24
|
)
|
Unrealized risk management
interest related instrument
|
|
|
(2,775
|
)
|
|
|
(1,599
|
)
|
|
|
|
|
Depreciation and amortization
expense
|
|
|
43,220
|
|
|
|
4,088
|
|
|
|
619
|
|
Restricted units amortization
expense
|
|
|
142
|
|
|
|
|
|
|
|
|
|
Advisory termination fee
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
22,192
|
|
Plus
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management
instrument-unrealized
|
|
|
(26,306
|
)
|
|
|
7,308
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income as
reported
|
|
$
|
(23,314
|
)
|
|
$
|
2,750
|
|
|
$
|
20,982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
The following table summarizes our quarterly financial data for
2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarters Ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
June 30,
|
|
|
March 31,
|
|
|
|
2006
|
|
|
2006
|
|
|
2006
|
|
|
2006
|
|
|
|
($ in thousands)
|
|
|
Sales of natural gas, NGLs and
condensate
|
|
$
|
113,909
|
|
|
$
|
132,830
|
|
|
$
|
123,250
|
|
|
$
|
116,922
|
|
Gathering and treating services
|
|
|
4,367
|
|
|
|
4,549
|
|
|
|
4,192
|
|
|
|
1,754
|
|
Risk management
instrument realized transactions
|
|
|
2,180
|
|
|
|
(449
|
)
|
|
|
(240
|
)
|
|
|
811
|
|
Risk management
instrument unrealized
|
|
|
(4,975
|
)
|
|
|
14,480
|
|
|
|
(14,931
|
)
|
|
|
(20,881
|
)
|
Other revenues
|
|
|
185
|
|
|
|
109
|
|
|
|
147
|
|
|
|
180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating
revenues
|
|
|
115,666
|
|
|
|
151,519
|
|
|
|
112,418
|
|
|
|
98,787
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of natural gas and NGLs
|
|
|
88,699
|
|
|
|
100,645
|
|
|
|
93,807
|
|
|
|
94,429
|
|
Segment profit
|
|
|
26,967
|
|
|
|
50,873
|
|
|
|
18,610
|
|
|
|
4,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
9,013
|
|
|
|
9,227
|
|
|
|
8,881
|
|
|
|
5,784
|
|
General and administrative expense
|
|
|
4,052
|
|
|
|
2,965
|
|
|
|
3,683
|
|
|
|
2,461
|
|
Advisory termination fee
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
expense
|
|
|
11,762
|
|
|
|
11,244
|
|
|
|
11,001
|
|
|
|
9,214
|
|
Interest net including
realized risk management instrument
|
|
|
7,490
|
|
|
|
7,881
|
|
|
|
7,541
|
|
|
|
7,471
|
|
Unrealized risk management
interest related instrument
|
|
|
(136
|
)
|
|
|
6,449
|
|
|
|
(4,113
|
)
|
|
|
(4,975
|
)
|
Income tax provision
|
|
|
486
|
|
|
|
236
|
|
|
|
508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(11,700
|
)
|
|
$
|
12,872
|
|
|
$
|
(8,889
|
)
|
|
$
|
(15,597
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
19,019
|
|
|
$
|
24,202
|
|
|
$
|
20,978
|
|
|
$
|
16,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per unit
basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
(0.09
|
)
|
|
$
|
0.44
|
|
|
$
|
(0.31
|
)
|
|
$
|
(0.63
|
)
|
Subordinated units
|
|
$
|
(0.46
|
)
|
|
$
|
0.44
|
|
|
$
|
(0.31
|
)
|
|
$
|
(0.63
|
)
|
General partner
|
|
$
|
(0.46
|
)
|
|
$
|
0.44
|
|
|
$
|
(0.31
|
)
|
|
$
|
(0.63
|
)
|
41
The following table summarizes our quarterly financial data for
2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarters Ended
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
June 30,
|
|
|
March 31,
|
|
|
|
2005
|
|
|
2005
|
|
|
2005
|
|
|
2005
|
|
|
|
($ in thousands)
|
|
|
Sales of natural gas, NGLs and
condensate
|
|
$
|
43,839
|
|
|
$
|
6,255
|
|
|
$
|
5,030
|
|
|
$
|
4,797
|
|
Gathering and treating services
|
|
|
6,070
|
|
|
|
(292
|
)
|
|
|
239
|
|
|
|
230
|
|
Risk management
instrument realized transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management
instrument unrealized
|
|
|
7,308
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other revenues
|
|
|
214
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating
revenues
|
|
|
57,431
|
|
|
|
5,963
|
|
|
|
5,269
|
|
|
|
5,027
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of natural gas and NGLs
|
|
|
41,530
|
|
|
|
4,896
|
|
|
|
4,720
|
|
|
|
4,126
|
|
Segment profit
|
|
|
15,901
|
|
|
|
1,067
|
|
|
|
549
|
|
|
|
901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
2,085
|
|
|
|
530
|
|
|
|
124
|
|
|
|
216
|
|
General and administrative expense
|
|
|
3,364
|
|
|
|
475
|
|
|
|
493
|
|
|
|
433
|
|
Advisory termination fee
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
expense
|
|
|
3,310
|
|
|
|
258
|
|
|
|
260
|
|
|
|
260
|
|
Interest net including
realized risk management instrument
|
|
|
5,693
|
|
|
|
(15
|
)
|
|
|
(12
|
)
|
|
|
(36
|
)
|
Unrealized risk management
interest related instrument
|
|
|
(1,599
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (income)
|
|
|
(171
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
3,219
|
|
|
$
|
(181
|
)
|
|
$
|
(316
|
)
|
|
$
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
3,144
|
|
|
$
|
62
|
|
|
$
|
(68
|
)
|
|
$
|
252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per unit
basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
0.13
|
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
0.00
|
|
Subordinated units
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
General partner
|
|
$
|
1.02
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
42
Eagle
Rock Predecessor Texas Panhandle
Acquisition
The following table reflects the historical financial results of
the Eagle Rock Predecessor of the Texas Panhandle Assets
acquired December 1, 2005:
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Eagle Rock Predecessor
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Period from
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January 1,
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2005 to
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Year Ended
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Year Ended
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Year Ended
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November 30,
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December 31,
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December 31,
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December 31,
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2005
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2004
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2003
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2002
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($ in thousands)
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Statement of Operations
Data:
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Operating revenues
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$
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396,953
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$
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335,519
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$
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297,290
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$
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194,898
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Unrealized derivative
gains/(losses)
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Realized derivative gains
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Total operating revenues
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396,953
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335,519
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297,290
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194,898
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Cost of natural gas and NGLs
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316,979
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263,840
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249,284
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155,757
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Operating and maintenance expense
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27,518
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27,427
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23,905
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22,276
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General and administrative expense
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Depreciation and amortization
expense
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8,157
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8,268
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7,187
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7,457
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Operating Income
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44,299
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35,984
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16,914
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9,408
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Interest (income) expense
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(859
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)
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(646
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)
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(189
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)
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Other (income)
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(17
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)
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(23
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)
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(52
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)
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(944
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)
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Income before income
taxes
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45,175
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36,653
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17,155
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10,352
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Income tax provision
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15,811
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12,731
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6,071
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(6,465
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)
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Income from continuing
operations
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29,364
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23,922
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11,084
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16,817
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Discontinued operations
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Cumulative effect of change in
accounting principle
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227
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Net income
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$
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29,364
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$
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23,922
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$
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10,857
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$
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16,817
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Balance Sheet Data (at period
end):
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Property plant and equipment, net
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$
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242,487
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$
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243,939
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$
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246,640
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$
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248,624
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Total assets
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376,447
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304,631
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259,577
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339,489
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Long-term debt
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Net equity
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233,708
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204,344
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180,422
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159,281
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Cash Flow Data:
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Net cash flows provided by (used
in):
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Operating activities
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$
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47,603
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$
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41,813
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$
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32,219
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$
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13,326
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Investing activities
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(6,708
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)
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(5,567
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)
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(5,203
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)
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(12,992
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)
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Financing activities
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(40,895
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)
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(36,246
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)
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(27,016
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(334
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)
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43
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Item 7.
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Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
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The following discussion analyzes our financial condition and
results of operations. The following discussion of our financial
condition and results of operations should be read in
conjunction with our historical consolidated financial
statements and notes included elsewhere in this Annual
Report.
Overview
We are a Delaware limited partnership formed in March 2006 to
own and operate the assets that have historically been owned and
operated by Eagle Rock Pipeline, L.P. and its subsidiaries. In
2002, certain members of our management team formed Eagle Rock
Energy, Inc. to provide midstream services to natural gas
producers. In connection with the acquisition in 2003 of the Dry
Trail plant (subsequently sold in July 2004), a
CO2
tertiary recovery plant located in the Oklahoma panhandle,
members of our management team and Natural Gas Partners formed
Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy,
Inc., to own, operate, acquire and develop complementary natural
gas midstream assets. Our growth is organic as well as through
acquisitions. We have grown significantly through acquisitions,
including the acquisitions of:
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our Texas Panhandle Systems from ONEOK Texas Field Services,
L.P.;
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our Brookeland processing plant and system and Masters Creek
system from Duke Energy Field Services, L.P. and Swift Energy
Corporation;
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our pro-rata undivided interests in the Indian Springs
processing plant and Camp Ruby gathering system, both of which
are operated by an affiliate of Enterprise Products Partners,
L.P.; and
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Midstream Gas Services, L.P.
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Our organic growth projects include the expansion and extension
of our gathering systems in the Texas Panhandle (East-West
gathering pipeline) and our Tyler County pipeline and extension
allowing for flexibility between our southeast Texas and
Louisiana System (Brookeland, Masters Creek and Indian Springs),
as well as increasing gas well comments and processing plants
modifications. In addition, we will, in the first half of 2007,
be extending our Tyler County pipeline and a start up of an idle
processing plant in the Texas Panhandle Systems.
We believe we have significant opportunities for continued
expansion of our existing gathering and processing systems in
order to increase the capacity, efficiency and profitability of
these systems through the implementation of commercial and
operational development projects.
Our
Operations
Our results of operations for our Texas Panhandle Systems and
our southeast Texas and Louisiana System are determined
primarily by the volumes of natural gas gathered, compressed,
treated, processed and transported through our gathering,
processing and pipeline systems and the associated commodity
prices for natural gas, NGLs and condensate. We gather and
process natural gas pursuant to a variety of arrangements
generally categorized as fee-based arrangements,
percent-of-proceeds
arrangements and keep-whole arrangements. Under
fee-based arrangements, we earn cash fees for the services we
render. Under the latter two types of arrangements, we generally
purchase raw natural gas and sell processed natural gas and NGLs.
Percent-of-proceeds
and keep-whole arrangements involve commodity price risk to us
because our margin is based in part on natural gas and NGL
prices. We seek to minimize our exposure to fluctuations in
commodity prices in several ways, including managing our
contract portfolio. In managing our contract portfolio, we
classify our gathering and processing contracts according to the
nature of commodity risk implicit in the settlement structure of
those contracts.
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Fee-Based Arrangements. Under these
arrangements, we generally are paid a fixed cash fee for
performing the gathering and processing service. This fee is
directly related to the volume of natural gas that flows through
our systems and is not directly dependent on commodity prices. A
sustained decline, however, in commodity prices could result in
a decline in volumes and, thus, a decrease in our
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44
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fee revenues. These arrangements provide stable cash flows, but
minimal, if any, upside in higher commodity price environments.
As of December 31, 2006, these arrangements accounted for
approximately 11% of our natural gas volumes.
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Percent-of-Proceeds
Arrangements. Under these arrangements, we
generally gather raw natural gas from producers at the wellhead,
transport the gas through our gathering system, process the gas
and sell the processed gas
and/or NGLs
at prices based on published index prices. These arrangements
provide upside in high commodity price environments, but result
in lower margins in low commodity price environments. We regard
the margin from this type of arrangement, that is, the sale
proceeds less amounts remitted to the producers, as an important
analytical measure of these arrangements. The price paid to
producers is based on an agreed percentage of one of the
following: (1) the actual sale proceeds; (2) the
proceeds based on an index price; or (3) the proceeds from
the sale of processed gas or NGLs or both. We refer to contracts
in which we share only in specified percentages of the proceeds
from the sale of NGLs and in which the producer receives 100% of
the proceeds from natural gas sales, as
percent-of-liquids
arrangements. Under
percent-of-proceeds
arrangements, our margin correlates directly with the prices of
natural gas and NGLs and under
percent-of-liquids
arrangements, our margin correlates directly with the prices of
NGLs (although there is often a fee-based component to both of
these forms of contracts in addition to the commodity sensitive
component). As of December 31, 2006, these arrangements
accounted for about 77% of our natural gas volumes.
Approximately 76% of the
percent-of-proceeds
volumes as of December 31, 2006 also have fee components.
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Keep-Whole Arrangements. Under these
arrangements, we process raw natural gas to extract NGLs and pay
to the producer the full thermal equivalent volume of raw
natural gas received from the producer in the form of either
processed gas or its cash equivalent. We are generally entitled
to retain the processed NGLs and to sell them for our account.
Accordingly, our margin is a function of the difference between
the value of the NGLs produced and the cost of the processed gas
used to replace the thermal equivalent value of those NGLs. The
profitability of these arrangements is subject not only to the
commodity price risk of natural gas and NGLs, but also to the
price of natural gas relative to NGL prices. These arrangements
can provide large profit margins in favorable commodity price
environments, but also can be subject to losses if the cost of
natural gas exceeds the value of its thermal equivalent of NGLs.
Many of our keep-whole contracts include provisions that reduce
our commodity price exposure, including (1) conditioning
floors that require the keep-whole contract to convert to a
fee-based arrangement if the NGLs have a lower value than their
thermal equivalent in natural gas, (2) embedded discounts
to the applicable natural gas index price under which we may
reimburse the producer an amount in cash for the thermal
equivalent volume of raw natural gas acquired from the producer,
or (3) fixed cash fees for ancillary services, such as
gathering, treating and compressing. As of December 31,
2006, these arrangements accounted for about 10% of our natural
gas volumes. Approximately 74% of these keep-whole arrangements
have fee components.
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In addition, we are a seller of NGLs and are exposed to
commodity price risk associated with downward movements in NGL
prices. NGL prices have experienced volatility in recent years
in response to changes in the supply and demand for NGLs and
market uncertainty. In response to this volatility, we have
instituted a hedging program to reduce our exposure to commodity
price risk. Under this program, we have hedged substantially all
of our share of NGL volumes under
percent-of-proceed
and keep-whole contracts in 2006 and 2007 through the purchase
of NGL put contracts, costless collar contracts and swap
contracts. We have also hedged substantially all of our share of
NGL volumes under
percent-of-proceed
contracts from 2008 through 2010 through a combination of direct
NGL hedging as well as indirect hedging through crude oil
costless collars. Additionally, to mitigate the exposure to
natural gas prices from keep-whole volumes, we have purchased
natural gas calls from 2006 to 2007 to cover substantially all
of our short natural gas position associated with our keep-whole
volumes. We anticipate after 2007, our short natural gas
position will become a long natural gas position because of our
increased volumes in the Texas Panhandle and the volumes
contributed from our Brookeland/Masters Creek acquisition. In
addition, we intend to pursue fee-based arrangements, where
market conditions permit, and to increase retained percentages
of natural gas and NGLs
45
under
percent-of-proceed
arrangements. We continually monitor our hedging and contract
portfolio and expect to continue to adjust our hedge position as
conditions warrant.
The following is a summary of the contracts that are significant
to our operations, which contracts consist of a natural gas
liquids exchange agreement, a gathering and processing agreement
and four gas purchase agreements.
ONEOK Hydrocarbon. We are a party to a natural
gas liquids exchange agreement with ONEOK Hydrocarbon, L.P.,
dated December 1, 2005. We deliver all of our natural gas
liquids extracted at six of our natural gas processing plants in
the Texas Panhandle to ONEOK for transportation and
fractionation services. We take title to all of these volumes
and they are physically delivered to Conway, Kansas where
mid-continent type natural gas liquids pricing is available,
with an option to exchange certain volumes at Mont Belvieu,
Texas where gulf coast type natural gas liquids pricing is
available. The primary contract term expires on June 30,
2010, of which an extension to June 30, 2015, may be
mutually agreed to by the parties.
Chesapeake Energy Marketing. We are a party to
a natural gas purchase agreement with Chesapeake Energy
Marketing Inc., dated July 1, 1997, whereby we purchase raw
natural gas from a number of wells on acreage dedicated to us
located in Moore and Carson Counties, Texas. The natural gas
from these wells is delivered into our Stinnett and Cargray
gathering and processing systems. The acreage dedication under
this contract is for the life of the leases from which the
natural gas is produced. We pay Chesapeake an index posted gas
price, less a fixed charge and fixed commodity fee and a fixed
fuel percentage. Under this contract, there is an annual option
to renegotiate the fuel and fees components. The original
agreement was between MC Panhandle, Inc. and MidCon Gas Services
Corp. and, as a result of ownership changes, the contract is now
between Chesapeake and us.
Anadarko E&P. We are a party to a gas
gathering and processing agreement with Anadarko E & P
Company LP, dated September 1, 1993, whereby we gather and
process raw natural gas from a number of wells on acreage
dedicated to us located in Jasper and Newton Counties, Texas.
The natural gas from these wells is delivered into our
Brookeland gathering system and plant. The acreage dedication
under this contract is for the life of the leases from which the
natural gas is produced. We receive a percentage of the natural
gas liquid value and a percentage of the natural gas residue
value for gathering and processing services. The original
agreement was between Union Pacific Resources Company and Sonat
Exploration Company and, as a result of ownership changes, the
contract is now between Anadarko and us.
Ergon Energy Partners, L.P. We are a party to
a gas purchase agreement with Ergon Energy Partners, L.P., dated
September 1, 2005, whereby we gather and process raw
natural gas from a number of wells on acreage dedicated to us
located in Tyler County, Texas. The natural gas from these wells
is delivered to our Tyler County pipeline system. The term of
this contract runs through September 30, 2011. We receive a
percentage of the natural gas liquid value and fees for
gathering and processing services.
Cimarex Energy Marketing. We are a party to a
gas purchase agreement with Cimarex Energy Co., dated
March 28, 1994, whereby we gather and process raw natural
gas from a number of wells on acreage dedicated to us located in
Roberts and Hemphill Counties, Texas, delivered to our Canadian
processing plant. This is a life of lease contract. We receive a
percentage of the natural gas liquid value and a percentage of
the natural gas residue value for gathering and processing
services. The original agreement was between Warren Petroleum
Company and Wallace Oil & Gas, Inc. and, as a result of
ownership changes, the contract is now between Cimarex and us.
How We
Evaluate Our Operations
Our management uses a variety of financial and operational
measurements to analyze our performance. We view these
measurements as important factors affecting our profitability
and review these measurements on a monthly basis for consistency
and trend analysis. These measures include volumes, margin,
operating expenses, and Adjusted EBITDA on a company-wide basis.
Volumes. We must continually obtain new
supplies of natural gas to maintain or increase throughput
volumes on our gathering and processing systems. Our ability to
maintain existing supplies of natural gas and
46
obtain new supplies is impacted by (1) the level of
workovers or recompletions of existing connected wells and
successful drilling activity in areas currently dedicated to our
pipelines, (2) our ability to compete for volumes from
successful new wells in other areas and (3) our ability to
obtain natural gas that has been released from other
commitments. We routinely monitor producer activity in the areas
served by our gathering and processing systems to pursue new
supply opportunities.
Margins. As of December 31, 2006, our
overall portfolio of processing contracts reflected a net short
position in natural gas of approximately 5,810 MMBtu/d
(meaning we were a net buyer of natural gas) and a net long
position in NGLs (including condensate) of approximately
6,877 Bbls/d (meaning we were a net seller of NGLs). As a
result, during this period, our margins were positively impacted
to the extent the price of NGLs increased in relation to the
price of natural gas and were adversely impacted to the extent
the price of NGLs declined in relation to the price of natural
gas. We refer to the price of NGLs in relation to the price of
natural gas as the fractionation spread. This portfolio
performed well in response to favorable fractionation spreads
during these periods. Because of the hedging program of our
commodity risk, we have been able to develop overall favorable
fractionation spreads within a range and we anticipate our unit
margins will not be subject to significant downward fluctuations
in commodity prices were to change in an unfavorable
relationship.
Risk Management. For the year ended
December 31, 2006, our risk management portfolio value
changes reflected a $26.3 million unrealized non-cash loss
recorded to Total Revenues for our natural gas, natural gas
liquids and condensate associated derivatives. In addition, we
recorded $2.8 million unrealized non-cash gain within
Interest and Other Expense related to the interest rate swaps
associated with our credit agreement. As both of the unrealized
positions reflect underlying commodity prices and interest rates
both in the short and long-term, the unrealized value position
will be subject to variability from period to period.
Operating Expenses. Operating expenses are a
separate measure we use to evaluate operating performance of
field operations. Direct labor, insurance, repair and
maintenance, utilities and contract services comprise the most
significant portion of our operating expenses. These expenses
are largely independent of the volumes through our systems, but
fluctuate depending on the activities performed during a
specific period. We do not deduct operating expenses from total
revenues in calculating segment margin because we separately
evaluate commodity volume and price changes in segment margin.
Adjusted EBITDA. We define Adjusted EBITDA as
net income (loss) plus income tax,
interest-net,
depreciation and amortization expense, other non-cash operating
expenses less non realized revenues risk management loss (gain)
activities and less net income from discontinued operations.
Adjusted EBITDA is useful in determining our ability to sustain
or increase distributions. By excluding unrealized derivative
gains (losses), a non-cash charge which represents the change in
fair market value of our executed derivative instruments and is
independent of our assets performance or cash flow
generating ability, we believe Adjusted EBITDA reflects more
accurately our ability to generate cash sufficient to pay
interest costs, support our level of indebtedness, make cash
distributions to our unitholders and general partner and finance
our maintenance capital expenditures. We further believe that
Adjusted EBITDA also describes more accurately the underlying
performance of our operating assets by isolating the performance
of our operating assets from the impact of an unrealized,
non-cash measure designed to describe the fluctuating inherent
value of a financial asset. Similarly, by excluding the impact
of non-recurring discontinued operations, Adjusted EBITDA
provides users of our financial statements a more accurate
picture of our current assets cash generation ability,
independently from that of assets which are no longer a part of
our operations.
Adjusted EBITDA should not be considered an alternative to net
income, operating income, cash flows from operating activities
or any other measure of financial performance presented in
accordance with GAAP.
General
Trends and Outlook
We expect our business to continue to be affected by the
following key trends. Our expectations are based on assumptions
made by us and information currently available to us. To the
extent our underlying assumptions about or interpretations of
available information prove to be incorrect, our actual results
may vary materially from our expected results.
47
Natural Gas Supply, Demand and
Outlook. Natural gas continues to be a critical
component of energy consumption in the United States. According
to the Energy Information Administration, or EIA, total annual
domestic consumption of natural gas is expected to increase from
approximately 22.2 trillion cubic feet, or Tcf, in 2005 to
approximately 22.35 Tcf in 2010. During the last three years,
the United States has on average consumed approximately 22.3 Tcf
per year, while total marketed domestic production averaged
approximately 18.5 Tcf per year during the same period. The
industrial and electricity generation sectors currently account
for the largest usage of natural gas in the United States.
We believe current natural gas prices and the existing strong
demand for natural gas will continue to result in relatively
high levels of natural gas-related drilling in the United States
as producers seek to increase their level of natural gas
production. Although the natural gas reserves in the United
States have increased overall in recent years, a corresponding
increase in production has not been realized. We believe this
lack of increased production is attributable to insufficient
pipeline infrastructure, the continued depletion of existing
wells and a tight labor and equipment market. We believe an
increase in United States natural gas production, additional
sources of supply such as liquid natural gas, and imports of
natural gas will be required for the natural gas industry to
meet the expected increased demand for natural gas in the United
States.
Most of the areas in which we operate are experiencing
significant drilling activity. Although we anticipate continued
high levels of exploration and production activities in
substantially all of the areas in which we operate, fluctuations
in energy prices can affect production rates over time and
levels of investment by third parties in exploration for and
development of new natural gas reserves. We have no control over
the level of natural gas exploration and development activity in
the areas of our operations.
Impact of Interest Rates and Inflation. The
credit markets have experienced historically lows in interest
rates over the past several years. If the overall United States
economy continues to strengthen, we believe it is likely that
monetary policy will tighten further, resulting in higher
interest rates to counter possible inflation. Interest rates on
future credit facilities and debt offerings could be higher than
current levels, causing our financing costs to increase
accordingly. Although this could limit our ability to raise
funds in the capital markets, we expect in this regard to remain
competitive with respect to acquisitions and capital projects,
as our competitors would face similar circumstances.
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our results of
operations in 2005 or 2006. It may in the future, however,
increase the cost to acquire or replace property, plant and
equipment and may increase the costs of labor and supplies. Our
operating revenues and costs are influenced to a greater extent
by price changes in natural gas and NGLs. To the extent
permitted by competition, regulation and our existing
agreements, we have and will continue to pass along increased
costs to our customers in the form of higher fees.
Financial
Statement Presentation and Comparability of Financial
Results
Our historical financial statements consist of:
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|
The financial statements of Eagle Rock Pipeline, L.P., as the
accounting acquirer of ONEOK Texas Field Services, L.P., and the
entity contributed to Eagle Rock Energy Partners, L.P., in
connection with our initial public offering. For a discussion of
the results of operations of Eagle Rock Pipeline, please read
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations Eagle
Rock Pipeline Results of Operations. The financial statements of
Eagle Rock Pipeline, together with the notes thereto, are also
included elsewhere in this report.
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Our historical results of operations for the periods presented
may not be comparable, either from period to period or going
forward, for the reasons described below:
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We have grown rapidly through acquisitions. Our acquisitions
were completed at different dates and with numerous sellers and
were accounted for using the purchase method of accounting.
Under the purchase method of accounting, results from such
acquisitions are recorded in the financial statements only from
the date of acquisition.
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48
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On December 5, 2003, Eagle Rock Pipeline commenced
operations by acquiring the Dry Trail plant from Williams Field
Service Company for approximately $18.0 million, and in
July 2004, Eagle Rock Pipeline sold the Dry Trail plant to
Celero Energy, L.P. for approximately $37.4 million,
resulting in a pre-tax realized gain on the disposition of
approximately $19.5 million in 2004. The Dry Trail
operations are reflected as discontinued operations for Eagle
Rock Pipeline for 2003 and 2004.
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In connection with our acquisition of Eagle Rock Predecessor on
December 1, 2005, the book basis of the assets of Eagle
Rock Predecessor was increased to reflect the purchase price,
which had the effect of increasing the depreciation expense
associated with the assets of Eagle Rock Energy Partners, L.P.
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As a result of our increased debt related to the acquisition of
Eagle Rock Predecessor, our interest expense increased
subsequent to December 1, 2005.
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After our acquisition of Eagle Rock Predecessor, we initiated a
risk management program comprised of NGL puts, costless collars
and swaps, crude costless collars and natural gas calls, as well
as interest rate swaps that we accounted for using
mark-to-market
accounting. These amounts are included in unrealized/realized
gain (loss) from risk management activities.
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We completed construction of the Tyler County pipeline on
February 28, 2006, which was flowing 28.4 MMcf/d of
natural gas to the Indian Springs processing plant as of
December 31, 2006. As a result, our historical financial
results for periods prior to March 31, 2006, do not include
the financial results from the operation of this asset.
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On March 27, 2006, Eagle Rock Pipeline completed a private
placement of 5,455,050 common units for $98.3 million to
fund our Brookeland/Masters Creek acquisition. These common
units in Eagle Rock Pipeline were converted into common units in
us upon consummation of our initial public offering on
approximately a
1-for-0.719
common unit basis.
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On March 31, 2006, we purchased an 80% interest in the
Brookeland gathering and processing facility, a 76.3% interest
in the Masters Creek gathering system and 100% of the Jasper NGL
line from Duke Energy Field Services. On April 7, 2006, we
purchased the remaining interest in the Brookeland and Masters
Creek facilities owned by Swift Energy Corporation for a total
purchase price of approximately $95.7 million. The acquired
assets are located in southeast Texas and complement our
existing southeast Texas assets. As a result, our historical
financial results for periods prior to March 31, 2006 do
not include the financial results from our ownership of these
assets.
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On June 2, 2006, we purchased all of the partnership
interests in Midstream Gas Services, L.P. for approximately
$4.7 million in cash and 1,125,416 common units in Eagle
Rock Pipeline. These common units in Eagle Rock Pipeline were
converted into common units in us upon consummation of our
initial public offering on approximately a
1-for-0.719
common unit basis. We will issue up to 798,155 of our common
units (pre-IPO units), which we refer to as the Deferred Common
Units, to Natural Gas Partners VII, L.P., the primary equity
owner of MGS, as a contingent earn-out payment if MGS achieves
certain financial objectives for the year ending
December 31, 2007. The acquired operations are located in
Roberts County in the Texas Panhandle within our East Panhandle
System. We expect this acquisition to provide significant
synergies and gathering and processing capacity and to enhance
our strategic presence in the area. As a result, our historical
financial results for the periods prior to June 2, 2006, do
not include the financial results from our ownership of these
interests.
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Critical
Accounting Policies and Estimates
Conformity with accounting principles generally accepted in the
United States requires management to make estimates and
judgments that affect the amounts reported in the financial
statements and notes. On an on-going basis, we make and evaluate
estimates and judgments based on managements best
available knowledge of previous, current, and expected future
events. Given that a substantial portion of our operations were
acquired within the past twelve months, we base our estimates on
historical experience and various other assumptions that we
believe to be reasonable under the circumstances. Actual results
may differ from these estimates, and estimates are subject to
change due to modifications in the underlying conditions or
49
assumptions. Currently, we do not foresee any reasonably likely
changes to our current estimates and assumptions which would
materially affect amounts reported in the financial statements
and notes. We have selected the following critical accounting
policies that currently affect our financial condition and
results of operations for discussion.
Revenue and Cost of Sales Recognition. We
record revenue and cost of sales on the gross basis for those
transactions where we act as the principal and take title to
natural gas, NGLs or condensates that is purchased for resale.
When our customers pay us a fee for providing a service such as
gathering, treating or transportation we record the fees
separately in revenues.
We currently record the monthly results of operations using
primarily actual results which include settling most of our
volumes with producers, shippers and customers around the
25th of the month following the production month. This
process results in us reporting later than other similar
partnerships that report on estimates.
Risk Management Activities. We have structured
our hedging activities in order to minimize our commodity
pricing and interest rate risks. These hedging activities rely
upon forecasts of our expected operations and financial
structure over the next five years. If our operations or
financial structure are significantly different from these
forecasts, we could be subject to adverse financial results as a
result of these hedging activities. We mitigate this potential
exposure by retaining an operational cushion between our
forecasted transactions and the level of hedging activity
executed.
From the inception of our hedging program in October 2005
through December 2006, we used
mark-to-market
accounting for our commodity hedges and interest rate swaps.
There were no derivatives for the periods before
September 30, 2005. For the twelve months ended
December 31, 2006, we incurred $24.0 million of
realized and unrealized losses within total revenue related to
our commodity risk management activities. This consisted of
$2.3 million in net realized gain and $26.3 million of
net unrealized loss. Within the interest and other expense
section, we recorded $3.3 million of realized and
unrealized gain related to our credit facility interest rate
risk management activities. These consisted of $0.5 million
realized net gain and a $2.8 million net unrealized gain.
We recorded monthly realized gains and losses on hedge
instruments based upon cash settlements information. The
settlement amounts vary due to the volatility in the commodity
market prices throughout each month. We also record unrealized
gains and losses quarterly based upon the future value on
mark-to-market
hedges through their expiration dates. The expiration dates vary
but are currently no later than January 2011 for our interest
rate hedges, and December 2010 for our commodity hedges. The
option premium costs we incurred as part of our Panhandle
acquisition are being expensed through the unrealized risk
management instruments in total revenue. We monitor and review
hedging positions regularly.
Depreciation Expense and Cost Capitalization
Policies. Our assets consist primarily of natural
gas gathering pipelines and processing plants. We capitalize all
construction-related direct labor and material costs, as well as
indirect construction costs. Indirect construction costs include
general engineering and the costs of funds used in construction.
The cost of funds used in construction represents capitalized
interest. These costs are then expensed over the life of the
constructed asset through the recording of depreciation expense.
As discussed in Note 2 to the Consolidated Financial
Statements, depreciation of our assets is generally computed
using the straight-line method over the estimated useful life of
the assets. The costs of renewals and betterments which extend
the useful life of property, plant and equipment are also
capitalized. The costs of repairs, replacements and maintenance
projects are expensed as incurred.
The computation of depreciation expense requires judgment
regarding the estimated useful lives and salvage value of
assets. As circumstances warrant, depreciation estimates are
reviewed to determine if any changes are needed. Such changes
could involve an increase or decrease in estimated useful lives
or salvage values which would impact future depreciation expense.
Impairment of Long-Lived Assets We assess our
long-lived assets for impairment based on
SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets. A long-lived asset is tested
for impairment whenever events or changes in circumstances
indicate its carrying amount may exceed its fair
50
value. Fair values are based on the sum of the undiscounted
future cash flows expected to result from the use and eventual
disposition of the assets.
Examples of long-lived asset impairment indicators include:
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a significant decrease in the market price of a long-lived asset
or asset group;
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a significant adverse change in the extent or manner in which a
long-lived asset or asset group is being used or in its physical
condition;
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a significant adverse change in legal factors or in the business
climate could affect the value of a long-lived asset or asset
group, including an adverse action or assessment by a regulator
which would exclude allowable costs from the rate-making process;
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an accumulation of costs significantly in excess of the amount
originally expected for the acquisition or construction of a
long-lived asset or asset group;
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a current-period operating cash flow loss combined with a
history of operating cash flow losses or a projection or
forecast that demonstrates continuing losses associated with the
use of a long-lived asset or asset group; and
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a current expectation that, more likely than not, a long-lived
asset or asset group will be sold or otherwise disposed of
significantly before the end of its previously estimated useful
life.
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Environmental Remediation. Current accounting
guidelines require us to recognize a liability and expense
associated with environmental remediation if (i) government
agencies mandate such activities or one of our properties were
added to the Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA) database, (ii) the existence of
a liability is probable and (iii) the amount can be
reasonably estimated. To date, we have recorded a
$0.3 million liability for remediation expenses. If
governmental regulations change, we could be required to incur
additional remediation costs which may have a material impact on
our profitability.
As a result of the adoption of Statement of Financial Accounting
Standards, or SFAS, No. 143 Accounting for Asset
Retirement Obligations, Eagle Rock Pipeline has recorded a
long-term liability of approximately $1.8 million,
primarily consisting of the Panhandle and Brookeland asset
acquisitions. Related accretion expense has been recorded in
operating expenses and depreciation and amortization expense has
also been recorded. See Note 2.
51
Eagle
Rock Pipeline Results of Operations
The following table is a summary of the results of operations of
Eagle Rock Pipeline for the three years ended December 31,
2006, 2005 and 2004.
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Year Ended
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Year Ended
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Year Ended
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December 31,
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December 31,
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December 31,
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2006
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2005
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2004
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($ in thousands)
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Operating Revenues:
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Sales of natural gas, NGLs and
condensate
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$
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486,910
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$
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59,921
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$
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9,837
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Compressing, gathering and
processing services
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14,862
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6,247
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799
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Gain (loss) on risk management
instruments
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(24,004
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7,308
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Other
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621
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214
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Total operating revenues
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478,389
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73,690
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10,636
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Cost of natural gas and cost of
natural gas and NGLs
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377,580
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55,272
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8,811
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Segment gross margin(a)
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100,810
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18,419
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1,825
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Operating and maintenance expense
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32,905
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2,955
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34
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General and administrative expense
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13,161
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4,765
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2,406
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Advisory termination fee
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6,000
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Depreciation and amortization
expense
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43,220
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4,088
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619
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Interest and other income
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(996
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(171
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(24
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Interest and other expense
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28,604
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4,031
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Income tax provision
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1,230
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(Loss) income from continuing
operations
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(23,314
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2,750
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(1,210
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Income from discontinued operations
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22,192
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Net (loss) income
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$
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(23,314
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$
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2,750
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$
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20,982
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Adjusted EBITDA(b)
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$
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81,192
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$
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3,390
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$
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(615
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(a) |
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Segment gross margin consists of total revenues less cost of
natural gas and NGLs. Please read Summary
Non-GAAP Financial Matters. |
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(b) |
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Adjusted EBITDA consists of net income plus income tax,
interest-net,
depreciation and amortization expense, other non-cash operating
expenses less non realized revenues risk management loss (gain)
activities and less net income from discontinued operations. |
Year
Ended December 31, 2006 Compared with Year Ended
December 31, 2005
Financial results for the twelve months ended December 31,
2006, include activities of the ONEOK Texas Field Services, L.P.
assets (Panhandle Assets) (acquired in December
2005), Brookeland assets (acquired in March and April
2006) and acquisition of MGS (acquired in June 2006).
Operating revenues for sales of natural gas, NGLs and condensate
increased by $427.0 million, primarily from the Panhandle
Assets (twelve months of contribution in 2006 versus one month
in 2005), Brookeland assets and MGS acquisitions and the
contribution from the newly constructed Tyler County pipeline
during the latter part of 2006. The increase of
$8.6 million in revenues for compression, gathering and
processing services was also favorably impacted by the increased
activities from the acquired assets.
As a result of our commodity hedging activities, total revenues
include a realized gain of $2.3 million on risk management
investments that were settled for the twelve month period and an
unrealized
mark-to-market
net loss of $26.3 million which includes the fair value
change of the option premiums associated with the Panhandle
Assets. As the forward price curves for our hedged commodities
shift in relation to the caps, floors, swap and strike prices at
which we have executed our derivative instruments, the fair
market value of such
52
instruments changes through time. The
mark-to-market
net unrealized loss reflects overall unfavorable forward curve
price movements during the twelve months period for the
underlying commodities for the derivative instruments. The net
unrealized loss is comprised of $18.6 million gain related
to our NGL position and crude oil as the forward curve prices in
these commodities decreased during the quarter. Partially
offsetting the unrealized gain, we recorded an unrealized net
loss of $25.7 million related to natural gas forward curve
price movements during the year. The $19.2 million
remaining difference refers to the amortization of the put
premiums as the underlying options have expired. The unrealized
net loss of $26.3 million did not have a significant impact
on cash activities for the 2006 period.
Given the uncertainty surrounding future commodity prices, and
the general inability to predict these as they relate to the
caps, floors, swaps and strike prices at which we have hedged
our exposure, it is difficult to predict the magnitude and
impact that marking our hedges to market will have on our income
from operations in the future. Conversely, negative commodity
price movements affecting our revenues and costs are expected to
be compensated by our executed derivative instruments.
Purchase of natural gas and NGLs increased by
$322.3 million reflecting the cost of goods expense for the
increased sales of natural gas, NGLs and condensate revenue as
discussed above.
Segment gross margin increased by $82.4 million reflecting
the increased business activity in revenues and purchases, as
discussed above. Reducing segment gross margin for the twelve
months 2006 period is the $26.3 unrealized
mark-to-market
loss related to our risk management activities as described
above. Excluding this amount, segment gross margin would have
been $127.1 million as compared to $11.1 million for
the 2005 twelve month period.
Operations and maintenance expense increased by
$30.0 million for the year ended 2006 compared to 2005, due
to the increased operations from the acquired assets as well as
from the first phase of the Tyler County pipeline project
completed earlier in 2006.
General and administrative expense also increased by
$8.4 million, as the Partnership built up its corporate
infrastructure and personnel to manage the acquired assets and
public partnership expenses. Included in general and
administrative expense is property tax, total employee benefit
programs and the Partnerships property and liability
insurance programs.
Adjusted EBITDA for the 2006 year was $81.2 million as
compared to $3.4 million for 2005. The increase is
primarily from the contribution of the acquired assets, as well
as the contribution from the Tyler County Pipeline project.
During the fourth quarter of 2006, Holdings paid
$6.0 million at the time of the initial public offering to
terminate the advisory services agreement with Natural Gas
Partners. The transaction was recorded as an expense on the
Partnerships income with the offset to members
equity.
As the purchase price of the acquired assets was allocated and
pushed down to the operating entities balance sheets,
depreciation and amortization expense also increased by
$39.1 million from the associated higher fixed assets and
intangible assets of the acquired assets, as well as additions
during the year.
As the Panhandle acquisition was substantially financed with a
credit loan facility, interest expense, net increased by
$23.7 million, including interest swap realized gain of
$0.5 million. We did not have outstanding debt prior to the
Panhandle Assets acquisition in 2005. Included in interest
expense for 2006 is approximately $0.4 million of direct
cost expensed related to the amended and restated credit
agreement which became effective on August 31, 2006, as
well as higher debt issuance cost amortization during 2006.
We recorded an unrealized
mark-to-market
gain of $2.8 million related to our interest rate risk
management position. The unrealized gain relates to our future
periods interest swaps and from changes during the year in the
underlying interest rate associated with the derivatives. The
unrealized
mark-to-market
gain did not have a significant impact on cash activities during
the 2006 period.
We recorded $1.2 million of income taxes related to
temporary differences caused by the Texas entity level tax to
become effective in 2008.
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Year
Ended December 31, 2005 Compared with Year Ended
December 31, 2004
Financial results as of December 31, 2005, include one
month of operations of the Panhandle Assets acquired on
December 1, 2005, and are, therefore, not directly
comparable to results as of December 31, 2004. Prior to
this acquisition, Eagle Rock Pipeline owned pro-rata,
non-operated interests in the Indian Springs and Camp Ruby
assets, and had begun construction of the Tyler County pipeline.
With the Panhandle acquisition, revenue increased by
$63.1 million, cost of natural gas and NGLs increased by
$46.5 million, and operating and maintenance expense
increased by $2.9 million, from December 31, 2004 to
December 31, 2005. This significant increase in results is
directly attributable to the relative large scale of the assets
acquired in relation to our previously existing business.
General and administrative expenses also increased by
$2.4 million, as Eagle Rock Pipeline built up its corporate
infrastructure and personnel to manage the acquired assets.
Depreciation and amortization expense increased by
$3.5 million, as a result of the Panhandle acquisition. As
the Panhandle acquisition was partly financed with a
$400.0 million term loan facility, interest expense
increased by $4.0 million, including interest rate swap
unrealized losses of $1.6 million, whereas we were
previously unleveraged as of December 31, 2004. During the
year ended December 31, 2004, $22.2 million was
recognized as income from discontinued operations related to the
gain on the sale and the results of operations of the Dry Trail
plant in 2004.
Other
Matters
Hurricanes Katrina and Rita. Hurricanes
Katrina and Rita struck the Gulf Coast region of the
United States on August 29, 2005 and
September 24, 2005, respectively, causing widespread damage
to the energy infrastructure in the region. The storms did not
cause material direct damage to any of our assets in the region.
While neither Hurricane Katrina nor Hurricane Rita caused
material direct damage to our facilities, Hurricane Rita did
disrupt the operations of NGL pipelines and fractionators in the
Houston, Texas area and caused power outages to some of our
producers in the southeast Texas area. As a result of these
disruptions, we were forced to temporarily curtail certain of
our producers in the region for approximately four days and to
operate our Indian Springs facility in a reduced recovery mode
for approximately six days.
Wild fires in Texas Panhandle. Wild fires in
the Texas Panhandle during the week of March 11, 2006,
temporarily affected our operations in the region. While the
fires did not cause material direct damage to our facilities,
some experienced down-time was caused by power outages at the
local electric co-ops. Our Lefors and Cargray plants came back
up with reduced flow rates as producers had shut-in their
production during the fires. There was minimal and temporary
damage sustained in the field to a very small number of metering
facilities and one flow line. Less than $0.1 million was
spent on repairs caused by the fires. The overall economic
impact has been estimated to be between $0.5 million and
$1.0 million.
Environmental. A Phase I environmental
study was performed on our Texas Panhandle assets by an
environmental consultant engaged by us in connection with our
pre-acquisition due diligence process in 2005. As a result of
performing the Phase I environmental study, we are planning
to conduct environmental investigations at 11 properties, the
costs of which are estimated to collectively range between
$0.2 million and $0.4 million and for which we have
accrued reserves in the amount of $0.3 million as of
December 31, 2005, with no change for the 2006 year.
Depending on the findings made during those investigations, and
in anticipation of implementing amended SPCC plans at multiple
locations as well as performing selected cavern closures, we
estimate that an additional $1.2 million to
$2.5 million in costs could be incurred by us in resolving
environmental issues at those properties. We believe that the
likelihood that we will be liable for any significant potential
remediation liabilities identified in the study is remote.
Separately, (1) we are entitled to indemnification with
respect to certain environmental liabilities retained by prior
owners of these properties, and (2) we purchased an
environmental pollution liability insurance policy. The policy
pays for
on-site
clean-up as
well as costs and damages to third parties and currently has a
one-year term with a $5.0 million limit subject to a
$0.5 million deductible. We expect to renew this policy on
an annual basis.
54
Liquidity
and Capital Resources
Historically, our sources of liquidity have included cash
generated from operations, equity investments by our owners and
borrowings under our credit facilities.
With the completion of the IPO offering, we expect our sources
of liquidity to include:
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cash generated from operations;
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borrowings under our credit facilities;
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debt offerings; and
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issuance of additional partnership units.
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We believe the cash generated from these sources will be
sufficient to meet our minimum quarterly cash distributions and
our requirements for short-term working capital and capital
expenditures for the next twelve months.
Cash
Flows
Since the formation of Eagle Rock Pipeline, L.P. in 2005 through
December 31, 2006, several key events having major impacts
on our cash flows are:
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the acquisition of the midstream assets in the Texas Panhandle
on December 1, 2005 for approximately $531.1 million,
which was financed through an additional equity contribution of
$133.0 million and debt of $400.0 million, not
including $27.5 million in risk management costs related to
option premiums; and
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the acquisition of the Brookeland gathering and processing
facility and related assets on March 31, 2006 and
April 7, 2006 for approximately $95.8 million, which
we financed entirely with equity.
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the acquisition of all of the partnership interests in Midstream
Gas Services, L.P. on June 2, 2006 for approximately
$25.0 million which we paid with $4.7 million in cash
and $20.3 million in Eagle Rock Pipeline, L.P. units.
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Working Capital (Deficit). Working capital is
the amount by which current assets exceed current liabilities
and is a measure of our ability to pay our liabilities as they
become due. The working capital was $12.1 million at
December 31, 2006 and $29.2 million as of
December 31, 2005.
The net decrease in working capital of $17.1 million from
December 31, 2005 to December 31, 2006, resulted
primarily from the following factors:
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cash balances decreased overall by $8.8 million and was
impacted from the results of operations, timing of cash receipts
and disbursements, as well as capital expenditures levels;
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risk management net working capital balance decreased by a net
$8.0 million as a result of the changes in the
mark-to-market
unrealized positions and fair value changing of the option
premiums;
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prepayments and other current assets increased by
$1.4 million primarily from the property and liability
prepaid insurance balances;
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accounts payable decreased by $2.7 million from
December 31, 2006, primarily as a result of timing of
payments and impacts from commodity price changes for natural
gas and NGLs; and
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|
accrued liabilities increase of $14.6 million primarily
reflects accrued interest for the credit agreement, property tax
accruals, employee paid absence liability and other accruals.
|
Cash
Flows Year Ended 2006 Compared to Year Ended 2005
Cash Flow from Operating Activities. Increase
of $56.7 million during the current year is the result of
increased income from both the acquired assets and the growth
capital expenditure projects.
55
Cash Flows From Investing Activities. Cash
flows used in investing activities for the year ended
December 31, 2006, as compared to the year ended
December 31, 2005, decreased by $408.4 million. The
investing activities for the current year reflect the Brookeland
and MGS acquisition assets, $101.2 million, as well as a
higher capital expenditure level of $38.4 million versus
$4.2 million for the year ended 2005. In addition, cost for
acquiring intangibles, primarily pipeline
rights-of-way
is a $2.2 million increase between the two years. The
capital expenditure amount for the current year reflects the
Tyler County pipeline extensions, Red Deer processing plant
refurbishment and start up, East-West gathering pipeline, other
growth programs, as well as, maintenance and well connect
capital outlays. For 2005, the Panhandle acquisition comprised
$531.1 million of the investing activities.
Cash Flows From Financing Activities. Cash
flows provided by in financing activities for the year ended
December 31, 2006, decreased by $485.2 million, over
the year ended December 31, 2005. Key differences between
years include $407.6 million in Revolver and Term Loan
borrowings in 2005 as compared to a $2.7 million net
repayment in 2006, $98.5 million of equity contribution
before the initial public offering in 2006 versus
$192.4 million contributed in 2005 (both are primarily the
equity contributions associated with the Texas Panhandle asset
acquisition in 2005 and the Brookeland and MGS acquisitions in
2006). In addition, payments of $27.5 million for
derivative contracts, primarily the put contracts related to the
Texas Panhandle asset acquisition, were made in 2005.
Distributions, not including the IPO-related distributions, were
a cash outflow of $22.0 million in 2006, as compared to
$9.7 million in 2005. Net cash inflow from the initial
public offering, including the overallotment, was primarily used
for distributions to pre-IPO members for capital expenditure and
working reimbursements, arrearage distributions and units
purchased for the overallotment, as well as issuance costs
related to the initial public offering.
Capital
Requirements
The midstream energy business can be capital intensive,
requiring significant investment for the acquisition or
development of new facilities. We categorize our capital
expenditures as either:
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growth capital expenditures, which are made to acquire
additional assets to increase our business, to expand and
upgrade existing systems and facilities or to construct or
acquire similar systems or facilities; or
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maintenance capital expenditures, which are made to replace
partially or fully depreciated assets, to meet regulatory
requirements, to maintain the existing operating capacity of our
assets and extend their useful lives or to maintain existing
system volumes and related cash flows.
|
For the December 31, 2006 year, we spent
$38.4 million for capital expenditures, $27.1 million
for growth and $11.3 million for maintenance. Growth
includes the Tyler County pipeline as well as the East-West
gathering pipeline in the Texas Panhandle Systems and the Red
Deer processing plant project. We have budgeted approximately
$42.1 million in capital expenditures for the year ended
December 31, 2007, of which $30.8 million represents
growth capital expenditures and approximately $11.3 million
represents maintenance capital expenditures. For the year ended
December 31, 2005, our growth capital expenditures were
$4.8 million and our maintenance capital expenditures were
$0.0 million, including non-cash expenditures in accounts
payable.
Since our inception in 2002, we have made substantial growth
capital expenditures, including those relating to the
acquisition of the Dry Trail plant, the Camp Ruby gathering
system, the Indian Springs processing plant, the Panhandle
Assets and the Brookeland and Masters Creek gathering and
processing assets. We anticipate we will continue to make
significant growth capital expenditures and acquisitions.
Consequently, our ability to develop and maintain sources of
funds to meet our capital requirements is critical to our
ability to meet our growth objectives.
We continually review opportunities for both organic growth
projects and acquisitions which will enhance our financial
performance. Because we will distribute most of our available
cash to our unitholders, we will depend on borrowings under our
amended and restated credit facility and the incurrence of debt
and equity securities to finance any future growth capital
expenditures or acquisitions. The upward trend in interest rates
56
experienced recently will increase our borrowing costs on
additional debt financing incurred to finance future
acquisitions, as compared to our borrowing costs under our
currently hedged credit facility.
Amended
and Restated Credit Agreement
On August 31, 2006, we entered into an amended and restated
credit facility which provides for $300.0 million aggregate
principal amount of Series B Term Loans and up to
$200.0 million aggregate principal amount of revolving
commitments. The amended and restated credit agreement includes
a sub limit for the issuance of standby letters of credit for
the aggregate unused amount of the revolver. In addition, the
credit facility allows us to expand the Term and Revolving
Commitment up to an additional $100.0 million if certain
financial conditions are met. At December 31, 2006, we had
$299.3 million outstanding under the term loan,
$105.4 million outstanding under the revolver and
$2.5 million of outstanding letters of credit.
At our election, the term loan and the revolver bear interest on
the unpaid principal amount either at a base rate plus the
applicable margin (defined as 1.25% per annum, reducing to
1.00% when consolidated funded debt to Adjusted EBITDA (as
defined) is less than 3.5 to 1); or at the adjusted Eurodollar
rate plus the applicable margin (defined as 2.25% per
annum, reducing to 2.00% when consolidated funded debt to
Adjusted EBITDA (as defined) is less than 3.5 to 1). At
August 31, 2006, we elected the Eurodollar rate plus the
applicable margin (defined as 2.25%) for a cumulative rate of
7.65%. The applicable margin will increase by 0.50% per
annum on January 31, 2007, a result of the Partnership not
pursuing a rating by both S&P and Moodys, per the
agreement.
Base rate interest loans are paid the last day of each March,
June, September and December. Eurodollar rate loans are paid the
last day of each interest period, representing one-, two-,
three- or six-, nine- or twelve-months, as selected by us.
Interest on the term loans is paid each December 31,
March 31, June 30 and September 30 of each year,
commencing on September 30, 2006. We pay a commitment fee
equal to (1) the average of the daily difference between
(a) the revolver commitments and (b) the sum of the
aggregate principal amount of all outstanding revolver loans
plus the aggregate principal amount of all outstanding swing
loans times (2) 0.50% per annum; provided, the
commitment fee percentage shall increase by 0.25% per annum
on January 31, 2007. We also pay a letter of credit fee
equal to (1) the applicable margin for revolving loans that
are Eurodollar rate loans times (2) the average aggregate
daily maximum amount available to be drawn under all such
letters of credit (regardless of whether any conditions for
drawing could then be met and determined as of the close of
business on any date of determination). Additionally, we pay a
fronting fee equal to 0.125%, per annum, times the average
aggregate daily maximum amount available to be drawn under all
letters of credit.
The obligations under the amended and restated credit agreement
are secured by first priority liens on substantially all of our
assets, including a pledge of all of the capital stock of each
of our subsidiaries. In addition, the credit facility contains
various covenants limiting our ability to incur indebtedness,
grant liens and make distributions and certain financial
covenants requiring us to maintain:
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an interest coverage ratio (the ratio of our consolidated
Adjusted EBITDA to our consolidated interest expense, in each
case as defined in the credit agreement) of not less than 2.5 to
1.0, determined as of the last day of each quarter for the four
quarter period ending on the date of determination; and a
leverage ratio (the ratio of our consolidated indebtedness to
our consolidated Adjusted EBITDA, in each case as defined in the
credit agreement) of not more than 5.0 to 1.0 (or, on a
temporary basis for not more than three consecutive quarters
following the consummation of certain acquisitions, not more
than 5.25 to 1.0).
|
We will use the available borrowing capacity under our amended
and restated credit facility for working capital purposes,
maintenance and growth capital expenditures and future
acquisitions. The Partnership has approximately
$80.0 million of unused capacity under the agreement with
availability as of December 31, 2006, of approximately
$24.0 million.
Off-Balance Sheet Obligations. We have no
off-balance sheet transactions or obligations.
57
Debt Covenants. At December 31, 2006, we
were in compliance with the covenants of the credit facilities.
Total Contractual Cash Obligations. The
following table summarizes our total contractual cash
obligations as of December 31, 2006. All of the
$405.7 million of term loans outstanding on
December 31, 2006 are scheduled for interest rate resets on
three-month intervals. Interest rates were last reset for all
amounts outstanding on December 31, 2006.
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Payments Due by Perio
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Contractual Obligations
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Total
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2007
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2008
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|
|
2009
|
|
|
2010-2011
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Thereafter
|
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($ in millions)
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|
Long-term debt (including
interest)(1)
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$
|
554.8
|
|
|
$
|
31.1
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|
$
|
31.1
|
|
|
$
|
31.1
|
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|
$
|
461.5
|
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|
$
|
0.0
|
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Operating leases
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|
4.4
|
|
|
|
0.7
|
|
|
|
0.7
|
|
|
|
0.7
|
|
|
|
0.3
|
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|
|
2.0
|
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Purchase obligations(2)
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|
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|
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|
|
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Total contractual obligations
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$
|
559.2
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|
$
|
31.8
|
|
|
$
|
31.8
|
|
|
$
|
31.8
|
|
|
$
|
461.8
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|
$
|
2.0
|
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|
|
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(1) |
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Assumes our fixed swapped average interest rate of 4.92% plus
the applicable margin under our amended and restated credit
agreement, which remains constant in all periods. |
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(2) |
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Excludes physical and financial purchases of natural gas, NGLs,
and other energy commodities due to the nature of both the price
and volume components of such purchases, which vary on a daily
or monthly basis. Additionally, we do not have contractual
commitments for fixed price
and/or fixed
quantities of any material amount. |
Recent
Accounting Pronouncements
In February 2006, the Financial Accounting Standards Board, or
the FASB, issued SFAS No. 155, Accounting for
Certain Hybrid Financial Instruments, an amendment of FASB
Statements No. 133 and No. 140
(SFAS No. 155). SFAS No. 155 amends
SFAS No. 133, which required a derivative embedded in
a host contract which does not meet the definition of a
derivative be accounted for separately under certain conditions.
SFAS No. 155 amends SFAS No. 133 to narrow
the scope of such exception to strips which represent rights to
receive only a portion of the contractual interest cash flows or
of the contractual principal cash flows of a specific debt
instrument. In addition, SFAS No. 155 amends
SFAS No. 140, Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of
Liabilities, which permitted a qualifying special-purpose
entity to hold only a passive derivative financial instrument
pertaining to beneficial interests issued or sold to parties
other than the transferor. SFAS No. 155 amends
SFAS No. 140 to allow a qualifying special purpose
entity to hold a derivative instrument pertaining to beneficial
interests that itself is a derivative financial instrument.
SFAS No. 155 is effective for all financial
instruments acquired or issued (or subject to a re-measurement
event) following the start of an entitys first fiscal year
beginning after September 15, 2006. The Partnership adopted
SFAS No. 155 on January 1, 2007, and does not
expect this standard to have a material impact, if any, on our
combined financial statements.
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements. This statement defines fair
value, establishes a framework for measuring fair value, and
expands disclosure about fair value measurements. This statement
is effective for financial statements issued for fiscal years
beginning after November 15, 2007. The Company is currently
evaluating the effect the adoption of this statement will have,
if any, on its consolidated results of operations and financial
position.
In February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities (SFAS No. 159), which permits entities to
choose to measure many financial instruments and certain other
items at fair value. SFAS No. 159 is effective for us
as of January 1, 2008 and will have no impact on amounts
presented for periods prior to the effective date. We cannot
currently estimate the impact of SFAS No. 159 on our
consolidated results of operations, cash flows or financial
position and have not yet determined whether or not we will
choose to measure items subject to SFAS No. 159 at
fair value.
58
In October 2005, the FASB issued Staff Position
FAS 13-1
concerning the accounting for rental expenses associated with
operating leases for land or buildings which are incurred during
a construction period. We considered how this might apply to our
payment for
rights-of-way
associated with the construction of pipelines, and we do not
anticipate any changes to our accounting practices or impacts on
our results of operations or financial condition in light of
this recently issued Staff Position.
In July 2006, the FASB issued FASB Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109 (FIN 48),
which clarifies the accounting and disclosure for uncertainty in
tax positions, as defined. FIN 48 seeks to reduce the
diversity in practice associated with certain aspects of the
recognition and measurement related to accounting for income
taxes. This interpretation is effective for fiscal years
beginning after December 15, 2006. We do not expect that
the adoption of FIN 48 will have a material impact on our
results of operations or financial position.
Recent
Developments
On February 7, 2007, the Partnership declared a $0.3625
distribution per common unit for the fourth quarter of 2006,
prorated to $0.2679 per common unit for the timing of the
initial public offering on October 24, 2006. The
distribution to the common units was paid on February 15,
2007. No distribution was made to the subordinated or general
partners for the quarter.
On April 2, 2007, the Partnership announced it has signed a
definitive purchase agreement to acquire Laser Midstream Energy,
L.P. and certain of its subsidiaries for $136.8 million,
including $110.0 million in cash and 1,407,895 of common
units of the Partnership. The assets subject to this transaction
include over 405 miles of gathering systems and related
compression and processing facilities in South Texas, East Texas
and North Louisiana. The acquisition is subject to customary
closing conditions and is expected to close in late April.
In addition, Eagle Rock announced that it has signed a
definitive agreement to acquire certain fee minerals, royalties
and working interest properties from Montierra
Minerals & Production, L.P. (a Natural Gas Partners
VII, L.P. portfolio company) and NGP-VII Income Co-Investment
Opportunities, L.P. (a Natural Gas Partners affiliate) for an
aggregate purchase price of $127.6 million, subject to
price adjustments. Montierra and such co-investment fund
(collectively, Montierra) will receive as
consideration a total of 6,400,000 EROC common units and
$6.0 million in cash. The assets conveyed in this
transaction include minerals acres, and interests in wells with
net proved producing reserves of approximately 4.6 billion
cubic feet of gas (unaudited) and 2.5 million barrels of
oil (unaudited).
The Partnership also announced on April 2, 2007, it has
entered into a unit purchase agreement to sell in a private
placement 7,005,495 common units to third-party investors, for
total cash proceeds of $127.5 million. The Partnership also
has agreed to file a registration statement with the SEC
registering for resale the common units within 90 days
after the closing. The proceeds from this equity private
placement will fully fund the cash portion of the purchase price
of the Laser acquisition. The Partnership anticipates that the
private placement will close simultaneously with the Laser
acquisition.
In addition, the Partnership has received $100 million in
additional commitments to increase its revolver facility under
its existing Amended and Restated Credit Facility. The increase
of the revolver provides the Partnership with approximately
$175 million in borrowing availability.
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Item 7A.
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Quantitative
and Qualitative Disclosures About Market Risk.
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Risk and
Accounting Policies
We are exposed to market risks associated with commodity prices,
counterparty credit and interest rates. Our management has
established a comprehensive review of our market risks and is
developing risk management policies and procedures to monitor
and manage these market risks. Our general partner is
responsible for delegation of transaction authority levels, and
with the planned establishment of a Risk Management Committee,
our general partner will be responsible for the overall approval
of market risk management policies. The Risk Management
Committee will be composed of directors (including, on an ex
59
officio basis, our chief executive officer) who receive regular
briefings on positions and exposures, credit exposures and
overall risk management in the context of market activities. The
Risk Management Committee will be responsible for the overall
management of credit risk and commodity price risk, including
monitoring exposure limits.
See Critical Accounting Policies and
Estimates Risk Management Activities for
further discussion of the accounting for derivative contracts.
Commodity
Price Risk
We are exposed to the impact of market fluctuations in the
prices of natural gas, NGLs and other commodities as a result of
our gathering, processing and marketing activities, which
produce a naturally long position in NGLs and a natural short
position in natural gas. We attempt to mitigate commodity price
risk exposure by matching pricing terms between our purchases
and sales of commodities. To the extent that we market
commodities in which pricing terms cannot be matched and there
is a substantial risk of price exposure, we attempt to use
financial hedges to mitigate the risk. It is our policy not to
take any speculative marketing positions.
Both our profitability and our cash flow are affected by
volatility in prevailing natural gas and NGL prices. Natural gas
and NGL prices are impacted by changes in the supply and demand
for NGLs and natural gas, as well as market uncertainty.
Historically, changes in the prices of heavy NGLs, such as
natural gasoline, have generally correlated with changes in the
price of crude oil. For a discussion of the volatility of
natural gas and NGL prices, please read Risk
Factors. Adverse effects on our cash flow from increases
in natural gas prices and decreases in NGL product prices could
adversely affect our ability to make distributions to
unitholders. We manage this commodity price exposure through an
integrated strategy that includes management of our contract
portfolio, matching sales prices of commodities with purchases,
optimization of our portfolio by monitoring basis and other
price differentials in our areas of operations, and the use of
derivative contracts. Our overall direct exposure to movements
in natural gas prices is managed to minimize the risk of our
natural short position for 2006 and 2007, the periods for which
we have hedged our natural gas exposure to this point, as well
as a result of natural hedges inherent in our contract
portfolio. Natural gas prices, however, can also affect our
profitability indirectly by influencing the level of drilling
activity and related opportunities for our service. We are a
seller of NGLs and are exposed to commodity price risk
associated with downward movements in NGL prices. NGL prices
have experienced volatility in recent years in response to
changes in the supply and demand for NGLs and market
uncertainty. In response to this volatility, we have instituted
a hedging program to reduce our exposure to commodity price
risk. Under this program, we have hedged substantially all of
our share of expected NGL volumes under
percent-of-proceed
and keep-whole contracts in 2006 and 2007 through the purchase
of NGL put contracts, costless collar contracts and swap
contracts. We have also hedged substantially all of our share of
expected NGL volumes under
percent-of-proceed
contracts from 2008 through 2010 through a combination of direct
NGL hedging as well as indirect hedging through crude oil
costless collars. Additionally, to mitigate the exposure to
natural gas prices from keep-whole volumes, we have purchased
natural gas calls from 2006 to 2007 and entered into swaps for
the months of August and September 2006 to cover substantially
all of our short natural gas position associated with our
keep-whole volumes. We anticipate that after 2007, our short
natural gas position will become a long natural gas position
because of our increased volumes in the Texas Panhandle and the
volumes contributed from our Brookeland/Masters Creek
acquisition. In addition, we intend to pursue fee-based
arrangements, where market conditions permit, and to increase
retained percentages of natural gas and NGLs under
percent-of-proceed
arrangements. We continually monitor our hedging and contract
portfolio and expect to continue to adjust our hedge position as
conditions warrant.
We have not designated our contracts as accounting hedges under
Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities. As
a result, we mark our derivatives to market with the resulting
change in fair value included in our statement of operations.
60
The following table sets forth certain information regarding our
NGL options, valued as of December 31, 2006:
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Cap
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Floor
|
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Notional
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Strike
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Strike
|
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Volumes
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Price
|
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Price
|
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Fair
|
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Commodity
|
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Period
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(Bbls)
|
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Type
|
|
($/gal)
|
|
($/gal)
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
($ in thousands)
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|
|
Ethane
|
|
|
Jan-Dec 2007
|
|
|
408,000
|
|
Puts
|
|
|
|
$
|
0.5396
|
|
|
$
|
989
|
|
|
|
|
Jan-Dec 2008
|
|
|
102,000
|
|
Costless Collar
|
|
0.6500
|
|
|
0.5500
|
|
|
|
115
|
|
|
|
|
Jan-Dec 2009
|
|
|
42,000
|
|
Costless Collar
|
|
0.5800
|
|
|
0.4800
|
|
|
|
0
|
|
|
|
|
Jan-Dec 2010
|
|
|
108,000
|
|
Costless Collar
|
|
0.5300
|
|
|
0.4300
|
|
|
|
(94
|
)
|
Propane
|
|
|
Jan-Dec 2007
|
|
|
636,000
|
|
Puts
|
|
|
|
$
|
0.9000
|
|
|
$
|
3,019
|
|
|
|
|
Jan-Dec 2009
|
|
|
126,000
|
|
Costless Collar
|
|
0.8700
|
|
|
0.7650
|
|
|
|
(400
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)
|
|
|
|
Jan-Dec 2010
|
|
|
120,000
|
|
Costless Collar
|
|
0.8100
|
|
|
0.7050
|
|
|
|
(505
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)
|
Normal Butane
|
|
|
Jan-Dec 2007
|
|
|
384,000
|
|
Puts
|
|
|
|
$
|
1.0900
|
|
|
$
|
2,174
|
|
|
|
|
Jan-Dec 2009
|
|
|
66,000
|
|
Costless Collar
|
|
1.0350
|
|
|
0.9350
|
|
|
|
(244
|
)
|
|
|
|
Jan-Dec 2010
|
|
|
132,000
|
|
Costless Collar
|
|
1.0200
|
|
|
0.8200
|
|
|
|
(636
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)
|
Iso Butane
|
|
|
Jan-Dec 2007
|
|
|
156,000
|
|
Puts
|
|
|
|
$
|
1.0888
|
|
|
$
|
951
|
|
|
|
|
Jan-Dec 2009
|
|
|
30,000
|
|
Costless Collar
|
|
1.0350
|
|
|
0.9350
|
|
|
|
(119
|
)
|
|
|
|
Jan-Dec 2010
|
|
|
60,000
|
|
Costless Collar
|
|
1.0200
|
|
|
0.8200
|
|
|
|
(302
|
)
|
Natural Gasoline
|
|
|
Jan-Dec 2007
|
|
|
564,000
|
|
Puts
|
|
|
|
$
|
1.2413
|
|
|
$
|
3,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8,514
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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The following table sets forth certain information regarding our
NGL fixed swaps, valued as of December 31, 2006:
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|
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes
|
|
Wt. Avg. $/Gallon
|
|
Fair Market
|
|
Commodity
|
|
Period
|
|
|
(MBbls)
|
|
We Receive
|
|
|
We Pay
|
|
Value
|
|
|
|
|
|
|
|
|
($ in thousands)
|
|
|
Ethane
|
|
|
Jan-Dec 2007
|
|
|
|
96
|
|
|
$
|
0.6950
|
|
|
OPIS avg
|
|
$
|
494
|
|
|
|
|
Jan-Dec 2008
|
|
|
|
102
|
|
|
|
0.6000
|
|
|
OPIS avg
|
|
|
162
|
|
|
|
|
Jan-Dec 2009
|
|
|
|
120
|
|
|
|
0.5300
|
|
|
OPIS avg
|
|
|
45
|
|
|
|
|
Jan-Dec 2010
|
|
|
|
108
|
|
|
|
0.4800
|
|
|
OPIS avg
|
|
|
(65
|
)
|
Propane
|
|
|
Jan-Dec 2007
|
|
|
|
60
|
|
|
$
|
0.9300
|
|
|
OPIS avg
|
|
$
|
(23
|
)
|
|
|
|
Jan-Dec 2009
|
|
|
|
126
|
|
|
|
0.8150
|
|
|
OPIS avg
|
|
|
(413
|
)
|
|
|
|
Jan-Dec 2010
|
|
|
|
120
|
|
|
|
0.7550
|
|
|
OPIS avg
|
|
|
(519
|
)
|
Normal Butane
|
|
|
Jan-Dec 2007
|
|
|
|
24
|
|
|
$
|
1.1400
|
|
|
OPIS avg
|
|
$
|
19
|
|
|
|
|
Jan-Dec 2009
|
|
|
|
66
|
|
|
|
0.9850
|
|
|
OPIS avg
|
|
|
(244
|
)
|
Iso Butane
|
|
|
Jan-Dec 2007
|
|
|
|
12
|
|
|
$
|
1.1400
|
|
|
OPIS avg
|
|
$
|
5
|
|
|
|
|
Jan-Dec 2009
|
|
|
|
30
|
|
|
|
0.9850
|
|
|
OPIS avg
|
|
|
(119
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(658
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
The following table sets forth certain information regarding our
crude oil options, valued as of December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cap
|
|
|
Floor
|
|
|
|
|
|
|
|
|
Notional
|
|
|
|
|
Strike
|
|
|
Strike
|
|
|
Fair
|
|
|
|
|
|
Volumes
|
|
|
|
|
Price
|
|
|
Price
|
|
|
Market
|
|
Period
|
|
Commodity
|
|
(Bbls)
|
|
|
Type
|
|
($/Bbl)
|
|
|
($/Bbl)
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
($ in thousands)
|
|
|
Jan-Dec 2007
|
|
NYMEX WTI
|
|
|
528,000
|
|
|
Puts
|
|
|
|
|
|
|
$ 50.00
|
|
|
$
|
1,645
|
|
Jan-Dec 2007
|
|
NYMEX WTI
|
|
|
720,000
|
|
|
Costless Collar
|
|
|
81.66
|
|
|
|
75.00
|
|
|
|
7,971
|
|
Jan-Dec 2008
|
|
NYMEX WTI
|
|
|
960,000
|
|
|
Costless Collar
|
|
|
67.39
|
|
|
|
50.00
|
|
|
|
(5,281
|
)
|
Jan-Dec 2009
|
|
NYMEX WTI
|
|
|
480,000
|
|
|
Costless Collar
|
|
|
66.40
|
|
|
|
50.00
|
|
|
|
(2,614
|
)
|
Jan-Dec 2010
|
|
NYMEX WTI
|
|
|
480,000
|
|
|
Costless Collar
|
|
|
67.86
|
|
|
|
50.00
|
|
|
|
(2,154
|
)
|
Jan-Dec 2007
|
|
NYMEX WTI WTS
|
|
|
240,000
|
|
|
Swap
|
|
|
WTS
|
|
|
|
WTI $ 6.05
|
|
|
|
(334
|
)
|
|
|
Differential
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(767
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth certain information regarding our
natural gas options, valued as of December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wt. Avg.
|
|
|
|
|
|
|
|
|
Notional
|
|
|
|
|
Strike
|
|
|
Fair
|
|
|
|
|
|
Volumes
|
|
|
|
|
Price
|
|
|
Market
|
|
Period
|
|
Commodity
|
|
(MMBtu)
|
|
|
Type
|
|
($ MMBtu)
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
($ in thousands)
|
|
|
Jan-Dec 2007
|
|
NYMEX Henry Hub
|
|
|
1,200,000
|
|
|
Calls
|
|
|
9.63
|
|
|
|
1,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Please see Interest Rate Risk for valuation of
interest rate swaps.
The table below summarizes the changes in commodity and interest
rate risk management assets for the applicable periods:
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
12/31/2006
|
|
|
12/31/2005
|
|
|
|
($ in thousands)
|
|
|
Net risk management assets at
beginning of period
|
|
$
|
33,160
|
|
|
$
|
|
|
Investment premium payments
(amortization)
|
|
|
(19,227
|
)
|
|
|
27,452
|
|
Cash received from settled
contracts
|
|
|
(2,824
|
)
|
|
|
|
|
Settlements of positions
|
|
|
2,824
|
|
|
|
|
|
Unrealized
mark-to-market
valuations of positions
|
|
|
(4,305
|
)
|
|
|
5,708
|
|
|
|
|
|
|
|
|
|
|
Balance of risk management assets
at end of period
|
|
$
|
9,628
|
|
|
$
|
33,160
|
|
|
|
|
|
|
|
|
|
|
Credit
Risk
Our purchase and resale of natural gas exposes us to credit
risk, as the margin on any sale is generally a very small
percentage of the total sale price. Therefore, a credit loss can
be very large relative to our overall profitability. We are
diligent in attempting to ensure that we issue credit only to
credit-worthy counterparties and that in appropriate
circumstances any such extension of credit is backed by adequate
collateral such as a letter of credit or parental guarantees.
Interest
Rate Risk
The credit markets recently have experienced record lows in
interest rates. As the overall economy strengthens, it is likely
that monetary policy will tighten further, resulting in higher
interest rates to counter possible inflation. Interest rates on
future credit facilities and debt offerings could be higher than
current
62
levels, causing our financing costs to increase accordingly.
Although this could limit our ability to raise funds in the debt
capital markets, we expect to remain competitive with respect to
acquisitions and capital projects, as our competitors would face
similar circumstances.
We are exposed to variable interest rate risk as a result of
borrowings under our existing credit agreement.
In December 2005, we entered into various interest rate swaps.
These swaps convert the variable-rate term loan into a
fixed-rate obligation. The purpose of entering into this swap is
to eliminate interest rate variability by converting LIBOR-based
variable-rate payments to fixed-rate payments for a period of
five years from January 1, 2006 to January 1, 2011.
Amounts received or paid under these swaps were recorded as
reductions or increases in interest expense. The table below
summarizes the terms, amounts received or paid and the fair
values of the various interest swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
Expiration
|
|
|
Notional
|
|
|
|
|
|
Amounts Paid
|
|
|
December 31,
|
|
Effective Date
|
|
Date
|
|
|
Amount
|
|
|
Fixed Rate
|
|
|
in 2005
|
|
|
2006
|
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/03/2006
|
|
|
01/03/2011
|
|
|
$
|
100
|
|
|
|
4.9500
|
|
|
|
0.00
|
|
|
$
|
(318,782
|
)
|
01/03/2006
|
|
|
01/03/2011
|
|
|
|
100
|
|
|
|
4.9625
|
|
|
|
0.00
|
|
|
|
(267,129
|
)
|
01/03/2006
|
|
|
01/03/2011
|
|
|
|
50
|
|
|
|
4.8800
|
|
|
|
0.00
|
|
|
|
(294,612
|
)
|
01/03/2006
|
|
|
01/03/2011
|
|
|
|
50
|
|
|
|
4.8800
|
|
|
|
0.00
|
|
|
|
(294,612
|
)
|
|
|
Item 8.
|
Financial
Statements and Supplementary Data.
|
Our consolidated financial statements, together with the
independent registered public accounting firms report of
Deloitte & Touche LLP (Deloitte &
Touche), begin on
page F-1
of this Annual Report.
|
|
Item 9.
|
Changes
in and Disagreements With Accountants on Accounting and
Financial Disclosure.
|
None.
|
|
Item 9A.
|
Controls
and Procedures.
|
Disclosure
Controls
At the end of the period covered by this report, an evaluation
was performed under the supervision and with the participation
of our management, including the Chief Executive Officer and
Chief Financial Officer of the general partner of our general
partner, of the effectiveness of the design and operation of our
disclosure controls and procedures (as such terms are defined in
Rule 13a 15(e) and 15d 15(e) of the
Exchange Act of 1934, as amended). Based on that evaluation,
management, including the Chief Executive Officer and Chief
Financial Officer of the general partner of our general partner,
concluded our disclosure controls and procedures were effective
as of December 31, 2006, to provide reasonable assurance
the information required to be disclosed by us in the reports we
file or submit under the Exchange Act of 1934, as amended, are
properly recorded, processed, summarized and reported, within
the time periods specified in the SECs rules and forms.
Disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that information
required to be disclosed by an issuer in the reports that it
files or submits under the Exchange Act is accumulated and
communicated to the issuers management, including its
principal executive and principal financial officers, or persons
performing similar functions, as appropriate to allow timely
decisions regarding required disclosure.
Internal
Control over Financial Reporting
In anticipation of becoming subject to the provisions of
Section 404 of the Sarbanes-Oxley Act of 2002, we
initiated, in late 2006, an evaluation and program of
documentation, implementation and testing of internal control
over financial reporting. This program will continue through
2007, culminating with our initial
63
Section 404 certification and attestation in early 2008. As
of December 31, 2006, we have evaluated the effectiveness
of our system of internal control over financial reporting, as
well as changes therein, in compliance with
Rule 13a-15
of the SECs rules under the Securities Exchange Act and
have filed the certifications with this report required by
Rule 13a-14.
In the course of that evaluation, we found no fraud, whether or
not material, that involved management or other employees who
have a significant role in our internal control over financial
reporting and no material weaknesses. There have been no changes
in our internal controls over financial reporting that occurred
during the three months ended December 31, 2006, that have
materially affected, or are reasonably likely to affect
materially, our internal controls over financial reporting.
|
|
Item 9B.
|
Other
Information.
|
None.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance.
|
The following table shows information regarding the current
directors and executive officers of Eagle Rock Energy G&P,
LLC, which is the general partner of our general partner.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position with Eagle Rock Energy G&P, LLC
|
|
Alex A. Bucher, Jr.
|
|
|
52
|
|
|
President and Chief Executive
Officer, Director
|
Richard W. FitzGerald
|
|
|
52
|
|
|
Senior Vice President, Chief
Financial Officer and Treasurer
|
Alfredo Garcia
|
|
|
41
|
|
|
Senior Vice President, Corporate
Development
|
William E. Puckett
|
|
|
51
|
|
|
Senior Vice President, Commercial
Operations
|
J. Stacy Horn
|
|
|
45
|
|
|
Vice President, Commercial
Development
|
Stephen O. McNair
|
|
|
44
|
|
|
Vice President, Operations and
Technical Services
|
William J. Quinn
|
|
|
36
|
|
|
Director, Chairman of the Board
|
Kenneth A. Hersh
|
|
|
43
|
|
|
Director
|
Philip B. Smith
|
|
|
55
|
|
|
Director
|
John A. Weinzierl
|
|
|
38
|
|
|
Director
|
William K. White
|
|
|
64
|
|
|
Director
|
Because of its ownership of a majority interest in Eagle Rock
Holdings, L.P., Natural Gas Partners has the right to elect all
of the members of the board of directors of Eagle Rock Energy
G&P, LLC. Our directors hold office until the earlier of
their death, resignation, retirement, disqualification or
removal by the member of Eagle Rock Energy G&P, LLC. The
executive officers serve at the discretion of the board of
directors. There are no family relationships among any of our
directors or executive officers. The executive officers of Eagle
Rock Energy G&P, LLC will devote all of their time to our
business and operations.
Alex A. Bucher, Jr. was elected Chairman of the
Board, President and Chief Executive Officer of Eagle Rock
Energy G&P, LLC in August 2006 and served as Chairman of the
Board until January 2007, when William J. Quinn succeeded
Mr. Bucher as Chairman of the Board. Mr. Bucher
continues to serve as a director. Mr. Bucher also served as
President, Chief Executive Officer, Treasurer and Director of
Eagle Rock Energy G&P, LLC from March 2006 until August
2006. Mr. Bucher serves as the Chairman of the compensation
committee. Mr. Bucher has been Secretary, Chief Executive
Officer and Director of Eagle Rock Pipeline, L.P. since December
2005 and Eagle Rock Energy, Inc. from December 2003 to December
2005. In June 2002, Mr. Bucher co-founded Eagle Rock
Energy, Inc. and served as its President and Treasurer from June
2002 until December 2003. From November 1999 to June 2002,
Mr. Bucher was Vice President of Operations and Vice
President and Director of Business Development for MidCoast,
subsequently Enbridge,
64
Inc., an energy transportation and distribution company. Prior
to joining MidCoast, Mr. Bucher was Vice President and
Regional Manager for Dynegy, Inc., a gas gathering and
processing company.
Richard W. FitzGerald was elected Senior Vice President,
Chief Financial Officer and Treasurer of Eagle Rock Energy
G&P, LLC and Eagle Rock Pipeline, L.P. in August 2006. From
May 2003 to August 2006, Mr. FitzGerald was Senior Vice
President and Chief Financial Officer of Natco Group, Inc. From
April 1999 to April 2003, Mr. FitzGerald was Senior Vice
President and Chief Financial Officer of Universal Compression
Inc. Prior to that, Mr. FitzGerald was Vice President of
Financial Planning and Services for KN Energy from January
1998 to April 1999.
Alfredo Garcia was elected Senior Vice President,
Corporate Development of Eagle Rock Energy G&P, LLC in
August 2006. Mr. Garcia served as Senior Vice President and
Chief Financial Officer of Eagle Rock Energy G&P, LLC from
March 2006 until August 2006, and as Chief Financial Officer of
Eagle Rock Pipeline, L.P. from December 2005 until August 2006
and Eagle Rock Energy, Inc. from February 2004 through December
2005. From March 1999 until February 2004, Mr. Garcia was
founder and director of Investment Analysis &
Management, LLC, a financial advisory and consulting firm.
During this period, he also acted as Chief Financial Officer at
TrueCentric, LLC, a software
start-up
company. Prior to this, Mr. Garcia was a Latin American
Associate for HM Capital Partners, a private equity firm
formerly known as Hicks Muse Tate & Furst.
William E. Puckett was elected Senior Vice President,
Commercial Operations of Eagle Rock Energy G&P, LLC in March
2006. Mr. Puckett has been Vice President, Commercial
Operations of Eagle Rock Pipeline, L.P. since December 2005.
From September 1999 until November 2005, Mr. Puckett was
Vice President, Technical Services for Dynegy, Inc., a gas
gathering and processing company. Mr. Puckett has also
served in a variety of positions in marketing, processing and
operations.
J. Stacy Horn was elected Vice President, Commercial
Development of Eagle Rock Energy G&P, LLC in March 2006.
Mr. Horn has been Vice President, Commercial Development of
Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock
Energy, Inc. from October 2004 to December 2005. Prior to
joining Eagle Rock Energy, Inc., Mr. Horn was Commercial
Manager, Director of Business Development for El Paso Field
Services, L.P., a natural gas gathering and processing and
transportation company, from December 2000 to October 2004.
Stephen McNair was elected Vice President of Operations
and Technical Services of Eagle Rock Energy G&P, LLC in
August 2006. Mr. McNair has been Vice President of Natural
Gas Services for TEPPCO in Denver, Colorado from March 2005 to
July 2006. From September 2002 to January 2005, Mr. McNair
was Vice President Rocky Mountain Region for Duke
Energy Field Services. Prior to that, Mr. McNair held the
position of General Manager West Permian Region for
Duke Energy Field Service from April 2000 to August of 2002.
William J. Quinn was appointed Chairman of the Board of
Eagle Rock Energy G&P, LLC in January 2007. Mr. Quinn
was elected Director in March 2006 and serves as a member of the
compensation committee. Mr. Quinn has been a director of
Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock
Energy, Inc. from December 2003 through December 2005.
Mr. Quinn is the Executive Vice President of NGP Energy
Capital Management and is a managing partner of the Natural Gas
Partners private equity funds and has served in those or similar
capacities since 1998. He currently serves on the investment
committee of NGP Capital Resources Company, a business
development company that focuses on the energy industry.
Kenneth A. Hersh was elected Director of Eagle Rock
Energy G&P, LLC in March 2006. Mr. Hersh has been a
director of Eagle Rock Pipeline, L.P. since December 2005 and
Eagle Rock Energy, Inc. from December 2003 through December
2005. Mr. Hersh is the Chief Executive Officer of NGP
Energy Capital Management and is a managing partner of the
Natural Gas Partners private equity funds and has served in
those or similar capacities since 1989. He currently serves as a
director of NGP Capital Resources Company, a business
development company that focuses on the energy industry.
Mr. Hersh has served as a director of Energy Transfer
Partners, L.L.C., the indirect general partner of Energy
Transfer Partners, L.P., a natural gas gathering and processing
and transportation and storage and retail propane company, since
February 2004 and
65
has served as a director of LE GP, LLC, the general partner of
Energy Transfer Equity, L.P., since October 2002.
Philip B. Smith was elected Director of Eagle Rock Energy
G&P, LLC in October 2006 and serves as a member of the audit
committee, the conflicts committee and the compensation
committee of the board of directors of Eagle Rock Energy
G&P, LLC. From April 2002 to September 2006, Mr. Smith
has been administering estates and managing private investments.
From January 1999 until March 2002, Mr. Smith was Chief
Executive Officer and Chairman of the Board of Directors of
Prize Energy Corp. in Grapevine, Texas. From 1996 until 1999, he
served as a director of HS Resources, Inc. and of Pioneer
Natural Resources Company and its predecessor, MESA, Inc.
John A. Weinzierl was elected Director of Eagle Rock
Energy G&P, LLC in March 2006. Mr. Weinzierl has been a
director of Eagle Rock Pipeline, L.P. since December 2005 and
Eagle Rock Energy, Inc. from December 2003 through December
2005. Mr. Weinzierl is a managing director of the Natural
Gas Partners private equity funds and has served in that
capacity since 2005. Upon joining Natural Gas Partners in 1999,
Mr. Weinzierl served as an associate until 2000, and as a
principal until he became a managing director in December 2004.
He presently serves as a director for several of Natural Gas
Partners private portfolio companies.
William K. White was elected Director of Eagle Rock
Energy G&P, LLC in October 2006 and serves as Chairman of
the audit committee and as Chairman of the conflicts committee
of the board of directors of Eagle Rock Energy G&P, LLC.
Mr. White is President of Amado Energy Management, LLC, a
position he has held since December 2002. He is also a member of
the board of directors of Teton Energy Corporation. From
September 1996 to November 2002, Mr. White was Vice
President, Finance and Administration and Chief Financial
Officer for Pure Resources, Inc. From January 1995 to July 1996,
Mr. White was a Senior Vice President for TCW Asset
Management Company.
Effective January 31, 2007, Joan A.W. Schnepp,
formerly Executive Vice President, Secretary and director,
resigned from Eagle Rock Energy G&P, LLC. Ms. Schnepp,
who co-founded Eagle Rock in June 2002 left to pursue other
interests.
|
|
Item 11.
|
Executive
Compensation.
|
Reimbursement
of Expenses of Our General Partner
Neither our general partner nor Eagle Rock Energy G&P, LLC
receives any management fee or other compensation for its
management of our partnership. Our general partner and its
affiliates, including Eagle Rock Energy G&P, LLC, however,
is reimbursed for all expenses incurred on our behalf, including
expenses relating to the cost of employee, officer and director
compensation and benefits properly allocable to us and all other
expenses necessary or appropriate to the conduct of our business
and allocable to us. We recognize and record these expenses in
our financial statements on an accrual basis and in the same
period as our general partner or its affiliates incur them on
our behalf.
Executive
Compensation
All employees, including executive and other officers, are
employed by Eagle Rock Energy G&P, LLC, as the general
partner of our general partner. The compensation of the
executive officers of Eagle Rock Energy G&P, LLC during 2006
was set by the compensation committee of Eagle Rock Energy
G&P, LLCs board of directors prior to our initial
public offering in October 2006 and, consequently, was not
designed specifically for the management of our assets or our
business. The compensation committee of Eagle Rock Energy
G&P, LLC is in the process of designing a comprehensive
executive compensation program to provide competitive
compensation opportunities that align and drive executive
officer performance in support of our business strategies and
attract, motivate and retain high quality talent with the skills
and competencies appropriate for our business. During this
process, the compensation committee of Eagle Rock Energy
G&P, LLC may consult with one or more compensation
consultants and review relevant market data in determining
compensation levels and compensation program elements. We
anticipate that our executive compensation
66
program will include a mix of base salary, cash awards, and
equity awards fit the overall compensation objectives identified
by the compensation committee of Eagle Rock Energy G&P, LLC.
Because compensation in 2006 was not designed specifically to
compensate executive officers for efforts relating solely to our
business as a publicly traded partnership, we believe the
specific compensation information relating to our executive
officers is not indicative of compensation for the executive
officers under our current structure as a publicly traded
partnership. Therefore, we have not reported such compensation
for 2006.
Employment
and Severance Agreements
At the time of his employment, Richard W. FitzGerald entered
into an employment agreement with Eagle Rock Energy G&P,
LLC, which provides for an annual base salary of $200,000. The
agreement also entitles Mr. FitzGerald to participate in
our compensation and benefit plans, and receive company-provided
disability benefits and life insurance and certain other fringe
benefits. Mr. FitzGerald is also eligible to participate in
a company-sponsored incentive bonus plan. In addition, the
agreement contains a severance provision that provides that if
Mr. FitzGeralds employment is terminated for any
reason other than cause, he is entitled to a one-time severance
payment in the amount of his annual base salary. As part of his
employment agreement, Mr. FitzGerald has also made an
investment of $50,000 in Eagle Rock Holdings, L.P. and was
granted 150,000 units in Eagle Rock Holdings, L.P. that are
subject to vesting restrictions. For a description of the units
in Eagle Rock Holdings, L.P., see Item 13. Certain
Relationships and Related Transactions and Director Independence.
We have not entered into any other employment agreements with
our executive officers.
Compensation
of Directors
Officers or employees of Eagle Rock Energy G&P, LLC or its
affiliates who also serve as directors will not receive
additional compensation for their service as a director of Eagle
Rock Energy G&P, LLC. Our general partner anticipates that
directors who are not officers or employees of Eagle Rock Energy
G&P, LLC or its affiliates will receive compensation for
serving on the board of directors and committee meetings. It is
expected that such directors will receive (a) $50,000 per
year as an annual retainer fee; (b) $5,000 per year for
each committee of the board of directors on which such director
serves; (c) 5,000 restricted common units upon becoming a
director, vesting in one-third increments over a three-year
period; (d) 1,000 restricted common units on each
anniversary of becoming a director, vesting in one-third
increments over a three-year period; (e) reimbursement for
out-of-pocket
expenses associated with attending meetings of the board of
directors or committees; (f) reimbursement for educational
costs relevant to the directors duties; and
(g) director and officer liability insurance coverage. Each
director is fully indemnified by us for his actions associated
with being a director to the fullest extent permitted under
Delaware law.
67
|
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Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Unitholder Matters.
|
The following table sets forth the beneficial ownership of our
units as of March 26, 2007 held by:
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each person or group of persons who then will beneficially own
5% or more of the then outstanding units;
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each member of the board of directors of Eagle Rock Energy
G&P, LLC;
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each named executive officer of Eagle Rock Energy G&P,
LLC; and
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all directors and officers of Eagle Rock Energy G&P, LLC as
a group.
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Percentage of
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Percentage of
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Percentage of Total
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Common
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Common
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Subordinated
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Subordinated
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Common and
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Units to be
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Units to be
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Units to be
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Units to be
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Subordinated Units
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Beneficially
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Beneficially
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Beneficially
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Beneficially
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to be Beneficially
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Name of Beneficial Owner(1)
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Owned
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Owned
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Owned
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Owned
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Owned
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Eagle Rock Holdings, L.P.(2)
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2,187,871
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10.5
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%
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20,691,495
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100.0
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%
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55.1
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%
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Robert J. Raymond(3)
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1,348,581
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6.5
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%
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%
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3.2
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%
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Williams, Jones &
Associates, Inc.(4)
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1,334,950
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6.4
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%
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%
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3.2
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%
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Alex A. Bucher, Jr.(2)(7)
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175,989
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*
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%
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1,615,212
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7.8
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%
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4.3
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%
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Joan A. W. Schnepp(2)(5)(7)
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113,210
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*
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%
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1,065,944
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5.2
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%
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2.8
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%
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Richard W. FitzGerald(2)(7)
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32,986
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*
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%
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170,097
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*
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%
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*
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%
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Alfredo Garcia(2)(7)
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80,691
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*
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%
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763,122
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3.7
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%
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2.0
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%
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William E. Puckett(2)(7)
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28,337
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*
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%
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173,416
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*
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%
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*
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%
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J. Stacy Horn(2)(7)
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24,674
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*
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%
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124,590
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*
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%
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*
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%
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Stephen O. McNair(2)(7)
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21,905
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*
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%
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107,867
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*
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%
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*
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%
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Kenneth A. Hersh(6)
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%
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%
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|
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%
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William J. Quinn
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10,000
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*
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%
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*
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%
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*
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%
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John A. Weinzierl
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8,800
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*
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%
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*
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%
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*
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%
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William K. White
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7,700
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*
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%
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*
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%
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*
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%
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Philip B. Smith
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5,000
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*
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%
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|
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*
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%
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|
|
*
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%
|
All directors and executive
officers as a group (12 persons)
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509,292
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2.4
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%
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4,020,248
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19.4
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%
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10.9
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%
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|
|
|
* |
|
Less than 1% |
|
(1) |
|
Unless otherwise indicated, the address for all beneficial
owners in this table is 16701 Greenspoint Park Drive,
Suite 200 Houston, Texas 77060. |
|
(2) |
|
Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P.,
Alex A. Bucher, Jr., Joan A. W. Schnepp, Richard W.
FitzGerald, Alfredo Garcia, William E. Puckett, J. Stacy Horn
and Stephen O. McNair have approximately a 31.09%, 47.94%,
7.80%, 5.15%, 0.82%, 3.69%, 0.84%, 0.60% and 0.52% limited
partner interest, respectively, in Eagle Rock Holdings, L.P.
Eagle Rock GP, L.L.C., which is owned 39.14%, 60.35%, 0.35% and
0.16% by Natural Gas Partners VII, L.P., Natural Gas Partners
VIII, L.P., Mr. Bucher and Ms. Schnepp, respectively,
owns a 1.0% general partner interest in Eagle Rock Holdings,
L.P. The units held by Eagle Rock Holdings, L.P., are reported
in this table as beneficially owned by Mr. Bucher,
Ms. Schnepp, Mr. Garcia, Mr. Puckett,
Mr. FitzGerald, Mr. McNair and Mr. Horn in
proportion to their beneficial ownership in Eagle Rock Holdings,
L.P., and Eagle Rock GP, L.L.C. |
|
(3) |
|
RR Advisors, LLC, RCH Energy MLP Fund GP, L.P., RCH Energy
MLP Fund, L.P., RCH Energy MLP Fund-A, L.P., RCH Energy
Opportunity Fund I GP, L.P., and RCH Energy Opportunity
Fund I, L.P. all beneficially own units of Eagle Rock
Energy Partners, L.P. Robert J. Raymond is the sole member of RR
Advisors, LLC, which is the general partner of RCH Energy
Opportunity Fund I GP, L.P., which is the |
68
|
|
|
|
|
general partner of RCH Energy Opportunity Fund I, L.P., and
RCH Energy MLP Fund GP, L.P., which is the general partner
of RCH Energy MLP Fund, L.P., and RCH Energy MLP Fund-A, L.P.
and, as sole member of each entity, Mr. Raymond holds
voting and dispositive power over the units owned by each such
entity. |
|
(4) |
|
Kenneth A. Paulo, Senior Vice President of Williams,
Jones & Associates, Inc., has voting and dispositive
power over the units beneficially owned by Williams,
Jones & Associates, Inc. |
|
(5) |
|
Effective January 31, 2007, Ms. Schnepp resigned from
all offices and her position as a member of the board of
directors of Eagle Rock Energy G&P, LLC. |
|
(6) |
|
G.F.W. Energy VII, L.P., GFW VII, L.L.C., G.F.W. Energy VIII,
L.P. and GFW VIII, L.L.C. may be deemed to beneficially own the
units held by Eagle Rock Holdings, L.P., that are attributable
to Natural Gas Partners VII, L.P. and Natural Gas Partners VIII,
L.P. by virtue of GFW VII, L.L.C. being the sole general partner
of G.F.W. Energy VII, L.P. and GFW VIII, L.L.C. being the sole
general partner of G.F.W. Energy VIII, L.P. Kenneth A. Hersh,
who is a member of each of GFW VII, L.L.C. and GFW VIII, L.L.C.,
may also be deemed to share the power to vote, or to direct the
vote, and to dispose, or to direct the disposition of, the
units. Mr. Hersh disclaims any deemed beneficial ownership
of the units held by Eagle Rock Holdings, L.P. |
|
(7) |
|
In addition to the units he holds through his ownership of Eagle
Rock Holdings, L.P., and Eagle Rock G&P, LLC, Alex A.
Bucher, Jr. also owns 5,200 units through our directed
unit program. In addition to the units she holds through her
ownership of Eagle Rock Holdings, L.P., and Eagle Rock G&P,
LLC, Joan A.W. Schnepp also owns 500 units through our
directed unit program. In addition to the units he holds through
his ownership of Eagle Rock Holdings, L.P., Richard W.
FitzGerald also beneficially owns 5,000 units through our
directed unit program, plus 10,000 units that are subject
to a three-year vesting schedule pursuant to our long-term
incentive plan. In addition to the units he holds through his
ownership of Eagle Rock Holdings, L.P., William E. Puckett also
beneficially owns 10,000 units that are subject to a
three-year vesting schedule pursuant to our long-term incentive
plan. In addition to the units he holds through his ownership of
Eagle Rock Holdings, L.P., J. Stacy Horn also beneficially owns
1,500 units through our directed unit program plus
10,000 units that are subject to a three-year vesting
schedule pursuant to our long-term incentive plan. In addition
to the units he holds through his ownership of Eagle Rock
Holdings, L.P., Stephen O. McNair also beneficially owns
500 units through our directed unit program plus
10,000 units that are subject to a three-year vesting
schedule pursuant to our long-term incentive plan. |
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence.
|
Since January 1, 2006, we have been involved in several
transactions involving Holdings or affiliates of Natural Gas
Partners. Holdings, which is the sole member of Eagle Rock
Energy G&P, LLC, which is the general partner of our general
partner, is currently owned by Natural Gas Partners
(approximately 79.8%) and certain members of our management
team, including Alex A. Bucher, Chief Executive Officer of
G&P (approximately 7.8%), Alfredo Garcia, Senior Vice
President, Corporate Development of G&P (approximately
3.7%), Richard W. FitzGerald, Senior Vice President, Chief
Financial Officer and Treasurer of G&P (approximately 0.8%),
William E. Puckett, Senior Vice President, Commercial Operations
of G&P (approximately 0.8%), J. Stacy Horn, Senior Vice
President, Commercial Development of G&P (approximately
0.6%), and Stephen O. McNair, Vice President, Operations and
Technical Services of G&P (approximately 0.5%). The
following members of the board of directors of G&P hold
positions at Natural Gas Partners set forth next to each
persons name: William J. Quinn, Executive Vice President
of NGP Energy Capital Management and a managing partner of the
Natural Gas Partners private equity funds, Kenneth A. Hersh,
Chief Executive Officer of NGP Energy Capital Management and is
a managing partner of the Natural Gas Partners private equity
funds, John A. Weinzierl, a managing director of the Natural Gas
Partners private equity funds.
Holdings had a management advisory arrangement with Natural Gas
Partners requiring a quarterly fee payment. The agreement was
modified on December 1, 2005 to increase the management fee
to $0.5 million annually and to a $1.0 million annual
level upon the completion of our initial public offering, or
IPO. We expensed the fee paid under the advisory arrangement.
For the twelve months periods ended December 31, 2005 and
December 31, 2006, respectively, we expensed
$0.1 million and $0.4 million for the agreement
69
activity. At the time of the initial public offering, Holdings
terminated the agreement with a $6.0 million payment to
Natural Gas Partners. The termination fee was recorded as an
expense during the fourth quarter 2006 with the offset to
members equity.
During the fourth quarter 2005, Eagle Rock Pipeline, L.P., our
predecessor, declared and accrued a $5.0 million
distribution. This distribution was included in the balance
sheet at December 31, 2005, in distribution
payable-affiliate. In addition, for 2006, we paid
$215.2 million distributions to Holdings, including its
ownership in our general partner, for initial public offering
related activities and earning distributions.
As discussed in Note 4 accompanying our Consolidated
Financial Statements for the year ended December 31, 2006,
on June 2, 2006, we acquired Midstream Gas Services, L.P.,
which was a portfolio company of Natural Gas Partners VII, L.P.,
which is an affiliate of Natural Gas Partners. As part of the
consideration for the acquisition, Natural Gas Partners VII,
L.P. received pre-IPO units of limited partner interest in Eagle
Rock Pipeline, L.P., which were converted into our common units
at the time of the initial public offering. During 2006 and
separate from regular distributions relating to ownership of our
common units after the initial public offering, we caused
distributions to be made to Natural Gas Partners VII, L.P. for
the units of $3.7 million related to initial public
offering activities and earning distributions.
On July 1, 2006, we entered into a
month-to-month
contract for the sale of natural gas with an affiliate of
Natural Gas Partners, under which our Texas Panhandle Systems
has the option to sell a portion of its natural gas supply. We
received a Letter of Credit related to this agreement securing
the purchase of any natural gas under this agreement. We
recorded $19.4 million of revenues in 2006 from this
relationship.
In the fourth quarter 2006 and in connection with consummating
our initial public offering, entered into an Omnibus Agreement
with G&P, Holdings and our general partner, Eagle Rock
Energy GP, L.P., which requires us to reimburse G&P for the
payment of certain expenses incurred by G&P or its
employees, officers, or representatives on our behalf, including
payroll, benefits, insurance and other operating expenses, and
provides certain indemnification obligations.
|
|
Item 14.
|
Principal
Accountant Fees and Services.
|
The following set forth fees billed by Deloitte &
Touche LLP for the audit of our annual financial statements and
other services rendered for the fiscal years ended
December 31, 2006, 2005 and 2004:
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|
|
December 31
|
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|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Audit fees(1)
|
|
$
|
1,762,006
|
|
|
$
|
1,180,000
|
|
|
$
|
234,000
|
|
Audit related fees(2)
|
|
|
|
|
|
|
60,000
|
|
|
|
|
|
Tax fees(3)
|
|
|
16,660
|
|
|
|
53,000
|
|
|
|
164,000
|
|
All other fees
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,778,666
|
|
|
$
|
1,293,000
|
|
|
$
|
398,000
|
|
|
|
|
(1) |
|
Includes fees for audits of annual financial statements of our
companies, reviews of the related quarterly financial
statements, and services that are normally provided by the
independent accountants in connection with statutory and
regulatory filings or engagements, including reviews of interim
financial statements, audits of businesses acquired and other
customary documents filed with the Securities and Exchange
Commission. |
|
(2) |
|
Includes fees related to consultations concerning financial
accounting and reporting standards and services related to the
implementation of our internal controls over financial reporting. |
|
(3) |
|
Includes fees related to professional services for tax
compliance, tax advice, and tax planning. |
Pursuant to the charter of the Audit Committee, the Audit
Committee is responsible for the oversight of our accounting,
reporting and financial practices. The Audit Committee has the
responsibility to select, appoint, engage, oversee, retain,
evaluate and terminate our external auditors; pre-approve all
audit and non-
70
audit services to be provided, consistent with all applicable
laws, to us by our external auditors; and to establish the fees
and other compensation to be paid to our external auditors. The
Audit Committee also oversees and directs our internal auditing
program and reviews our internal controls.
The Audit Committee has started a process for the pre-approval
of audit and permitted non-audit services provided by our
principal independent accountants. The policy requires that all
services provided by Deloitte & Touch LLP, including
audit services, audit-related services, tax services and other
services, must be pre-approved by the Committee.
The Audit Committee reviews the external auditors proposed
scope and approach as well as the performance of the external
auditors. It also has direct responsibility for and sole
authority to resolve any disagreements between our management
and our external auditors regarding financial reporting,
regularly reviews with the external auditors any problems or
difficulties the auditors encountered in the course of their
audit work, and, at least annually, uses its reasonable efforts
to obtain and review a report from the external auditors
addressing the following (among other items):
|
|
|
|
|
the auditors internal quality-control procedures;
|
|
|
|
any material issues raised by the most recent internal
quality-control review, or peer review, of the external auditors;
|
|
|
|
the independence of the external auditors;
|
|
|
|
the aggregate fees billed by our external auditors for each of
the previous two fiscal years; and
|
|
|
|
the rotation of the lead partner.
|
PART IV
|
|
Item 15.
|
Exhibits
and Financial Statement Schedules.
|
(a)(1) Financial Statements:
The following financial statements and the Report of Independent
Registered Public Accounting Firm are filed as a part of this
report on the pages indicated:
(a)(2) Financial Statement Schedules:
None.
(a)(3) Exhibits:
The following documents are included as exhibits to this report:
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.1
|
|
Certificate of Limited Partnership
of Eagle Rock Energy Partners, L.P. (incorporated by reference
to Exhibit 3.1 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
|
3
|
.2
|
|
Amended and Restated Agreement of
Limited Partnership of Eagle Rock Energy Partners, L.P.
(included as Appendix A to the Prospectus and including
specimen unit certificate for the common units) (incorporated by
reference to Exhibit 3.2 of the registrants
registration statement on
Form S-1
(File
No. 333-134750))
|
|
3
|
.3
|
|
Certificate of Limited Partnership
of Eagle Rock Energy GP, L.P. (incorporated by reference to
Exhibit 3.3 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
|
|
3
|
.4
|
|
Limited Partnership Agreement of
Eagle Rock Energy GP, L.P. (incorporated by reference to
Exhibit 3.4 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
|
|
3
|
.5
|
|
Certificate of Formation of Eagle
Rock Energy G&P, LLC (incorporated by reference to
Exhibit 3.5 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
|
71
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
3
|
.6
|
|
Amended and Restated Limited
Liability Company Agreement of Eagle Rock Energy G&P, LLC
(incorporated by reference to Exhibit 3.6 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
4
|
.1
|
|
Registration Rights Agreement
dated March 27, 2006, among Eagle Rock Pipeline, L.P. and
the Purchasers listed thereto (incorporated by reference to
Exhibit 4.1 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
|
|
4
|
.2
|
|
Tag Along Agreement dated
March 27, 2006, among Eagle Rock Pipeline, L.P., Eagle Rock
Pipeline GP, LLC, Eagle Rock Holdings, L.P., and the Purchasers
listed thereto. (incorporated by reference to Exhibit 4.2
of the registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
4
|
.3
|
|
Form of Registration Rights
Agreement between Eagle Rock Energy Partners, L.P. and Eagle
Rock Holdings, L.P. (incorporated by reference to
Exhibit 4.3 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
|
|
4
|
.4
|
|
Form of Common Unit Certificate
(included as Exhibit A to the Amended and Restated
Partnership Agreement of Eagle Rock Energy Partners, L.P., which
is included as Appendix A to the Prospectus) (incorporated
by reference to Exhibit 3.2 of the registrants
registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.1
|
|
Amended and Restated Credit and
Guaranty Agreement (incorporated by reference to
Exhibit 3.1 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
|
|
10
|
.2
|
|
Form of Omnibus Agreement
(incorporated by reference to Exhibit 3.1 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.3**
|
|
Form of Eagle Rock Energy
Partners, L.P. Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.3 of the registrants
registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.4
|
|
Sale, Contribution and Exchange
Agreement by and among the general and limited partners of
Midstream Gas Services, L.P., Eagle Rock Energy Services, L.P.
and Eagle Rock Pipeline, L.P. (incorporated by reference to
Exhibit 10.4 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.5
|
|
Natural Gas Liquids Exchange
Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas
Field Services, L.P. (incorporated by reference to
Exhibit 10.5 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.6
|
|
Gas Sales and Purchase Agreement
between MC Panhandle, Inc. (Chesapeake Energy Marketing Inc.)
and MidCon Gas Services Corp. (Eagle Rock Field Services, L.P.)
(incorporated by reference to Exhibit 10.6 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.7
|
|
Brookeland Gas Facilities Gas
Gathering and Processing Agreement between Union Pacific
Resources Company (Anadarko E&P Company LP) and Sonat
Exploration Company (Eagle Rock Field Services, L.P.)
(incorporated by reference to Exhibit 10.7 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.8
|
|
Minimum Volume Agreement between
ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC
(incorporated by reference to Exhibit 10.8 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.9
|
|
Gas Purchase Agreement between
ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC
(incorporated by reference to Exhibit 10.9 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.10
|
|
Gas Purchase Contract between
Warren Petroleum Company (Eagle Rock Field Services, L.P.) and
Wallace Oil & Gas, Inc. (Cimarex Energy Co.)
(incorporated by reference to Exhibit 10.10 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.11
|
|
Form of Contribution, Conveyance
and Assumption Agreement (incorporated by reference to
Exhibit 10.11 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.12**
|
|
Employment Agreement dated
August 2, 2006 between Eagle Rock Energy G&P, LLC and
Richard W. FitzGerald (incorporated by reference to
Exhibit 10.12 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
72
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
10
|
.13
|
|
Base Contract for Sale and
Purchase of Natural Gas between Eagle Rock Field Services, L.P.
and Odyssey Energy Services, LLC (incorporated by reference to
Exhibit 10.13 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
|
14
|
.1
|
|
Code of Ethics posted on the
Companys website at www.eaglerockenergy.com.
|
|
21
|
.1
|
|
List of Subsidiaries of Eagle Rock
Energy Partners, L.P. (incorporated by reference to
Exhibit 21.1 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
|
23
|
.1*
|
|
Consent of Deloitte &
Touche LLP
|
|
24
|
.1*
|
|
Powers of Attorney
|
|
31
|
.1*
|
|
Certification of Periodic
Financial Reports by Alex A. Bucher, Jr. in satisfaction of
Section 302 of the Sarbanes-Oxley Act of 2002
|
|
31
|
.2*
|
|
Certification of Periodic
Financial Reports by Richard W. FitzGerald in satisfaction of
Section 302 of the Sarbanes-Oxley Act of 2002
|
|
32
|
.2*
|
|
Certification of Periodic
Financial Reports by Alex A. Bucher, Jr. in satisfaction of
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
32
|
.2*
|
|
Certification of Periodic
Financial Reports by Richard W. FitzGerald in satisfaction of
Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
* |
|
Filed herewith |
|
** |
|
Management contract or compensatory plan or arrangement required
to be filed as an exhibit hereto. |
|
|
|
Portions of this exhibit have been omitted pursuant to a request
for confidential treatment. |
73
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report on its behalf by the undersigned, thereunto duly
authorized, on April 2, 2007.
EAGLE ROCK ENERGY PARTNERS, L.P.
By: Eagle Rock Energy GP, L.P., its general partner
By: Eagle Rock Energy G&P, LLC, its general partner
|
|
|
|
By:
|
/s/ Alex
A. Bucher, Jr.
|
Name: Alex A. Bucher, Jr.
|
|
|
|
Title:
|
President and Chief Executive Officer
|
EAGLE ROCK ENERGY PARTNERS, L.P.
By: Eagle Rock Energy GP, L.P., its general partner
By: Eagle Rock Energy G&P, LLC, its general partner
|
|
|
|
By:
|
/s/ Richard
W. FitzGerald
|
Name: Richard W. FitzGerald
|
|
|
|
Title:
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacity and on the dates
indicated:
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
/s/ Alex
A. Bucher
Alex
A. Bucher
|
|
President and Chief Executive
Officer (Principal Executive Officer)
|
|
April 2, 2007
|
|
|
|
|
|
/s/ Richard
W. FitzGerald
Richard
W. FitzGerald
|
|
Senior Vice President, Chief
Financial Officer and Treasurer
(Principal Financial and Accounting Officer)
|
|
April 2, 2007
|
|
|
|
|
|
/s/ Alfredo
Garcia
Alfredo
Garcia
|
|
Senior Vice President,
Corporate Development
|
|
April 2, 2007
|
|
|
|
|
|
/s/ William
J. Quinn
William
J. Quinn
|
|
Chairman of the Board and Director
|
|
April 2, 2007
|
74
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
/s/ Kenneth
A. Hersh
Kenneth
A. Hersh
|
|
Director
|
|
April 2, 2007
|
|
|
|
|
|
/s/ Philip
B. Smith
Philip
B. Smith
|
|
Director
|
|
April 2, 2007
|
|
|
|
|
|
/s/ John
A. Weinzierl
John
A. Weinzierl
|
|
Director
|
|
April 2, 2007
|
|
|
|
|
|
/s/ William
K. White
William
K. White
|
|
Director
|
|
April 2, 2007
|
75
CONSOLIDATED
FINANCIAL STATEMENTS
OF EAGLE ROCK ENERGY PARTNERS, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page
|
|
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
|
|
|
|
|
|
|
|
F-7
|
|
|
|
|
F-7
|
|
|
|
|
F-11
|
|
|
|
|
F-12
|
|
|
|
|
F-14
|
|
|
|
|
F-15
|
|
|
|
|
F-17
|
|
|
|
|
F-18
|
|
|
|
|
F-19
|
|
|
|
|
F-19
|
|
|
|
|
F-20
|
|
|
|
|
F-21
|
|
|
|
|
F-23
|
|
|
|
|
F-23
|
|
|
|
|
F-23
|
|
|
|
|
F-24
|
|
|
|
|
F-24
|
|
|
|
|
F-25
|
|
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Eagle Rock Energy G&P, LLC and
Unitholders of
Eagle Rock Energy Partners, L.P.
Houston, Texas
We have audited the consolidated balance sheets of Eagle Rock
Energy Partners, L.P. and subsidiaries (formerly Eagle Rock
Pipeline, L.P.) (the Partnership) as of
December 31, 2006 and 2005, and the related consolidated
statements of operations, members equity, and cash flows
for each of the three years in the period ended
December 31, 2006. These financial statements are the
responsibility of the Partnerships management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. The Partnership is not required
to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audit included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Partnerships internal control
over financial reporting. Accordingly, we express no such
opinion. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe our
audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of the Partnership as
of December 31, 2006 and 2005, and the results of its
operations and its cash flows for each of the three years in the
period ended December 31, 2006, in conformity with
accounting principles generally accepted in the United States of
America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
April 2, 2007
F-2
EAGLE
ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED
BALANCE SHEETS
AS OF
DECEMBER 31, 2006 AND 2005
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
($ in thousands)
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
10,581
|
|
|
$
|
19,372
|
|
Accounts receivable
|
|
|
43,567
|
|
|
|
43,557
|
|
Risk management assets
|
|
|
13,837
|
|
|
|
21,830
|
|
Prepayments and other current
assets
|
|
|
2,679
|
|
|
|
1,277
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
70,664
|
|
|
|
86,036
|
|
PROPERTY, PLANT AND
EQUIPMENT Net
|
|
|
554,063
|
|
|
|
441,588
|
|
INTANGIBLE ASSETS Net
|
|
|
130,001
|
|
|
|
115,000
|
|
RISK MANAGEMENT ASSETS
|
|
|
17,373
|
|
|
|
44,023
|
|
OTHER ASSETS
|
|
|
7,800
|
|
|
|
14,012
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
779,901
|
|
|
$
|
700,659
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS
EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
49,558
|
|
|
$
|
43,401
|
|
Distributions payable-affiliate
|
|
|
|
|
|
|
5,000
|
|
Accrued liabilities
|
|
|
7,996
|
|
|
|
2,324
|
|
Risk management liabilities
|
|
|
1,005
|
|
|
|
2,260
|
|
Current maturities of long-term
debt
|
|
|
|
|
|
|
3,866
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
58,559
|
|
|
|
56,851
|
|
LONG-TERM DEBT
|
|
|
405,731
|
|
|
|
404,600
|
|
ASSET RETIREMENT OBLIGATIONS
|
|
|
1,819
|
|
|
|
679
|
|
DEFERRED TAX LIABILITY
|
|
|
1,229
|
|
|
|
|
|
RISK MANAGEMENT LIABILITIES
|
|
|
20,576
|
|
|
|
30,433
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
MEMBERS EQUITY:
|
|
|
|
|
|
|
|
|
Common Unitholders(1)
|
|
|
116,283
|
|
|
|
208,013
|
|
Subordinated Unitholders(2)
|
|
|
176,248
|
|
|
|
|
|
General Partner
|
|
|
(544
|
)
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
Total members equity
|
|
|
291,987
|
|
|
|
208,096
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
779,901
|
|
|
$
|
700,659
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
20,691,495 and 24,150,739 units were issued and outstanding for
2006 and 2005, respectively.
|
|
(2)
|
20,691,495 and 0 units were issued and outstanding for 2006 and
2005, respectively.
|
See notes to consolidated financial statements.
F-3
EAGLE
ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED
STATEMENTS OF OPERATIONS
FOR THE
YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
($ in thousands, except
|
|
|
|
per unit amounts)
|
|
|
REVENUE:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas liquids sales
|
|
$
|
234,354
|
|
|
$
|
29,192
|
|
|
$
|
8,797
|
|
Natural gas sales
|
|
|
195,146
|
|
|
|
26,463
|
|
|
|
968
|
|
Condensate
|
|
|
57,411
|
|
|
|
4,266
|
|
|
|
72
|
|
Gathering, compression, and
processing fees
|
|
|
14,862
|
|
|
|
6,247
|
|
|
|
799
|
|
(Loss) gain on risk management
instruments
|
|
|
(24,004
|
)
|
|
|
7,308
|
|
|
|
|
|
Other
|
|
|
621
|
|
|
|
214
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
478,390
|
|
|
|
73,690
|
|
|
|
10,636
|
|
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of natural gas and natural
gas liquids
|
|
|
377,580
|
|
|
|
55,272
|
|
|
|
8,811
|
|
Operations and maintenance
|
|
|
32,905
|
|
|
|
2,955
|
|
|
|
34
|
|
General and administrative
|
|
|
13,161
|
|
|
|
4,765
|
|
|
|
2,406
|
|
Advisory termination fee
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
43,220
|
|
|
|
4,088
|
|
|
|
619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
472,866
|
|
|
|
67,080
|
|
|
|
11,870
|
|
OPERATING INCOME (LOSS)
|
|
|
5,524
|
|
|
|
6,610
|
|
|
|
(1,234
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income
|
|
|
996
|
|
|
|
171
|
|
|
|
24
|
|
Interest and other expense
|
|
|
(28,604
|
)
|
|
|
(4,031
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
|
(27,608
|
)
|
|
|
(3,860
|
)
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX PROVISION
|
|
|
1,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(LOSS) INCOME FROM CONTINUING
OPERATIONS
|
|
|
(23,314
|
)
|
|
|
2,750
|
|
|
|
(1,210
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME FROM DISCONTINUED OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
22,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET (LOSS) INCOME
|
|
$
|
(23,314
|
)
|
|
$
|
2,750
|
|
|
$
|
20,982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET (LOSS) INCOME PER COMMON
UNIT BASIC AND DILUTED:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing
operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
(1.26
|
)
|
|
$
|
0.11
|
|
|
$
|
(0.05
|
)
|
Subordinated units
|
|
|
(0.43
|
)
|
|
|
|
|
|
|
|
|
General partner units
|
|
|
(0.80
|
)
|
|
|
4.06
|
|
|
|
(0.05
|
)
|
Income from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.87
|
|
General partner units
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income Common units
|
|
$
|
(1.26
|
)
|
|
$
|
0.11
|
|
|
$
|
0.92
|
|
Subordinated units
|
|
|
(0.43
|
)
|
|
|
|
|
|
|
|
|
General partner units
|
|
|
(0.80
|
)
|
|
|
4.06
|
|
|
|
|
|
Basic and Diluted (units in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
12,123
|
|
|
|
24,151
|
|
|
|
24,151
|
|
Subordinated units
|
|
|
17,873
|
|
|
|
|
|
|
|
|
|
General partner units
|
|
|
557
|
|
|
|
20
|
|
|
|
|
|
See notes to consolidated financial statements.
F-4
EAGLE
ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
FOR THE
YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
($ in thousands)
|
|
|
CASH FLOWS FROM OPERATING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(23,314
|
)
|
|
$
|
2,750
|
|
|
$
|
20,982
|
|
Adjustments to reconcile net income
(loss) to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
43,220
|
|
|
|
4,088
|
|
|
|
1,174
|
|
Amortization of debt issuance costs
|
|
|
1,114
|
|
|
|
76
|
|
|
|
|
|
Net realized gain on derivative
contracts
|
|
|
(978
|
)
|
|
|
|
|
|
|
|
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
(19,465
|
)
|
Advisory termination fee
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
Equity-based compensation
|
|
|
142
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
1,424
|
|
|
|
5
|
|
|
|
|
|
Changes in assets and
liabilities net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(10
|
)
|
|
|
(42,821
|
)
|
|
|
688
|
|
Prepayments and other current assets
|
|
|
(1,422
|
)
|
|
|
(358
|
)
|
|
|
214
|
|
Risk management activities
|
|
|
23,531
|
|
|
|
(5,709
|
)
|
|
|
|
|
Accounts and distributions payable
|
|
|
3,105
|
|
|
|
40,094
|
|
|
|
167
|
|
Accrued liabilities
|
|
|
5,672
|
|
|
|
103
|
|
|
|
2
|
|
Other assets
|
|
|
(3,492
|
)
|
|
|
104
|
|
|
|
111
|
|
Other current liabilities
|
|
|
|
|
|
|
|
|
|
|
(221
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
operating activities
|
|
|
54,992
|
|
|
|
(1,667
|
)
|
|
|
3,652
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property, plant and
equipment
|
|
|
(38,416
|
)
|
|
|
(4,157
|
)
|
|
|
(20,491
|
)
|
Sale of fixed assets
|
|
|
|
|
|
|
|
|
|
|
37,409
|
|
Acquisitions, net
|
|
|
(101,182
|
)
|
|
|
(530,951
|
)
|
|
|
|
|
Escrow cash
|
|
|
7,643
|
|
|
|
(7,643
|
)
|
|
|
|
|
Purchase of intangible assets
|
|
|
(2,918
|
)
|
|
|
(750
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by
investing activities
|
|
|
(134,873
|
)
|
|
|
(543,501
|
)
|
|
|
16,918
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Repayment of) proceeds from
long-term debt
|
|
|
(4,635
|
)
|
|
|
400,000
|
|
|
|
(14,000
|
)
|
Proceeds from revolver
|
|
|
12,500
|
|
|
|
7,600
|
|
|
|
|
|
Repayment of revolver
|
|
|
(10,600
|
)
|
|
|
|
|
|
|
|
|
Payment of debt issuance costs
|
|
|
(2,939
|
)
|
|
|
(6,535
|
)
|
|
|
|
|
Payment for derivative contracts
|
|
|
|
|
|
|
(27,452
|
)
|
|
|
|
|
Proceeds from derivative contracts
|
|
|
978
|
|
|
|
|
|
|
|
|
|
Unit issuance costs for IPO
|
|
|
(3,723
|
)
|
|
|
|
|
|
|
|
|
Net cash in flow from IPO,
including overallotment
|
|
|
248,067
|
|
|
|
|
|
|
|
|
|
Distributions of IPO proceeds to
pre-IPO members
|
|
|
(245,067
|
)
|
|
|
|
|
|
|
|
|
Contribution by members
|
|
|
98,540
|
|
|
|
192,369
|
|
|
|
45
|
|
Distributions to members and
affiliates
|
|
|
(22,033
|
)
|
|
|
(9,679
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
financing activities
|
|
|
71,088
|
|
|
|
556,304
|
|
|
|
(13,955
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET (DECREASE) INCREASE IN CASH AND
CASH EQUIVALENTS
|
|
|
(8,791
|
)
|
|
|
11,136
|
|
|
|
6,615
|
|
CASH AND CASH
EQUIVALENTS Beginning of period
|
|
|
19,372
|
|
|
|
8,235
|
|
|
|
1,620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH
EQUIVALENTS End of period
|
|
$
|
10,581
|
|
|
$
|
19,372
|
|
|
$
|
8,235
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid net of
amounts capitalized
|
|
$
|
30,657
|
|
|
$
|
|
|
|
$
|
317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments in property, plant and
equipment not paid
|
|
$
|
6,573
|
|
|
$
|
1,190
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions payable to member
|
|
$
|
|
|
|
$
|
5,000
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepayment financed by note payable
|
|
$
|
|
|
|
$
|
866
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common units for MGS
acquisition
|
|
$
|
20,280
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
F-5
EAGLE
ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED
STATEMENTS OF MEMBERS EQUITY
FOR THE
YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Rock
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
Number of
|
|
|
|
|
|
Pipeline, L.P.
|
|
|
|
|
|
|
General
|
|
|
Common
|
|
|
Common
|
|
|
Subordinated
|
|
|
Subordinated
|
|
|
Predecessor
|
|
|
|
|
|
|
Partner
|
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
|
Equity
|
|
|
Total
|
|
|
|
($ in thousands, except unit amounts)
|
|
|
BALANCE January 1,
2004
|
|
$
|
|
|
|
|
24,150,731
|
(1)
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
6,628
|
|
|
$
|
6,628
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,982
|
|
|
|
20,982
|
|
Capital contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45
|
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE
December 31, 2004
|
|
|
|
|
|
|
24,150,731
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27,655
|
|
|
|
27,655
|
|
Net income
|
|
|
83
|
|
|
|
|
|
|
|
4,067
|
|
|
|
|
|
|
|
|
|
|
|
(1,400
|
)
|
|
|
2,750
|
|
Capital contributions
|
|
|
|
|
|
|
|
|
|
|
142,688
|
|
|
|
|
|
|
|
|
|
|
|
49,681
|
|
|
|
192,369
|
|
Distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,679
|
)
|
|
|
(14,679
|
)
|
Conversion of predecessor equity to
common units
|
|
|
|
|
|
|
|
|
|
|
61,258
|
|
|
|
|
|
|
|
|
|
|
|
(61,258
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE
December 31, 2005
|
|
|
83
|
|
|
|
24,150,731
|
(1)
|
|
|
208,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
208,096
|
|
Net loss
|
|
|
(448
|
)
|
|
|
|
|
|
|
(15,229
|
)
|
|
|
|
|
|
|
(7,637
|
)
|
|
|
|
|
|
|
(23,314
|
)
|
Distributions
|
|
|
(287
|
)
|
|
|
|
|
|
|
(4,160
|
)
|
|
|
|
|
|
|
(12,587
|
)
|
|
|
|
|
|
|
(17,033
|
)
|
Conversion of common units to
subordinated units
|
|
|
|
|
|
|
(20,691,495
|
)
|
|
|
(193,481
|
)
|
|
|
20,691,495
|
|
|
|
193,481
|
|
|
|
|
|
|
|
|
|
Issuance of common
units March 2006
|
|
|
|
|
|
|
3,922,930
|
(2)
|
|
|
98,540
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98,540
|
|
Issuance of common units in MGS
acquisition
|
|
|
|
|
|
|
809,329
|
(2)
|
|
|
20,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,280
|
|
IPO and overallotment
|
|
|
4,883
|
|
|
|
12,500,000
|
|
|
|
37,144
|
|
|
|
|
|
|
|
206,039
|
|
|
|
|
|
|
|
248,067
|
|
Distribution of IPO proceeds
|
|
|
(4,824
|
)
|
|
|
|
|
|
|
(35,860
|
)
|
|
|
|
|
|
|
(204,382
|
)
|
|
|
|
|
|
|
(245,067
|
)
|
IPO offering costs
|
|
|
(74
|
)
|
|
|
|
|
|
|
(1,593
|
)
|
|
|
|
|
|
|
(2,056
|
)
|
|
|
|
|
|
|
(3,723
|
)
|
Advisory fee termination
|
|
|
120
|
|
|
|
|
|
|
|
2,567
|
|
|
|
|
|
|
|
3,313
|
|
|
|
|
|
|
|
6,000
|
|
Restricted units expense
|
|
|
3
|
|
|
|
|
|
|
|
61
|
|
|
|
|
|
|
|
78
|
|
|
|
|
|
|
|
142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE
December 31, 2006
|
|
$
|
(544
|
)
|
|
|
20,691,495
|
|
|
$
|
116,283
|
|
|
|
20,691,495
|
|
|
$
|
176,248
|
|
|
$
|
|
|
|
$
|
291,987
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents adjusted common units for presentation purposes.
Based upon units on formation in March 2006, adjusted for IPO
unit rate conversion. |
|
(2) |
|
Units issued adjusted for IPO conversion. |
See notes to consolidated financial statements.
F-6
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND
2004
|
|
NOTE 1.
|
ORGANIZATION
AND DESCRIPTION OF BUSINESS
|
Eagle Rock Pipeline, L.P., a Texas limited partnership, is an
indirect wholly-owned subsidiary of Eagle Rock Holdings, L.P.
(Holdings). Holdings is a portfolio company of
Irving, Texas based private equity capital firm, Natural Gas
Partners. Eagle Rock Pipeline, L.P. was formed on
November 14, 2005 for the purpose of owning a limited
partnership interest in Eagle Rock Midstream Resources, L.P.
In May 2006, Eagle Rock Energy Partners, L.P., a Delaware
limited partnership, an indirect wholly-owned subsidiary of
Holdings, was formed for the purpose of completing a public
offering of common units. On October 24, 2006, it offered
and sold 12,500,000 common units in its initial public offering,
or IPO, at a price of $19.00 per unit. Net proceeds from
the sale of the units, $222.1 million after underwriting
costs, were used for reimbursement of capital expenditures for
investors prior to the initial public offering, replenish
working capital, and distribution arrearage payment. In
connection with the initial public offering, Eagle Rock
Pipeline, L.P. was merged with and into a newly formed
subsidiary of Eagle Rock Energy Partners, L.P. (Eagle Rock
Energy or the Partnership).
Basis of Presentation and Principles of
Consolidation The accompanying financial
statements include assets, liabilities and the results of
operations of Eagle Rock Energy from October 24, 2006, and
the results of operations of Eagle Rock Pipeline, L.P. and its
predecessor entities for the periods prior to October 24,
2006. The reorganization of these entities was accounted for as
a reorganization of entities under common control. The general
partner of Eagle Rock Energy and Eagle Rock Midstream Resources,
L.P. is Eagle Rock Energy GP, L.P., a wholly-owned subsidiary of
Holdings. Eagle Rock Pipeline, L.P., Eagle Rock Midstream
Resources L.P. and their subsidiaries and, effective
October 24, 2006, Eagle Rock Energy Partners, L.P. are
collectively referred to as Eagle Rock Energy or the
Partnership.
Eagle Rock Energy, through its wholly-owned subsidiaries and
partnerships, provides midstream energy services, including
gathering, transportation, treating, processing and conditioning
services in the Texas Panhandle region. The Partnerships
natural gas pipelines collect natural gas from designated points
near producing wells and transports these volumes to third-party
pipelines, the Partnerships gas processing plants,
utilities and industrial consumers. Natural gas shipped to the
Partnerships gas processing plants, either on the
Partnerships pipelines or third-party pipelines, is
treated to remove contaminants, conditioned or processed into
mixed natural gas liquids, or NGLs. The Partnership conducts it
operation within two geographic areas of Texas. The
Partnerships Texas Panhandle assets consist of assets
acquired from ONEOK, Inc. on December 1, 2005 (see
Note 4), and include gathering and processing assets (the
Texas Panhandle Systems). The Partnerships
southeast Texas and Louisiana assets include a non-operated 25%
undivided interest in a processing plant as well as a
non-operated 20% undivided interest in a connected gathering
system. In December 2005, the Partnership began operations of a
newly constructed pipeline in east Texas that connects to the
non-operated system (collectively, the Texas and Louisiana
System). This pipeline was completed on February 28,
2006. On March 31, 2006, the Partnerships southeast
Texas and Louisiana System completed the acquisition of 100%
interest in the Brookeland and Masters Creek processing plants
in east Texas from Duke Energy Field Services. (see Note 4)
On June 2, 2006, the Partnerships Texas Panhandle
Systems completed the acquisition of 100% of Midstream Gas
Services, L.P. (see Note 4)
|
|
NOTE 2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
The accompanying consolidated financial statements have been
prepared in accordance with accounting principles generally
accepted in the United States. Eagle Rock Energy is the owner of
a non-operating undivided interest in a gas processing plant and
a gas gathering system. Eagle Rock Energy owns these interests
as tenants in common with the majority owner-operator of the
facilities. Accordingly, Eagle Rock Energy includes its pro-rata
share of assets, liabilities, revenues and expenses related to
these assets in its financial statements. All significant
intercompany accounts and transactions are eliminated in the
consolidated financial statements.
F-7
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Use of Estimates The preparation of the
financial statements in conformity with accounting policies
generally accepted in the United States of America requires
management to make estimates and assumptions which affect the
reported amounts of assets, liabilities, revenues and expenses
and disclosure of contingent assets and liabilities that exist
at the date of the financial statements. Although management
believes the estimates are appropriate, actual results can
differ from those estimates.
Cash and Cash Equivalents Cash and cash
equivalents include certificates of deposit or other highly
liquid investments with maturities of three months or less at
the time of purchase.
Concentration and Credit Risk Concentration
and credit risk for the Partnership principally consists of cash
and cash equivalents and accounts receivable.
The Partnership places its cash and cash equivalents with
high-quality institutions and in money market funds. The
Partnership derives its revenue from customers primarily in the
natural gas industry. On June 1, 2006, the Partnership
increased the parties to which it was selling liquids and
natural gas from two to eleven. These industry concentrations
have the potential to impact the Partnerships overall
exposure to credit risk, either positively or negatively, in
that the Partnerships customers could be affected by
similar changes in economic, industry or other conditions.
However, the Partnership believes the credit risk posed by this
industry concentration is offset by the creditworthiness of the
Partnerships customer base. The Partnerships
portfolio of accounts receivable is comprised primarily of
mid-size to large domestic corporate entities.
Certain Other Concentrations The Partnership
relies on natural gas producer customers for its natural gas and
natural gas liquid supply, with two producers accounting for
29.2% of its natural gas supply in its Texas Panhandle Systems
and 55.9% of its natural gas supply in the Texas and Louisiana
System for the year ended December 31, 2006. Those
suppliers accounted for 28.1% of the natural gas supply for the
year ended December 31, 2005. While there are numerous
natural gas and natural gas liquid producers and some of these
producer customers are subject to long-term contracts, the
Partnership may be unable to negotiate extensions or
replacements of these contracts, on favorable terms, if at all.
If the Partnership were to lose all or even a portion of the
natural gas volumes supplied by these producers and was unable
to acquire comparable volumes, the Partnerships results of
operations and financial position could be materially adversely
affected.
Property, Plant, and Equipment Property,
plant, and equipment consists primarily of gas gathering
systems, gas processing plants, NGL pipelines, conditioning and
treating facilities and other related facilities, which are
carried at cost less accumulated depreciation. The Partnership
charges repairs and maintenance against income when incurred and
capitalizes renewals and betterments, which extend the useful
life or expand the capacity of the assets. The Partnership
calculates depreciation on the straight-line method principally
over 20-year
estimated useful lives of the Partnerships newly developed
or acquired assets, with usually no residual value. The weighted
average useful lives are as follows:
|
|
|
|
|
Pipelines and equipment
|
|
|
20 years
|
|
Gas processing and equipment
|
|
|
20 years
|
|
Office furniture and equipment
|
|
|
5 years
|
|
The Partnership capitalizes interest on major projects during
extended construction time periods. Such interest is allocated
to property, plant and equipment and amortized over the
estimated useful lives of the related assets. During the year
ended December 31, 2006, the Partnership capitalized
interest of $0.4 million. The Partnership capitalized
interest of $10,300 related to the construction of a pipeline in
2005.
The costs of maintenance and repairs, which are not significant
improvements, are expensed when incurred. Expenditures to extend
the useful lives of the assets or enhance its productivity or
efficiency from its original design are capitalized over the
expected benefit or useful period.
Impairment of Long-Lived Assets Management
evaluates whether the carrying value of long-lived assets has
been impaired when circumstances indicate the carrying value of
those assets may not be recoverable. This evaluation is based on
undiscounted cash flow projections. The carrying amount is not
F-8
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
recoverable if it exceeds the undiscounted sum of cash flows
expected to result from the use and eventual disposition of the
asset. Management considers various factors when determining if
these assets should be evaluated for impairment, including but
not limited to:
|
|
|
|
|
significant adverse change in legal factors or in the business
climate;
|
|
|
|
a current-period operating or cash flow loss combined with a
history of operating or cash flow losses or a projection or
forecast which demonstrates continuing losses associated with
the use of a long-lived asset;
|
|
|
|
an accumulation of costs significantly in excess of the amount
originally expected for the acquisition or construction of a
long-lived asset;
|
|
|
|
significant adverse changes in the extent or manner in which an
asset is used or in its physical condition;
|
|
|
|
a significant change in the market value of an asset; or
|
|
|
|
a current expectation that, more likely than not, an asset will
be sold or otherwise disposed of before the end of its estimated
useful life.
|
If the carrying value is not recoverable on an undiscounted
basis, the impairment loss is measured as the excess of the
assets carrying value over its fair value. Management
assesses the fair value of long-lived assets using commonly
accepted techniques, and may use more than one method,
including, but not limited to, recent third-party comparable
sales, internally developed discounted cash flow analysis and
analysis from outside advisors. Significant changes in market
conditions resulting from events such as the condition of an
asset or a change in managements intent to utilize the
asset would generally require management to reassess the cash
flows related to the long-lived assets.
Intangible Assets Intangible assets consist
of
right-of-ways
and easements and acquired customer contracts, which the
Partnership amortizes over the term of the agreement or
estimated useful life. Amortization expense was approximately
$15.8 million for the year ended December 31, 2006,
and approximately $1.2 million for the year ended
December 31, 2005. There was no amortization expense for
any period prior to December 1, 2005. Estimated aggregate
amortization expense for each of the five succeeding years is as
follows: 2007 $16.4 million; 2008
$16.4 million; 2009 $16.4 million;
2010 $16.4 million; and 2011
$7.7 million. Intangible assets consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
($ in thousands)
|
|
|
Rights-of-way
and easements at cost
|
|
$
|
66,801
|
|
|
$
|
57,714
|
|
Less: accumulated amortization
|
|
|
(7,407
|
)
|
|
|
(237
|
)
|
Contracts
|
|
|
80,210
|
|
|
|
58,499
|
|
Less: accumulated amortization
|
|
|
(9,603
|
)
|
|
|
(975
|
)
|
|
|
|
|
|
|
|
|
|
Net Intangible assets
|
|
$
|
130,001
|
|
|
$
|
115,000
|
|
|
|
|
|
|
|
|
|
|
The amortization period for our
rights-of-way
and easements was 20 years and contracts range from 5 to
15 years, respectively, and overall, approximately
13 years average in total as of December 31, 2006. The
amortization period for our
rights-of-way
and easements are 20 years and contracts are 5 years,
respectively, and overall, approximately 12 years average
in total as of December 31, 2005.
Other Assets Other assets primarily consist
of costs associated with debt issuance ($7.8 million at
December 31, 2006), net of amortization. Amortization of
debt issuance costs is calculated using the straight-line method
over the maturity of the associated debt (or the expiration of
the contract).
Transportation and Exchange Imbalances In the
course of transporting natural gas and natural gas liquids for
others, the Partnership may receive for redelivery different
quantities of natural gas or natural gas
F-9
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
liquids than the quantities actually delivered. These
transactions result in transportation and exchange imbalance
receivables or payables which are recovered or repaid through
the receipt or delivery of natural gas or natural gas liquids in
future periods, if not subject to cash out provisions. Imbalance
receivables are included in accounts receivable and imbalance
payables are included in accounts payable on the consolidated
balance sheets and
marked-to-market
using current market prices in effect for the reporting period
of the outstanding imbalances. As of December 31, 2006 and
2005, the Partnership had imbalance receivables totaling
$0.3 million and $0.2 million, respectively, and
imbalance payables totaling $1.9 million and
$0.8 million, respectively. Changes in market value and the
settlement of any such imbalance at a price greater than or less
than the recorded imbalance results in either an upward or
downward adjustment, as appropriate, to the cost of natural gas
sold.
Revenue Recognition Eagle Rock Energys
primary types of sales and service activities reported as
operating revenue include:
|
|
|
|
|
sales of natural gas, NGLs and condensate;
|
|
|
|
natural gas gathering, processing and transportation, from which
Eagle Rock Energy generates revenues primarily through the
compression, gathering, treating, processing and transportation
of natural gas; and
|
|
|
|
NGL transportation from which we generate revenues from
transportation fees.
|
Revenues associated with sales of natural gas, NGLs and
condensate are recognized when title passes to the customer,
which is when the risk of ownership passes to the purchaser and
physical delivery occurs. Revenues associated with
transportation and processing fees are recognized when the
service is provided.
For gathering and processing services, Eagle Rock Energy either
receives fees or commodities from natural gas producers
depending on the type of contract. Commodities received are in
turn sold and recognized as revenue in accordance with the
criteria outlined above. Under the
percentage-of-proceeds
contract type, Eagle Rock Energy is paid for its services by
keeping a percentage of the NGLs produced and a percentage of
the residue gas resulting from processing the natural gas. Under
the keep-whole contract type, Eagle Rock Energy purchases
wellhead natural gas and sells processed natural gas and NGLs to
third parties.
Transportation, compression and processing-related revenue are
recognized in the period when the service is provided and
include the Partnerships fee-based service revenue for
services such as transportation, compression and processing.
Environmental Expenditures Environmental
expenditures are expensed or capitalized as appropriate,
depending upon the future economic benefit. Expenditures which
relate to an existing condition caused by past operations and do
not generate current or future revenue are expensed. Liabilities
for these expenditures are recorded on an undiscounted basis
when environmental assessments
and/or
clean-ups
are probable and the costs can be reasonably estimated. The
Partnership has recorded environmental liabilities of
$0.3 million as of December 31, 2006 and 2005.
Income Taxes No provision for federal income
taxes related to the operation of Eagle Rock Energy is included
in the accompanying consolidated financial statements as such
income is taxable directly to the partners holding interests in
the Partnership. The State of Texas enacted a margin tax in May
2006 which requires the Partnership to pay beginning in 2008,
based on 2007 results. The method of calculation for this margin
tax is similar to an income tax, requiring the Partnership to
recognize currently the impact of this new tax on the future tax
effects of temporary differences between the financial statement
carrying amounts and the tax basis of existing assets and
liabilities. Approximately $1.2 million deferred state tax
liability has been recorded at December 31, 2006. (see
Note 15)
Derivatives Statement of Financial Accounting
Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended
(SFAS No. 133), establishes accounting and reporting
standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for
hedging activities. SFAS No. 133 requires an entity to
recognize all derivatives as either assets or liabilities
F-10
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
in the statement of financial position and measure those
instruments at fair value. SFAS No. 133 provides that
normal purchase and normal sale contracts, when appropriately
designated, are not subject to the statement. Normal purchases
and normal sales are contracts which provide for the purchase or
sale of something other than a financial instrument or
derivative instrument that will be delivered in quantities
expected to be used or sold by the reporting entity over a
reasonable period in the normal course of business. The
Partnerships forward natural gas purchase and sales
contracts are designated as normal purchases and sales.
Substantially all forward contracts fall within a one-month to
five-year term; however, the Partnership does have certain
contracts which extend through the life of the dedicated
production. The Partnership uses financial instruments such as
puts, swaps and other derivatives to mitigate the risks to cash
flows resulting from changes in commodity prices and interest
rates. The Partnership recognizes these financial instruments on
its consolidated balance sheet at the instruments fair
value with changes in fair value reflected in the statement of
operations, as the Partnership has not designated any of these
derivative instruments as hedges. The cash flows from
derivatives are reported as cash flows from operating activities
unless the derivative contract is deemed to contain a financing
element. Derivatives deemed to contain a financing element are
reported as a financing activity in the statement of cash flows.
See Note 10 for a description of the Partnerships
risk management activities.
|
|
NOTE 3.
|
NEW
ACCOUNTING PRONOUNCEMENTS
|
In May 2005, the Financial Accounting Standards Board, or the
FASB, issued SFAS No. 154, Accounting Changes and
Error Corrections. This statement establishes new standards
on the accounting for and reporting of changes in accounting
principles and error corrections. This statement requires
retrospective application to the financial statements of prior
periods for all such changes, unless it is impracticable to do
so. The Partnership adopted this statement beginning
January 1, 2006. The adoption of this statement had no
impact and is not expected to have a material effect on our
financial position or results of operations on future financial
statements.
In February 2006, the FASB issued SFAS No. 155,
Accounting for Certain Hybrid Financial Instruments, an
amendment of FASB Statements No. 133 and No. 140 (SFAS
No. 155). SFAS No. 155 amends
SFAS No. 133, which required a derivative embedded in
a host contract which does not meet the definition of a
derivative be accounted for separately under certain conditions.
SFAS No. 155 amends SFAS No. 133 to narrow
the scope of such exception to strips which represent rights to
receive only a portion of the contractual interest cash flows or
of the contractual principal cash flows of a specific debt
instrument. In addition, SFAS No. 155 amends
SFAS No. 140, Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of
Liabilities, which permitted a qualifying special-purpose
entity to hold only a passive derivative financial instrument
pertaining to beneficial interests issued or sold to parties
other than the transferor. SFAS No. 155 amends
SFAS No. 140 to allow a qualifying special purpose
entity to hold a derivative instrument pertaining to beneficial
interests that itself is a derivative financial instrument.
SFAS No. 155 is effective for all financial
instruments acquired or issued (or subject to a re-measurement
event) following the start of an entitys first fiscal year
beginning after September 15, 2006. The Partnership will
adopt SFAS No. 155 on January 1, 2007, and does
not expect this standard to have a material impact, if any, on
our consolidated financial statements.
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements. This statement defines fair
value, establishes a framework for measuring fair value, and
expands disclosure about fair value measurements. The statement
is effective for financial statements issued for fiscal years
beginning after November 15, 2007. The Company is currently
evaluating the effect the adoption of this statement will have,
if any, on its consolidated results of operations and financial
position.
In February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities, (SFAS No. 159) which permits entities to
choose to measure many financial instruments and certain other
items at fair value. SFAS No. 159 is effective for us
as of January 1, 2008 and will have no
F-11
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
impact on amounts presented for periods prior to the effective
date. We cannot currently estimate the impact of
SFAS No. 159 on our consolidated results of
operations, cash flows or financial position and have not yet
determined whether or not we will choose to measure items
subject to SFAS No. 159 at fair value.
A significant portion of the Partnerships sale and
purchase arrangements are accounted for on a gross basis in the
statements of operations as natural gas sales and costs of
natural gas, respectively. These transactions are contractual
arrangements which establish the terms of the purchase of
natural gas at a specified location and the sale of natural gas
at a different location at the same or at another specified
date. These arrangements are detailed either jointly, in a
single contract or separately, in individual contracts which are
entered into concurrently or in contemplation of one another
with a single or multiple counterparties. Both transactions
require physical delivery of the natural gas and the risk and
reward of ownership are evidenced by title transfer, assumption
of environmental risk, transportation scheduling, credit risk
and counterparty nonperformance risk. In accordance with the
provision of Emerging Issues Task Force Issue
No. 04-13,
Accounting for Purchases and Sales of Inventory with the Same
Counterparty (EITF
04-13),
the Partnership reflects the amounts of revenues and purchases
for these transactions as a net amount in its consolidated
statements of operations beginning with April 2006. For the year
ended December 31, 2006, the Partnership did not enter into
any purchase and sale agreements with the same counterparty. As
a result, the adoption of EITF
04-13 had no
effect on the results of operations for the year ended
December 31, 2006.
In October 2005, the FASB issued Staff Position
FAS 13-1
concerning the accounting for rental expenses associated with
operating leases for land or buildings which are incurred during
a construction period. We considered how this might apply to our
payment for
rights-of-way
associated with the construction of pipelines, and we do not
anticipate any changes to our accounting practices or impacts on
our results of operations or financial condition in light of
this recently issued Staff Position.
In July 2006, the FASB issued FASB Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109 (FIN 48),
which clarifies the accounting and disclosure for uncertainty in
tax positions, as defined. FIN 48 seeks to reduce the
diversity in practice associated with certain aspects of the
recognition and measurement related to accounting for income
taxes. This interpretation is effective for fiscal years
beginning after December 15, 2006. We do not expect that
the adoption of FIN 48 will have a material impact on our
results of operations or financial position.
On December 1, 2005, the Partnership completed its
acquisition of ONEOK Field Services Texas (ONEOK
Texas) for $531.1 million (the Panhandle
Acquisition) to expand the Partnerships asset base
and to obtain critical mass. ONEOK Texas provides natural gas
midstream services in the Texas Panhandle and its assets
primarily consist of gathering pipelines and processing plants.
The results of operations have been included in the statement of
operations since the date of acquisition. The Partnership
financed the Panhandle Acquisition and related transactions and
costs with proceeds from the following:
Borrowings of approximately $393.5 million of the
$400.0 million initially borrowed under the new Credit
Facility discussed in Note 6;
Net proceeds received from Holdings from a $133.0 million
private placement of equity to Natural Gas Partners.
With the assistance of a third-party valuation firm, management
has prepared an assessment of the fair value of the property,
plant and equipment and intangible assets of the Panhandle
Acquisition as of December 1, 2005. The purchase price
allocation was finalized during the fourth quarter 2006. The
purchase price has been allocated as presented below.
F-12
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
($ in thousands)
|
|
|
Accounts receivable and other
current assets
|
|
$
|
673
|
|
Property, plant, and equipment
|
|
|
420,551
|
|
Intangibles
|
|
|
115,265
|
|
Accounts payable
|
|
|
(2,047
|
)
|
Other current liabilities
|
|
|
(1,931
|
)
|
Asset retirement obligations
|
|
|
(1,405
|
)
|
|
|
|
|
|
|
|
$
|
531,106
|
|
|
|
|
|
|
All liabilities assumed were at their fair values. The fair
value of intangibles is estimated to be $115.5 million.
There were no identified intangibles which were determined to
have indefinite lives.
On March 31, 2006, the Partnerships southeast Texas
and Louisiana System completed the acquisition of an 80%
interest in the Brookeland gathering and processing facility, a
76.3% interest in the Masters Creek gathering system and 100% of
the Jasper NGL line for $75.7 million to solidify the
Partnerships southeast Texas and Louisiana operations and
to integrate with the segments existing operations. The
Partnership commenced recording these results of operations on
April 1, 2006. On April 7, 2006, the remaining
interests were acquired for $20.2 million and the results
of operations have been recorded effective as of April 1,
2006, as results of operations for the period April 1, 2006
to April 7, 2006, were not material. Included in other
assets at December 31, 2005 is $7.6 million of escrow
cash on deposit for the acquisition of these assets. This escrow
cash was released on March 31, 2006. The purchase price was
allocated on a preliminary basis to property, plant and
equipment and intangibles in the amounts of $88.8 million
and $7.9 million, respectively, based on their respective
fair value as determined by management with the assistance of a
third-party valuation specialist. In addition to long-term
assets, the Partnership assumed certain accrued liabilities. The
purchase price has been allocated as presented below.
|
|
|
|
|
|
|
($ in thousands)
|
|
|
Property, plant, and equipment
|
|
$
|
88,858
|
|
Intangibles
|
|
|
7,992
|
|
Other current liabilities
|
|
|
(750
|
)
|
Asset retirement obligations
|
|
|
291
|
|
|
|
|
|
|
|
|
$
|
95,809
|
|
|
|
|
|
|
On June 2, 2006, the Partnership purchased Midstream Gas
Services, L.P. (MGS) for $4.7 million in cash
and 809,174 (1,125,416 pre-IPO conversion) in common units to
integrate with the Texas Panhandle Systems existing
operations. The Partnership will issue up to 798,113 common
units, converted at the time of the initial public offering
(1-for-0.719),
to Natural Gas Partners VII, L.P., the primary equity owner of
MGS, as a contingent earn-out payment if MGS achieves certain
financial objectives for the year ending December 31, 2007.
The Partnership commenced recording the results of operations on
June 2, 2006.
F-13
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following pro forma information for the year ended
December 31, 2006 and 2005, assumes the Brookeland
gathering and processing facility, the Masters Creek gathering
system, the Jasper NGL line and the MGS interests (only for
2006) had been acquired on January 1, 2006 and 2005,
respectively (unaudited):
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
($ in thousands)
|
|
|
Pro forma earnings data:
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
492,507
|
|
|
$
|
508,904
|
|
Costs and expenses
|
|
|
(489,723
|
)
|
|
|
(478,066
|
)
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
|
2,784
|
|
|
|
30,838
|
|
Other income (expense), net
|
|
|
(27,786
|
)
|
|
|
(31,078
|
)
|
Income tax provision
|
|
|
(1,230
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
$
|
(26,232
|
)
|
|
$
|
(240
|
)
|
|
|
|
|
|
|
|
|
|
In July 2004, the Partnership acquired a 25% undivided interest
in a processing plant as well as a 20% undivided interest in a
connected gathering system for $19.9 million. The results
of operations have been recorded on a pro-rata consolidation
basis and have been included in the statement of operations
since the date of acquisition.
|
|
NOTE 5.
|
FIXED
ASSETS AND ASSET RETIREMENT OBLIGATIONS
|
Fixed assets consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
($ in thousands)
|
|
|
Land
|
|
$
|
853
|
|
|
$
|
327
|
|
Plant
|
|
|
81,485
|
|
|
|
63,718
|
|
Gathering and pipeline
|
|
|
433,779
|
|
|
|
345,296
|
|
Equipment and machinery
|
|
|
37,185
|
|
|
|
24,386
|
|
Vehicles and transportation
equipment
|
|
|
2,740
|
|
|
|
1,970
|
|
Office equipment, furniture, and
fixtures
|
|
|
511
|
|
|
|
133
|
|
Computer equipment and software
|
|
|
4,623
|
|
|
|
508
|
|
Corporate
|
|
|
126
|
|
|
|
126
|
|
Linefill
|
|
|
3,923
|
|
|
|
3,674
|
|
Construction in progress
|
|
|
19,677
|
|
|
|
4,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
584,902
|
|
|
|
445,025
|
|
Less: accumulated depreciation
|
|
|
(30,839
|
)
|
|
|
(3,438
|
)
|
|
|
|
|
|
|
|
|
|
Net fixed assets
|
|
$
|
554,063
|
|
|
$
|
441,588
|
|
|
|
|
|
|
|
|
|
|
Depreciation expense for the years ended December 31, 2006
and 2005 were $27.4 million and $2.9 million,
respectively.
Asset Retirement Obligations On
December 31, 2005, we adopted FASB Interpretation
No. 47, Accounting for Conditional Asset Retirement
Obligations, an interpretation of FASB Statement No. 143
(FIN 47). FIN 47 clarified that the term
conditional asset retirement obligation, as used in
SFAS No. 143, Accounting for Asset Retirement
Obligations, refers to a legal obligation to perform an
asset retirement activity in which the timing
and/or
method of settlement are conditional upon a future event that
may or may not be within our control. Although uncertainty about
the timing
and/or
method of settlement may exist and may be
F-14
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
conditional upon a future event, the obligation to perform the
asset retirement activity is unconditional. Accordingly, we are
required to recognize a liability for the fair value of a
conditional asset retirement obligation if the fair value of the
liability can be reasonably estimated. The adoption of
FIN 47 had no impact on the Partnerships consolidated
financial statements.
A reconciliation of our liability for asset retirement
obligations is as follows:
|
|
|
|
|
|
|
($ in thousands)
|
|
|
Asset retirement
obligations January 1, 2005
|
|
$
|
|
|
Addition, primarily Panhandle
acquisitions
|
|
|
674
|
|
Accretion expense
|
|
|
5
|
|
|
|
|
|
|
Asset retirement
obligations December 31, 2005
|
|
|
679
|
|
Additions for Brookeland and MGS
acquisitions
|
|
|
297
|
|
Purchase price allocation
adjustment on Panhandle assets
|
|
|
698
|
|
Additional liability on newly
built assets
|
|
|
17
|
|
Accretion expense
|
|
|
128
|
|
|
|
|
|
|
Asset retirement
obligations December 31, 2006
|
|
$
|
1,819
|
|
|
|
|
|
|
Asset retirement obligations prior to January 1, 2005 were
not significant.
Long-term debt consists of:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
($ in thousands)
|
|
|
Revolver
|
|
$
|
106,481
|
|
|
$
|
7,600
|
|
Term loan
|
|
|
299,250
|
|
|
|
400,000
|
|
Other
|
|
|
|
|
|
|
866
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
405,731
|
|
|
|
408,466
|
|
Less: current portion
|
|
|
|
|
|
|
3,866
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
405,731
|
|
|
$
|
404,600
|
|
|
|
|
|
|
|
|
|
|
On August 31, 2006, the Partnership amended and restated
its existing credit agreement (the Amended and Restated
Credit Agreement). The Amended and Restated Credit
Agreement is a $500.0 million credit agreement with a
syndicate of commercial and investment banks and institutional
lenders, with Goldman Sachs Credit Partners L.P., as the
administrative agent. The Amended and Restated Credit Agreement
provides for $300.0 million aggregate principal amount of
Series B Term Loans (the Term Loan) and up to
$200.0 million aggregate principal amount of Revolving
Commitments (the Revolver). A $750,000 principal
payment was made toward the Term Loan in October 2006, reducing
the Term Loan aggregate principal amount to $299.3 million.
The Amended and Restated Credit Agreement includes a sub limit
for the issuance of standby letters of credit for the aggregate
unused amount of the Revolver. At December 31, 2006, the
Partnership had $2.5 million of outstanding letters of
credit. In addition, the loan agreement allows the Partnership
to expand its credit facility by an additional
$100.0 million if the Partnership meets certain financial
conditions.
In connection with the Amended and Restated Credit Agreement,
the Partnership incurred debt issuance costs of
$2.4 million to the Consolidated Statement of Operations
during the year ended December 31, 2006, of which
approximately $0.4 million was expensed directly, with the
remaining portion to be amortized over the remaining term of the
agreement.
F-15
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Prior to the initial public offering, the principal amount due
under the Term Loan was to be repaid in consecutive quarterly
installments on the four quarterly scheduled interest payment
dates applicable to the Term Loan, commencing September 30,
2006, in an amount equal to one-quarter percent (0.25%) of the
original principal amount outstanding with the remaining
outstanding principal amount due on the Term Loan maturity date.
With the consummation of the Partnerships initial public
offering on October 27, 2006, quarterly installments under
the Term Loan ceased with the balance due on the Term Loan
maturity date, August 31, 2011. The Revolver matures on the
revolving commitment termination date, August 31, 2011.
In certain instances defined in the Amended and Restated Credit
Agreement, the Term Loan is subject to mandatory repayments and
the Revolver is subject to a commitment reduction for cumulative
asset sales exceeding $15.0 million; insurance/condemnation
proceeds; the issuance of equity securities; and the issuance of
debt.
The Amended and Restated Credit Agreement contains various
covenants which limit the Partnerships ability to grant
certain liens; make certain loans and investments; make certain
capital expenditures outside the Partnerships current
lines of business or certain related lines of business; make
distributions other than from available cash; merge or
consolidate with or into a third party; or engage in certain
asset dispositions, including a sale of all or substantially all
of the Partnerships assets. Additionally, the Amended and
Restated Credit Agreement limits the Partnerships ability
to incur additional indebtedness with certain exceptions and
purchase money indebtedness and indebtedness related to capital
or synthetic leases not to exceed $7.5 million.
The Amended and Restated Credit Agreement also contains
covenants, which, among other things, require the Partnership,
on a consolidated basis, to maintain specified ratios or
conditions as follows:
|
|
|
|
|
Adjusted EBITDA (as defined) to interest expense of not less
than 2.0 to 1.0 through December 31, 2006, and 2.50 to 1.0
thereafter; and
|
|
|
|
Total consolidated funded debt to Adjusted EBITDA (as defined)
of not more than 6.0 to 1.0 through December 31, 2006, and
5.0 to 1.0 thereafter and 5.25 to 1.0 for the three quarters
following a material acquisition;
|
Based upon the senior debt to Adjusted EBITDA ratio calculated
as of December 31, 2006 (utilizing the September and
December 2006 quarters Consolidated Adjusted EBITDA as defined
under the Credit Agreement annualized for an annual Adjusted
EBITDA amount for the ratio), the Partnership has approximately
$80.0 million of unused capacity under the Amended and
Restated Credit Agreement Revolver with $24.0 million
available capacity at year end.
At the Partnerships election, the Term Loan and the
Revolver bear interest on the unpaid principal amount either at
a base rate plus the applicable margin (defined as
1.25% per annum, reducing to 1.00% when consolidated funded
debt to Adjusted EBITDA (as defined) is less than 3.5 to 1); or
at the Adjusted Eurodollar Rate plus the applicable margin
(defined as 2.25% per annum, reducing to 2.00% when
consolidated funded debt to Adjusted EBITDA (as defined) is less
than 3.5 to 1). At August 31, 2006, the Partnership elected
the Eurodollar Rate plus the applicable margin (defined as
2.25%) for a cumulative rate of 7.65%. The applicable margin
increased by 0.50% per annum on January 31, 2007,
under the Amended and Restated Credit Agreement as the
Partnership elected not to obtain a rating by S&P and
Moodys.
Base rate interest loans are paid the last day of each March,
June, September and December. Eurodollar Rate Loans are paid the
last day of each interest period, representing one-, two-,
three- or six-, nine- or twelve-months, as selected by the
Partnership. Interest on the Term Loan is paid approximately
each December 31, March 31, June 30 and
September 30 of each year, commencing on September 30,
2006. The Partnership pays a commitment fee equal to
(1) the average of the daily difference between
(a) the revolver commitments and (b) the sum of the
aggregate principal amount of all outstanding revolver loans
plus the aggregate principal amount of all outstanding swing
loans times (2) 0.50% per annum; provided, the
commitment fee percentage increased by 0.25% per annum on
January 31, 2007, as the Partnership elected not to obtain
a rating by S&P and Moodys. The Partnership also pays
a letter of credit fee equal to (1) the
F-16
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
applicable margin for revolving loans which are Eurodollar Rate
loans times (2) the average aggregate daily maximum amount
available to be drawn under all such Letters of Credit
(regardless of whether any conditions for drawing could then be
met and determined as of the close of business on any date of
determination). Additionally, the Partnership pays a fronting
fee equal to 0.125%, per annum, times the average aggregate
daily maximum amount available to be drawn under all letters of
credit.
The obligations under the Amended and Restated Credit Agreement
are secured by first priority liens on substantially all of the
Partnerships assets, including a pledge of all of the
capital stock of each of its subsidiaries.
Prior to entering into the Amended and Restated Credit
Agreement, the Partnership operated under a $475.0 million
credit agreement (the Credit Agreement) with a
syndicate of commercial banks, including Goldman Sachs Credit
Partners L.P., as the administrative agent. The Credit Agreement
was entered into on December 1, 2005. The Credit Agreement
provided for $400.0 million aggregate principal amount of
Series A Term Loans (the Original Term Loan)
and up to $75.0 million ($100.0 million effective
June 2, 2006) aggregate principal amount of Revolving
Commitments (the Original Revolver). The Credit
Agreement included a sub limit for the issuance of standby
letters of credit for the lesser of $55.0 million or the
aggregate unused amount of the Original Revolver. At
December 31, 2005, the Partnership had $400.0 million
outstanding under the Original Term Loan, $7.6 million
outstanding under the Original Revolver and $0.1 million of
outstanding letters of credit.
Scheduled maturities of long-term debt as of December 31,
2006, were as follows:
|
|
|
|
|
|
|
Principal
|
|
|
|
Amount
|
|
|
|
($ in thousands)
|
|
|
2007
|
|
$
|
0
|
|
2008
|
|
|
0
|
|
2009
|
|
|
0
|
|
2010
|
|
|
0
|
|
2011
|
|
|
405,731
|
|
|
|
|
|
|
|
|
$
|
405,731
|
|
|
|
|
|
|
The Partnership was in compliance with the financial covenants
under the Amended and Restated Credit Agreement as of
December 31, 2006. If an event of default existed under the
Amended and Restated Credit Agreement, the lenders would be able
to accelerate the maturity of the Amended and Restated Credit
Agreement and exercise other rights and remedies.
At December 31, 2005, the Partnership had common units
outstanding representing 98.01% of limited partnership interest
and 1.99% of general partner interests, all of which were
controlled by Holdings. On March 27, 2006, the Partnership
sold 5,455,050 common units in a private placement for
$98.3 million and converted the 98.01% limited partnership
interest into 33,582,918 subordinated units. In June 2006, the
Partnership issued 1,125,416 common units in connection with the
MGS acquisition. At the initial public offering, the pre-IPO
common units outstanding were converted into publicly traded
common units using a factor of approximately 0.7191.
Additionally, Holdings contributed $0.2 million in cash
during 2006. For the initial public offering, the Partnership
issued 12.5 million common units. The overallotment option
was exercised by the underwriters in November 2006 with
1,463,785 common units being issued from common units acquired
by the Partnership from Holdings and selected private investors.
The exercise of the overallotment did not result in additional
shares being issued by the Partnership. At December 31,
2006, there were 20,691,496 common units and 20,691,496
subordinated units (all subordinated units owned by Holdings)
outstanding. In addition, there were 122,450 restricted unvested
common units outstanding.
F-17
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Additionally, during the fourth quarter of 2006, Holdings paid
$6.0 million to terminate the advisory fee arrangement with
Natural Gas Partners. The expense was recorded on the
Partnerships financial results of operations with the
offset to members equity (see Note 8).
Subordinated units represent limited liability interests in the
Partnership, and holders of subordinated units exercise the
rights and privileges available to unitholders under the limited
liability company agreement. Subordinated units, during the
subordination period, will generally receive quarterly cash
distributions only when the common units have received a minimum
quarterly distribution of $0.3625 per unit. Subordinated
units will convert into common units on a
one-for-one
basis when the subordination period ends. Pursuant to the
Partnerships agreement of limited partnership, the
subordination period will extend to the earliest date following
March 31, 2009 for which there does not exist any
cumulative common unit arrearage.
On August 15, 2006, the Partnership declared and paid a
distribution of $1.9 million to its common unit holders. As
of September 30, 2006, the Partnership was in arrears on
its subordinated units and general partner units in the amount
of $10.7 million and $0.3 million, respectively for
the second quarter of 2006. The arrearages were declared and
paid at the time of the initial public offering. The IPO net
cash received was $222.1 million, including
$3.0 million for initial public offering transaction costs
reimbursement to the Partnership. Distributions of
$219.1 million were made in the fourth quarter for capital
expenditure and working capital reimbursements and distribution
arrearages. On November 14, 2006, the Partnership
distributed $14.4 million from its third quarter 2006
results. This distribution was made to the unitholders on record
as of September 30, 2006. In November, the Partnership
received net cash of $26.0 million for the exercise of the
overallotment by the underwriters. This amount was used to buy
common units from Holdings and certain Pre-IPO investors.
On January 26, 2006, the Partnership declared its 2006
fourth quarter distribution to its common unitholders of record
as of February 7, 2007. The distribution amount per common
unit was $0.3625 which was adjusted to $0.2679 per unit for the
partial quarter the units were outstanding due to the initial
public offering date. The distribution was made on
February 15, 2007. No distributions were declared on the
general partner or subordinated units.
|
|
NOTE 8.
|
RELATED
PARTY TRANSACTIONS
|
Holdings had a management advisory arrangement with Natural Gas
Partners requiring a quarterly fee payment. The agreement was
modified on December 1, 2005, to increase the management
fee to $0.5 million annually, with an escalation to
$1.0 million annually, upon the completion of the initial
public offering by the Partnership. The fee paid under the
advisory arrangement has been expensed by the Partnership. For
years ended 2006 and 2005, the Partnership expensed the
$0.4 million and $0.1 million for the management
advisory arrangement. At the time of the initial public
offering, Holdings terminated the agreement with a
$6.0 million payment to Natural Gas Partners. The
termination fee was recorded as an expense of the Partnership
during the fourth quarter of 2006, with the offset as a capital
contribution.
During the fourth quarter of 2005, the Partnership declared and
accrued a $5.0 million distribution. This distribution was
included in the balance sheet at December 31, 2005, in
distribution payable-affiliate. In addition, for 2006, the
Partnership paid a $215.2 million distribution to Holdings,
for initial public offering related activities and earning
distributions. A portion of this amount was distributed to
Holdings from the Partnerships distributions to its
general partner. Holdings owns and controls the general partner
of the partnership while Holdings is controlled by Natural Gas
Partners with minority ownership by certain management personnel
and board members of the Partnerships general partner.
As discussed in Note 4, on June 2, 2006, the
Partnership acquired Midstream Gas Services, L.P., which was a
portfolio company of Natural Gas Partners in its Natural Gas
Partners Vll, L.P. As part of the consideration for the
acquisition, Natural Gas Partners received pre-initial public
offering common units in the Partnership which were converted at
the time of the initial public offering. During 2006, the
Partnership made
F-18
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
distributions of $3.7 million to Natural Gas Partners for
these units for the initial public offering, overallotment and
other distribution activities.
On July 1, 2006, the Partnership entered into a month to
month contract for the sale of natural gas with an affiliate of
Natural Gas Partners, under which the Partnerships Texas
Panhandle Systems has the option to sell a portion of its gas
supply. The Partnership has received a Letter of Credit related
to this agreement. The Partnership recorded $19.4 million
of revenues in 2006 from the agreement, of which there was a
receivable of $2.7 million outstanding at December 31,
2006.
In the fourth quarter of 2006, the Partnership entered into an
Omnibus Agreement with Eagle Rock Energy G&P, LLC, Holdings
and the Partnerships general partner which requires the
Partnership to reimburse Eagle Rock Energy G&P, LLC for the
payment of certain expenses incurred on the Partnerships
behalf, including payroll, benefits, insurance and other
operating expenses, and provides certain indemnification
obligations.
The Partnership does not directly employ any persons to manage
or operate our business. Those functions are provided by our
general partner. We reimburse the general partner for all direct
and indirect costs of these services.
|
|
NOTE 9.
|
FAIR
VALUE OF FINANCIAL INSTRUMENTS
|
The fair value of accounts receivable and accounts payable are
not materially different from their carrying amounts because of
the short-term nature of these instruments.
The carrying amount of cash equivalents is believed to
approximate their fair values because of the short maturities of
these instruments. As of December 31, 2006, the debt
associated with the Credit Agreement bore interest at floating
rates. As such, carrying amounts of this debt instruments
approximates fair value.
|
|
NOTE 10.
|
RISK
MANAGEMENT ACTIVITIES
|
The Credit Agreement required the Partnership to enter into
interest rate risk management activities. In December 2005, the
Partnership entered into various interest rate swaps. These
swaps convert the variable-rate term loan into a fixed-rate
obligation. The purpose of entering into this swap is to
eliminate interest rate variability by converting LIBOR-based
variable-rate payments to fixed-rate payments for a period of
five years from January 1, 2006 to January 1, 2011.
Amounts received or paid under these swaps were recorded as
reductions or increases in interest expense. The table below
summarizes the terms, amounts received or paid and the fair
values of the various interest swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
Roll Forward
|
|
Expiration
|
|
|
Notional
|
|
|
Fixed
|
|
|
December 31,
|
|
Effective Date
|
|
Date
|
|
|
Amount
|
|
|
Rate
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands)
|
|
|
01/03/2006
|
|
|
01/03/2011
|
|
|
$
|
100,000,000
|
|
|
|
4.9500
|
%
|
|
$
|
(319
|
)
|
01/03/2006
|
|
|
01/03/2011
|
|
|
|
100,000,000
|
|
|
|
4.9625
|
|
|
|
(267
|
)
|
01/03/2006
|
|
|
01/03/2011
|
|
|
|
50,000,000
|
|
|
|
4.8800
|
|
|
|
(295
|
)
|
01/03/2006
|
|
|
01/03/2011
|
|
|
|
50,000,000
|
|
|
|
4.8800
|
|
|
|
(295
|
)
|
For the year ended December 31, 2006, the Partnership
recorded a fair value gain within interest expense of
$2.8 million (unrealized) and a $0.5 million realized
gain. As of December 31, 2006, the fair value liability of
these contracts totaled $1.2 million.
The prices of natural gas and NGLs are subject to fluctuations
in response to changes in supply, market uncertainty and a
variety of additional factors which are beyond the
Partnerships control. In order to manage the risks
associated with natural gas and NGLs, the Partnership engages in
risk management activities that take the form of commodity
derivative instruments. Currently these activities are governed
by the general partner, which today typically prohibits
speculative transactions and limits the type, maturity and
notional
F-19
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
amounts of derivative transactions. We will be implementing a
Risk Management Policy which will allow management to execute
crude oil, natural gas liquids and natural gas hedging
instruments in order to reduce exposure to substantial adverse
changes in the prices of these commodities. We intend to monitor
and ensure compliance with this Risk Management Policy through
senior level executives in our operations, finance and legal
departments.
In October and December 2005, the Partnership entered into the
following:
|
|
|
|
|
Over-the-counter
NGL puts, costless collar and swap transactions for the sale of
Mont Belvieu gas liquids with a combined notional amount of
530,000 Bbls per month for a term from January 2006 through
December 2010;
|
|
|
|
Condensate puts and costless collar transactions for the sale of
West Texas Intermediate crude oil with a combined notional
amount of 250,000 Bbls per month for a term from January 2006
through December 2010; and
|
|
|
|
Natural gas calls for the sale of Henry Hub natural gas with a
notional amount of 200,000 MMBtu per month for a term from
January 2006 through December 2007.
|
During 2006, the Partnership entered into the following
additional risk management activities:
|
|
|
|
|
Costless collar transactions for West Texas Intermediate crude
oil with a combined notional amount of 50,000 Bbls per
month for a term of October through December 2006; and,
60,000 Bbls per month for a term of January 2007 through
December 2007.
|
|
|
|
Fixed swap agreements to hedge WTS-WTI basis differential in
amount of 20,000 Bbls per month for a term of
October-December 2006; and, 20,000 Bbls per month for a
term of January through December 2007.
|
|
|
|
Natural gas fixed swap agreements to hedge short natural gas
positions with a combined notional amount of 100,000 MMBtu
per month for the term of August 2006 through September 2006.
|
The counterparties used for these transactions have investment
grade ratings. The NGL and condensate derivatives are intended
to hedge the risk of weakening NGL and condensate prices with
offsetting increases in the value of the puts based on the
correlation between NGL prices and crude oil prices. The natural
gas derivatives are included to hedge the risk of increasing
natural gas prices with the offsetting value of the natural gas
calls.
Eagle Rock Energy has not designated these derivative
instruments as hedges and as a result is marking these
derivative contracts to market with changes in fair values
recorded as an adjustment to the
mark-to-market
gains /losses on risk management transactions within revenue.
For the year ended December 31, 2005, the Partnership
recorded a fair value gain of $7.3 million related to these
contracts. As of December 31, 2005, the fair value of these
contracts totaled $34.8 million. For the year ended
December 31, 2006, the Partnership recorded a loss on risk
management instruments of $24.0 million, representing a
fair value (unrealized) loss of $7.1 million, amortization
of put premiums of $19.2 million and net (realized)
settlements gain to the Partnership of $2.3 million. As of
December 31, 2006, the fair value of these contracts,
including the put premiums, totaled $8.4 million.
|
|
NOTE 11.
|
COMMITMENTS
AND CONTINGENT LIABILITIES
|
Litigation The Partnership is subject to
several lawsuits, primarily related to the payments of liquids
and gas proceeds in accordance with contractual terms. The
Partnership has accruals of $1.5 million as of
December 31, 2006 and $1.63 million, as of
December 31, 2005, related to these matters. In addition,
the Partnership is also subject to other lawsuits related to the
payment of liquid and gas proceeds in accordance with
contractual terms for which the Partnership has been indemnified
up to a certain dollar amount. For the indemnified lawsuits, the
Partnership has not established any accruals as the likelihood
of these suits being successful against them is considered
remote. If there ultimately is a finding against the Partnership
in the
F-20
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
indemnified cases, the Partnership could make a claim against
the indemnification up to limits of the indemnification. These
matters are not expected to have a material adverse effect on
our financial position, results of operations or cash flows.
Insurance Eagle Rock Energy carries insurance
coverage which includes the assets and operations, which
management believes is consistent with companies engaged in
similar commercial operations with similar type properties.
These insurance coverages includes (1) commercial general
public liability insurance for liabilities arising to third
parties for bodily injury and property damage resulting from
Eagle Rock Energy field operations; (2) workers
compensation liability coverage to required statutory limits;
(3) automobile liability insurance for all owned, non-owned
and hired vehicles covering liabilities to third parties for
bodily injury and property damage, (4) property insurance
covering the replacement value of all real and personal property
damage, including damages arising from boiler and machinery
breakdowns, earthquake, flood damage and business
interruption/extra expense, and (5) corporate liability
policies including Directors and Officers coverage and
Employment Practice liability coverage. All coverages are
subject to certain deductibles, terms, and conditions common for
companies with similar types of operation.
Eagle Rock Energy also maintains excess liability insurance
coverage above the established primary limits for commercial
general liability and automobile liability insurance. Limits,
terms, conditions and deductibles are comparable to those
carried by other energy companies of similar size. The cost of
general insurance coverages continued to fluctuate over the past
year reflecting the changing conditions of the insurance markets.
Regulatory Compliance In the ordinary course
of business, the Partnership is subject to various laws and
regulations. In the opinion of management, compliance with
existing laws and regulations will not materially affect the
financial position of the Partnership.
Environmental The operation of pipelines,
plants and other facilities for gathering, transporting,
processing, treating, or storing natural gas, NGLs and other
products is subject to stringent and complex laws and
regulations pertaining to health, safety, and the environment.
As an owner or operator of these facilities, the Partnership
must comply with United States laws and regulations at the
federal, state and local levels that relate to air and water
quality, hazardous and solid waste management and disposal, and
other environmental matters. The cost of planning, designing,
constructing and operating pipelines, plants, and other
facilities must incorporate compliance with environmental laws
and regulations and safety standards. Failure to comply with
these laws and regulations may trigger a variety of
administrative, civil and potentially criminal enforcement
measures, including citizen suits, which can include the
assessment of monetary penalties, the imposition of remedial
requirements, and the issuance of injunctions or restrictions on
operation. Management believes that, based on currently known
information, compliance with these laws and regulations will not
have a material adverse effect on the Partnerships
combined results of operations, financial position or cash
flows. At December 31, 2006 and 2005, the Partnership had
accrued $0.3 million for environmental matters.
Other Commitments and Contingencies The
Partnership utilizes assets under operating leases for its
corporate office, certain rights-of way and facilities
locations, vehicles and in several areas of its operation.
Rental expense, including leases with no continuing commitment,
amounted to $0.2 million, $0.2 million, and $37,000
for the years ended December 31, 2006, 2005 and 2004,
respectively. Rental expense for leases with escalation clauses
is recognized on a straight-line basis over the initial lease
term. At December 31, 2006, commitments under long-term
non-cancelable operating leases for the next five years and
thereafter are payable as follows: 2007
$0.7 million; 2008 $0.7 million;
2009 $0.7 million; 2010
$0.3 million; 2011 $0.3 million; and
thereafter $2.0 million.
Based on the Partnerships approach to managing its assets,
the Partnership believes its operations consist of two
geographic segments and one functional (corporate) segment:
(i) gathering, processing, transportation and marketing of
natural gas in the Texas Panhandle Systems, (ii) gathering,
natural gas processing and related
F-21
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
NGL transportation in the Texas and Louisiana System, and
(iii) risk management and other corporate activities. The
Partnerships chief operating decision-maker currently
reviews its operations using these segments. The Partnership
evaluates segment performance based on segment margin before
depreciation and amortization. Transactions between reportable
segments are conducted on a basis believed to be at market
values. Prior to the December 1, 2005, acquisition of the
Panhandle Acquisition, the Partnership had only one segment.
Summarized financial information concerning the
Partnerships reportable segments is shown in the following
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas and
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
Panhandle
|
|
|
Louisiana
|
|
|
Corporate
|
|
|
Total
|
|
|
|
($ in millions)
|
|
|
Sales to external customers
|
|
$
|
422.1
|
|
|
$
|
79.4
|
|
|
$
|
(23.1
|
)(a)
|
|
$
|
478.4
|
|
Interest expense and other
financing costs
|
|
|
|
|
|
|
|
|
|
|
28.6
|
|
|
|
28.6
|
|
Depreciation and amortization
|
|
|
36.3
|
|
|
|
5.9
|
|
|
|
1.0
|
|
|
|
43.2
|
|
Segment profit (loss)(b)
|
|
|
104.5
|
|
|
|
19.4
|
|
|
|
(23.1
|
)
|
|
|
100.8
|
|
Capital expenditures
|
|
|
12.2
|
|
|
|
20.7
|
|
|
|
5.5
|
|
|
|
38.4
|
|
Segment assets
|
|
|
573.6
|
|
|
|
148.9
|
|
|
|
57.4
|
|
|
|
779.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas and
|
|
|
|
|
|
|
|
Year Ended December 31, 2005
|
|
Panhandle
|
|
|
Louisiana
|
|
|
Corporate
|
|
|
Total
|
|
|
|
($ in millions)
|
|
|
Sales to external customers
|
|
$
|
43.0
|
|
|
$
|
23.4
|
|
|
$
|
7.3
|
(a)
|
|
$
|
73.7
|
|
Interest expense and other
financing costs
|
|
|
|
|
|
|
|
|
|
|
4.0
|
|
|
|
4.0
|
|
Depreciation and amortization
|
|
|
2.9
|
|
|
|
1.0
|
|
|
|
0.1
|
|
|
|
4.1
|
|
Segment profit(b)
|
|
|
7.8
|
|
|
|
3.3
|
|
|
|
7.3
|
|
|
|
18.4
|
|
Capital expenditures
|
|
|
|
|
|
|
4.1
|
|
|
|
0.1
|
|
|
|
4.2
|
|
Segment assets
|
|
|
525.4
|
|
|
|
82.0
|
|
|
|
93.3
|
|
|
|
700.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas and
|
|
|
|
|
|
|
|
Year Ended December 31, 2004
|
|
Panhandle
|
|
|
Louisiana
|
|
|
Corporate
|
|
|
Total
|
|
|
|
($ in millions)
|
|
|
Sales to external customers
|
|
$
|
|
|
|
$
|
10.6
|
|
|
$
|
|
|
|
$
|
10.6
|
|
Interest expense and other
financing costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
0.6
|
|
|
|
|
|
|
|
0.6
|
|
Segment profit(b)
|
|
|
|
|
|
|
1.8
|
|
|
|
|
|
|
|
1.8
|
|
Capital expenditures
|
|
|
|
|
|
|
20.5
|
|
|
|
|
|
|
|
20.5
|
|
Segment assets
|
|
|
|
|
|
|
19.7
|
|
|
|
8.3
|
|
|
|
28.0
|
|
|
|
|
(a) |
|
Represents results of our derivatives activity. |
|
(b) |
|
Segment profit (loss) is defined as sales to external customers
minus cost of natural gas and natural gas liquids and other cost
of sales. Sales to external customers for the corporate column
include the impact of the risk management activities. |
F-22
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table reconciles segment profit (loss) to income
from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
($ in millions)
|
|
|
Segment profit
|
|
$
|
100.8
|
|
|
$
|
18.4
|
|
|
$
|
1.8
|
|
Operations and maintenance
|
|
|
(32.9
|
)
|
|
|
(2.9
|
)
|
|
|
|
|
General and administrative
|
|
|
(13.2
|
)
|
|
|
(4.8
|
)
|
|
|
(2.4
|
)
|
Advisory termination fee
|
|
|
(6.0
|
)
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
(43.2
|
)
|
|
|
(4.1
|
)
|
|
|
(0.6
|
)
|
Interest expense, net
|
|
|
(27.6
|
)
|
|
|
(3.9
|
)
|
|
|
|
|
Provision for income taxes
|
|
|
(1.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from continuing
operations
|
|
$
|
(23.3
|
)
|
|
$
|
2.7
|
|
|
$
|
(1.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 13.
|
DISCONTINUED
OPERATIONS
|
On July 1, 2004, the Partnership closed on the sale of its
Dry Trail assets for $37.4 million. The Dry Trail assets
consisted of a
CO2
tertiary recovery plant near Hough, Oklahoma. The Dry Trail
assets had revenues of $5.1 million in 2004, and generated
income of $2.7 million, which is net of interest expense
allocated to these operations of $0.3 million in 2004. All
interest incurred during the period the Partnership owned the
Dry Trail assets was allocated to discontinued operations as the
debt was specifically related to those assets and was paid off
with proceeds from the sale. The Partnership realized a gain of
$19.5 million in 2004 on the sale.
|
|
NOTE 14.
|
EMPLOYEE
BENEFIT PLAN
|
In 2004, the Partnership began providing a defined contribution
benefit plan to its employees who have been with the Partnership
longer than six months. The plan provides for a dollar for
dollar matching contribution by the Partnership of up to 3% of
an employees contribution and 50% of additional
contributions up to an additional 2%. Additionally, the
Partnership contributes 6% of a participating employees
base salary annually, contributed at 3% twice a year. Expenses
under the plan for the years ended December 31, 2006, 2005
and 2004 were approximately $0.3 million, $37,000 and
$65,000, respectively.
In May 2006, the State of Texas enacted a margin tax which will
become effective in 2008. This margin tax will require the
Partnership to determine a tax of 1.0% on our
margin, as defined in the law, beginning in 2008
based on our 2007 results. The margin to which the tax rate will
be applied generally will be calculated as our revenues for
federal income tax purposes less the cost of the products sold
for federal income tax purposes, in the State of Texas. Under
the provisions of Statement of Financial Accounting Standards
No. 109, Accounting for Income Taxes, the
Partnership is required to record the effects on deferred taxes
for a change in tax rates or tax law in the period which
includes the enactment date.
Under FAS 109, taxes based on income like the Texas margin
tax are accounted for using the liability method under which
deferred income taxes are recognized for the future tax effects
of temporary differences between the financial statement
carrying amounts and the tax basis of existing assets and
liabilities using the enacted statutory tax rates in effect at
the end of the period. A valuation allowance for deferred tax
assets is recorded when it is more likely than not that the
benefit from the deferred tax asset will not be realized.
Temporary differences related to the Partnerships property
will affect the Texas margin tax, and we have recorded a
deferred tax liability in the amount of $1.2 million as of
December 31, 2006.
F-23
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 16.
|
EQUITY-BASED
COMPENSATION
|
On October 24, 2006, the general partner for Eagle Rock
Energy Partners, L.P., approved a long-term incentive plan (LTIP
for its employees, directors and consultants who provide
services to the Partnership covering an aggregate of 1,000,000
common unit options, restricted units and phantom units. With
the consummation of the initial public offering on October 24,
2006, 124,450 restricted common units were issued to the
employees and directors of the General Partner who provide
services to the Partnership. The awards generally vest on the
basis of one third of the award each year. During the
restriction period, distribution associated with the granted
awards will be held by the Partnership and will be distributed
to the awardees upon the restriction lapsing. No options or
phantom units have been issued to date.
A summary of the restricted common units activity for the year
ended December 31, 2006, is provided below:
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Weighted Average
|
|
|
|
Restricted
|
|
|
Grant - Date
|
|
|
|
Units
|
|
|
Fair Value
|
|
|
Outstanding at beginning of period
|
|
|
|
|
|
$
|
0
|
|
Granted
|
|
|
124,250
|
|
|
|
18.75
|
|
Vested
|
|
|
|
|
|
|
|
|
Forfeitures
|
|
|
(1,800
|
)
|
|
|
18.75
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
122,450
|
|
|
$
|
18.75
|
|
|
|
|
|
|
|
|
|
|
For the fourth quarter of 2006, compensation expense of
$0.1 million was recorded related to the granted restricted
units.
As of December 31, 2006, unrecognized compensation costs
related to the outstanding restricted units under our LTIP
totaled $2.2 million. The granted restricted units were
valued at the market price of the initial public offering less a
discount for the delayed in their cash distributions during the
unvested period. The remaining expense is to be recognized over
a weighted average of 2.75 years.
|
|
NOTE 17.
|
EARNINGS
PER UNIT
|
Basic earnings per unit is computed by dividing the net income,
or loss, by the weighted average number of units outstanding
during a period. To determine net income, or loss, allocated to
each class of ownership (common, subordinated and general
partner), we first allocated net income, or loss, by the amount
of distributions made for the quarter by each class, if any. The
remaining net income, or loss, after the deduction for the
related quarter distribution was allocated to each class in
proportion to the class weighted average number of units
outstanding for a period, as compared to the weighted average
number of units for all classes for the period. To determine the
weighted average number of units outstanding for a period, we
converted units existing during 2006, prior to the initial
public offering, at the initial public offering conversion rate
(1-for-0.7139),
resulting in equivalent units for all periods. For 2005 and
2004 unit determinations, we used the initial public
offering converted common and general partner units at the
beginning of 2006 as the adjusted weighted average units for
these earlier periods. General partner units were outstanding
for this calculation as of December 1, 2005, which is the
timing of the Texas Panhandle acquisition and an organization
formation. There were no previous stated units during these
periods. Net income for 2005 and 2004 was allocated to the
common and general partner based upon the adjusted weighted
average units determined above for each class.
We issued restricted, unvested common units at the time of the
initial public offering, October 24, 2006. These units will
be considered in the diluted common unit weighted average number
in periods of net income. In periods of net losses, such as the
fourth quarter and total year 2006, the units are excluded from
the diluted earnings per unit calculation due to their
antidilutive effect.
F-24
EAGLE
ROCK ENERGY PARTNERS, L.P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At December 31, 2006, we had 20,691,495 common units,
20,691,495 subordinated units and 844,551 general partner units
outstanding. In addition, we had 122,450 restricted unvested
common units granted and outstanding.
The following table presents our calculation of basic earnings
per unit for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
($ in thousands)
|
|
|
Net (loss) income:
|
|
$
|
(23,314
|
)
|
|
$
|
2,750
|
|
|
$
|
20,982
|
|
Net (loss) income allocated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
(15,229
|
)
|
|
|
2,667
|
|
|
|
20,982
|
|
Subordinated units
|
|
|
(7,637
|
)
|
|
|
|
|
|
|
|
|
General partner units
|
|
|
(448
|
)
|
|
|
83
|
|
|
|
|
|
Weighted average unit outstanding
during period:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
12,123
|
|
|
|
24,151
|
|
|
|
24,151
|
|
Subordinated units
|
|
|
17,873
|
|
|
|
|
|
|
|
|
|
General partner units
|
|
|
557
|
|
|
|
20
|
|
|
|
|
|
Earnings Per Unit
continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
(1.26
|
)
|
|
$
|
0.11
|
|
|
$
|
(0.05
|
)
|
Subordinated units
|
|
$
|
(0.43
|
)
|
|
$
|
|
|
|
$
|
|
|
General partner units
|
|
$
|
(0.80
|
)
|
|
$
|
4.06
|
|
|
$
|
(0.05
|
)
|
|
|
NOTE 18.
|
SUBSEQUENT
EVENTS
|
On February 7, 2007, the Partnership declared a $0.3625
distribution per common unit for the fourth quarter of 2006,
prorated to $0.2679 per common unit for the timing of the
initial public offering on October 24, 2006. The
distribution to the common units was paid on February 15,
2007. No distribution was made to the subordinated or general
partners for the quarter.
On April 2, 2007, the Partnership announced it has signed a
definitive purchase agreement to acquire Laser Midstream Energy,
L.P. and certain of its subsidiaries for $136.8 million,
including $110.0 million in cash and 1,407,895 of common
units of the Partnership. The assets subject to this transaction
include gathering systems and related compression and processing
facilities in South Texas, East Texas and North Louisiana. The
acquisition is subject to customary closing conditions and is
expected to close in late April.
In addition, Eagle Rock announced that it has signed a
definitive agreement to acquire certain fee minerals, royalties
and working interest properties from Montierra
Minerals & Production, L.P. (a Natural Gas Partners
VII, L.P. portfolio company) and NGP-VII Income Co-Investment
Opportunities, L.P. (a Natural Gas Partners affiliate) for an
aggregate purchase price of $127.6 million, subject to
price adjustments. Montierra and such co-investment fund
(collectively, Montierra) will receive as
consideration a total of 6,400,000 EROC common units and
$6.0 million in cash. The assets conveyed in this
transaction include minerals acres, and interests in wells with
net proved producing reserves of approximately 4.6 billion
cubic feet of gas (unaudited) and 2.5 million barrels of
oil (unaudited).
The Partnership also announced on April 2, 2007, it had
entered into a unit purchase agreement to sell in a private
placement 7,005,495 common units to third-party investors, for
total cash proceeds of $127.5 million. The Partnership also
has agreed to file a registration statement with the SEC
registering for resale the common units within 90 days
after the closing. The proceeds from this equity private
placement will fully fund the cash portion of the purchase price
of the Laser acquisition. The Partnership anticipates that the
private placement will close simultaneously with the Laser
acquisition.
In addition, the Partnership has received $100 million in
additional commitments to increase its revolver facility under
its existing Amended and Restated Credit Facility. The increase
of the revolver provides the Partnership with approximately
$175 million in borrowing availability.
* * * *
F-25
Index to
Exhibits
|
|
|
|
|
Exhibit
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Number
|
|
Description
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3
|
.1
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Certificate of Limited Partnership
of Eagle Rock Energy Partners, L.P. (incorporated by reference
to Exhibit 3.1 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
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3
|
.2
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Amended and Restated Agreement of
Limited Partnership of Eagle Rock Energy Partners, L.P.
(included as Appendix A to the Prospectus and including specimen
unit certificate for the common units) (incorporated by
reference to Exhibit 3.2 of the registrants
registration statement on
Form S-1
(File
No. 333-134750))
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3
|
.3
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Certificate of Limited Partnership
of Eagle Rock Energy GP, L.P. (incorporated by reference to
Exhibit 3.3 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
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|
3
|
.4
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|
Limited Partnership Agreement of
Eagle Rock Energy GP, L.P. (incorporated by reference to
Exhibit 3.4 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
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|
3
|
.5
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|
Certificate of Formation of Eagle
Rock Energy G&P, LLC (incorporated by reference to Exhibit
3.5 of the registrants registration statement on
Form S-1
(File
No. 333-134750))
|
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3
|
.6
|
|
Amended and Restated Limited
Liability Company Agreement of Eagle Rock Energy G&P, LLC
(incorporated by reference to Exhibit 3.6 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
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4
|
.1
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|
Registration Rights Agreement
dated March 27, 2006, among Eagle Rock Pipeline, L.P. and
the Purchasers listed thereto (incorporated by reference to
Exhibit 4.1 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
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4
|
.2
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Tag Along Agreement dated
March 27, 2006, among Eagle Rock Pipeline, L.P., Eagle Rock
Pipeline GP, LLC, Eagle Rock Holdings, L.P., and the Purchasers
listed thereto. (incorporated by reference to Exhibit 4.2
of the registrants registration statement on
Form S-1
(File No.
333-134750))
|
|
4
|
.3
|
|
Form of Registration Rights
Agreement between Eagle Rock Energy Partners, L.P. and Eagle
Rock Holdings, L.P. (incorporated by reference to
Exhibit 4.3 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
|
|
4
|
.4
|
|
Form of Common Unit Certificate
(included as Exhibit A to the Amended and Restated
Partnership Agreement of Eagle Rock Energy Partners, L.P., which
is included as Appendix A to the Prospectus) (incorporated by
reference to Exhibit 3.2 of the registrants
registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.1
|
|
Amended and Restated Credit and
Guaranty Agreement (incorporated by reference to
Exhibit 3.1 of the registrants registration statement
on
Form S-1
(File
No. 333-134750))
|
|
10
|
.2
|
|
Form of Omnibus Agreement
(incorporated by reference to Exhibit 3.1 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.3**
|
|
Form of Eagle Rock Energy
Partners, L.P. Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.3 of the registrants
registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.4
|
|
Sale, Contribution and Exchange
Agreement by and among the general and limited partners of
Midstream Gas Services, L.P., Eagle Rock Energy Services, L.P.
and Eagle Rock Pipeline, L.P. (incorporated by reference to
Exhibit 10.4 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.5
|
|
Natural Gas Liquids Exchange
Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas
Field Services, L.P. (incorporated by reference to
Exhibit 10.5 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.6
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Gas Sales and Purchase Agreement
between MC Panhandle, Inc. (Chesapeake Energy Marketing Inc.)
and MidCon Gas Services Corp. (Eagle Rock Field Services, L.P.)
(incorporated by reference to Exhibit 10.6 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
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|
10
|
.7
|
|
Brookeland Gas Facilities Gas
Gathering and Processing Agreement between Union Pacific
Resources Company (Anadarko E&P Company LP) and Sonat
Exploration Company (Eagle Rock Field Services, L.P.)
(incorporated by reference to Exhibit 10.7 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
|
|
|
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Exhibit
|
|
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Number
|
|
Description
|
|
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10
|
.8
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Minimum Volume Agreement between
ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC
(incorporated by reference to Exhibit 10.8 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
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10
|
.9
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Gas Purchase Agreement between
ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC
(incorporated by reference to Exhibit 10.9 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.10
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|
Gas Purchase Contract between
Warren Petroleum Company (Eagle Rock Field Services, L.P.) and
Wallace Oil & Gas, Inc. (Cimarex Energy Co.)
(incorporated by reference to Exhibit 10.10 of the
registrants registration statement on
Form S-1
(File
No. 333-134750))
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10
|
.11
|
|
Form of Contribution, Conveyance
and Assumption Agreement (incorporated by reference to
Exhibit 10.11 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
|
|
10
|
.12**
|
|
Employment Agreement dated
August 2, 2006 between Eagle Rock Energy G&P, LLC and
Richard W. FitzGerald (incorporated by reference to
Exhibit 10.12 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
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10
|
.13
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|
Base Contract for Sale and
Purchase of Natural Gas between Eagle Rock Field Services, L.P.
and Odyssey Energy Services, LLC (incorporated by reference to
Exhibit 10.13 of the registrants registration
statement on
Form S-1
(File
No. 333-134750))
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14
|
.1
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|
Code of Ethics posted on the
Companys website at www.eaglerockenergy.com.
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21
|
.1
|
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List of Subsidiaries of Eagle Rock
Energy Partners, L.P. (incorporated by reference to Exhibit 21.1
of the registrants registration statement on
Form S-1
(File
No. 333-134750))
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23
|
.1*
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|
Consent of Deloitte &
Touche LLP
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24
|
.1*
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Powers of Attorney
|
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31
|
.1*
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Certification of Periodic
Financial Reports by Alex A. Bucher, Jr. in satisfaction of
Section 302 of the Sarbanes-Oxley Act of 2002
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31
|
.2*
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Certification of Periodic
Financial Reports by Richard W. FitzGerald in satisfaction of
Section 302 of the Sarbanes-Oxley Act of 2002
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32
|
.2*
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Certification of Periodic
Financial Reports by Alex A. Bucher, Jr. in satisfaction of
Section 906 of the Sarbanes-Oxley Act of 2002
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32
|
.2*
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Certification of Periodic
Financial Reports by Richard W. FitzGerald in satisfaction of
Section 906 of the Sarbanes-Oxley Act of 2002
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* |
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Filed herewith |
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** |
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Management contract or compensatory plan or arrangement required
to be filed as an exhibit hereto. |
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Portions of this exhibit have been omitted pursuant to a request
for confidential treatment. |