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0000950134-07-004567.txt : 20070301
0000950134-07-004567.hdr.sgml : 20070301
20070301160400
ACCESSION NUMBER: 0000950134-07-004567
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 8
CONFORMED PERIOD OF REPORT: 20061231
FILED AS OF DATE: 20070301
DATE AS OF CHANGE: 20070301
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: CROSSTEX ENERGY INC
CENTRAL INDEX KEY: 0001209821
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 522235832
STATE OF INCORPORATION: DE
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 000-50536
FILM NUMBER: 07663405
BUSINESS ADDRESS:
STREET 1: C/O CROSSTEX ENERGY, INC.
STREET 2: 2501 CEDAR SPRINGS STE 600
CITY: DALLAS
STATE: TX
ZIP: 75201
BUSINESS PHONE: 2149539500
MAIL ADDRESS:
STREET 1: C/O CROSSTEX ENERGY, INC.
STREET 2: 2501 CEDAR SPRINGS STE 600
CITY: DALLAS
STATE: TX
ZIP: 75201
FORMER COMPANY:
FORMER CONFORMED NAME: CROSSTEX ENERGY HOLDINGS INC
DATE OF NAME CHANGE: 20021211
10-K
1
d43870e10vk.htm
FORM 10-K
e10vk
SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C.
20549
Form 10-K
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 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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For the transition period
from to
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Commission file number:
000-50536
CROSSTEX ENERGY, INC.
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other
jurisdiction of
incorporation or organization)
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52-2235832
(I.R.S. Employer
Identification No.)
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2501 CEDAR SPRINGS
DALLAS, TEXAS
(Address of principal
executive offices)
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75201
(Zip
Code)
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(214) 953-9500
(Registrants
telephone number, including area code)
SECURITIES
REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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Title of Each Class
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Name of Exchange on which Registered
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Common Stock, Par Value $0.01 Per
Share
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The NASDAQ Global Select Market
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SECURITIES
REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None.
Indicate by check mark if registrant is a well-known seasoned
issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of 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. o
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 þ Accelerated
filer o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
The aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant was
approximately $753,399,000 on June 30, 2006, based on
$95.08 per share, the closing price of the Common Stock as
reported on the NASDAQ Global Select Market on such date.
At February 16, 2007, there were 45,976,423 shares of
common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Registrants Proxy Statement relating to
its 2007 Annual Stockholders Meeting to be filed with the
Securities and Exchange Commission are incorporated by reference
herein into Part III of this Report.
TABLE OF
CONTENTS
DESCRIPTION
i
CROSSTEX
ENERGY, INC.
PART I
General
Crosstex Energy, Inc. is a Delaware corporation, formed in April
2000. We completed our initial public offering in January 2004.
Our shares of common stock are listed on the NASDAQ Global
Select Market under the symbol XTXI. Our executive
offices are located at 2501 Cedar Springs, Dallas, Texas 75201,
and our telephone number is
(214) 953-9500.
Our Internet address is www.crosstexenergy.com. In the
Investors section of our web site, we post the
following filings as soon as reasonably practicable after they
are electronically filed with or furnished to the Securities and
Exchange Commission: our annual report on
Form 10-K;
our quarterly reports on
Form 10-Q;
our current reports on
Form 8-K;
and any amendments to those reports or statements filed or
furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended. All such filings on
our web site are available free of charge. In this report, the
terms Crosstex Energy, Inc. as well as the terms
our, we, and us, or like
terms, are sometimes used as references to Crosstex Energy, Inc.
and its consolidated subsidiaries. References in this report to
Crosstex Energy, L.P., the Partnership,
CELP or like terms refer to Crosstex Energy, L.P.
itself or Crosstex Energy, L.P. together with its consolidated
subsidiaries.
CROSSTEX
ENERGY, INC.
Our assets consist almost exclusively of partnership interests
in Crosstex Energy, L.P., a publicly traded limited partnership
engaged in the gathering, transmission, treating, processing and
marketing of natural gas. These partnership interests consist of
the following:
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5,332,000 common units, 4,668,000 subordinated units and
6,414,830 senior subordinated series C units, representing
an aggregate 42% limited partner interest in the
Partnership; and
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100% ownership interest in Crosstex Energy GP, L.P., the general
partner of the Partnership, which owns a 2.0% general partner
interest and all of the incentive distribution rights in the
Partnership.
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Our cash flows consist almost exclusively of distributions from
the Partnership on the partnership interests we own. The
Partnership is required by its partnership agreement to
distribute all its cash on hand at the end of each quarter, less
reserves established by its general partner in its sole
discretion to provide for the proper conduct of the
Partnerships business or to provide for future
distributions.
The incentive distribution rights entitle us to receive an
increasing percentage of cash distributed by the Partnership as
certain target distribution levels are reached. Specifically,
they entitle us to receive 13.0% of all cash distributed in a
quarter after each unit has received $0.25 for that quarter,
23.0% of all cash distributed after each unit has received
$0.3125 for that quarter and 48.0% of all cash distributed after
each unit has received $0.375 for that quarter.
Distributions by the Partnership have increased from
$0.25 per unit for the quarter ended March 31, 2003
(its first full quarter of operations after its initial public
offering) to $0.56 per unit for the quarter ended
December 31, 2006. As a result, our distributions from the
Partnership pursuant to our ownership of an aggregate of
10,000,000 common and subordinated units have increased from
$2.5 million for the quarter ended March 31, 2003 to
$5.6 million for the quarter ended December 31, 2006;
our distributions pursuant to our 2% general partner interest
have increased from $74,000 to $0.4 million; and our
distributions pursuant to our incentive distribution rights have
increased from zero to $5.5 million during this period. The
senior subordinated C units do not receive distributions until
they convert to common units in February 2008. As a result, we
have increased our dividend from $0.10 per share for the quarter
ended March 31, 2004 (the first dividend payout after our
initial public offering, giving effect to our
three-for-one
stock split on December 15, 2006) to $0.22 per
share for the quarter ended December 31, 2006.
We intend to continue to pay to our stockholders, on a quarterly
basis, dividends equal to the cash we receive from our
Partnership distributions, less reserves for expenses, future
dividends and other uses of cash, including:
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federal income taxes, which we are required to pay because we
are taxed as a corporation;
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the expenses of being a public company;
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other general and administrative expenses;
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capital contributions to the Partnership upon the issuance by it
of additional partnership securities in order to maintain the
general partners 2.0% general partner interest; and
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reserves our board of directors believes prudent to maintain.
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If the Partnership is successful in implementing its business
strategy and increasing distributions to its partners, we expect
to continue to increase dividends to our stockholders, although
the timing and amount of any such increased dividends will not
necessarily be comparable to the increased Partnership
distributions.
Our ability to pay dividends is limited by the Delaware General
Corporation Law, which provides that a corporation may only pay
dividends out of existing surplus, which is defined
as the amount by which a corporations net assets exceeds
its stated capital. While our ownership of the general partner
and the common, subordinated, and senior subordinated C units of
the Partnership are included in our calculation of net assets,
the value of these assets may decline to a level where we have
no surplus, thus prohibiting us from paying
dividends under Delaware law.
The Partnerships strategy is to increase distributable
cash flow per unit by making accretive acquisitions of assets
that are essential to the production, transportation and
marketing of natural gas and natural gas liquids, or NGLs,
improving the profitability of its assets by increasing their
utilization while controlling costs, accomplishing economies of
scale through new construction or expansion opportunities in its
core operating areas and maintaining financial flexibility to
take advantage of opportunities. If the Partnership is
successful in implementing this strategy, we believe the total
amount of cash distributions it makes will increase and our
share of those distributions will also increase. Under its
current capital structure, each $0.01 per unit increase in
distributions by the Partnership increases its total quarterly
distribution by $532,000 and we would receive $366,000 or 69% of
that increase.
So long as we own the Partnerships general partner, under
the terms of an omnibus agreement with the Partnership we are
prohibited from engaging in the business of gathering,
transmitting, treating, processing, storing and marketing
natural gas and transporting, fractionating, storing and
marketing NGLs, except to the extent that the Partnership, with
the concurrence of a majority of its independent directors
comprising its conflicts committee, elects not to engage in a
particular acquisition or expansion opportunity. The Partnership
may elect to forego an opportunity for several reasons,
including:
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the nature of some or all of the targets assets or income
might affect the Partnerships ability to be taxed as a
partnership for federal income tax purposes;
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the board of directors of Crosstex Energy GP, LLC, the general
partner of the general partner of the Partnership, may conclude
that some or all of the target assets are not a good strategic
opportunity for the Partnership; or
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the seller may desire equity, rather than cash, as consideration
or may not want to accept the Partnerships units as
consideration.
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We have no present intention of engaging in additional
operations or pursuing the types of opportunities that we are
permitted to pursue under the omnibus agreement, although we may
decide to pursue them in the future, either alone or in
combination with the Partnership. In the event that we pursue
the types of opportunities that we are permitted to pursue under
the omnibus agreement, our board of directors, in its sole
discretion, may retain all, or a portion of, the cash
distributions we receive on our partnership interests in the
Partnership to finance all, or a portion of, such transactions,
which may reduce or eliminate dividends paid to our stockholders.
CROSSTEX
ENERGY, L.P.
Crosstex Energy, L.P., is an independent midstream energy
company engaged in the gathering, transmission, treating,
processing and marketing of natural gas and NGLs. It connects
the wells of natural gas producers in its market areas to its
gathering systems, treats natural gas to remove impurities to
ensure that it meets pipeline quality specifications, processes
natural gas for the removal of NGLs, fractionates NGLs into
purity products and markets those products for a fee, transports
natural gas and ultimately provides natural gas to a variety of
markets. It purchases natural gas from natural gas producers and
other supply points and sells that natural gas to utilities,
industrial
2
consumers, other marketers and pipelines and thereby generates
gross margins based on the difference between the purchase and
resale prices. It operates processing plants that process gas
transported to the plants by major interstate pipelines or from
its own gathering systems under a variety of fee arrangements.
In addition, it purchases natural gas from producers not
connected to its gathering systems for resale and sells natural
gas on behalf of producers for a fee.
The Partnership has two operating segments, Midstream and
Treating. The Midstream division focuses on the gathering,
processing, transmission and marketing of natural gas and NGLs,
while the Treating division focuses on the removal of impurities
from natural gas to meet pipeline quality specifications. The
primary Midstream assets include approximately 5,000 miles
of natural gas gathering and transmission pipelines, 12 natural
gas processing plants and four fractionators. The gathering
systems consist of a network of pipelines that collect natural
gas from points near producing wells and transport it to larger
pipelines for further transmission. The transmission pipelines
primarily receive natural gas from the Partnerships
gathering systems and from third party gathering and
transmission systems and deliver natural gas to industrial
end-users, utilities and other pipelines. The processing plants
remove NGLs from a natural gas stream and the Partnerships
fractionators separate the NGLs into separate NGL products,
including ethane, propane, iso- and normal butanes and natural
gasoline. The primary Treating assets include approximately 210
natural gas treating plants and 43 dew point control plants. The
Partnerships natural gas treating plants remove carbon
dioxide and hydrogen sulfide from natural gas prior to
delivering the gas into pipelines to ensure that it meets
pipeline quality specifications. See Note 15 to the
consolidated financial statements for financial information
about these operating segments.
Set forth in the table below is a list of the Partnerships
significant acquisitions since January 1, 2003.
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Acquisition
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Purchase
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Acquisition
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Date
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Price
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Asset Type
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(In thousands)
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DEFS Acquisition
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June 2003
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$
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68,124
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Gathering and transmission systems
and processing plants
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LIG Acquisition
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April 2004
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73,692
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Gathering and transmission systems
and processing plants
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Crosstex Pipeline Partners
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December 2004
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5,100
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Gathering pipeline
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Graco Operations
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January 2005
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9,257
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Treating plants
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Cardinal Gas Services
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May 2005
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6,710
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Treating plants and gas processing
plants
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El Paso Acquisition
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November 2005
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480,976
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Processing and liquids business
(including 23.85% interest in Blue Water gas processing plant)
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Hanover Amine Treating
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February 2006
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51,700
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Treating plants
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Blue Water Acquisition
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May 2006
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16,454
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Additional 35.42% interest in gas
processing plant
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Chief Acquisition
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June 2006
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475,287
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Gathering and transmission systems
and carbon dioxide treating plant
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Cardinal Gas Solutions
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October 2006
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6,330
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Dew point control plants and
treating plants
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As generally used in the energy industry and in this document,
the following terms have the following meanings:
/d = per day
Bcf = billion cubic feet
Btu = British thermal units
Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet
NGL = natural gas liquid
3
Business
Strategy
The Partnerships strategy is to increase distributable
cash flow per unit by making accretive acquisitions of assets
that are essential to the production, transportation and
marketing of natural gas and NGLs; accomplishing economies of
scale through new construction or expansion in core operating
areas; improving the profitability of its assets by increasing
their utilization while controlling costs; and maintaining
financial flexibility to take advantage of opportunities. It
will also build new assets in response to producer and market
needs, such as the Partnerships expansion projects located
in north Louisiana and north Texas as discussed in Recent
Acquisitions and Expansion below. We believe the expanded
scope of the Partnerships operations, combined with a
continued high level of drilling in its principal geographic
areas, should present opportunities for continued expansion in
its existing areas of operation as well as opportunities to
acquire or develop assets in new geographic areas that may serve
as a platform for future growth. Key elements of the strategy
include the following:
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Pursuing accretive acquisitions. The
Partnership intends to use its acquisition and integration
experience to continue to make strategic acquisitions of
midstream and treating assets that offer the opportunity for
operational efficiencies and the potential for increased
utilization and expansion of the acquired asset. The Partnership
pursues acquisitions that it believes will add to existing core
areas in order to capitalize on its existing infrastructure,
personnel and producer and consumer relationships. The
Partnership also examines opportunities to establish new core
areas in regions with significant natural gas reserves and high
levels of drilling activity or with growing demand for natural
gas, primarily through the acquisition or development of key
assets that will serve as a platform for further growth. The
Partnership established two new core areas through the
acquisition and consolidation of its south Texas assets in 2001
through 2003 and the acquisition of the LIG Pipeline Company and
subsidiaries, which we collectively refer to as LIG, in 2004,
and the ongoing work to consolidate with the 2005 acquisition of
the south Louisiana processing business from El Paso
Corporation, or El Paso. With the acquisition of the
natural gas gathering pipeline systems and related facilities
from Chief Holdings LLC, or Chief, and the completion of
construction of the North Texas Pipeline, or NTP, in 2006, the
Partnership has established a core area in north Texas.
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Undertaking construction and expansion opportunities
(organic growth). The Partnership
leverages its existing infrastructure and producer and customer
relationships by constructing and expanding systems to meet new
or increased demand for gathering, transmission, treating,
processing and marketing services. These projects include
expansion of existing systems and construction of new
facilities, which has driven the growth of the Treating division
in recent years. In April 2006, the Partnership completed
construction and commenced operations on the new
133-mile NTP
to transport gas from the Barnett Shale. The Partnership is in
the process of expanding capacity on the NTP, as well as
expanding its north Texas processing capacity and completing the
buildout of its north Texas gathering system acquired in the
Chief acquisition in response to the increased producer activity
in this area. The Partnership also has a major expansion of the
LIG system underway that is expected to commence operation in
2007, as discussed in detail below. The Partnership continues to
pursue organic growth opportunities in Texas, Louisiana and
elsewhere.
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Improving existing system profitability. After
the Partnership acquires or constructs a new system, it begins
an aggressive effort to market services directly to both
producers and end users in order to connect new supplies of
natural gas, improve margins and more fully utilize the
systems capacity. As part of this process, the Partnership
focuses on providing a full range of services to producers and
end users, including supply aggregation, transportation and
hedging, which the Partnership believes provides a competitive
advantage when competing for sources of natural gas supply.
Since treating services are not provided by many of the
Partnerships competitors, it has an additional advantage
in competing for new supply when gas requires treating to meet
pipeline specifications. Furthermore, the Partnership emphasizes
increasing the percentage of natural gas sales directly to end
users, such as industrial and utility consumers, in an effort to
increase operating margins.
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Recent
Acquisitions and Expansion
Chief Midstream Assets. On June 29, 2006,
the Partnership acquired the natural gas gathering pipeline
systems and related facilities of Chief in the Barnett Shale for
$475.3 million. The acquired systems, which we refer
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to in conjunction with the NTP as our North Texas Assets,
consist of approximately 226 miles of existing pipeline
with up to an additional 400 miles of planned pipelines,
located in Parker, Tarrant, Denton, Palo Pinto, Erath, Hood,
Somervell, Hill and Johnson Counties, Texas. The acquired assets
also include a 125 million cubic feet per day carbon
dioxide treating plant and compression facilities with 26,000
horsepower. At the closing of that transaction, approximately
160,000 net acres previously owned by Chief and acquired by
Devon Energy Corporation, or Devon, simultaneously with our
acquisition, as well as 60,000 net acres owned by other
producers, were dedicated to the systems.
North Texas Pipeline System. In April 2006,
the Partnership completed construction and commenced service on
the NTP, a
new 133-mile
pipeline and associated gathering lines from an area near
Fort Worth, Texas to a point near Paris, Texas, with a
capacity of approximately 250,000 MMBtu/d. The NTP connects
production from the Barnett Shale to markets in north Texas and
to markets accessed by the Natural Gas Pipeline Company, or NGPL
pipeline and other markets. The NTP allows contracted gas to
flow to markets that were not previously available to some key
Barnett Shale producers. The Partnership plans to expand the NTP
in the second quarter of 2007 to a total capacity of
approximately 375,000 MMBtu/d. The NTP will interconnect
with a new interstate gas pipeline to be constructed by
Boardwalk Pipeline Partners, L.P. known as the Gulf Crossing
Pipeline. The Gulf Crossing Pipeline will provide the
Partnerships customers access to premium midwest and east
coast markets. The Partnership has committed to contract for
150,000 MMBtu/d for ten years of firm transportation
capacity on the Gulf Crossing Pipeline when it commences
service, which is expected in the latter part of 2008.
North Louisiana Expansion Project. The
Partnerships North Louisiana Expansion project is an
extension of its LIG system which is designed to better serve
Louisiana intrastate markets and interstate markets, and to
provide additional and much needed take-away pipeline capacity
to the producers developing natural gas in the fields south of
Shreveport, Louisiana. The expansion consists of 63 miles
of 24 mainline with 9 miles of 16 gathering
lateral pipeline and 10,000 horsepower of compression.
Interconnects on the North Louisiana Expansion include
connections with the interstate pipelines of ANR Pipeline,
Columbia Gulf Transmission, Texas Gas Transmission and Trunkline
Gas with additional interconnects under consideration. The
capacity of the expansion is approximately 250 MMcf/d. Four
of the largest suppliers of natural gas to the new pipeline are
El Paso Production, JW Operating, KCS Resources and
Winchester Production, which together have committed
185 MMcf/d of capacity. The pipeline is expected to be
partially operational in late March 2007 with total completion
expected by early May 2007.
Blue Water Processing Plant Acquisition. In
May 2006, the Partnership acquired an additional 35.42% interest
in the Blue Water gas processing plant for $16.5 million,
increasing its total ownership interest to 59.27%. The
Partnership also became the operator of the plant in May 2006.
The Partnerships initial 23.85% interest in this
processing plant was acquired as part of the November 2005
El Paso acquisition.
Cardinal Treating Assets. On October 2,
2006, the Partnership acquired the treating and dew point
control business of Cardinal Gas Solutions, L.P. for
$6.3 million. The acquired assets include 10 dew point
control plants and seven amine treating plants.
Hanover Acquisition. On February 1, 2006,
the Partnership acquired 48 amine treating plants from a
subsidiary of Hanover Compression Company for $51.7 million.
Other
Developments
Three-for-One
Stock Split. On December 15, 2006, we
completed a
three-for-one
stock split in the form of a stock dividend. All share amounts
in this Annual Report on
Form 10-K
give effect to such stock split.
Partnerships Issuance of Senior Subordinated
Series C Units. On June 29, 2006, the
Partnership issued an aggregate of 12,829,650 senior
subordinated series C units representing limited partner
interests in a private equity offering for net proceeds of
$359.3 million. The senior subordinated series C units
were issued at $28.06 per unit, which represented a
discount of 25% to the market value of common units on such
date. We purchased 6,414,830 of the senior subordinated
series C units. In addition, Crosstex Energy GP, L.P. made
a general partner contribution of $9.0 million in
connection with this issuance to maintain its 2% general partner
interest. The senior subordinated series C units will
automatically convert to common units on the first date on or
before February 16, 2008 that
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conversion is permitted by the Partnerships partnership
agreement at a ratio of one common unit for each senior
subordinated series C unit.
Partnerships Bank Credit Facility. On
June 29, 2006, the Partnership amended its bank credit
facility to, among other things, provide for revolving credit
borrowings up to a maximum principal amount of
$1.0 billion. The bank credit agreement includes procedures
for additional financial institutions selected by the
Partnership to become lenders under the agreement, or for any
existing lender to increase its commitment in an amount approved
by the Partnership and the lender, subject to a maximum of
$300 million for all such increases in commitments of new
or existing lenders. The maturity date was also extended to June
2011.
Partnerships Senior Secured Notes. In
March and July 2006, the Partnership amended its shelf agreement
governing the senior secured notes to increase its availability
from $200.0 million to $510.0 million. In March 2006,
the Partnership issued $60.0 million aggregate principal
amount of senior secured notes with an interest rate of 6.32%
and a maturity of ten years. In July 2006, the Partnership
issued $245.0 million aggregate principal amount of senior
secured notes with an interest rate of 6.96% and a maturity of
ten years. Proceeds were used to pay indebtedness under its bank
credit facility.
June 2006 Issuance of Capital Stock. On
June 29, 2006, we issued 7,650,780 shares of common
stock in a private placement for total net proceeds of
$179.9 million. Lubar Equity Fund, LLC, an affiliate of one
of our directors, purchased 468,210 of the shares at a purchase
price of $25.633 per share and unrelated third parties
purchased 7,182,570 shares at a purchase price of
$23.39 per share. We used the proceeds from the stock
issuance to purchase $180.0 million of senior subordinated
series C units representing limited partner interests of
the Partnership described in Partnerships
Issuance of Senior Subordinated Series C Units
above.
Midstream
Segment
Gathering, Processing and Transmission. The
Partnerships primary Midstream assets include systems
located primarily along the Texas Gulf Coast and in
south-central Mississippi and in Louisiana, which, in the
aggregate, consist of approximately 5,000 miles of
pipeline, 12 natural gas processing plants and four
fractionators and contributed approximately 79% and 76% of its
gross margin in 2006 and 2005, respectively.
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South Louisiana Processing Assets. The
Partnerships Louisiana natural gas processing and liquids
business, which was acquired on November 1, 2005 and is
referred to as the Partnerships South Louisiana Processing
Assets, includes a total of 2.3 Bcf/d of processing
capacity, 66,000 barrels per day of fractionation capacity,
2.4 million barrels of underground storage and
400 miles of liquids transport lines.
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The South Louisiana Processing Assets primarily consist of:
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Eunice Processing Plant and Fractionation
Facility. The Eunice facilities are located near
Eunice, Louisiana. The Eunice processing plant has a capacity of
1.2 Bcf/d and processed approximately 756 MMcf/d of
natural gas for the year ended December 31, 2006. The plant
is connected to onshore, continental shelf and deepwater gas
production and has downstream connections to the ANR Pipeline,
Florida Gas Transmission and Texas Gas Transmission. The Eunice
fractionation facility has a capacity of 36,000 barrels per
day of liquid products. This facility also has
190,000 barrels of above-ground storage capacity. The
fractionation facility produces ethane, propane, iso-butane,
normal butane and natural gasoline for various customers. The
fractionation facility is directly connected to the southeast
propane market and pipelines to the Anse La Butte storage
facility. The Partnership has a five-year storage agreement at
the Anse La Butte facility for 100,000 barrels of NGL
storage beginning January 1, 2007.
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Pelican Processing Plant. The Pelican
processing plant complex is located in Patterson, Louisiana and
has a designed capacity of 600 MMcf/d of natural gas. For
the year ended December 31, 2006, the plant processed
approximately 370 MMcf/d. The Pelican plant is connected
with continental shelf and deepwater production and has
downstream connections to the ANR Pipeline.
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Sabine Pass Processing Plant. The Sabine Pass
processing plant is located 15 miles east of the Sabine
River at Johnsons Bayou, Louisiana and has a processing
capacity of 300 MMcf/d of natural gas. The Sabine Pass
plant is connected to continental shelf and deepwater gas
production with downstream
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connections to Florida Gas Transmission, Tennessee Gas Pipeline
and Transco. For the year ended December 31, 2006, this
facility processed approximately 217 MMcf/d.
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Blue Water Gas Processing Plant. The
Partnership acquired a 23.85% interest in the Blue Water gas
processing plant in the November 2005 El Paso acquisition
and acquired an additional 35.42% interest in May 2006, at which
time it became the operator of the plant. The plant has a net
processing capacity to the acquired interest of 186 MMcf/d.
For the year ended December 31, 2006, this facility
processed approximately 127 MMcf/day net to our interest.
The Blue Water plant is located near Crowley, Louisiana. The
Blue Water facility is connected to continental shelf and
deepwater production volumes through the Blue Water pipeline
system. Downstream connections from this plant include the
Tennessee Gas Pipeline and Columbia Gulf. The facility also
performs liquid natural gas (LNG) conditioning services for the
Excelerate Energy LNG tanker unloading facility.
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Riverside Fractionation Plant. The Riverside
fractionator and loading facility is located on the Mississippi
River upriver from Geismar, Louisiana. The Riverside plant has a
fractionation capacity of 28,000 to 30,000 barrels per day
of liquids products and fractionates liquids delivered by the
Cajun Sibon pipeline system from the Pelican, Blue Water and Cow
Island plants or by truck. The Riverside facility has
above-ground storage capacity of approximately
102,000 barrels.
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Napoleonville Storage Facility. The
Napoleonville NGL storage facility is connected to the Riverside
facility and has a total capacity of approximately
2.4 million barrels of underground storage.
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Cajun Sibon Pipeline System. The Cajun Sibon
pipeline system consists of approximately 400 miles of
6 and 8 pipelines with a system capacity of
approximately 28,000 barrels per day. The pipeline
transports unfractionated NGLs, referred to as raw make, from
the Pelican plant and the Blue Water plant to either the
Riverside fractionator or the Napoleonville storage facility.
Alternate deliveries can be made to the Eunice plant.
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The Partnership contracted to buy the South Louisiana Processing
Assets from El Paso two weeks before Hurricane Katrina
struck the Gulf Coast, and approximately six weeks before
Hurricane Rita struck. While the hurricanes did not do any
significant damage to the Partnerships South Louisiana
Processing Assets, both hurricanes did extensive damage to Gulf
of Mexico drilling, production and transportation facilities. In
addition, as a result of the hurricanes, drilling activity in
the Gulf of Mexico since that time has been reduced, resulting
in an exacerbation of declining trends for production in the
area. The Partnership estimates that Gulf of Mexico production
is 20-25%
below pre-hurricane levels, and as a result, it has lower
volumes in the plants than it estimated at the time of the
acquisition. This has resulted in 2006 cash flows from the
assets at levels significantly below levels the Partnership had
anticipated at the time of the acquisition. In addition, a
pipeline that supplies natural gas to the Eunice processing
plant unilaterally changed the methodology used to allocate fuel
and losses. These changes, may result in increased expenses
associated with the Eunice Plant operations for the Partnership
and its customers. The Partnership is currently in negotiations
with the pipeline supplier and evaluating its remedies. The
Partnership is evaluating alternative strategies for the
operation of the assets that it believes will significantly
improve cash flows.
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North Texas Assets. On June 29, 2006, the
Partnership acquired the natural gas gathering pipeline systems
and related facilities of Chief in the Barnett Shale. The
acquired systems consist of approximately 226 miles of
existing pipeline with up to an additional 400 miles of
planned pipelines, located in Parker, Tarrant, Denton, Palo
Pinto, Erath, Hood, Somervell, Hill and Johnson counties, Texas.
The acquired assets also include a 125 million cubic feet
per day carbon dioxide treating plant and compression facilities
with 26,000 horsepower. At the closing of that transaction,
approximately 160,000 net acres previously owned by Chief
and acquired by Devon simultaneously with the Partnerships
acquisition, as well as 60,000 net acres owned by other
producers, were dedicated to the systems. Immediately following
the closing of the Chief acquisition, we began expanding our
North Texas pipeline gathering system. As of December 31,
2006, the Partnership had installed approximately 49 miles
of gathering pipeline and connected 85 new wells to its
gathering systems, 46 of which are owned or controlled by Devon
and 39 of which are owned or controlled by other producers. In
addition to expanding its gathering system, the Partnership had
installed 4,400 horsepower of additional compression to handle
the increased volumes. The Partnership also installed the new
Azle Plant, a 55,000 Mcf/d cryogenic processing plant and
added inlet refrigeration to an existing
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30,000 Mcf/d plant in order to remove hydrocarbon liquids
from growing gas streams. The Partnership has increased total
throughput on this gathering system from approximately
115 MMcf/d at the time of the acquisition to
230 MMcf/d for the month of December 2006.
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The Partnership plans to expand its NTP system in the second
quarter of 2007 to a total capacity of approximately
375,000 MMBtu/day.
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The Partnership has committed to contract for
150,000 MMBtu/day of firm transportation capacity on a new
interstate gas pipeline to be constructed by Boardwalk Pipeline
Partners, L.P. known as the Gulf Crossing Pipeline, which will
connect with the Partnerships NTP system in Lamar County,
Texas. The Gulf Crossing Pipeline will provide the
Partnerships customers access to premium midwest and east
coast markets.
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LIG System. The Partnership acquired the LIG
system on April 1, 2004. The LIG system is the largest
intrastate pipeline system in Louisiana, consisting of
approximately 2,000 miles of gathering and transmission
pipeline, and had an average throughput of approximately
692,000 MMBtu/d for the year ended December 31, 2006.
The system also includes two operating processing plants with an
average throughput of 328,000 MMBtu/d for the year ended
December 31, 2006. The system has access to both rich and
lean gas supplies. These supplies reach from north Louisiana to
new offshore production in southeast Louisiana. LIG has a
variety of transportation and industrial sales customers, with
the majority of its sales being made into the industrial
Mississippi River corridor between Baton Rouge and New Orleans.
The Partnership is extending its LIG system to better serve its
customers. The North Louisiana Expansion consists of
63 miles of 24 mainline with 9 miles of
gathering lateral pipeline and 10,000 horsepower of compression.
The capacity of the expansion is approximately 250 MMcf/d.
The pipeline is expected to be partially operational in late
March 2007 with total completion expected by early May 2007.
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South Texas System. The Partnership has
assembled a highly-integrated south Texas system comprised of
approximately
1,400-miles
of intrastate gathering and transmission pipelines and a
processing plant with a processing capacity of approximately
150 MMcf/d. The south Texas system was built through a
number of acquisitions and follow-on organic projects, including
acquisitions of the Gulf Coast system, the Corpus Christi
system, the Gregory gathering system and processing plant, the
Hallmark system and the Vanderbilt system. Average throughput on
the system for the year ended December 31, 2006 was
approximately 457,000 MMBtu/d. Average throughput in the
processing plant was approximately 99,000 MMBtu/d for that
period. The system gathers gas from major production areas in
the Texas gulf coast and delivers gas to the industrial markets,
power plants, other pipelines and gas distribution companies in
the region from Corpus Christi to the Houston area.
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Other Midstream assets and activities include:
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Mississippi Pipeline System. This
approximately
603-mile
system in south Mississippi gathers wellhead supply in the
region and sells it through direct market connections to
utilities and industrial end-users. Average throughput on the
system was approximately 107,000 MMBtu/d for the year ended
December 31, 2006.
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Arkoma Gathering System. This approximately
140-mile
low-pressure gathering system in southeastern Oklahoma delivers
gathered gas into a mainline transmission system. For the year
ended December 31, 2006, throughput on the system averaged
approximately 22,000 MMBtu/d.
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Other. Other midstream assets consist of a
variety of gathering lines and a processing plant with a
processing capacity of approximately 66,000 Bcf/d. Total
volumes gathered and resold were approximately
65,000 MMBtu/d for the year ended December 31, 2006.
Total volumes processed were approximately 22,000 MMBtu/d
in the period.
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Off-System Services. The Partnership offers
natural gas marketing services on behalf of producers for
natural gas that does not move on its assets. It markets this
gas on a number of interstate and intrastate pipelines. These
volumes averaged approximately 139,000 MMBtu/d in 2006.
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8
Treating
Segment
The Partnership operates (or leases to producers for operation)
treating plants that remove carbon dioxide and hydrogen sulfide
from natural gas before it is delivered into transportation
systems to ensure that it meets pipeline quality specifications.
The treating division contributed approximately 21% and 24% of
the Partnerships gross margin in 2006 and 2005,
respectively. The Partnerships treating business has grown
from 112 plants in operation at December 31, 2005 to 160
plants in operation at December 31, 2006. During 2006, the
Partnership spent an aggregate of $58.0 million in two
separate acquisitions to acquire 55 treating plants, 10 dew
point control plants and related spare parts inventory. Pipeline
companies have begun enforcing gas quality specifications to
lower the dew point of the gas they receive and transport. A
higher relative dew point can sometimes cause liquid
hydrocarbons to condense in the pipeline and cause operating
problems and gas quality issues to the downstream markets.
Hydrocarbon dew point plants are skid mounted process equipment
that remove these hydrocarbons. Typically these plants use a
Joules-Thompson expansion process to lower the temperature of
the gas stream and collect the liquids before they enter the
downstream pipeline. The Partnerships Treating division
views dew point control as complementary to its treating
business.
The Partnership believes it has the largest gas treating
operation in the Texas and Louisiana gulf coast. Natural gas
from certain formations in the Texas gulf coast, as well as
other locations, is high in carbon dioxide,which generally needs
to be removed before introduction of the gas into transportation
pipelines. Many of its active plants are treating gas from the
Wilcox and Edwards formations in the Texas gulf coast, both of
which are deeper formations that are high in carbon dioxide. In
cases where producers pay the Partnership to operate the
treating facilities, it either charges a fixed rate per Mcf of
natural gas treated or a fixed monthly fee.
The Partnership also owns an undivided 12.4% interest in the
Seminole gas processing plant, which is located in Gaines
County, Texas, and which is accounted for as part of the
Treating division. The Seminole plant has dedicated long-term
reserves from the Seminole San Andres unit, to which it
also supplies carbon dioxide under a long-term arrangement.
Revenues at the plant are derived from a fee it charges
producers, primarily those at the Seminole San Andres unit,
for each Mcf of carbon dioxide returned to the producer for
reinjection. The fees currently average approximately $0.68 for
each Mcf of carbon dioxide returned. The owners of the Seminole
plant also receive 50% of the NGLs produced by the plant.
The Partnerships treating growth strategy is based on the
belief that if gas prices remain at recent levels, producers
will be encouraged to drill deeper gas formations. It believes
the gas recovered from these formations is more likely to be
high in carbon dioxide, a contaminant that generally needs to be
removed before introduction into transportation pipelines. When
completing a well, producers place a high value on immediate
equipment availability, as they can more quickly begin to
realize cash flow from a completed well. The Partnership
believes its track record of reliability, current availability
of equipment and its strategy of sourcing new equipment gives it
a significant advantage in competing for new treating business.
Treating process. The amine treating process
involves a continuous circulation of a liquid chemical called
amine that physically contacts with the natural gas. Amine has a
chemical affinity for hydrogen sulfide and carbon dioxide that
allows it to remove the impurities from the gas. After mixing,
gas and reacted amine are separated and the impurities are
removed from the amine by heating. Treating plants are sized by
the amine circulation capacity in terms of gallons per minute.
9
Industry
Overview
The following diagram illustrates the natural gas treating,
gathering, processing, fractionation and transmission process.
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. The midstream industry is
generally characterized by regional competition based on the
proximity of gathering systems and processing plants to natural
gas producing wells.
Natural gas gathering. The natural gas
gathering process begins with the drilling of wells into gas
bearing rock formations. Once a well has been completed, the
well is connected to a gathering system. Gathering systems
typically consist of a network of small diameter pipelines and,
if necessary, compression systems that collect natural gas from
points near producing wells and transport it to larger pipelines
for further transmission.
Natural gas treating. 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 is high in carbon dioxide. Most treating plants
and transmission pipelines are placed at or near a well and
remove carbon dioxide and hydrogen sulfide from natural gas
before it is introduced into gathering systems to ensure that it
meets pipeline quality specifications. Pipeline companies have
begun enforcing gas quality specifications to lower the dew
point of the gas they receive and transport. A higher relative
dew point can sometimes cause liquid hydrocarbons to condense in
the pipeline and cause operating problems and gas quality issues
to the downstream markets. Hydrocarbon dew point plants are skid
mounted process equipment that remove these hydrocarbons.
Typically these plants use a Joules-Thompson expansion process
to lower the temperature of the gas stream and collect the
liquids before they enter the downstream pipeline. The
Partnerships Treating division views dew point control as
complementary to its treating business.
Natural gas processing and fractionation. The
principal components of natural gas are methane and ethane, but
most natural gas also contains varying amounts of NGLs and
contaminants, such as water, sulfur compounds, nitrogen or
helium. Most natural gas produced by a well is not suitable for
long-haul pipeline transportation or commercial use and must be
processed to remove the heavier hydrocarbon components and
contaminants. Natural gas in commercial distribution systems is
composed almost entirely of methane and ethane, with moisture
and other contaminants removed to very low concentrations.
Natural gas is processed not only to remove unwanted
contaminants that would interfere with pipeline transportation
or use of the natural gas, but also to separate from the gas
those hydrocarbon liquids that have higher value as NGLs. The
removal and separation of individual hydrocarbons by processing
is possible because of differences in weight, boiling point,
vapor pressure and other physical characteristics. Natural gas
processing involves the separation of natural gas into pipeline
quality natural gas and a mixed NGL stream, as well as the
removal of contaminants. NGL fractionation facilities separate
mixed NGL streams into discrete NGL products: ethane, propane,
isobutane, normal butane and natural gasoline.
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Natural gas transmission. Natural gas
transmission pipelines receive natural gas from mainline
transmission pipelines, processing plants, and gathering systems
and deliver it to industrial end-users, utilities and to other
pipelines.
Supply/Demand
Balancing
As the Partnership purchases natural gas, it normally
establishes a margin by selling natural gas for physical
delivery to third-party users. It can also use
over-the-counter
derivative instruments or enter into a future delivery
obligation under futures contracts on the New York Mercantile
Exchange. Through these transactions, it seeks to maintain a
position that is substantially balanced between purchases, on
the one hand, and sales or future delivery obligations, on the
other hand. Its policy is not to acquire and hold natural gas
future contracts or derivative products for the purpose of
speculating on price changes.
Competition
The business of providing natural gas gathering, transmission,
treating, processing and marketing services for natural gas and
NGLs is highly competitive. The Partnership faces strong
competition in acquiring new natural gas supplies and in the
marketing and transportation of natural gas and NGLs. Its
competitors include major integrated oil companies, interstate
and intrastate pipelines and other natural gas gatherers and
processors. Competition for natural gas supplies is primarily
based on geographic location of facilities in relation to
production or markets, the reputation, efficiency and
reliability of the gatherer and the pricing arrangements offered
by the gatherer. Many of its competitors offer more services or
have greater financial resources and access to larger natural
gas supplies than we do. The Partnerships competition will
likely differ in different geographic areas.
The Partnerships gas treating operations face competition
from manufacturers of new treating and dew point control plants
and from a small number of regional operators that provide
plants and operations similar to the Partnership. It also faces
competition from vendors of used equipment that occasionally
operate plants for producers. In addition, the Partnership
routinely loses business to gas gatherers who have underutilized
treating or processing capacity and can take the producers
gas without requiring wellhead treating. The Partnership may
also lose wellhead treating opportunities to blending. Some
pipeline companies have the limited ability to waive their
quality specifications and allow producers to deliver their
contaminated gas untreated. This is generally referred to as
blending because of the receiving companys ability to
blend this gas with cleaner gas in the pipeline such that the
resulting gas meets pipeline specification.
In marketing natural gas and NGLs, the Partnership has numerous
competitors, including marketing affiliates of interstate
pipelines, major integrated oil companies, and local and
national natural gas gatherers, brokers and marketers of widely
varying sizes, financial resources and experience. Local
utilities and distributors of natural gas are, in some cases
engaged directly, and through affiliates, in marketing
activities that compete with the Partnership.
The Partnership faces strong competition for acquisitions and
development of new projects from both established and
start-up
companies. Competition increases the cost to acquire existing
facilities or businesses, and results in fewer commitments and
lower returns for new pipelines or other development projects.
Many of its competitors have greater financial resources or
lower capital costs, or are willing to accept lower returns or
greater risks. The Partnerships competition differs by
region and by the nature of the business or the project involved.
Natural
Gas Supply
The Partnerships transmission pipelines have connections
with major interstate and intrastate pipelines, which it
believes have ample supplies of natural gas in excess of the
volumes required for these systems. In connection with the
construction and acquisition of gathering systems, the
Partnership evaluates well and reservoir data furnished by
producers to determine the availability of natural gas supply
for the systems
and/or
obtain a minimum volume commitment from the producer that
results in a rate of return on the investment. Based on these
facts, the Partnership believes that there should be adequate
natural gas supply to recoup the investment with an adequate
rate of return. It does not routinely obtain independent
evaluations of reserves dedicated to its systems due to the cost
and relatively limited benefit of such evaluations. Accordingly,
it does not have estimates of total reserves dedicated to its
systems or the anticipated life of such producing reserves.
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Credit
Risk and Significant Customers
The Partnership is diligent in attempting to ensure that it
issues credit to only credit-worthy customers. However, the
purchase and resale of gas exposes the Partnership to
significant 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 the Partnerships
overall profitability.
During the year ended December 31, 2006, the Partnership
had one customer that individually accounted for approximately
13.4% of consolidated revenues. While this customer represents a
significant percentage of consolidated revenues, the loss of
this customer would not have a material impact on its results of
operations.
Regulation
Regulation by FERC of Interstate Natural Gas
Pipelines. The Partnership does not own any
interstate natural gas pipelines, so the Federal Energy
Regulatory Commission, or FERC, does not directly regulate its
operations under the National Gas Act, or NGA. However,
FERCs regulation of interstate natural gas pipelines
influences certain aspects of its business and the market for
its products. In general, FERC has authority over natural gas
companies that provide natural gas pipeline transportation
services in interstate commerce and its authority to regulate
those services includes:
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the certification and construction of new facilities;
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the extension or abandonment of services and facilities;
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the maintenance of accounts and records;
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the acquisition and disposition of facilities;
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maximum rates payable for certain services; and
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the initiation and discontinuation of services.
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The rates, terms and conditions of service under which the
Partnership transports natural gas in its pipeline systems in
interstate commerce are subject to FERC jurisdiction under
Section 311 of the Natural Gas Policy Act, or NGPA. Rates
for services provided under Section 311 of the NGPA may not
exceed a fair and equitable rate, as defined in the
NGPA. The rates are generally subject to review every three
years by the FERC or by an appropriate state agency. Rates for
interstate services provided under NGPA Section 311 on our
south Texas, Louisiana and Mississippi pipeline systems were
each subject to review in 2006 and no substantial changes were
made to their rates.
Intrastate Pipeline Regulation. The
Partnerships intrastate natural gas pipeline operations
generally are not subject to rate regulation by FERC, but they
are subject to regulation by various agencies of the states in
which they are located. Most states have agencies that possess
the authority to review and authorize natural gas transportation
transactions and the construction, acquisition, abandonment and
interconnection of physical facilities. Some states also have
state agencies that regulate transportation rates, service terms
and conditions and contract pricing to ensure their
reasonableness and to ensure that the intrastate pipeline
companies that they regulate do not discriminate among similarly
situated customers.
Gathering Pipeline
Regulation. Section 1(b) of the NGA exempts
natural gas gathering facilities from the jurisdiction of FERC
under the NGA. The Partnership owns a number of natural gas
pipelines that we believe meet the traditional tests FERC has
used to establish a pipelines status as a gatherer not
subject to FERC jurisdiction. 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.
The Partnership is subject to state 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.
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Sales of Natural Gas. The price at which the
Partnership sells natural gas currently is not subject to
federal regulation and, for the most part, is not subject to
state regulation. The Partnerships 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. FERC is continually proposing and implementing
new rules and regulations affecting those segments of the
natural gas industry, most notably interstate natural gas
transmission companies, that remain subject to 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 less extensive
regulation. We cannot predict the ultimate impact of these
regulatory changes on the Partnerships natural gas
marketing operations, and we note that some of FERCs more
recent proposals may adversely affect the availability and
reliability of interruptible transportation service on
interstate pipelines. We do not believe that the Partnership
will be affected by any such FERC action materially differently
than other natural gas marketers with whom they compete.
Environmental
Matters
General. The Partnerships operation of
treating, processing and fractionation plants, pipelines and
associated facilities in connection with the gathering, treating
and processing of natural gas and the transportation,
fractionation and storage of NGLs is subject to stringent and
complex federal, state and local laws and regulations relating
to release of hazardous substances or wastes into the
environment or otherwise relating to protection of the
environment. As with the industry generally, compliance with
existing and anticipated environmental laws and regulations
increases its overall costs of doing business, including cost of
planning, constructing, and operating plants, pipelines and
other facilities. Included in the Partnerships
construction and operation costs are capital cost items
necessary to maintain or upgrade equipment and facilities.
Similar costs are likely upon any future acquisition of
operating assets.
Any failure to comply with applicable environmental laws and
regulations, including those relating to obtaining required
governmental approvals, may result in the assessment of
administrative, civil or criminal penalties, imposition of
investigatory or remedial activities and, in less common
circumstances, issuance of injunctions or construction bans or
delays. While we believe that the Partnership currently holds
all material governmental approvals required to operate its
major facilities, the Partnership is currently evaluating and
updating permits for certain of its facilities specifically
including those obtained in recent acquisitions. As part of the
regular overall evaluation of its operations, the Partnership
has implemented procedures and is presently working to ensure
that all governmental approvals, for both recently acquired
facilities and existing operations, are updated as may be
necessary. We believe that the Partnerships operations and
facilities are in substantial compliance with applicable
environmental laws and regulations and that the cost of
compliance with such laws and regulations will not have a
material adverse effect on its operating results or financial
condition.
The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus there can be no assurance as to the amount
or timing of future expenditures for environmental compliance or
remediation, and actual future expenditures may be different
from the amounts we currently anticipate. Moreover, risks of
process upsets, accidental releases or spills are associated
with the Partnerships possible future operations, and we
cannot assure you that the Partnership will not incur
significant costs and liabilities including those relating to
claims for damage to property and persons as a result of such
upsets, releases, or spills. In the event of future increases in
costs, the Partnership may be unable to pass on those cost
increases to its customers. A discharge of hazardous substances
or wastes into the environment could, to the extent the event is
not insured, subjects the Partnership to substantial expense,
including both the cost to comply with applicable laws and
regulations and the cost related to claims made by neighboring
landowners and other third parties for personal injury or damage
to property. The Partnership will attempt to anticipate future
regulatory requirements that might be imposed and plan
accordingly to comply with changing environmental laws and
regulations and to minimize costs.
Hazardous Substance and Waste. To a large
extent, the environmental laws and regulations affecting the
Partnerships possible future operations relate to the
release of hazardous substances or solid wastes into soils,
groundwater, and surface water, and include measures to control
environmental pollution of the environment. These
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laws and regulations generally regulate the generation, storage,
treatment, transportation, and disposal of solid and hazardous
wastes, and may require investigatory and corrective actions at
facilities where such waste may have been released or disposed.
For instance, the Comprehensive Environmental Response,
Compensation and Liability Act, or CERCLA, also known as the
Superfund law, and comparable state laws, impose
liability without regard to fault or the legality of the
original conduct, on certain classes of persons that contributed
to a release of hazardous substance into the
environment. These persons include the owner or operator of the
site where a release occurred and companies that disposed or
arranged for the disposal of the hazardous substances found at
the site. Under CERCLA, these persons may be subject to joint
and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, for
damages to natural resources, and for the costs of certain
health studies. CERCLA also authorizes the EPA and, in some
cases, third parties to take actions in response to threats to
the public health or the environment and to seek to recover from
the responsible classes of persons the costs they incur. It is
not uncommon for neighboring landowners and other third parties
to file claims for personal injury and property damage allegedly
caused by hazardous substances or other wastes released into the
environment. Although petroleum as well as natural
gas and NGLs are excluded from CERCLAs definition of a
hazardous substance, in the course of future,
ordinary operations, the Partnership may generate wastes that
may fall within the definition of a hazardous
substance. The Partnership may be responsible under CERCLA
for all or part of the costs required to clean up sites at which
such wastes have been disposed. The Partnership has not received
any notification that it may be potentially responsible for
cleanup costs under CERCLA or any analogous state laws.
The Partnership also generates, and may in the future generate,
both hazardous and nonhazardous solid wastes that are subject to
requirements of the federal Resource Conservation and Recovery
Act, or RCRA, and comparable state statutes. From time to time,
the Environmental Protection Agency, or EPA, has considered the
adoption of stricter disposal standards for nonhazardous wastes,
including crude oil and natural gas wastes. The Partnership is
not currently required to comply with a substantial portion of
the RCRA requirements because its operations generate minimal
quantities of hazardous wastes. However, it is possible that
some wastes generated by it that are currently classified as
nonhazardous may in the future be designated as hazardous
wastes, resulting in the wastes being subject to more
rigorous and costly disposal requirements. Changes in applicable
regulations may result in an increase in the Partnerships
capital expenditures or plant operating expenses.
The Partnership currently owns or leases, and has in the past
owned or leased, and in the future may own or lease, properties
that have been used over the years for natural gas gathering,
treating or processing and for NGL fractionation, transportation
or storage. Solid waste disposal practices within the NGL
industry and other oil and natural gas related industries have
improved over the years with the passage and implementation of
various environmental laws and regulations. Nevertheless, some
hydrocarbons and other solid wastes have been disposed of on or
under various properties owned or leased by the Partnership
during the operating history of those facilities. In addition, a
number of these properties may have been operated by third
parties over whom the Partnership had no control as to such
entities handling of hydrocarbons or other wastes and the
manner in which such substances may have been disposed of or
released. These properties and wastes disposed thereon may be
subject to CERCLA, RCRA, and analogous state laws. Under these
laws, the Partnership could be required to remove or remediate
previously disposed wastes or property contamination, including
groundwater contamination or to perform remedial operations to
prevent future contamination.
The Partnership acquired the South Louisiana Processing Assets
from El Paso in November 2005. One of the acquired locations,
the Cow Island Gas Processing Facility, has a known active
remediation project for benzene contaminated groundwater. The
cause of contamination was attributed to a leaking natural gas
condensate storage tank. The site investigation and active
remediation being conducted at this location is under the
guidance of the Louisiana Department of Environmental Quality
(LDEQ) based on the Risk-Evaluation and Corrective Action Plan
Program (RECAP) rules. In addition, the Partnership is working
with both the LDEQ and the Louisiana State University, Louisiana
Water Resources Research Institute, on the development and
implementation of a new remediation technology that will
drastically reduce the remediation time as well as the costs
associated with such remediation projects. The estimated
remediation costs are expected to be approximately
$0.5 million. Since this remediation project is a result of
previous owners operation and the actual contamination
occurred prior to the Partnerships ownership, these costs
were accrued as part of the purchase price.
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The Partnership acquired LIG Pipeline Company, and its
subsidiaries, on April 1, 2004 from American Electric Power
Company (AEP). Contamination from historical operations was
identified during due diligence at a number of sites owned by
the acquired companies. AEP has indemnified the Partnership for
these identified sites. Moreover, AEP has entered into an
agreement with a third-party company pursuant to which the
remediation costs associated with these sites have been assumed
by this third-party company that specializes in remediation
work. The Partnership does not expect to incur any material
liability in connection with the remediation associated with
these sites.
The Partnership acquired assets from Duke Energy Field Services,
L.P. (DEFS) in June 2003 that have environmental contamination,
including a gas plant in Montgomery County near Conroe, Texas.
At Conroe, contamination from historical operations had been
identified at levels that exceeded the applicable state action
levels. Consequently, site investigation
and/or
remediation are underway to address those impacts. The estimated
remediation cost for the Conroe plant site is currently
estimated to be approximately $3.2 million. Under the
purchase and sale agreement, DEFS retained the liability for
cleanup of the Conroe site. Moreover, DEFS has entered into an
agreement with a third-party company pursuant to which the
remediation costs associated with the Conroe site have been
assumed by this third-party company that specializes in
remediation work. The Partnership does not expect to incur any
material liability in connection with the remediation associated
with this site.
Air Emissions. The Partnerships current
and future operations will likely be, subject to the Clean Air
Act and comparable state statutes. Amendments to the Clean Air
Act were enacted in 1990. Moreover, recent or soon to be adopted
changes to state implementation plans for controlling air
emissions in regional, non-attainment areas require or will
require most industrial operations in the United States to incur
capital expenditures in order to meet air emission control
standards developed by the EPA and state environmental agencies.
As a result of these amendments, the Partnerships
gathering, treating and processing of natural gas, fractionation
and storage of NGLs, or facilities therefor or any of its future
assets that emit volatile organic compounds or nitrogen oxides
may become subject to increasingly stringent regulations,
including requirements that some sources install maximum or
reasonably available control technology. Such requirements, if
applicable to the Partnerships operations, could cause
capital expenditures to be incurred in the next several years
for air pollution control equipment in connection with
maintaining or obtaining governmental approvals addressing air
emission related issues. In addition, the 1990 Clean Air
Act Amendments established a new operating permit for major
sources, which applies to some of the facilities and which may
apply to some of the Partnerships possible future
facilities. Failure to comply with applicable air statutes or
regulations may lead to the assessment of administrative, civil
or criminal penalties, and may result in the limitation or
cessation of construction or operation of certain air emission
sources. Although we can give no assurances, we believe
implementation of the 1990 Clean Air Act Amendments will not
have a material adverse effect on the Partnerships
financial condition or operating results.
Clean Water Act. The Federal Water Pollution
Control Act, also known as the Clean Water Act, and similar
state laws impose restrictions and strict controls regarding the
discharge of pollutants, including natural gas liquid related
wastes, into state waters or waters of the United States.
Regulations promulgated pursuant to these laws require that
entities that discharge into federal and state waters obtain
National Pollutant Discharge Elimination System, or NPDES,
and/or state
permits authorizing these discharges. The Clean Water Act and
analogous state laws assess administrative, civil and criminal
penalties for discharges of unauthorized pollutants into the
water and impose substantial liability for the costs of removing
spills from such waters. In addition, the Clean Water Act and
analogous state laws require that individual permits or coverage
under general permits be obtained by covered facilities for
discharges of storm water runoff. The Partnership believes that
it is in substantial compliance with Clean Water Act permitting
requirements as well as the conditions imposed thereunder, and
that continued compliance with such existing permit conditions
will not have a material effect on its results of operations.
Employee Safety. The Partnership is subject to
the requirements of the Occupational Safety and Health Act,
referred to as OSHA, and comparable state laws that regulate the
protection of the health and safety of workers. In addition, the
OSHA hazard communication standard requires that information be
maintained about hazardous materials used or produced in
operations and that this information be provided to employees,
state and local government authorities and citizens. The
Partnership believes that its operations are in substantial
compliance with the OSHA requirements, including general
industry standards, record keeping requirements, and monitoring
of occupational exposure to regulated substances.
15
Safety Regulations. The Partnerships
pipelines are subject to regulation by the U.S. Department
of Transportation under the Hazardous Liquid Pipeline Safety
Act, as amended, or HLPSA, and the Pipeline Integrity Management
in High Consequence Areas (Gas Transmission Pipelines) amendment
to 49 CFR Part 192, effective February 14, 2004
relating to the design, installation, testing, construction,
operation, replacement and management of pipeline facilities.
The HLPSA covers crude oil, carbon dioxide, NGL and petroleum
products pipelines and requires any entity which owns or
operates pipeline facilities to comply with the regulations
under the HLPSA, to permit access to and allow copying of
records and to make certain reports and provide information as
required by the Secretary of Transportation. The Pipeline
Integrity Management in High Consequence Areas (Gas Transmission
Pipelines) amendment to 49 CFR Part 192 (PIM) requires
operators of gas transmission pipelines to ensure the integrity
of their pipelines through hydrostatic pressure testing, the use
of in-line inspection tools or through risk-based direct
assessment techniques. In addition, the TRRC regulates the
Partnerships pipelines in Texas under its own pipeline
integrity management rules. The Texas rule includes certain
transmission and gathering lines based upon pipeline diameter
and operating pressures. The Partnership believes that its
pipeline operations are in substantial compliance with
applicable HLPSA and PIM requirements; however, due to the
possibility of new or amended laws and regulations or
reinterpretation of existing laws and regulations, there can be
no assurance that future compliance with the HLPSA or PIM
requirements will not have a material adverse effect on its
results of operations or financial positions.
Office
Facilities
In addition to the Partnerships gathering and treating
facilities discussed above, the Partnership occupies
approximately 95,400 square feet of space at its executive
offices in Dallas, Texas under a lease expiring in June 2014 and
approximately 16,000 square feet of office space for the
Partnerships south Louisiana operations in Houston, Texas
with lease terms expiring in January 2013.
Employees
As of December 31, 2006, the Partnership (through its
subsidiaries) employed approximately 610 full-time
employees. Approximately 287 of the employees were general and
administrative, engineering, accounting and commercial personnel
and the remainder were operational employees. The Partnership is
not party to any collective bargaining agreements, and has not
had any significant labor disputes in the past. We believe that
the Partnership has good relations with its employees.
The following risk factors and all other information
contained in this report should be considered carefully when
evaluating us. These risk factors could affect our actual
results. Other risks and uncertainties, in addition to those
that are described below, may also impair our business
operations. If any of the following risks occurs, our business,
financial condition or results of operations could be affected
materially and adversely. In that case, we may be unable to pay
dividends to our shareholders and the trading price of our
common shares could decline. These risk factors should be read
in conjunction with the other detailed information concerning us
set forth in our accompanying financial statements and notes and
contained in Item 7. Managements Discussion and
Analysis of Financial Condition and Results of Operations
included herein.
Our
cash flow consists almost exclusively of distributions from
Crosstex Energy, L.P.
Our only cash-generating assets are our partnership interests in
Crosstex Energy, L.P. Our cash flow is therefore completely
dependent upon the ability of the Partnership to make
distributions to its partners. The amount of cash that the
Partnership can distribute to its partners, including us, each
quarter principally depends upon the amount of cash it generates
from its operations, which will fluctuate from quarter to
quarter based on, among other things:
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the amount of natural gas transported in its gathering and
transmission pipelines;
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the level of the Partnerships processing and treating
operations;
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the fees the Partnership charges and the margins it realizes for
its services;
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the price of natural gas;
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the relationship between natural gas and NGL prices; and
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its level of operating costs.
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In addition, the actual amount of cash the Partnership will have
available for distribution will depend on other factors, some of
which are beyond its control, including:
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the level of capital expenditures the Partnership makes;
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the cost of acquisitions, if any;
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its debt service requirements;
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fluctuations in its working capital needs;
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restrictions on distributions contained in its bank credit
facility;
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its ability to make working capital borrowings under its bank
credit facility to pay distributions;
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prevailing economic conditions; and
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the amount of cash reserves established by the general partner
in its sole discretion for the proper conduct of its business.
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We are
largely prohibited from engaging in activities that compete with
the Partnership.
So long as we own the general partner of the Partnership, we are
prohibited by an omnibus agreement with the Partnership from
engaging in the business of gathering, transmitting, treating,
processing, storing and marketing natural gas and transporting,
fractionating, storing and marketing NGLs, except to the extent
that the Partnership, with the concurrence of its independent
directors comprising its conflicts committee, elects not to
engage in a particular acquisition or expansion opportunity.
This exception for competitive activities is relatively limited.
Although we have no current intention of pursuing the types of
opportunities that we are permitted to pursue under the omnibus
agreement such as competitive opportunities that the Partnership
declines to pursue or permitted activities that are not
competition with the Partnership, the provisions of the omnibus
agreement may, in the future, limit activities that we would
otherwise pursue.
In our
corporate charter, we have renounced business opportunities that
may be pursued by the Partnership or by affiliated stockholders
that hold a majority of our common stock.
In our restated charter and in accordance with Delaware law, we
have renounced any interest or expectancy we may have in, or
being offered an opportunity to participate in, any business
opportunities, including any opportunities within those classes
of opportunity currently pursued by the Partnership, presented
to:
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persons who are officers or directors of the company or who, on
October 1, 2003, were, and at the time of presentation are,
stockholders of the company (or to persons who are affiliates or
associates of such officers, directors or stockholders), if the
company is prohibited from participating in such opportunities
by the omnibus agreement; or
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two affiliated stockholders with an interest in our company,
Yorktown Energy Partners IV, L.P. and Yorktown Energy
Partners V, L.P., or any other investment fund sponsored or
managed by Yorktown Partners LLC, including any fund still to be
formed, or to any of our directors who is an affiliate or
designate of these entities.
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As a result of this renunciation, these officers, directors and
stockholders should not be deemed to be breaching any fiduciary
duty to us if they or their affiliates or associates pursue
opportunities presented as described above.
17
A
significant portion of our partnership interests in the
Partnership are subordinated to the common units.
We own 16,414,830 units representing limited partner
interests in the Partnership, of which 4,668,000 are
subordinated units, 6,414,830 are senior subordinated
series C units and 5,332,000 are common units. The senior
subordinated series C units will automatically convert into
common units on the first date on or after February 16,
2008 that conversion is permitted by the Partnerships
partnership agreement. Generally, the senior subordinated
series C units will not be entitled to participate in the
Partnerships distributions of available cash until
February 16, 2008. During the subordination period, the
subordinated units will not receive any distributions in a
quarter until the Partnership has paid the minimum quarterly
distribution of $0.25 per unit, plus any arrearages in the
payment of the minimum quarterly distribution from prior
quarters, on all of the outstanding common units. Distributions
on the subordinated units are therefore more uncertain than
distribution on the common units. Furthermore, no distributions
may be made on the incentive distribution rights until the
minimum quarterly distribution has been paid on all outstanding
units. Therefore, distributions with respect to the incentive
distribution rights are even more uncertain than distributions
on the subordinated units. Neither the subordinated units nor
the incentive distribution rights are entitled to any arrearages
from prior quarters.
Generally, the subordination period ends, and the subordinated
units convert to common units, only after December 31, 2007
and only upon the satisfaction of certain financial tests.
Although
we control the Partnership, the general partner owes fiduciary
duties to the Partnership and the unitholders.
Conflicts of interest exist and may arise in the future as a
result of the relationship between us and our affiliates,
including the general partner, on the one hand, and the
Partnership and its limited partners, on the other hand. The
directors and officers of Crosstex Energy GP, LLC have fiduciary
duties to manage the general partner in a manner beneficial to
us, its owner. At the same time, the general partner has a
fiduciary duty to manage the Partnership in a manner beneficial
to the Partnership and its limited partners. The board of
directors of Crosstex Energy GP, LLC will resolve any such
conflict and has broad latitude to consider the interests of all
parties to the conflict. The resolution of these conflicts may
not always be in our best interest or that of our stockholders.
For example, conflicts of interest may arise in the following
situations:
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the allocation of shared overhead expenses to the Partnership
and us;
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the interpretation and enforcement of contractual obligations
between us and our affiliates, on the one hand, and the
Partnership, on the other hand, including obligations under the
omnibus agreement;
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the determination of the amount of cash to be distributed to the
Partnerships partners and the amount of cash to be
reserved for the future conduct of the Partnerships
business;
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the determination whether to make borrowings under the capital
facility to pay distributions to partners; and
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any decision we make in the future to engage in activities in
competition with the Partnership as permitted under our omnibus
agreement with the Partnership.
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If the
general partner is not fully reimbursed or indemnified for
obligations and liabilities it incurs in managing the business
and affairs of the Partnership, its value, and therefore the
value of our common stock, could decline.
The general partner may make expenditures on behalf of the
Partnership for which it will seek reimbursement from the
Partnership. In addition, under Delaware partnership law, the
general partner, in its capacity as the general partner of the
Partnership, has unlimited liability for the obligations of the
Partnership, such as its debts and environmental liabilities,
except for those contractual obligations of the Partnership that
are expressly made without recourse to the general partner. To
the extent the general partner incurs obligations on behalf of
the Partnership, it is entitled to be reimbursed or indemnified
by the general partner. In the event that the Partnership is
unable or unwilling to reimburse or indemnify the general
partner, the general partner may be unable to satisfy these
liabilities or obligations, which would reduce its value and
therefore the value of our common stock.
18
Acquisitions
in the Partnership typically increase debt and subject it to
other substantial risks, which could adversely affect results of
operations.
The Partnerships future financial performance will depend,
in part, on its ability to make acquisitions of assets and
businesses at attractive prices. From time to time, the
Partnership will evaluate and seek to acquire assets or
businesses that it believes complements existing business and
related assets. The Partnership may acquire assets or businesses
that it plans to use in a manner materially different from their
prior owners use. Any acquisition involves potential
risks, including:
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the inability to integrate the operations of acquired businesses
or assets;
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the diversion of managements attention from other business
concerns;
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the loss of customers or key employees from the acquired
businesses;
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a significant increase in the Partnerships
indebtedness; and
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potential environmental or regulatory liabilities and title
problems.
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Managements assessment of these risks is necessarily
inexact and may not reveal or resolve all existing or potential
problems associated with an acquisition. Realization of any of
these risks could adversely affect the Partnerships
operations and cash flows. If the Partnership consummates any
future acquisition, its capitalization and results of operations
may change significantly, and you will not have the opportunity
to evaluate the economic, financial and other relevant
information that the Partnership will consider in determining
the application of these funds and other resources.
The Partnership continues to consider large acquisition
candidates and transactions. The integration, financial and
other risks discussed above will be amplified if the size of its
future acquisitions increases.
The Partnerships acquisition strategy is based, in part,
on expectation of ongoing divestitures of gas processing and
transportation assets by large industry participants. A material
decrease in such divestitures will limit opportunities for
future acquisitions and could adversely affect the
Partnerships growth plans.
If the
Partnerships assumptions used in making the acquisition of
the Barnett Shale systems and facilities from Chief Holdings LLC
are inaccurate, its future financial performance may be
limited.
The Partnership acquired certain natural gas gathering pipeline
systems and related facilities in the Barnett Shale from Chief
Holdings LLC in June 2006. This acquisition was made based on
the Partnerships understanding of future drilling plans by
Devon Energy Corporation, which acquired Chiefs producing
assets and acreage previously owned by Chief that is dedicated
to the acquired systems. In addition, the Partnership assumed in
its analysis the continued drilling success by other producers
that own acreage dedicated to those systems, production success
on acreage not dedicated to the system and that it will be able
to tie a certain portion of that new production into the
systems. Production currently flowing through the systems is
very small relative to the quantities the Partnership has
assumed will be developed in the next few years. If its
assumptions are inaccurate, the drilling plans of the producers
are delayed, the producers are not successful in completing
their wells or the Partnership is not successful in its
commercial efforts to tie in gas from undedicated acreage, then
its anticipated results from the acquisition from Chief of these
assets could be significantly negatively impacted. In addition,
the failure to successfully integrate these assets with the
Partnerships existing business and operations in a timely
manner may have a material adverse effect on its business,
financial condition, results of operations and cash flows.
The
Partnership is vulnerable to operational, regulatory and other
risks associated with south Louisiana and the Gulf of Mexico,
including the effects of adverse weather conditions such as
hurricanes, because a significant portion of its assets are
located in south Louisiana.
Operations and revenues will be significantly impacted by
conditions in south Louisiana because the Partnership has a
significant portion of its assets located in south Louisiana.
This concentration of activity makes
19
the Partnership more vulnerable than many of its competitors to
the risks associated with Louisiana and the Gulf of Mexico,
including:
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adverse weather conditions, including hurricanes and tropical
storms;
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delays or decreases in production, the availability of
equipment, facilities or services; and
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changes in the regulatory environment.
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Because a significant portion of the Partnerships
operations could experience the same condition at the same time,
these conditions could have a relatively greater impact on
results of operations than they might have on other midstream
companies who have operations in a more diversified geographic
area.
In addition, the Partnerships operations in south
Louisiana are dependent upon continued conventional and deep
shelf drilling in the Gulf of Mexico. The deep shelf in the Gulf
of Mexico is an area that has had limited historical drilling
activity. This is due, in part, to its geological complexity and
depth. Deep shelf development is more expensive and inherently
more risky than conventional shelf drilling. A decline in the
level of deep shelf drilling in the Gulf of Mexico could have an
adverse effect on the Partnerships financial condition and
results of operations.
The
Partnerships profitability is dependent upon prices and
market demand for natural gas and NGLs, which are beyond its
control and have been volatile.
The Partnership is subject to significant risks due to
fluctuations in commodity prices. These risks are based upon
three components of business: (1) it purchases certain
volumes of natural gas at a price that is a percentage of a
relevant index; (2) certain processing contracts for its
Gregory system and its Plaquemine and Gibson processing plants
expose the Partnership to natural gas and NGL commodity price
risks; and (3) part of its fees from the Conroe and
Seminole gas plants as well as those acquired in the
El Paso acquisition are based on a portion of the NGLs
produced, and, therefore, is subject to commodity price risks.
The margins the Partnership realizes from purchasing and selling
a portion of the natural gas that it transports through its
pipeline systems decrease in periods of low natural gas prices
because gross margins related to such purchases are based on a
percentage of the index price. For the years ended
December 31, 2005 and 2006, the Partnership purchased
approximately 7.5% and 5.9%, respectively, of its gas at a
percentage of relevant index. Accordingly, a decline in the
price of natural gas could have an adverse impact on its results
of operations.
A portion of the Partnerships profitability is affected by
the relationship between natural gas and NGL prices. For a
component of the Gregory system and the Plaquemine plant and
Gibson plant volumes, natural gas is purchased, processed and
NGLs are extracted, and then the processed natural gas and NGLs
are sold. A portion of profits from the plants acquired in the
El Paso acquisition is dependent on NGL prices and elections by
the Partnership and the producers. In cases where the
Partnership processes gas for producers when they have the
ability to decide whether to process their gas, it may elect to
receive a processing fee or it may retain and sell the NGLs and
keep the producer whole on its sale of natural gas. Since the
Partnership extracts energy content, which is measured in
Btus, from the gas stream in the form of the liquids or
consume it as fuel during processing, the Partnership reduces
the Btu content of the natural gas. Accordingly, margins under
these arrangements can be negatively affected in periods in
which the value of natural gas is high relative to the value of
NGLs.
In the past, the prices of natural gas and NGLs have been
extremely volatile and this volatility is expected to continue.
For example, in 2005, the NYMEX settlement price for natural gas
for the prompt month contract ranged from a high of
$13.91 per MMBtu to a low of $6.12 per MMBtu. In 2006,
the same index ranged from $11.43 per MMBtu to
$4.20 per MMBtu. A composite of the OPIS Mt. Belvieu
monthly average liquids price based upon our average liquids
composition in 2005 ranged from a high of approximately
$1.16 per gallon to a low of approximately $0.80 per
gallon. In 2006, the same composite ranged from approximately
$1.20 per gallon to approximately $0.90 per gallon.
The Partnership may not be successful in balancing purchases and
sales. In addition, a producer could fail to deliver contracted
volumes or deliver in excess of contracted volumes, or a
consumer could purchase less than contracted volumes. Any of
these actions could cause purchases and sales not to be
balanced. If purchases and sales
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are not balanced, the Partnership will face increased exposure
to commodity price risks and could have increased volatility in
operating income.
The markets and prices for residue gas and NGLs depend upon
factors beyond the Partnerships 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 level of domestic industrial and manufacturing activity;
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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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The
Partnership must continually compete for natural gas supplies,
and any decrease in its supplies of natural gas could adversely
affect its financial condition and results of
operations.
If the Partnership is unable to maintain or increase the
throughput on its systems by accessing new natural gas supplies
to offset the natural decline in reserves, business and
financial results could be materially, adversely affected. In
addition, the Partnerships future growth will depend, in
part, upon whether it can contract for additional supplies at a
greater rate than the rate of natural decline in currently
connected supplies.
In order to maintain or increase throughput levels in the
Partnerships natural gas gathering systems and asset
utilization rates at its treating and processing plants, it must
continually contract for new natural gas supplies. The
Partnership may not be able to obtain additional contracts for
natural gas supplies. The primary factors affecting its ability
to connect new wells to its gathering facilities include success
in contracting for existing natural gas supplies that are not
committed to other systems and the level of drilling activity
near its gathering systems. Fluctuations in energy prices can
greatly affect production rates and investments by third parties
in the development of new oil and natural gas reserves. Drilling
activity generally decreases as oil and natural gas prices
decrease. Tax policy changes could have a negative impact on
drilling activity, reducing supplies of natural gas available to
the Partnerships systems. The Partnership has no control
over producers and depends on them to maintain sufficient levels
of drilling activity. A material decrease in natural gas
production or in the level of drilling activity in its principal
geographic areas for a prolonged period, as a result of
depressed commodity prices or otherwise, likely would have a
material adverse effect on the Partnerships results of
operations and financial position.
A
substantial portion of the Partnerships assets are
connected to natural gas reserves that will decline over time,
and the cash flows associated with those assets will decline
accordingly.
A substantial portion of the Partnerships assets,
including gathering systems and treating plants, is dedicated to
certain natural gas reserves and wells for which the production
will naturally decline over time. Accordingly, cash flows
associated with these assets will also decline. If the
Partnership is unable to access new supplies of natural gas
either by connecting additional reserves to existing assets or
by constructing or acquiring new assets that have access to
additional natural gas reserves, cash flows may decline.
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Growing
the Partnerships business by constructing new pipelines
and processing and treating facilities subjects the Partnership
to construction risks, risks that natural gas supplies will not
be available upon completion of the facilities and risks of
construction delay and additional costs due to obtaining
rights-of-way.
One of the ways the Partnership intends to grow business is
through the construction of or additions to existing gathering
systems and construction of new pipelines and gathering,
processing and treating facilities. The construction of
pipelines and gathering, processing and treating facilities
requires the expenditure of significant amounts of capital,
which may exceed the Partnerships expectations. Generally,
the Partnership may have only limited natural gas supplies
committed to these facilities prior to their construction.
Moreover, the Partnership may construct facilities to capture
anticipated future growth in production in a region in which
anticipated production growth does not materialize. The
Partnership may also rely on estimates of proved reserves in the
decision to construct new pipelines and facilities, which may
prove to be inaccurate because there are numerous uncertainties
inherent in estimating quantities of proved reserves. As a
result, new facilities may not be able to attract enough natural
gas to achieve the expected investment return, which could
adversely affect its results of operations and financial
condition. In addition, the Partnership faces the risks of
construction delay and additional costs due to obtaining
rights-of-way.
The
Partnership has limited control over the development of certain
assets because it is not the operator.
As the owner of non-operating interests in the Seminole gas
processing plant, the Partnership does not have the right to
direct or control the operation of the plants. As a result, the
success of the activities conducted at this plant, which is
operated by a third party, may be affected by factors outside of
the Partnerships control. The failure of the third-party
operator to make decisions, perform its services, discharge its
obligations, deal with regulatory agencies or comply with laws,
rules and regulations affecting these plants, including
environmental laws and regulations, in a proper manner could
result in material adverse consequences to the
Partnerships interest and adversely affect the
Partnerships results of operations.
The
Partnership expects to encounter significant competition in any
new geographic areas into which it seeks to expand and the
ability to enter such markets may be limited.
As the Partnership expands operations into new geographic areas,
it expects to encounter significant competition for natural gas
supplies and markets. Competitors in these new markets will
include companies larger than the Partnership, which have both
lower capital costs and greater geographic coverage, as well as
smaller companies, which have lower total cost structures. As a
result, the Partnership may not be able to successfully develop
acquired assets and markets located in new geographic areas and
the Partnerships results of operations could be adversely
affected.
The
Partnership is exposed to the credit risk of customers and
counterparties, and a general increase in the nonpayment and
nonperformance by its customers could have an adverse effect on
its financial condition and results of operations.
Risks of nonpayment and nonperformance by the Partnerships
customers is a major concern in its business. The Partnership is
subject to risks of loss resulting from nonpayment or
nonperformance by its customers. Any increase in the nonpayment
and nonperformance by its customers could adversely affect
results of the Partnerships operations.
The
Partnership may not be able to retain existing customers or
acquire new customers, which would reduce revenues and limit
future profitability.
The renewal or replacement of existing contracts with customers
at rates sufficient to maintain current revenues and cash flows
depends on a number of factors beyond the Partnerships
control, including competition from other pipelines, and the
price of, and demand for, natural gas in the markets it serves.
For the year ended December 31, 2006, approximately 71% of
the Partnerships sales of gas which were transported using
its physical facilities were to industrial end-users and
utilities. As a consequence of the increase in
22
competition in the industry and volatility of natural gas
prices, end-users and utilities are reluctant to enter into
long-term purchase contracts. Many end-users purchase natural
gas from more than one natural gas company and have the ability
to change providers at any time. Some of these end-users also
have the ability to switch between gas and alternate fuels in
response to relative price fluctuations in the market. Because
there are numerous companies of greatly varying size and
financial capacity that compete with the Partnership in the
marketing of natural gas, the Partnership often competes in the
end-user and utilities markets primarily on the basis of price.
The inability of the Partnerships management to renew or
replace current contracts as they expire and to respond
appropriately to changing market conditions could have a
negative effect on its profitability.
The
Partnership depends on certain key customers, and the loss of
any of its key customers could adversely affect its financial
results.
The Partnership derives a significant portion of its revenues
from contracts with key customers. To the extent that these and
other customers may reduce volumes of natural gas purchased
under existing contracts, the Partnership would be adversely
affected unless it was able to make comparably profitable
arrangements with other customers. Agreements with key customers
provide for minimum volumes of natural gas that each customer
must purchase until the expiration of the term of the applicable
agreement, subject to certain force majeure provisions.
Customers may default on their obligations to purchase the
minimum volumes required under the applicable agreements.
The
Partnerships business involves many hazards and
operational risks, some of which may not be fully covered by
insurance.
The Partnerships operations are subject to the many
hazards inherent in the gathering, compressing, treating and
processing of natural gas and storage of residue gas, including:
|
|
|
|
|
damage to pipelines, related equipment and surrounding
properties caused by hurricanes, floods, fires and other natural
disasters and acts of terrorism;
|
|
|
|
inadvertent damage from construction and farm equipment;
|
|
|
|
leaks of natural gas, NGLs and other hydrocarbons; and
|
|
|
|
fires and explosions.
|
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 the Partnerships
related operations. The Partnerships operations are
concentrated in Texas, Louisiana and the Mississippi Gulf Coast,
and a natural disaster or other hazard affecting this region
could have a material adverse effect on its operations. The
Partnership is not fully insured against all risks incident to
its business. In accordance with typical industry practice, the
Partnership does not have any property insurance on any of its
underground pipeline systems that would cover damage to the
pipelines. It is not insured against all environmental accidents
that might occur, other than those considered to be sudden and
accidental. Business interruption insurance covers only the
Gregory processing plant. If a significant accident or event
occurs that is not fully insured, it could adversely affect
operations and financial condition.
The
threat of terrorist attacks has resulted in increased costs, and
future war or risk of war may adversely impact the
Partnerships results of operations and its ability to
raise capital.
Terrorist attacks or the threat of terrorist attacks cause
instability in the global financial markets and other
industries, including the energy industry. Uncertainty
surrounding retaliatory military strikes or a sustained military
campaign may affect the Partnerships operations in
unpredictable ways, including disruptions of fuel supplies and
markets, and the possibility that infrastructure facilities,
including pipelines, production facilities, and transmission and
distribution facilities, could be direct targets, or indirect
casualties, of an act of terror. Instability in the financial
markets as a result of terrorism, the war in Iraq or future
developments could also affect the Partnerships ability to
raise capital.
23
Changes in the insurance markets attributable to the threat of
terrorist attacks have made certain types of insurance more
difficult for the Partnership to obtain. The Partnerships
insurance policies now generally exclude acts of terrorism. Such
insurance is not available at what the Partnership considers to
be acceptable pricing levels. A lower level of economic activity
could also result in a decline in energy consumption, which
could adversely affect revenues or restrict future growth.
Federal,
state or local regulatory measures could adversely affect the
Partnerships business.
While FERC generally does not regulate any of the
Partnerships operations, FERC influences certain aspects
of its business and the market for its products. The rates,
terms and conditions of service under which the Partnership
transports natural gas on its pipeline systems in interstate
commerce are subject to FERC regulation under Section 311
of the NGPA. The Partnerships intrastate natural gas
pipeline operations generally are not subject to rate regulation
by FERC, but they are subject to regulation by various agencies
of the states in which they are located. Should FERC or any of
these state agencies determine that our rates for
Section 311 transportation service or intrastate
transportation service should be lowered, its business could be
adversely affected.
The Partnerships gas gathering activities generally are
exempt from FERC regulation and NGA. 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 the
Partnerships gathering facilities are subject to change
based on future determinations by FERC and the courts. Natural
gas gathering may receive greater regulatory scrutiny at both
the state and federal levels since FERC has less extensively
regulated the gathering activities of interstate pipeline
transmission companies and a number of such companies have
transferred gathering facilities to unregulated affiliates. The
Partnerships 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 the Partnerships
operations, but the industry could be required to incur
additional capital expenditures and increased costs depending on
future legislative and regulatory changes.
Other state and local regulations also affect the
Partnerships business. It is subject to ratable take and
common purchaser statutes in the states where it operates.
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 have the effect of restricting the
Partnerships right as an owner of gathering facilities to
decide with whom it contracts to purchase or transport natural
gas. Federal law leaves any economic regulation of natural gas
gathering to the states, and some of the states in which it
operates have adopted complaint-based or other limited economic
regulation of natural gas gathering activities. States in which
the Partnership operates that have adopted some form of
complaint-based regulation, like Oklahoma and Texas, generally
allow 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.
The states in which the Partnership conducts operations
administer 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 substantial portions of the Partnerships 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, and it does not apply
to the Partnerships natural gas transmission pipelines. In
response 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.
Compliance with pipeline integrity regulations issued by the
TRRC, or those issued by the United States Department of
Transportation in December of 2003 could result in substantial
expenditures for testing, repairs and replacement. TRRC
regulations require periodic testing of all intrastate pipelines
meeting certain size and location requirements. the
Partnerships costs relating to compliance with the
required testing under the TRRC regulations were approximately
$1.1 million, $0.3 million and $1.9 million for
the years ended December 31, 2006, 2005 and
24
2004, respectively, and it expects the costs for compliance with
TRRC and DOT regulations to be $5.6 million during 2007. If
the Partnerships pipelines fail to meet the safety
standards mandated by the TRRC or the DOT regulations, then the
Partnership may be required to repair or replace sections of
such pipelines, the cost of which cannot be estimated at this
time.
The
Partnerships business involves hazardous substances and
may be adversely affected by environmental
regulation.
Many of the operations and activities of the Partnerships
gathering systems, plants and other facilities, including the
natural gas and processing liquids business in South Louisiana
recently acquired from El Paso, are subject to significant
federal, state and local environmental laws and regulations.
These laws and regulations impose obligations related to air
emissions and discharge of pollutants from the
Partnerships facilities and the cleanup of hazardous
substances and other wastes that may have been released at
properties currently or previously owned or operated by the
Partnership or locations to which it has sent wastes for
treatment or disposal. Various governmental authorities have the
power to enforce compliance with these regulations and the
permits issued under them, and violators are subject to
administrative, civil and criminal penalties, including civil
fines, injunctions or both. Strict, joint and several liability
may be incurred under these laws and regulations for the
remediation of contaminated areas. Private parties, including
the owners of properties through which the Partnerships
gathering systems pass, 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.
There is inherent risk of the incurrence of significant
environmental costs and liabilities in the Partnerships
business due to its handling of natural gas and other petroleum
products, air emissions related to the Partnerships
operations, historical industry operations, waste disposal
practices and the prior use of natural gas flow meters
containing mercury. In addition, the possibility exists that
stricter laws, regulations or enforcement policies could
significantly increase the Partnerships compliance costs
and the cost of any remediation that may become necessary. The
Partnership may incur material environmental costs and
liabilities. Furthermore, insurance may not provide sufficient
coverage in the event an environmental claim is made against the
Partnership.
The Partnerships business may be adversely affected by
increased costs due to stricter pollution control requirements
or liabilities resulting from non-compliance with required
operating or other regulatory permits. New environmental
regulations might adversely affect the Partnerships
products and activities, including processing, storage and
transportation, as well as waste management and air emissions.
Federal and state agencies could also impose additional safety
requirements, any of which could affect the Partnerships
profitability.
The
use of derivative financial instruments has in the past and
could in the future result in financial losses or reduce
income.
The Partnership uses
over-the-counter
price and basis swaps with other natural gas merchants and
financial institutions, and it uses futures and option contracts
traded on the New York Mercantile Exchange. Use of these
instruments is intended to reduce exposure to short-term
volatility in commodity prices. The Partnership could incur
financial losses or fail to recognize the full value of a market
opportunity as a result of volatility in the market values of
the underlying commodities or if one of its counterparties fails
to perform under a contract.
Due to
the Partnerships lack of asset diversification, adverse
developments in gathering, transmission, treating, processing
and commercial services businesses would materially impact its
financial condition.
The Partnership relies exclusively on the revenues generated
from our gathering, transmission, treating, processing and
commercial services businesses, and as a result its financial
condition depends upon prices of, and continued demand for,
natural gas and NGLs. Due to its lack of asset diversification,
an adverse development in one of these businesses would have a
significantly greater impact on financial condition and results
of operations than if it maintained more diverse assets.
25
The
Partnerships success depends on key members of management,
the loss or replacement of whom could disrupt its business
operations.
The Partnership depends on the continued employment and
performance of the officers of Crosstex Energy GP, LLC
and key operational personnel. Crosstex Energy GP, LLC enters
into employment agreements with each of its executive officers.
If any of these officers or other key personnel resign or become
unable to continue in their present roles and are not adequately
replaced, the Partnerships business operations could be
materially adversely affected. The Partnership does not maintain
any key man life insurance for any officers.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
We do not have any unresolved staff comments.
A description of the Partnerships properties is contained
in Item 1. Business.
Title to
Properties
Substantially all of the Partnerships 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 not
been subordinated to the
right-of-way
grants. The Partnership has obtained, where necessary, easement
agreements from public authorities and railroad companies to
cross over or under, or to lay facilities in or along,
watercourses, county roads, municipal streets, railroad
properties and state highways, as applicable. In some cases,
property on which the Partnerships pipeline was built was
purchased in fee. The Partnerships processing plants are
located on land that it leases or owns in fee. Their treating
facilities are generally located on sites provided by producers
or other parties.
We believe that the Partnership has satisfactory title to all of
its rights of way and land assets. Title to these assets may be
subject to encumbrances or defects. We believe that none of such
encumbrances or defects should materially detract from the value
of the Partnerships assets or from the Partnerships
interest in these assets or should materially interfere with
their use in the operation of the business.
|
|
Item 3.
|
Legal
Proceedings
|
Our operations and those of the Partnership are subject to a
variety of risks and disputes normally incident to our business.
As a result, at any given time we or the Partnership may be a
defendant in various legal proceedings and litigation arising in
the ordinary course of business. These include litigation on
disputes related to contracts, property rights, use or damage
and personal injury. We do not believe that any pending or
threatened claim or dispute is material to our financial results
or our operations. We maintain insurance policies with insurers
in amounts and with coverage and deductibles as we believe are
reasonable and prudent. However, this insurance may not 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.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
We held a special meeting of stockholders on October 26,
2006. At the meeting, the following proposals were approved by
the margins indicated below:
1. To amend the Companys Restated Certificate of
Incorporation (a) to increase our authorized capital stock
from 20,000,000 shares, consisting of
19,000,000 shares of common stock and 1,000,000 shares
of preferred stock, to 150,000,000 shares, consisting of
140,000,000 shares of common stock and
10,000,000 shares of preferred stock, and (b) to
clarify the liquidation provision applicable to our common stock.
26
|
|
|
|
|
For
|
|
|
9,221,442
|
|
Against
|
|
|
2,287,524
|
|
Abstain
|
|
|
15,564
|
|
Broker Non-Votes
|
|
|
0
|
|
2. To approve the Crosstex Energy, Inc. Long-Term Incentive
Plan (including the increase in the number of shares available
for issuance thereunder).
|
|
|
|
|
For
|
|
|
9,284,243
|
|
Against
|
|
|
2,156,983
|
|
Abstain
|
|
|
83,302
|
|
Broker Non-Votes
|
|
|
0
|
|
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
|
Our common stock is listed on the NASDAQ Global Select Market
under the symbol XTXI. Our common stock began
trading on January 12, 2004. On February 16, 2007, the
market price for our common stock was $31.33 per share and
there were approximately 12,200 record holders and beneficial
owners (held in street name) of the shares of our common stock.
The following table shows the high and low closing sales prices
per share, as reported by the NASDAQ Global Select Market, for
the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
|
|
|
|
Price Range(a)
|
|
|
Cash Dividends
|
|
|
|
High
|
|
|
Low
|
|
|
Paid per Share
|
|
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended December 31
|
|
$
|
33.00
|
|
|
$
|
28.28
|
|
|
$
|
0.220
|
|
Quarter Ended September 30
|
|
|
33.44
|
|
|
|
27.33
|
|
|
|
0.213
|
|
Quarter Ended June 30
|
|
|
32.00
|
|
|
|
23.83
|
|
|
|
0.207
|
|
Quarter Ended March 31
|
|
|
27.87
|
|
|
|
21.07
|
|
|
|
0.200
|
|
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended December 31
|
|
$
|
23.14
|
|
|
$
|
18.86
|
|
|
$
|
0.187
|
|
Quarter Ended September 30
|
|
|
22.35
|
|
|
|
16.02
|
|
|
|
0.153
|
|
Quarter Ended June 30
|
|
|
16.20
|
|
|
|
14.28
|
|
|
|
0.143
|
|
Quarter Ended March 31
|
|
|
14.72
|
|
|
|
13.22
|
|
|
|
0.137
|
|
|
|
|
(a) |
|
Share prices and cash dividends per share have been adjusted for
the
three-for-one
stock split on December 15, 2006. |
We intend to continue to pay to our stockholders, on a quarterly
basis, dividends equal to the cash we receive from our
Partnership distributions, less reserves for expenses, future
dividends and other uses of cash, including:
|
|
|
|
|
federal income taxes, which we are required to pay because we
are taxed as a corporation;
|
|
|
|
the expenses of being a public company;
|
|
|
|
other general and administrative expenses;
|
|
|
|
capital contributions to the Partnership upon the issuance by it
of additional partnership securities in order to maintain the
general partners 2.0% general partner interest; and
|
27
|
|
|
|
|
reserves our board of directors believes prudent to maintain.
|
If the Partnership continues to be successful in implementing
its business strategy and increasing distributions to its
partners, we would expect to continue to increase dividends to
our stockholders, although the timing and amount of any such
increased dividends will not necessarily be comparable to the
increased Partnership distributions.
The determination of the amount of cash dividends, including the
quarterly dividend referred to above, if any, to be declared and
paid will depend upon our financial condition, results of
operations, cash flow, the level of our capital expenditures,
future business prospects and any other matters that our board
of directors deems relevant. The Partnerships debt
agreements contain restrictions on the payment of distributions
and prohibit the payment of distributions if the Partnership is
in default. If the Partnership cannot make incentive
distributions to the general partner or limited partner
distributions to us, we will be unable to pay dividends on our
common stock.
Equity
Compensation Plan Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities
|
|
|
|
Number of Securities
|
|
|
|
|
|
Remaining Available for
|
|
|
|
to be Issued Upon
|
|
|
Weighted-Average
|
|
|
Future Issuance Under Equity
|
|
|
|
Exercise of Outstanding
|
|
|
Price of Outstanding
|
|
|
Compensation Plans
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
(Excluding Securities
|
|
Plan Category
|
|
and Rights
|
|
|
and Rights
|
|
|
Reflected In Column(a))
|
|
|
|
(a)
|
|
|
(b)
|
|
|
(c)
|
|
|
Equity Compensation Plans Approved
By Security Holders(1)
|
|
|
871,749(2
|
)
|
|
$
|
8.21(3
|
)
|
|
|
1,123,215
|
|
Equity Compensation Plans Not
Approved By Security Holders
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
(1) |
|
Our long-term incentive plan for our officers, employees and
directors was approved by our security holders in October 2006. |
|
(2) |
|
The number of securities includes 751,749 restricted shares that
have been granted under our long-term incentive plan that have
not vested. |
|
(3) |
|
The exercise prices for outstanding options under the plan as of
December 31, 2006 range from $6.50 to $13.33 per share. |
28
Performance
Graph
The following graph sets forth the cumulative total stockholder
return for our Common Stock, the Standard & Poors 500
Stock Index, and a peer group of publicly traded partners of
publicly traded limited partnerships in the midstream natural
gas, natural gas liquids and propane industries from
January 12, 2004, the date of our initial public offering,
through December 31, 2006. The chart assumes that $100 was
invested on January 12, 2004, with dividends reinvested.
The peer group includes Kinder Morgan, Inc., Mark West
Hydrocarbon, Inc., Inergy Holdings, L.P. and Enterprise GP
Holdings L.P. (Inergy Holdings, L.P.s initial public
offering was in June 2005, and Enterprise GP Holdings
L.P.s initial public offering was in August 2005, and it
has been assumed that these companies performed in accordance
with the peer group average prior to such dates).
COMPARISON
OF CUMULATIVE RETURNS SINCE JANUARY 12, 2004
AMONG CROSSTEX ENERGY, INC., S&P 500 AND PEER
GROUP
|
|
Item 6.
|
Selected
Financial Data
|
The following table sets forth selected historical financial and
operating data of Crosstex Energy, Inc. as of and for the dates
and periods indicated. The selected historical financial data
are derived from the audited financial statements of Crosstex
Energy, Inc. The summary historical financial and operating
include the results of operations of the Vanderbilt system
beginning in December 2002, the Mississippi pipeline system and
the Seminole processing plant beginning in June 2003, the LIG
assets beginning in April 2004, the South Louisiana Processing
Assets beginning November 2005, the Hanover assets beginning
January 2006, the NTP beginning April 2006, the Midstream assets
acquired from Chief beginning June 29, 2006 and other
smaller acquisitions completed during 2006.
The table should be read together with Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
(Dollars in thousands, except per share amounts)
|
|
|
Statement of Operations
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream
|
|
$
|
3,073,069
|
|
|
$
|
2,982,874
|
|
|
$
|
1,948,021
|
|
|
$
|
989,697
|
|
|
$
|
437,432
|
|
Treating
|
|
|
66,225
|
|
|
|
48,606
|
|
|
|
30,755
|
|
|
|
23,966
|
|
|
|
14,817
|
|
Profit on energy trading activities
|
|
|
2,510
|
|
|
|
1,568
|
|
|
|
2,228
|
|
|
|
2,266
|
|
|
|
1,791
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
3,141,804
|
|
|
|
3,033,048
|
|
|
|
1,981,004
|
|
|
|
1,015,929
|
|
|
|
454,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream purchased gas
|
|
|
2,859,815
|
|
|
|
2,860,823
|
|
|
|
1,861,204
|
|
|
|
946,412
|
|
|
|
414,244
|
|
Treating purchased gas
|
|
|
9,463
|
|
|
|
9,706
|
|
|
|
5,274
|
|
|
|
7,568
|
|
|
|
5,767
|
|
Operating expenses
|
|
|
101,036
|
|
|
|
56,768
|
|
|
|
38,396
|
|
|
|
19,880
|
|
|
|
11,420
|
|
General and administrative
|
|
|
47,707
|
|
|
|
34,145
|
|
|
|
22,005
|
|
|
|
14,816
|
|
|
|
7,704
|
|
Impairments
|
|
|
|
|
|
|
|
|
|
|
981
|
|
|
|
|
|
|
|
4,175
|
|
(Gain) loss on energy trading
contracts
|
|
|
(1,599
|
)
|
|
|
9,968
|
|
|
|
(279
|
)
|
|
|
361
|
|
|
|
134
|
|
Gain on sale of property
|
|
|
(2,108
|
)
|
|
|
(8,138
|
)
|
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
82,792
|
|
|
|
36,070
|
|
|
|
23,034
|
|
|
|
13,542
|
|
|
|
7,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
3,097,106
|
|
|
|
2,999,342
|
|
|
|
1,950,603
|
|
|
|
1,002,579
|
|
|
|
451,189
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
44,698
|
|
|
|
33,706
|
|
|
|
30,401
|
|
|
|
13,350
|
|
|
|
2,851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(51,051
|
)
|
|
|
(15,332
|
)
|
|
|
(9,115
|
)
|
|
|
(3,103
|
)
|
|
|
(2,381
|
)
|
Other income (expense)
|
|
|
1,774
|
|
|
|
391
|
|
|
|
802
|
|
|
|
179
|
|
|
|
(52
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(49,277
|
)
|
|
|
(14,941
|
)
|
|
|
(8,313
|
)
|
|
|
(2,924
|
)
|
|
|
(2,433
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before gain on
issuance of units by the partnership, income taxes and interest
of non-controlling partners in the partnerships net income
|
|
|
(4,579
|
)
|
|
|
18,765
|
|
|
|
22,088
|
|
|
|
10,426
|
|
|
|
418
|
|
Gain on issuance of partnership
units(1)
|
|
|
18,955
|
|
|
|
65,070
|
|
|
|
|
|
|
|
18,360
|
|
|
|
11,781
|
|
Income tax provision benefit
|
|
|
(11,118
|
)
|
|
|
(30,047
|
)
|
|
|
(5,149
|
)
|
|
|
(10,157
|
)
|
|
|
(6,871
|
)
|
Interest of non-controlling
partners in the partnerships net income
|
|
|
(13,027
|
)
|
|
|
(4,652
|
)
|
|
|
(8,239
|
)
|
|
|
(5,181
|
)
|
|
|
(99
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative
effect of change in accounting principle
|
|
|
16,285
|
|
|
|
49,136
|
|
|
|
8,700
|
|
|
|
13,448
|
|
|
|
5,229
|
|
Cumulative effect of change in
accounting principle
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,455
|
|
|
$
|
49,136
|
|
|
$
|
8,700
|
|
|
$
|
13,448
|
|
|
$
|
5,229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common
share-basic(2)
|
|
$
|
0.39
|
|
|
$
|
1.29
|
|
|
$
|
0.24
|
|
|
$
|
0.94
|
|
|
$
|
0.20
|
|
Net income per common
share-diluted(2)
|
|
$
|
0.39
|
|
|
$
|
1.26
|
|
|
$
|
0.22
|
|
|
$
|
0.37
|
|
|
$
|
0.15
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
(Dollars in thousands, except per share amounts)
|
|
|
Balance Sheet Data (end of
period):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital surplus (deficit)
|
|
$
|
(70,091
|
)
|
|
$
|
4,872
|
|
|
$
|
(18,265
|
)
|
|
$
|
(7,705
|
)
|
|
$
|
(11,141
|
)
|
Property and equipment, net
|
|
|
1,107,242
|
|
|
|
668,632
|
|
|
|
325,653
|
|
|
|
104,890
|
|
|
|
111,203
|
|
Total assets
|
|
|
2,206,698
|
|
|
|
1,445,325
|
|
|
|
606,768
|
|
|
|
370,485
|
|
|
|
241,424
|
|
Long-term debt
|
|
|
987,130
|
|
|
|
522,650
|
|
|
|
148,700
|
|
|
|
60,750
|
|
|
|
22,550
|
|
Interest of non-controlling
partners in the partnership
|
|
|
391,103
|
|
|
|
264,726
|
|
|
|
65,399
|
|
|
|
67,157
|
|
|
|
26,815
|
|
Stockholders equity
|
|
|
279,413
|
|
|
|
111,247
|
|
|
|
76,933
|
|
|
|
69,266
|
|
|
|
57,397
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used
in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
113,840
|
|
|
$
|
12,842
|
|
|
$
|
46,339
|
|
|
$
|
42,103
|
|
|
$
|
(5,050
|
)
|
Investing activities
|
|
|
(885,825
|
)
|
|
|
(614,822
|
)
|
|
|
(124,371
|
)
|
|
|
(110,288
|
)
|
|
|
(33,240
|
)
|
Financing activities
|
|
|
769,717
|
|
|
|
592,365
|
|
|
|
99,072
|
|
|
|
65,856
|
|
|
|
41,746
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream gross margin
|
|
$
|
215,764
|
|
|
$
|
123,619
|
|
|
$
|
89,045
|
|
|
$
|
45,551
|
|
|
$
|
24,979
|
|
Treating gross margin
|
|
|
56,762
|
|
|
|
38,900
|
|
|
|
25,481
|
|
|
|
16,398
|
|
|
|
9,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin(3)
|
|
$
|
272,526
|
|
|
$
|
162,519
|
|
|
$
|
114,526
|
|
|
$
|
61,949
|
|
|
$
|
34,029
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline throughput (MMBtu/d)
|
|
|
1,450,000
|
|
|
|
1,222,000
|
|
|
|
1,289,000
|
|
|
|
626,000
|
|
|
|
392,000
|
|
Natural gas processed (MMBtu/d)(4)
|
|
|
1,938,000
|
|
|
|
1,825,000
|
|
|
|
425,000
|
|
|
|
132,000
|
|
|
|
86,000
|
|
Producer services (MMBtu/d)
|
|
|
138,000
|
|
|
|
175,000
|
|
|
|
210,000
|
|
|
|
259,000
|
|
|
|
230,000
|
|
|
|
|
(1) |
|
We recognized gains of $19.0 million in 2006,
$65.1 million in 2005, $18.4 million in 2003 and
$11.8 million in 2002 as a result of the Partnership
issuing additional units to the public in public offerings at
prices per unit greater than our equivalent carrying value. |
|
(2) |
|
Per share amounts have been adjusted for the
two-for-one
stock split made in conjunction with our initial public offering
in January 2004 and a
three-for-one
stock split effected in December 2006. |
|
(3) |
|
Gross margin is defined as revenue, including treating fee
revenues and profit on energy trading activities, less related
cost of purchased gas. |
|
(4) |
|
Processed volumes during 2005 include a daily average for the
south Louisiana processing plants for November 2005 and December
2005, the two-month period these assets were operated by the
Partnership. |
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
You should read the following discussion of our financial
condition and results of operations in conjunction with the
financial statements and notes thereto included elsewhere in
this report. For more detailed information regarding the basis
of presentation for the following information, you should read
the notes to the financial statements included in this
report.
Overview
Crosstex Energy, Inc. is a Delaware corporation formed on
April 28, 2000 to engage in the gathering, transmission,
treating, processing and marketing of natural gas and NGLs
through its subsidiaries. On July 12, 2002, we formed
Crosstex Energy, L.P., a Delaware limited partnership, to
acquire indirectly substantially all of the assets, liabilities
and operations of its predecessor, Crosstex Energy Services,
Ltd. Our assets consist almost exclusively of partnership
interests in Crosstex Energy, L.P., a publicly traded limited
partnership engaged in the gathering, transmission, treating,
processing and marketing of natural gas and NGLs. These
partnership interests consist of (i) 5,332,000 common
units, 4,668,000 subordinated units and 6,414,830 senior
subordinated series C units, representing approximately 42%
of the limited partner interests in Crosstex Energy, L.P., and
(ii) 100% ownership interest in Crosstex Energy GP, L.P.,
the general partner of Crosstex Energy, L.P., which owns a 2.0%
general partner interest and all of the incentive distribution
rights in Crosstex Energy, L.P.
31
Our cash flows consist almost exclusively of distributions from
the Partnership on the partnership interests we own. The
Partnership is required by its partnership agreement to
distribute all its cash on hand at the end of each quarter, less
reserves established by its general partner in its sole
discretion to provide for the proper conduct of the
Partnerships business or to provide for future
distributions.
The incentive distribution rights entitle us to receive an
increasing percentage of cash distributed by the Partnership as
certain target distribution levels are reached. Specifically,
they entitle us to receive 13.0% of all cash distributed in a
quarter after each unit has received $0.25 for that quarter,
23.0% of all cash distributed after each unit has received
$0.3125 for that quarter, and 48.0% of all cash distributed
after each unit has received $0.375 for that quarter.
Distributions by the Partnership have increased from
$0.25 per unit for the quarter ended March 31, 2003
(its first full quarter of operation after its initial public
offering) to $0.56 per unit for the quarter ended
December 31, 2006. As a result, our distributions from the
Partnership pursuant to our ownership of our 10,000,000 common
and subordinated units have increased from $2.5 million for
the quarter ended March 31, 2003 to $5.6 million for
the quarter ended December 31, 2006; our distributions
pursuant to our 2% general partner interest have increased from
$74,000 to $0.4 million; and our distributions pursuant to
our incentive distribution rights have increased from zero to
$5.5 million. As a result, we have increased our dividend
from $0.10 per share (giving effect to the
three-for-one
stock split on December 15, 2006) for the quarter
ended March 31, 2004 (the first dividend payout after our
initial public offering) to $0.22 per share for the quarter
ended December 31, 2006.
Since we control the general partner interest in the
Partnership, we reflect our ownership interest in the
Partnership on a consolidated basis, which means that our
financial results are combined with the Partnerships
financial results and the results of our other subsidiaries. The
interest owned by non-controlling partners share of income
is reflected as an expense in our results of operations. We have
no separate operating activities apart from those conducted by
the Partnership, and our cash flows consist almost exclusively
of distributions from the Partnership on the partnership
interests we own. Our consolidated results of operations are
derived from the results of operations of the Partnership and
also include our gains on the issuance of units in the
Partnership, deferred taxes, interest of non- controlling
partners in the Partnerships net income, interest income
(expense) and general and administrative expenses not reflected
in the Partnerships results of operation. Accordingly, the
discussion of our financial position and results of operations
in this Managements Discussion and Analysis of
Financial Condition and Results of Operations primarily
reflects the operating activities and results of operations of
the Partnership.
The Partnership has two industry segments, Midstream and
Treating, with a geographic focus along the Texas gulf coast, in
the north Texas Barnett Shale area and in Mississippi and
Louisiana. The Partnerships Midstream division focuses on
the gathering, processing, transmission and marketing of natural
gas and NGLs, as well as providing certain producer services,
while the Treating division focuses on the removal of
contaminants from natural gas and NGLs to meet pipeline quality
specifications. For the year ended December 31, 2006, 79%
of the Partnerships gross margin was generated in the
Midstream division, with the balance in the Treating division.
The Partnership focuses on gross margin to manage its business
because its business is generally to purchase and resell natural
gas for a margin, or to gather, process, transport, market or
treat natural gas or NGLs for a fee. The Partnership buys and
sells most of its natural gas at a fixed relationship to the
relevant index price so margins are not significantly affected
by changes in natural gas prices. As explained under
Commodity Price Risk below, it enters into financial
instruments to reduce volatility in gross margin due to price
fluctuations.
During the past five years, the Partnership has grown
significantly as a result of construction and acquisition of
gathering and transmission pipelines and treating and processing
plants. From January 1, 2002 through December 31,
2006, it has invested over $1.7 billion to develop or
acquire new assets. The purchased assets were acquired from
numerous sellers at different periods and were accounted for
under the purchase method of accounting. Accordingly, the
results of operations for such acquisitions are included in our
financial statements only from the applicable date of the
acquisition. As a consequence, the historical results of
operations for the periods presented may not be comparable.
The Partnerships Midstream segment margins are determined
primarily by the volumes of natural gas gathered, transported,
purchased and sold through its pipeline systems, processed at
its processing facilities and the volumes of natural gas liquids
handled at its fractionation facilities. Treating segment
margins are largely a function
32
of the number and size of treating plants as well as fees earned
for removing impurities and from natural gas liquids at a
non-operated processing plant. The Partnership generates
revenues from five primary sources:
|
|
|
|
|
purchasing and reselling or transporting natural gas on the
pipeline systems it owns;
|
|
|
|
processing natural gas at its processing plants and
fractionating and marketing the recovered natural gas liquids;
|
|
|
|
treating natural gas at its treating plants;
|
|
|
|
recovering carbon dioxide and natural gas liquids at a
non-operated processing plant; and
|
|
|
|
providing off-system marketing services for producers.
|
The bulk of the Partnerships operating profits are derived
from the margins it realizes for purchasing and reselling
natural gas through its pipeline systems. Generally, the
Partnership buys gas from a producer, plant tailgate, or
transporter at either a fixed discount to a market index or a
percentage of the market index. The Partnership then transports
and resells the gas. The resale price is generally based on the
same index price at which the gas was purchased, and, if the
Partnership is to be profitable, at a smaller discount or larger
premium to the index than it was purchased. The Partnership
attempts to execute all purchases and sales substantially
concurrently, or it enters into a future delivery obligation,
thereby establishing the basis for the margin we will receive
for each natural gas transaction. The Partnerships
gathering and transportation margins related to a percentage of
the index price can be adversely affected by declines in the
price of natural gas. See Commodity Price Risk below
for a discussion of how it manages its business to reduce the
impact of price volatility.
Processing and fractionation revenues are largely fee based.
Processing fees are largely based on either a percentage of the
liquids volume recovered, or a fixed fee per unit processed.
Fractionation and marketing fees are generally fixed per unit of
product.
The Partnership generates treating revenues under three
arrangements:
|
|
|
|
|
a volumetric fee based on the amount of gas treated, which
accounted for approximately 48% and 51% of the operating income
in the Treating division for the years ended December 31,
2006 and 2005, respectively;
|
|
|
|
a fixed fee for operating the plant for a certain period, which
accounted for approximately 32% and 38% of the operating income
in the Treating division for the years ended December 31,
2006 and 2005, respectively; or
|
|
|
|
a fee arrangement in which the producer operates the plant,
which accounted for approximately 20% and 11% of the operating
income in the Treating division for the years ended
December 31, 2006 and 2005, respectively.
|
Operating expenses are costs directly associated with the
operations of a particular asset. Among the most significant of
these costs are those associated with direct labor and
supervision and associated transportation and communication
costs, property insurance, ad valorem taxes, repair and
maintenance expenses, measurement and utilities. These costs are
normally fairly stable across broad volume ranges, and
therefore, do not normally decrease or increase significantly in
the short term with decreases or increases in the volume of gas
moved through the asset.
Acquisitions
The Partnership has grown significantly through asset purchases
in recent years, which creates many of the major differences
when comparing operating results from one period to another. The
most significant asset purchases since January 1, 2003, are
the acquisitions of the Chief midstream assets, the South
Louisiana Processing Assets and the LIG Pipeline Company. It
also acquired treating operations totaling $16.0 million
and $58.0 million during 2005 and 2006, respectively.
On June 29, 2006, the Partnership acquired the natural gas
gathering pipeline systems and related facilities of Chief in
the Barnett Shale for $475.3 million. The acquired systems
consist of approximately 250 miles of existing pipeline
with up to an additional 400 miles of planned pipelines,
located in Parker, Tarrant, Denton, Palo Pinto, Erath, Hood,
Somervell, Hill and Johnson counties, all of which are located
in Texas. The acquired assets also
33
include a 125 MMcf/d carbon dioxide treating plant and
compression facilities with 26,000 horsepower. At closing,
approximately 160,000 net acres previously owned by Chief
and acquired by Devon simultaneously with the Partnerships
acquisition, as well as 60,000 net acres owned by other
producers, were dedicated to the systems. As of
December 31, 2006, the Partnership had installed
approximately 49 miles of gathering pipeline and connected
85 new wells to its gathering systems, 46 of which are owned or
controlled by Devon and 39 of which are owned or controlled by
other producers. In addition to expanding its gathering system,
the Partnership had installed 4,400 horsepower of
additional compression to handle the increased volumes. The
Partnership also installed a new 55,000 Mcf/d cryogenic
processing plant, referred to as its Azle plant, and added inlet
refrigeration to an existing 30,000 Mcf/d plant in order to
remove hydrocarbon liquids from growing gas streams. The
Partnership has increased total throughput on this gathering
system from approximately 115 MMcf/d at the time of the
acquisition to 230 MMcf/d for the month of December 2006.
On February 1, 2006, the Partnership acquired 48 amine
treating plants from a subsidiary of Hanover Compression Company
for $51.7 million.
On October 3, 2006, the Partnership acquired the
amine-treating business of Cardinal Gas Solutions Limited
Partnership for $6.3 million. The acquisition added 10 dew
point control plants and seven amine-treating plants to our
plant portfolio.
On November 1, 2005, the Partnership acquired
El Pasos processing and liquids business in South
Louisiana for $481.0 million. The assets acquired include
2.3 Bcf/d of processing capacity, 66,000 barrels per
day of fractionation capacity, 2.4 million barrels of
underground storage and 400 miles of liquids transport
lines. The primary facilities and other assets acquired consist
of: (1) the Eunice processing plant and fractionation
facility; (2) the Pelican processing plant; (3) the
Sabine Pass processing plant; (4) a 23.85% interest in the
Blue Water gas processing plant; (5) the Riverside
fractionator and loading facility; (6) the Cajun Sibon
pipeline; and (7) the Napoleonville NGL storage facility.
In May 2006, the Partnership acquired an additional 35.42%
interest in the Blue Water gas processing plant for
$16.5 million and became the operator of the plant.
On January 2, 2005, the Partnership acquired all of the
assets of Graco Operations for $9.3 million. Gracos
assets consisted of 26 treating plants and associated inventory.
On May 1, 2005, it acquired all of the assets of Cardinal
Gas Services for $6.7 million. Cardinals assets
consisted of nine gas treating plants, 19 dew point control
plants and equipment inventory.
In April 2004 the Partnership acquired LIG Pipeline Company and
its subsidiaries from a subsidiary of American Electric Power
(AEP) for $73.7 million in cash. The principal assets
acquired consist of approximately 2,000 miles of gas
gathering and transmission systems located in 32 parishes
extending from northwest and north-central Louisiana through the
center of the state to the south and southeast Louisiana and two
operating processing plants, with total processing capacity of
335,000 MMBtu/d. Average throughput at the time of our
acquisition was approximately 560,000 MMBtu/d. Customers
include power plants, municipal gas systems, and industrial
markets located principally in the industrial corridor between
New Orleans and Baton Rouge. The LIG system is connected to
several interconnected pipelines and the Jefferson Island
Storage facility providing access to additional system supply.
Other
Assets
We own two inactive gas plants and a receivable associated with
the Enron Corp. bankruptcy, which was collected in 2006, in
addition to our limited and general partner interests in the
Partnership. The two gas plants are the Jonesville processing
plant, which has been largely inactive since the beginning of
2001, and the Clarkson plant, acquired shortly before the
Partnerships initial public offering. In the third quarter
of 2004, we fully impaired our investment in the Jonesville
plant. We collected $1.6 million in excess of the carrying
value of the receivable from Enron during 2006 which is included
in other income.
Impact of
Federal Income Taxes
Crosstex Energy, Inc. is a corporation for federal income tax
purposes. As such, our federal taxable income is subject to tax
at a maximum rate of 35.0% under current law. We expect to have
significant amounts of taxable
34
income allocated to us as a result of our investment in the
Partnerships units, particularly because of remedial
allocations that will be made among the unitholders and because
of the general partners incentive distribution rights,
which we will benefit from as the sole owner of the general
partner. Taxable income allocated to us by the Partnership will
increase over the years as the ratio of income to distributions
increases for all of the unitholders.
As of December 31, 2006 we have a net operating loss
carryforward of $64.4 million for federal income taxes and
state loss carryforwards of $24.1 million. We estimate that
our net operating loss carryforward will be utilized to offset
most of the federal taxable income during 2007 and 2008. In
years after 2008, however, we do not expect to have this net
operating loss carryforward to offset our income. As a result,
we will have to pay tax on our federal taxable income at a
maximum rate of 35.0% under current law. Thus, the amount of
money available to make cash distributions to our stockholders
will decrease markedly after we use all of our net operating
loss carryforward.
Our use of this net operating loss carryforward will be limited
if there is a greater than 50.0% change in our stock ownership
over a three year period. However, we do not expect such a
change in ownership to limit our utilization of carryforwards
prior to their
20-year
expiration period.
Commodity
Price Risk
The Partnerships profitability has been and will continue
to be affected by volatility in prevailing NGL product and
natural gas prices. Changes in the prices of NGL products can
correlate closely with changes in the price of crude oil. NGL
product and natural gas prices have been subject to significant
volatility in recent years in response to changes in the supply
and demand for crude oil, NGL products and natural gas.
Profitability under the Partnerships gas processing
contracts is impacted by the margin between NGL sales prices and
the cost of natural gas and may be negatively affected by
decreases in NGL prices or increases in natural gas prices.
Changes in natural gas prices impact profitability since the
purchase price of a portion of the gas the Partnership buys is
based on a percentage of a particular natural gas price index
for a period, while the gas is resold at a fixed dollar
relationship to the same index. Therefore, during periods of low
gas prices, these contracts can be less profitable than during
periods of higher gas prices. However, on most of the gas we buy
and sell, margins are not affected by such changes because the
gas is bought and sold at a fixed relationship to the relevant
index. Therefore, while changes in the price of gas can have
very large impacts on revenues and cost of revenues, the changes
are equal and offsetting.
Set forth in the table below is the volume of the natural gas
purchased and sold at a fixed discount or premium to the index
price and at a percentage discount or premium to the index price
for the Partnerships principal gathering and transmission
systems and for its producer services business for the year
ended December 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
Gas Purchased
|
|
|
Gas Sold
|
|
|
|
Fixed
|
|
|
|
|
|
Fixed
|
|
|
|
|
|
|
Amount
|
|
|
Percentage of
|
|
|
Amount
|
|
|
Percentage of
|
|
Asset or Business
|
|
to Index
|
|
|
Index
|
|
|
to Index
|
|
|
Index
|
|
|
|
(In thousands of MMBtus)
|
|
|
LIG system
|
|
|
141,635
|
|
|
|
6,384
|
|
|
|
148,019
|
|
|
|
|
|
South Texas system(1)
|
|
|
148,111
|
|
|
|
15,134
|
|
|
|
148,186
|
|
|
|
|
|
North Texas system
|
|
|
28,177
|
|
|
|
|
|
|
|
28,177
|
|
|
|
|
|
Other assets and activities(1)
|
|
|
78,921
|
|
|
|
3,205
|
|
|
|
73,105
|
|
|
|
|
|
|
|
|
(1) |
|
Gas sold is less than gas purchased due to production of NGLs on
certain assets included in the south Texas system and other
assets. |
The Partnership estimates that, due to the gas that it purchases
at a percentage of index price, for each $0.50 per MMBtu
increase or decrease in the price of natural gas, its gross
margins increase or decrease by approximately $1.3 million
on an annual basis (before consideration of hedge positions). As
of December 31, 2006, it has hedged approximately 78% of
its exposure to such fluctuations in natural gas prices for 2007
and approximately 70% of our exposure to such fluctuations for
the first quarter of 2008. CELP expects to continue to hedge its
exposure to gas prices when market opportunities appear
attractive.
35
The Partnership processed approximately 70.4% of its volumes
during 2006 at Eunice, Pelican, Sabine and Blue Water under
percent of proceeds contracts, under which it
receives as a fee a portion of the liquids produced, and 29.6%
fixed fee per unit processed. Under percent of proceeds
contracts, it is exposed to changes in the prices of NGLs. For
the years 2007 and 2008, it has purchased puts or entered into
forward sales covering all of its anticipated minimum share of
NGLs production.
The Partnerships processing plants at Plaquemine and
Gibson have a variety of processing contract structures. In
general, the Partnership buys gas under keep-whole arrangements
in which it bears the risk of processing,
percentage-of-proceeds
arrangements in which it receives a percentage of the value of
the liquids recovered, and theoretical processing
arrangements in which the settlement with the producer is based
on an assumed processing result. Because the Partnership has the
ability to bypass certain volumes when processing is uneconomic,
it can limit its exposure to adverse processing margins. During
periods when processing margins are favorable, the Partnership
can substantially increase the volumes it is processing.
For the year ended December 31, 2006, the Partnership
purchased a small amount (approximately 5.1%) of the natural gas
volumes on its Gregory system under contracts in which it was
exposed to the risk of loss or gain in processing the natural
gas. The Partnership purchased the remaining approximately 94.9%
of the natural gas volumes on its Gregory system at a spot or
market price less a discount that includes a fixed margin for
gathering, processing and marketing the natural gas and NGLs at
its Gregory processing plant with no risk of loss or gain in
processing the natural gas.
The Partnership owns an undivided 12.4% interest in the Seminole
gas processing plant, which is located in Gaines County, Texas.
The Seminole plant has dedicated long-term reserves from the
Seminole San Andres unit, to which it also supplies carbon
dioxide under a long-term arrangement. Revenues at the plant are
derived from a fee it charges producers for each Mcf of carbon
dioxide returned to the producer for reinjection. The fees
currently average approximately $0.68 for each McF of carbon
dioxide returned. Reinjected carbon dioxide is used in a
tertiary oil recovery process in the field. The plant also
receives 50% of the NGLs produced by the plant. Therefore, the
Partnership has commodity price exposure due to variances in the
prices of NGLs. During 2006, its share of NGLs totaled
5.4 million gallons at an average price of $1.03 per
gallon. The Partnership executed forward sales on approximately
81% of its anticipated 2007 share of NGLs and approximately
40% of its share of NGLs for the first quarter of 2008.
Gas prices can also affect the Partnerships profitability
indirectly by influencing drilling activity and related
opportunities for gas gathering, treating and processing.
36
Results
of Operations
Set forth in the table below is certain financial and operating
data for the Midstream and Treating divisions for the periods
indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Dollars in millions)
|
|
|
Midstream revenues
|
|
$
|
3,073.1
|
|
|
$
|
2,982.9
|
|
|
$
|
1,948.0
|
|
Midstream purchased gas
|
|
|
(2,859.8
|
)
|
|
|
(2,860.8
|
)
|
|
|
(1,861.2
|
)
|
Profits on energy trading
activities
|
|
|
2.5
|
|
|
|
1.6
|
|
|
|
2.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream gross margin
|
|
|
215.8
|
|
|
|
123.7
|
|
|
|
89.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treating revenues
|
|
|
66.2
|
|
|
|
48.6
|
|
|
|
30.8
|
|
Treating purchased gas
|
|
|
(9.5
|
)
|
|
|
(9.7
|
)
|
|
|
(5.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treating gross margin
|
|
|
56.7
|
|
|
|
38.9
|
|
|
|
25.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin
|
|
$
|
272.5
|
|
|
$
|
162.6
|
|
|
$
|
114.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream Volumes
(MMBtu/d):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation
|
|
|
1,450,000
|
|
|
|
1,222,000
|
|
|
|
1,289,000
|
|
Processing
|
|
|
1,938,000
|
|
|
|
1,825,000
|
|
|
|
425,000
|
|
Producer services
|
|
|
138,000
|
|
|
|
175,000
|
|
|
|
210,000
|
|
Treating Plants in Operation at
Year End
|
|
|
160
|
|
|
|
112
|
|
|
|
74
|
|
Year
Ended December 31, 2006 Compared to Year Ended
December 31, 2005
Gross Margin and Profit on Energy Trading
Activities. Midstream gross margin was
$215.8 million for the year ended December 31, 2006
compared to $123.7 million for the year ended
December 31, 2005, an increase of $92.1 million, or
75%. This increase was primarily due to acquisitions, increased
system throughput and a favorable processing environment for
natural gas and natural gas liquids.
The South Louisiana Processing Assets acquired from El Paso
in November 2005 contributed $56.1 million to Midstream
gross margin growth in 2006. This amount was driven by the three
largest processing plants, Eunice, Pelican and Sabine Pass,
which contributed gross margin increases of $25.1 million,
$11.4 million and $9.1 million, respectively. The
Riverside fractionation facility and the Blue Water plant also
contributed gross margin growth to the south Louisiana
operations of $5.1 million and $3.7 million,
respectively. Operational improvements and volume increases on
the LIG system contributed margin growth of $12.5 million
during 2006. Increased processing volumes at the Gibson and
Plaquemine plants due to drilling successes by producers and
increased unit margins due to favorable NGL markets accounted
for a $9.5 million increase in gross margin. We acquired
the north Texas gathering system from Chief Holdings LLC in June
2006. This gathering system and related facilities contributed
$11.7 million of gross margin during 2006. The NTP
commenced operation during the second quarter of 2006 and
contributed $8.0 million in gross margin. These gains were
partially offset by volume and margin declines on our southern
region assets. Decreased throughput on the CCNG, Gregory and
Gulf Coast systems contributed to an overall margin decrease in
our southern region of $6.9 million.
The favorable processing margins the Partnership realized during
2006 at its South Louisiana Processing Assets, the Gibson plant
and the Plaquemine plant may be higher than processing margins
it may realize during 2007 and future periods if the NGL markets
do not remain as strong as they were during 2006. As discussed
above under Commodity Price Risk,
the Partnership receives a processing fee as a portion of
liquids processed or a percentage of the liquids recovered on a
substantial portion of the gas processed through these plants.
During periods when processing margins are favorable, as existed
during 2006, the Partnership experiences higher processing
margins. The Partnership has the ability to bypass certain
volumes when processing is uneconomic so it can limit its
exposure to adverse processing margins but our processing
margins will be lower during these periods.
37
In addition, the Partnership has the ability to buy gas from and
to sell gas to various gas markets through our pipeline systems.
During 2006 the Partnership was able to benefit from price
differentials between the various gas markets by selling gas
into markets with more favorable pricing thereby improving its
Midstream gross margin. If these price differentials do not
exist during 2007 and future periods, the Partnerships
Midstream gross margin may be lower.
Treating gross margin was $56.7 million for the year ended
December 31, 2006 compared to $38.9 million for the
year ended December 31, 2005, an increase of
$17.8 million, or 46%. Treating plants in service increased
from 112 plants at December 2005 to 160 plants at December 2006.
The increase in the number of plants in service is primarily due
to the acquisition of the amine treating assets from Hanover
Compressor Company in February of 2006. New plants associated
with the Hanover acquisition contributed $7.4 million in
gross margin growth. The operations acquired from Hanover also
include providing field services for producers which contributed
$1.0 million in gross margin for the year. Plant additions
from inventory and expansion projects at existing plants
contributed gross margin growth of $6.6 million and
$0.5 million, respectively. The Seminole plant contributed
$1.5 million of gross margin growth due to the
recalculation of fees based on rate escalations set forth in the
contract. The acquisition and installation of dew point control
plants contributed an additional $0.7 million increase to
gross margin.
Operating Expenses. Operating expenses were
$101.0 million for the year ended December 31, 2006
compared to $56.8 million for the year ended
December 31, 2005, an increase of $44.2 million, or
78%. An increase of $27.0 million in operating expenses was
associated with the South Louisiana Processing Assets which were
owned for a full year in 2006 and only two months in 2005. Other
Midstream increases of $7.7 million were due to the
commencement of operations of the NTP as well as the Chief
acquisition. The growth in the number of treating plants in
service increased operating expenses by $4.8 million.
Engineering and other technical service support costs also
increased $2.9 million due to our asset growth. The
remaining increase of $1.9 million is due to increased
costs on our other Midstream systems. Operating expenses
included stock-based compensation expenses of $1.1 million
and $0.4 million for the year ended December 31, 2006
and 2005, respectively.
General and Administrative Expenses. General
and administrative expenses were $47.7 million for the year
ended December 31, 2006 compared to $34.1 million for
the year ended December 31, 2005, an increase of
$13.6 million, or 40%. A substantial part of the increased
expenses resulted from staffing related costs of
$6.5 million. The staff additions associated with the
requirements of the El Paso, Hanover and Chief acquisitions
accounted for the majority of the $6.5 million increase.
Audit, legal and other consulting fees, office rent, travel,
training and other administrative expenses, which increased due
to the Partnerships growth, accounted for
$3.4 million of the increase. General and administrative
expenses included stock-based compensation expense of
$7.4 million and $3.7 million for the year ended
December 31, 2006 and 2005, respectively. The
$3.7 million increase in stock-based compensation,
determined in accordance with FAS 123R during 2006 and in
accordance with APB25 in 2005, primarily relates to an increase
in restricted stock and unit grants due to an increase in the
pool of eligible participants.
Gain/Loss on Derivatives. Gain on derivatives
was $1.6 million for the year ended December 31, 2006
compared to a loss of $10.0 million for the year ended
December 31, 2005. The gain in 2006 includes a gain of
$2.9 million on storage financial transactions (including
$0.7 million of realized gain), a gain of $0.7 million
associated with basis swaps (including $0.4 million of
realized gain), a gain of $1.5 million associated with
derivatives for third-party on-system financial transactions
(including $1.2 million of realized gains), and a gain of
$0.1 million due to ineffectiveness in hedged derivatives
partially offset by a loss of $3.6 million on puts acquired
in 2005 related to the acquisition of the South Louisiana
Processing Assets. As of December 31, 2006, the fair value
of the puts was $1.7 million. The loss in 2005 includes a
$9.2 million loss on the puts related to the acquisition of
the South Louisiana Processing Assets.
Gain/Loss on Sale of Property. Assets sold
during the year ended December 31, 2006 generated a net
gain of $2.1 million as compared to a gain of
$8.1 million during the year ended December 31, 2005.
The gain in 2006 primarily related to the sale of an inactive
gas processing facility acquired as part of the South Louisiana
Processing Assets. The gain in 2005 primarily related to the
sale of an inactive gas processing facility acquired as part of
the LIG acquisition.
38
Depreciation and Amortization. Depreciation
and amortization expenses were $82.8 million for the year
ended December 31, 2006 compared to $36.1 million for
the year ended December 31, 2005, an increase of
$46.7 million, or 130%. An increase of $28.7 million
in depreciation expense was associated with the
South Louisiana Processing Assets which were owned for a
full year in 2006 and only two months in 2005. The acquisition
of the north Texas gathering system from Chief, the commencement
of operations of the NTP and the related developments in north
Texas in 2006 increased depreciation expense by
$9.6 million. The acquisition of the treating assets from
Hanover in 2006 contributed an increase of $2.5 million and
other new treating plants acquired and placed in service
contributed an increase of $2.5 million. The remaining
increase of $3.4 million was a result of various other
expansion projects, including the expansion of our corporate
offices and related support facilities.
Interest Expense. Interest expense was
$51.0 million for the year ended December 31, 2006
compared to $15.3 million for the year ended
December 31, 2005, an increase of $35.7 million. The
increase relates primarily to an increase in debt outstanding as
a result of acquisitions and other growth projects and higher
interest rates between years (weighted average rate of 6.9% in
2006 compared to 6.3% in 2005).
Other Income. Other income was
$1.8 million for the year ended December 31, 2006
compared to $0.4 million for the year ended
December 31, 2005 because in 2006 we collected
$1.6 million in excess of the carrying value of the Enron
account receivable net of the allowance.
Gain on Issuance of Units of the
Partnership. As a result of the Partnership
issuing senior subordinated units in June 2005 to unrelated
parties at a price per unit greater than our equivalent carrying
value, our share of net assets of the Partnership increased by
$19.0 million. We recognized the $19.0 million gain
associated with the unit issuance in February 2006 when the
senior subordinated units converted to common units. We
recognized a gain of $65.1 million during 2005 associated
with the Partnerships issuance of common units in November
2005.
Income Taxes. We provide income taxes using
the liability method. Accordingly, deferred taxes are recorded
for the differences between the tax and book basis of assets and
liabilities that will reverse in future periods. Income tax
expense was $11.1 million for the year ended
December 31, 2006 compared to $30.0 million for the
year ended December 31, 2005, a decrease of
$18.9 million. The decrease in the gain on issuance of
units of the Partnership from $65.1 million during 2005 to
$19.0 million during 2006 is the primary reason for the
decrease in income taxes between years. Income after minority
interest also decreased $5.7 million between years which
also reduced the income tax expense between years.
Interest of Non-Controlling Partners in the
Partnerships Net Income. The interest of
non-controlling partners in the Partnerships net income
decreased by $17.7 million to a loss of $13.0 million
for the year ended December 31, 2006 compared to income of
$4.7 million for the year ended December 31, 2005 due
to the changes shown in the following summary (in thousands):
|
|
|
|
|
|
|
|
|
|
|
For the Year
|
|
|
|
Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Net income for the Partnership
|
|
$
|
(4,191
|
)
|
|
$
|
19,200
|
|
(Income) allocation to CEI for the
general partner incentive distribution
|
|
|
(20,422
|
)
|
|
|
(10,660
|
)
|
Stock-based compensation costs
allocated to CEI for its stock options and restricted stock
granted to Partnership officers, employees and directors
|
|
|
3,545
|
|
|
|
2,223
|
|
(Income)/loss allocation to CEI
for its 2% general partner share of Partnership (income) loss
|
|
|
421
|
|
|
|
(215
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocable to
limited partners
|
|
|
(20,647
|
)
|
|
|
10,548
|
|
Less: CEIs share of net
(income) loss allocable to limited partners
|
|
|
7,389
|
|
|
|
(6,337
|
)
|
Plus: Non-controlling
partners share of net income (loss) in Crosstex Denton
County Gathering, J.V.
|
|
|
231
|
|
|
|
441
|
|
|
|
|
|
|
|
|
|
|
Non-controlling partners
share of Partnership net income (loss)
|
|
$
|
(13,027
|
)
|
|
$
|
4,652
|
|
|
|
|
|
|
|
|
|
|
39
The general partner incentive distributions increased between
these years due to an increase in the distribution amounts per
unit and due to an increase in the number of common units
outstanding.
Cumulative Effect of Accounting Change. We
recorded a $0.2 million cumulative adjustment to recognize
the required change in reporting stock-based compensation under
FASB Statement No. 123R which was effective January 1,
2006. The cumulative effect of this change is reported in our
income net of taxes and non-controlling partners interest.
Year
Ended December 31, 2005 Compared to Year Ended
December 31, 2004
Gross Margin and Profit on Energy Trading
Activities. Midstream gross margin was
$123.7 million for the year ended December 31, 2005
compared to $89.0 million for the year ended
December 31, 2004, an increase of $34.7 million, or
39%. This increase was primarily due to acquisitions, volatile
prices in the last half of the year and operational improvements
on existing systems.
The acquisition of the South Louisiana Processing Assets
contributed $14.1 million in the fourth quarter of 2005.
The acquisition of the LIG assets on April 1, 2004
contributed $6.3 million to midstream gross margin in 2005
in our first full year of ownership. In addition, the
acquisition of all outside interests in Crosstex Pipeline
Partners, Ltd., as of December 31, 2004 accounted for
a gross margin increase of $1.7 million. Relatively high
and volatile natural gas prices during the quarters created
favorable margin opportunities on several systems, offset by the
negative impact on processing margins of high gas prices, as
certain gas was no longer economical to process. The impact of
these high and volatile gas prices on midstream operations was a
gross margin increase of $5.4 million. During the fourth
quarter, decline in gas prices created an imbalance gain of
$4.5 million and made processing more profitable.
Operational improvements and volume increases contributed margin
growth of $5.1 million on the Vanderbilt, Denton County and
Arkoma systems. In addition, the Gregory gathering system had a
margin increase of $1.7 million primarily due to two
measurement disputes which were settled during the year.
Treating gross margin was $38.9 million for the year ended
December 31, 2005 compared to $25.5 million in the
same period in 2004, an increase of $13.4 million, or 53%.
The increase in treating plants in service from 74 plants
at December 31, 2004 to 112 plants at December 31,
2005 contributed approximately $7.1 million in gross
margin. Existing plant assets contributed $5.0 million in
gross margin growth due primarily to plant expansion projects
and increased volumes. The acquisition and installation of dew
point control plants in 2005 contributed an additional
$0.6 million to gross margin.
Operating Expenses. Operating expenses were
$56.8 million for the year ended December 31, 2005
compared to $38.4 million for the year ended
December 31, 2004, an increase of $18.4 million, or
48%. An increase of $5.3 million was associated with the
acquisition of the South Louisiana Processing Assets from
El Paso. LIG assets added $4.6 million of variance due
to the fact that the assets were part of our business for the
entire year in 2005 as opposed to nine months in 2004. Midstream
operating expenses also increased by $2.6 million due to
small acquisitions, expansions of systems and the addition of
compressors or other rental services. The growth in treating
plants in service due to acquisition of the Graco assets and the
Cardinal assets as well as internal growth increased operating
expenses by $5.2 million. Operations expense includes
stock-based compensation expense of $0.4 million and
$0.2 million in 2005 and 2004, respectively.
General and Administrative Expenses. General
and administrative expenses were $34.1 million for the year
ended December 31, 2005, compared to $22.0 million for
the year ended December 31, 2004, an increase of
$12.1 million, or 55%. A significant contributor was
additional staffing-related costs, an incremental
$6.0 million over 2004. The staff additions required to
manage and optimize our acquisitions account for the majority of
the change, although a number of leadership and strategic
positions were added that will allow us to absorb future growth
more efficiently. Other expenses related to growth, including
office rent, utilities, and travel expenses, accounted for
$2.6 million of the increase. General and administrative
expense includes stock-based compensation expense of
$3.7 million in 2005 and $0.8 million in 2004. The
increase in stock-based compensation primarily relates to
restricted stock and unit grants and $0.4 million in
accelerated options.
40
(Gain) Loss on Derivatives. We had a loss on
derivatives of $10.0 million for the year ended
December 31, 2005 compared to a gain on derivatives of
$0.3 million for the year ended December 31, 2004. The
loss in 2005 includes a $9.2 million loss on puts acquired
in the third quarter of 2005 related to the acquisition of the
South Louisiana Processing Assets and a loss of
$0.7 million associated with derivatives for the
third-party on-system financial transactions and storage
financial transactions primarily due to higher commodity prices
at year end. As part of the overall risk management plan related
to the November 2005 acquisition of the South Louisiana
Processing Assets, the Partnership acquired puts, or rights to
sell a portion of the liquids from the plants at a fixed price
over a two-year period beginning January 1, 2006 for a
premium of $18.7 million. In December 2005 the Partnership
sold a portion of these puts for $4.3 million. These puts
were not designated as hedges as of December 31, 2005 and
were marked to market through our consolidated statement of
operations. The puts represent options, but not the obligation,
to sell the related underlying liquids volumes at a fixed price.
As the price of the underlying liquids increased significantly
in the period, the value of the puts declined, which is
reflected in gain/loss on derivatives.
Gain on Sale of Property. During 2005, the
Partnership sold an inactive gas processing facility acquired as
part of the LIG acquisition, which accounted for a substantial
part of the $8.1 million gain on sale of property.
Depreciation and Amortization. Depreciation
and amortization expenses were $36.1 million for the year
ended December 31, 2005 compared to $23.0 million for
the year ended December 31, 2004, an increase of
$13.1 million, or 57%. Of the increase, the acquisition of
the south Louisiana processing assets contributed
$5.5 million and the LIG assets contributed
$1.3 million. New treating plants placed in service
resulted in an increase of $2.3 million. The remaining
$3.9 million increase in depreciation and amortization is a
result of expansion projects and other new assets, including the
expansion of the Dallas office, computer software and equipment,
and expansions on midstream assets.
Interest Expense. Interest expense was
$15.3 million for the year ended December 31, 2005
compared to $9.1 million for the year ended
December 31, 2004, an increase of $6.2 million, or
68%. The increase relates primarily to an increase in average
debt outstanding. Average higher interest rates also increased
from 2004 to 2005 (weighted average rate of 6.1% in 2004
compared to 6.3% in 2005).
Other Income. Other income was
$0.4 million for the year ended December 31, 2005
compared to $0.8 million for the year ended
December 31, 2004. Other income in 2004 includes
$0.3 million related to a reimbursement for a construction
project in excess of our costs for such project.
Gain on Issuance of Units of the
Partnership. Principally as a result of the
Partnership issuing the senior subordinated series B units
and the public offering of common units, both of which happened
in November 2005, our share of the net assets of the Partnership
increased by $65.1 million. Accordingly, we recognized a
$65.1 million gain in 2005.
Income Tax Expense. Our income tax provision
was $30.1 million in 2005 compared to $5.1 million in
2004, an increase of $25.0 million. The increase in the tax
provision was primarily due to the taxes provided on the
$65.1 million gain on issuance of units of the Partnership
during 2005.
41
Interest of Non-controlling Partners in the
Partnerships Net Income. The interest of
non-controlling partners in the Partnerships net income
decreased by $3.6 million to income of $4.7 million
for the year ended December 31, 2005 compared to income of
$8.2 million for the year ended December 31, 2004 due
to the changes show in the following summary:
|
|
|
|
|
|
|
|
|
|
|
For the Year
|
|
|
|
Ended December 31,
|
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Net income for the Partnership
|
|
$
|
19,200
|
|
|
$
|
23,704
|
|
(Income) allocation to CEI for the
general partner incentive distribution
|
|
|
(10,660
|
)
|
|
|
(5,550
|
)
|
Stock-based compensation costs
allocated to CEI for its stock options and restricted stock
granted to Partnership officers, employees and directors
|
|
|
2,223
|
|
|
|
|
|
(Income) allocation to CEI for its
2% general partner share of Partnership (income)
|
|
|
(215
|
)
|
|
|
(363
|
)
|
|
|
|
|
|
|
|
|
|
Net income allocable to limited
partners
|
|
|
10,548
|
|
|
|
17,791
|
|
Less: CEIs share of net
(income) allocable to limited partners
|
|
|
(6,337
|
)
|
|
|
(9,841
|
)
|
Plus: Non-controlling
partners share of net income in Crosstex Denton County
Gathering, J.V.
|
|
|
441
|
|
|
|
289
|
|
|
|
|
|
|
|
|
|
|
Non-controlling partners
share of Partnership net income
|
|
$
|
4,652
|
|
|
$
|
8,239
|
|
|
|
|
|
|
|
|
|
|
The general partner incentive distributions increased between
these years due to an increase in the distribution amounts per
unit and due to an increase in the number of common units
outstanding.
Critical
Accounting Policies
The selection and application of accounting policies is an
important process that has developed as our business activities
have evolved and as the accounting rules have developed.
Accounting rules generally do not involve a selection among
alternatives, but involve an implementation and interpretation
of existing rules, and the use of judgment to the specific set
of circumstances existing in our business. Compliance with the
rules necessarily involves reducing a number of very subjective
judgments to a quantifiable accounting entry or valuation. We
make every effort to properly comply with all applicable rules
on or before their adoption, and we believe the proper
implementation and consistent application of the accounting
rules is critical. Our critical accounting policies are
discussed below. For further details on our accounting policies
and a discussion of new accounting pronouncements, see
Note 2 of the Notes to Consolidated Financial Statements.
Revenue Recognition and Commodity Risk
Management. We recognize revenue for sales or
services at the time the natural gas or natural gas liquids are
delivered or at the time the service is performed. We generally
accrue one to two months of sales and the related gas purchases
and reverse these accruals when the sales and purchases are
actually invoiced and recorded in the subsequent months. Actual
results could differ from the accrual estimates.
We utilize extensive estimation procedures to determine the
sales and cost of gas purchase accruals for each accounting
cycle. Accruals are based on estimates of volumes flowing each
month from a variety of sources. We use actual measurement data,
if it is available, and will use such data as producer/shipper
nominations, prior month average daily flows, estimated flow for
new production and estimated end-user requirements (all adjusted
for the estimated impact of weather patterns) when actual
measurement data is not available. Throughout the month or two
following production, actual measured sales and transportation
volumes are received and invoiced and used in a process referred
to as actualization. Through the actualization
process, any estimation differences recorded through the accrual
are reflected in the subsequent months accounting cycle
when the accrual is reversed and actual amounts are recorded.
Actual volumes purchased, processed or sold may differ from the
estimates due to a variety of factors including, but not limited
to: actual wellhead production or customer requirements being
higher or lower than the amount nominated at the beginning of
the month; liquids recoveries being higher or lower than
estimated because gas processed through the plants was richer or
leaner than estimated; the estimated impact of weather patterns
being different from the actual impact on sales and purchases;
and pipeline maintenance or allocation
42
causing actual deliveries of gas to be different than estimated.
We believe that our accrual process for the one to two months of
sales and purchases provides a reasonable estimate of such sales
and purchases.
The Partnership engages in price risk management activities in
order to minimize the risk from market fluctuations in the price
of natural gas and natural gas liquids. The Partnership manages
its price risk related to future physical purchase or sale
commitments by entering into either corresponding physical
delivery contracts or financial instruments with an objective to
balance its future commitments and significantly reduce its risk
to the movement in natural gas prices.
Prior to January 1, 2001, financial instruments which
qualified for hedge accounting were accounted for using the
deferral method of accounting, whereby unrealized gains and
losses were generally not recognized until the physical delivery
required by the contracts was made.
Effective January 1, 2001, we adopted Statement of
Financial Accounting Standards No. 133
(SFAS No. 133), Accounting for
Derivative Instruments and Hedging Activities. In accordance
with SFAS No. 133, all derivatives and hedging
instruments are recognized as assets or liabilities at fair
value. If a derivative qualifies for hedge accounting, changes
in the fair value can be offset against the change in the fair
value of the hedged item through earnings or recognized in other
comprehensive income until such time as the hedged item is
recognized in earnings.
The Partnership conducts off-system gas marketing
operations as a service to producers on systems that the Company
does not own. The Partnership refers to these activities as part
of energy trading activities. In some cases, the Partnership
earns an agency fee from the producer for arranging the
marketing of the producers natural gas. In other cases,
the Partnership purchases the natural gas from the producer and
enters into a sales contract with another party to sell the
natural gas.
The Partnership manages its price risk related to future
physical purchase or sale commitments for its Commercial
Services activities by entering into either corresponding
physical delivery contracts or financial instruments with an
objective to balance the Companys future commitments and
significantly reduce its risk to the movement in natural gas
prices. However, the Company is subject to counterparty risk for
both the physical and financial contracts. Prior to
October 26, 2002, the Company accounted for its Commercial
Services natural gas marketing activities as energy trading
contracts in accordance with
EITF 98-10,
Accounting for Contracts Involved in Energy Trading and Risk
Management Activities.
EITF 98-10
required energy-trading contracts to be recorded at fair value
with changes in fair value reported in earnings. In October
2002, the EITF reached a consensus to rescind EITF
No. 98-10.
Accordingly, energy trading contracts entered into subsequent to
October 25, 2002, should be accounted for under accrual
accounting rather than
mark-to-market
accounting unless the contracts meet the requirements of a
derivative under SFAS No. 133. The Companys
energy trading contracts qualify as derivatives, and
accordingly, the Company continues to use
mark-to-market
accounting for both physical and financial contracts of its
Commercial Services business. Accordingly, any gain or loss
associated with changes in the fair value of derivatives and
physical delivery contracts relating to the Companys
Commercial Services natural gas marketing activities are
recognized in earnings as profit or loss on energy trading
immediately.
For each reporting period, the Partnership records the fair
value of open energy trading contracts based on the difference
between the quoted market price and the contract price.
Accordingly, the change in fair value from the previous period
in addition to the realized gains or losses on settled
activities are reported as profit or loss on energy trading
activities in the statements of operations.
Sales of Securities by Subsidiaries. We
recognize gains and losses in the consolidated statements of
operations resulting from subsidiary sales of additional equity
interest, including the Partnerships limited partnership
units, to unrelated parties.
Impairment of Long-Lived Assets. In accordance
with Statement of Financial Accounting Standards No. 144,
Accounting for the Impairment or Disposal of Long-Lived
Assets, we evaluate the long-lived assets, including related
intangibles, of identifiable business activities for impairment
when events or changes in circumstances indicate, in
managements judgment, that the carrying value of such
assets may not be recoverable. The determination of whether
impairment has occurred is based on managements estimate
of undiscounted future cash flows attributable to the assets as
compared to the carrying value of the assets. If impairment has
occurred, the amount of
43
the impairment recognized is determined by estimating the fair
value for the assets and recording a provision for loss if the
carrying value is greater than fair value.
When determining whether impairment of one of our long-lived
assets has occurred, we must estimate the undiscounted cash
flows attributable to the asset. Our estimate of cash flows is
based on assumptions regarding the purchase and resale margins
on natural gas, volume of gas available to the asset, markets
available to the asset, operating expenses, and future natural
gas prices and NGL product prices. The amount of availability of
gas to an asset is sometimes based on assumptions regarding
future drilling activity, which may be dependent in part on
natural gas prices. Projections of gas volumes and future
commodity prices are inherently subjective and contingent upon a
number of variable factors, including but not limited to:
|
|
|
|
|
changes in general economic conditions in regions in which our
markets are located;
|
|
|
|
the availability and prices of natural gas supply;
|
|
|
|
the Partnerships ability to negotiate favorable sales
agreements;
|
|
|
|
the risks that natural gas exploration and production activities
will not occur or be successful;
|
|
|
|
the Partnerships dependence on certain significant
customers, producers, and transporters of natural gas; and
|
|
|
|
competition from other midstream companies, including major
energy producers.
|
Any significant variance in any of the above assumptions or
factors could materially affect our cash flows, which could
require us to record an impairment of an asset.
Liquidity
and Capital Resources
Cash Flows. Net cash provided by operating
activities was $113.8 million for the year ended
December 31, 2006 compared to cash provided by operations
of $12.8 million for the year ended December 31, 2005.
Income before non-cash income and expenses was
$88.2 million in 2006 and $61.7 million in 2005.
Changes in working capital provided $25.3 million in cash
flows from operating activities in 2006 and used
$48.9 million in cash flows from operating activities in
2005. Income before non-cash income and expenses increased
between years primarily due to asset acquisitions, as discussed
in Results of Operations Year Ended
December 31, 2006 Compared to Year Ended December 31,
2005. Changes in working capital are primarily due to the
timing of collections at the end of the quarterly periods. The
Partnership collects and pays large receivables and payables at
the end of each calendar month and the timing of these payments
and receipts may vary by a day or two between month-end periods,
causing these fluctuations.
Net cash used in investing activities was $885.8 million
and $614.8 million for the year ended December 31,
2006 and 2005, respectively. Net cash used in investing
activities during 2006 related to the $504.7 million Chief
acquisition ($474.9 million paid to Chief,
$0.4 million of direct acquisition costs and
$29.4 million for assumed capital expenditure liabilities
paid by us after acquisition), the $51.7 million Hanover
acquisition, the $16.5 million acquisition of our
additional interest in the Blue Water processing plant and the
$6.3 million Cardinal Gas Solutions acquisition. Costs for
the year ended December 31, 2006 associated with the
pipeline and processing plant construction, the connection of
new wells to various systems, pipeline integrity projects,
pipeline relocations and various other internal growth projects
totaled $314.9 million. The most significant projects
included in 2006 costs were the construction of the NTP of
$48.2 million, construction of a processing plant in Parker
County for the North Texas Assets of $76.1 million,
the construction of the North Louisiana Pipeline expansion of
$38.5 million and the expansion of the North Texas Assets
acquired from Chief of $31.0 million. Net cash used in
investing activities during 2005 related to the acquisition of
the El Paso assets ($489.4 million), the Graco assets
($9.3 million) and the Cardinal assets ($6.7 million).
The remaining cash used in investing activities for 2005 related
to internal growth projects including expenditures of the
approximately $80.0 million for the NTP project,
$21.2 million for buying, refurbishing and installing
treating plants and $19.9 million for expansions, well
connections and other capital projects on the pipeline,
gathering and processing assets.
Net cash provided by financing activities was
$769.7 million and $592.4 million for the years ended
December 31, 2006 and 2005, respectively. Financing
activities for 2006 related to equity from issuance of
44
common stock of $179.7 million, net proceeds from issuance
of Partnership units of $179.2 million, net borrowings
under the Partnerships amended credit facility of
$166.0 million and net borrowings under the
Partnerships senior secured notes of $298.5 million.
We paid dividends on our common stock of $34.7 million in
the year ended December 31, 2006 compared to
$21.6 million in the year ended December 31, 2005.
Distributions to non-controlling partners in the Partnership
totaled $34.5 million in 2006 compared to distributions of
$15.2 million in 2005 due to increases in the distribution
levels between years and due to increases in the number of units
outstanding. Drafts payable increased by $18.1 million
providing cash in 2006 compared to a decrease in drafts payable
of $8.8 million requiring use of cash in 2005. In order to
reduce its interest costs, the Partnership borrows money to fund
outstanding checks as they are presented to the bank.
Fluctuations in drafts payable are caused by timing of
disbursements, cash receipts and draws on the Partnerships
revolving credit facility.
Off-Balance Sheet Arrangements. We had no
off-balance sheet arrangements as of December 31, 2006 and
2005.
June 2006 Sale of Senior Subordinated Series C
Units. On June 29, 2006, the Partnership
issued an aggregate of 12,829,650 senior subordinated
series C units representing limited partner interests of
the Partnership in a private equity offering for net proceeds of
$359.3 million. The senior subordinated series C units
were issued at $28.06 per unit, which represented a
discount of 25% to the market value of common units on such
date. We purchased 6,414,830 of the senior subordinated
series C units. In addition, the Partnerships general
partner made a contribution of $9.0 million in connection
with the issuance to maintain its 2% general partner interest.
The senior subordinated series C units will automatically
convert to common units representing limited partner interests
of the Partnership on the first date on or before
February 16, 2008 that conversion is permitted by the
Partnerships partnership agreement at a ratio of one
common unit for each senior subordinated series C unit.
June 2006 Sale of Capital Stock. On
June 29, 2006, we issued 7,650,780 shares of common
stock in a private placement for total net proceeds of
$179.9 million. Lubar Equity Fund, LLC, an affiliate of one
of our directors, purchased 468,210 of the shares at a purchase
price of $25.633 per share and unrelated third parties
purchased 7,182,570 shares at a purchase price of
$23.39 per share. We used the proceeds of stock issuance to
purchase $180.0 million of senior subordinated
series C units representing limited partner interests of
the Partnership described in June 2006
Issuance of Senior Subordinated Series C Units
above.
November 2005 Sale of Senior Subordinated B
Units. On November 1, 2005, the Partnership
issued 2,850,165 senior subordinated series B units in a
private placement for a purchase price of $36.84 per unit.
The Partnership received net proceeds of approximately
$107.1 million, including the $2.1 million capital
contribution from its general partner and net of expenses
associated with the sale. The senior subordinated series B
units automatically converted into common units on
November 14, 2005 at a ratio of one common unit for each
senior subordinated series B unit and were not entitled to
distributions paid on November 14, 2005.
November 2005 Public Offering. In November and
December 2005, the Partnership issued 3,731,050 common
units to the public at a purchase price of $33.25 per unit.
The offering resulted in net proceeds to the Partnership of
$120.9 million, including the $2.5 million capital
contribution from its general partner and net of expenses
associated with the offering.
June 2005 Sale of Senior Subordinated
Units. In June 2005, the Partnership issued
1,495,410 senior subordinated units in a private equity offering
for net proceeds of $51.1 million, including our
$1.1 million capital contribution. These units
automatically converted to common units on a
one-for-one
basis on February 24, 2006. The senior subordinated units
received no distributions until their conversion to common units
in February 2006.
Bank Credit Facility. On June 29, 2006,
the Partnership amended its bank credit facility increasing
availability under the facility to $1.0 billion. The bank
credit agreement includes procedures for additional financial
institutions selected by the Partnership to become lenders under
the agreement, or for any existing lender to increase its
commitment in an amount approved by the Partnership and the
lender, subject to a maximum of $300.0 million for all such
increases in commitments of new or existing lenders. The
maturity date was also extended to June 2011.
Senior Secured Notes. In March 2006, the
Partnership issued $60.0 million aggregate principal amount
of senior secured notes with an interest rate of 6.32% and a
maturity of ten years. In July 2006, the Partnership issued
45
$245.0 million aggregate principal amount of senior secured
notes with an interest rate of 6.96% and a maturity of ten years.
Capital Requirements of the Partnership. The
natural gas gathering, transmission, treating and processing
businesses are capital-intensive, requiring significant
investment to maintain and upgrade existing operations. The
Partnerships capital requirements have consisted primarily
of, and it anticipates will continue to be:
|
|
|
|
|
maintenance capital expenditures, which are capital expenditures
made to replace partially or fully depreciated assets in order
to maintain existing operating capacity of the
Partnerships assets and to extend their useful lives, or
other capital expenditures which do not increase the
Partnerships cash flows; and
|
|
|
|
growth capital expenditures such as those to acquire additional
assets to grow the Partnerships business, to expand and
upgrade gathering systems, transmission capacity, processing
plants or treating plants, and to construct or acquire new
pipelines, processing plants or treating plants.
|
Given the Partnerships objective of growth through
acquisitions and large capital expansions, it anticipates that
it will continue to invest significant amounts of capital to
grow and to build and acquire assets. The Partnership actively
considers a variety of assets for potential development or
acquisition.
The Partnership believes that cash generated from operations
will be sufficient to meet its present quarterly distribution
level of $0.56 per quarter and to fund a portion of its
anticipated capital expenditures through December 31, 2006.
Total capital expenditures are budgeted to be approximately
$260.0 million in 2007. The Partnership expects to fund the
remaining capital expenditures from the proceeds of borrowings
under the revolving credit facility discussed below and with
future issuances of units. The Partnerships ability to pay
distributions to its unit holders and to fund planned capital
expenditures and to make acquisitions will depend upon its
future operating performance, which will be affected by
prevailing economic conditions in its industry and financial,
business and other factors, some of which are beyond its control.
Total Contractual Cash Obligations. A summary
of the Partnerships total contractual cash obligations as
of December 31, 2006, is as follows:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
Total
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
Thereafter
|
|
|
|
(In millions)
|
|
|
Long-Term Debt
|
|
$
|
987.1
|
|
|
$
|
10.0
|
|
|
$
|
9.4
|
|
|
$
|
9.4
|
|
|
$
|
20.3
|
|
|
$
|
520.0
|
|
|
$
|
418.0
|
|
Capital Lease Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
|
103.2
|
|
|
|
18.7
|
|
|
|
17.8
|
|
|
|
17.1
|
|
|
|
16.0
|
|
|
|
16.0
|
|
|
|
17.6
|
|
Unconditional Purchase Obligations
|
|
|
4.6
|
|
|
|
4.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Long-Term Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Obligations
|
|
$
|
1,094.9
|
|
|
$
|
33.3
|
|
|
$
|
27.2
|
|
|
$
|
26.5
|
|
|
$
|
36.3
|
|
|
$
|
536.0
|
|
|
$
|
435.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The above table does not include any physical or financial
contract purchase commitments for natural gas.
The unconditional purchase obligations for 2007 relate to
purchase commitments for equipment. The Partnership has also
committed to contract for 150,000 MMBtus/day of firm
transportation capacity on a pipeline that is expected to be in
service in the fourth quarter of 2008. This commitment is not
reflected in the summary above since the pipeline is not yet
constructed.
46
Description
of Indebtedness
As of December 31, 2006 and 2005, long-term debt consisted
of the following:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Bank credit facility, interest
based on Prime or LIBOR plus an applicable margin, interest
rates at December 31, 2006 and 2005 were 7.20% and 6.69%,
respectively
|
|
$
|
488,000
|
|
|
$
|
322,000
|
|
Senior secured notes, weighted
average interest rate of 6.76% and 6.64%, respectively
|
|
|
498,530
|
|
|
|
200,000
|
|
Note payable to Florida Gas
Transmission Company
|
|
|
600
|
|
|
|
650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
987,130
|
|
|
|
522,650
|
|
Less current portion
|
|
|
(10,012
|
)
|
|
|
(6,521
|
)
|
|
|
|
|
|
|
|
|
|
Debt classified as long-term
|
|
$
|
977,118
|
|
|
$
|
516,129
|
|
|
|
|
|
|
|
|
|
|
On June 29, 2006, the Partnership amended its bank credit
facility, increasing availability under the facility to
$1.0 billion and extending the maturity date from November
2010 to June 2011. The bank credit agreement includes procedures
for additional financial institutions selected by the
Partnership to become lenders under the agreement, or for any
existing lender to increase its commitment in an amount approved
by the Partnership and the lender, subject to a maximum of
$300 million for all such increases in commitments of new
or existing lenders.
The credit facility was used for the El Paso, Chief and
Hanover acquisitions and will be used to finance the acquisition
and development of gas gathering, treating, and processing
facilities, as well as general partnership purposes. At
December 31, 2006, $564.3 million was outstanding
under the credit facility, including $76.3 million of
letters of credit, leaving approximately $453.7 available for
future borrowings. The credit facility will mature in June 2011,
at which time it will terminate and all outstanding amounts
shall be due and payable. Amounts borrowed and repaid under the
credit facility may be re-borrowed.
The obligations under the bank credit facility are secured by
first priority liens on all of the Partnerships material
pipeline, gas gathering, treating, and processing assets, all
material working capital assets and a pledge of all of its
equity interests in certain of its subsidiaries, and rank
pari passu in right of payment with the senior secured
notes. The bank credit facility is guaranteed by certain of the
Partnerships subsidiaries and by the Partnership. The
Partnership may prepay all loans under the bank credit facility
at any time without premium or penalty (other than customary
LIBOR breakage costs), subject to certain notice requirements.
Under the amended credit agreement, borrowings bear interest at
the Partnerships option at the administrative agents
reference rate plus 0% to 0.25% or LIBOR plus 1.00% to 1.75%.
The applicable margin varies quarterly based on its leverage
ratio. The fees charged for letters of credit range from 1.00%
to 1.75% per annum, plus a fronting fee of 0.125% per
annum. The Partnership will incur quarterly commitment fees
based on the unused amount of the credit facilities. The
amendment to the credit facility also adjusted financial
covenants requiring the Partnership to maintain:
|
|
|
|
|
an initial ratio of total funded debt to consolidated earnings
before interest, taxes, depreciation and amortization (each as
defined in the credit agreement), measured quarterly on a
rolling four-quarter basis, of 5.25 to 1.00, pro forma for any
asset acquisitions. The maximum leverage ratio is reduced to
4.75 to 1.00 beginning July 1, 2007 and further reduces to
4.25 to 1.00 on January 1, 2008. The maximum leverage ratio
increases to 5.25 to 1.00 during an acquisition adjustment
period, as defined in the credit agreement; and
|
|
|
|
a minimum interest coverage ratio (as defined in the credit
agreement), measured quarterly on a rolling four quarter basis,
equal to 3.0 to 1.0.
|
Additionally, the bank credit facility was amended to allow for
borrowings under the Partnerships senior secured note
shelf agreement to increase from $260 million to
$510 million.
47
The credit agreement prohibits the Partnership from declaring
distributions to unitholders if any event of default, as defined
in the credit agreement, exists or would result from the
declaration of distributions. In addition, the bank credit
facility contains various covenants that, among other
restrictions, limit the Partnerships ability to:
|
|
|
|
|
incur indebtedness;
|
|
|
|
grant or assume liens;
|
|
|
|
make certain investments;
|
|
|
|
sell, transfer, assign or convey assets, or engage in certain
mergers or acquisitions;
|
|
|
|
make distributions;
|
|
|
|
change the nature of its business;
|
|
|
|
enter into certain commodity contracts;
|
|
|
|
make certain amendments to its or the operating
partnerships partnership agreement; and
|
|
|
|
engage in transactions with affiliates.
|
Each of the following will be an event of default under the bank
credit facility:
|
|
|
|
|
failure to pay any principal, interest, fees, expenses or other
amounts when due;
|
|
|
|
failure to observe any agreement, obligation, or covenant in the
credit agreement, subject to cure periods for certain failures;
|
|
|
|
certain judgments against the Partnership or any of its
subsidiaries, in excess of certain allowances;
|
|
|
|
certain ERISA events involving the Partnership or its
subsidiaries;
|
|
|
|
cross defaults to certain material indebtedness;
|
|
|
|
certain bankruptcy or insolvency events involving the
Partnership or its subsidiaries;
|
|
|
|
a change in control (as defined in the credit
agreement); and
|
|
|
|
the failure of any representation or warranty to be materially
true and correct when made.
|
In November 2006, the Partnership entered into an interest rate
swap covering a principal amount of $50.0 million in the
credit facility for a period of three years. The Partnership is
subject to interest rate risk on its credit facility. The
interest rate swap reduces this risk by fixing the LIBOR rate,
prior to credit margin, at 4.95%, on $50.0 million of
related debt outstanding over the term of the swap agreement
which expires on November 30, 2009. The Partnership has
elected not to designate this swap as a cash flow hedge for
FAS 133 accounting treatment. Accordingly, unrealized gains
or losses relating to the swap flow through the Consolidated
Statement of Operations as adjustments to interest expense over
the period hedged. The fair value of the interest rate swap at
December 31, 2006 was a $0.1 million asset.
48
Senior Secured Notes. The Partnership entered
into a master shelf agreement with an institutional lender in
2003 that was amended in subsequent years to increase
availability under the agreement, to $510.0 million,
pursuant to which the Partnership issued the following senior
secured notes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Month Issued
|
|
Amount
|
|
|
Interest Rate
|
|
|
Maturity
|
|
|
|
(In thousands)
|
|
|
|
|
|
June 2003
|
|
$
|
30,000
|
|
|
|
6.95
|
%
|
|
|
7 years
|
|
July 2003
|
|
|
10,000
|
|
|
|
6.88
|
%
|
|
|
7 years
|
|
June 2004
|
|
|
75,000
|
|
|
|
6.96
|
%
|
|
|
10 years
|
|
November 2005
|
|
|
85,000
|
|
|
|
6.23
|
%
|
|
|
10 years
|
|
March 2006
|
|
|
60,000
|
|
|
|
6.32
|
%
|
|
|
10 years
|
|
July 2006
|
|
|
245,000
|
|
|
|
6.96
|
%
|
|
|
10 years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total issued
|
|
|
505,000
|
|
|
|
|
|
|
|
|
|
Principal repaid
|
|
|
(6,470
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31,
2006
|
|
$
|
498,530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
These notes represent senior secured obligations and will rank
at least pari passu in right of payment with the bank
credit facility. The notes are secured, on an equal and ratable
basis with the Partnerships obligations under the credit
facility, by first priority liens on all of its material
pipeline, gas gathering and processing assets, all material
working capital assets and a pledge of all of its equity
interests in certain of its subsidiaries. The senior secured
notes are guaranteed by the Partnership and its significant
subsidiaries.
The $40.0 million of senior secured notes issued in 2003
are redeemable, at the Partnerships option and subject to
certain notice requirements, at a purchase price equal to 100%
of the principal amount together with accrued interest, plus a
make-whole amount determined in accordance with the master shelf
agreement. The senior secured notes issued in 2004, 2005 and
2006 provide for a call premium of 103.5% of par beginning three
years after issuance at rates declining from 103.5% to 100.0%.
The notes are not callable prior to three years after issuance.
During 2007 the notes may also incur an additional fee each
quarter ranging from 0.08% to 0.15% per annum on the
outstanding borrowings if the Partnerships leverage ratio,
as defined in the agreement, exceeds certain levels during such
quarterly period.
The master shelf agreement relating to the notes contains
substantially the same covenants and events of default as the
bank credit facility.
If an event of default resulting from bankruptcy or other
insolvency events occurs, the senior secured notes will become
immediately due and payable. If any other event of default
occurs and is continuing, holders of more than 50.1% in
principal amount of the outstanding notes may at any time
declare all the notes then outstanding to be immediately due and
payable. If an event of default relating to nonpayment of
principal, make-whole amounts or interest occurs, any holder of
outstanding notes affected by such event of default may declare
all the notes held by such holder to be immediately due and
payable.
The Partnership was in compliance with all debt covenants at
December 31, 2006 and 2005 and expects to be in compliance
for the next twelve months.
Intercreditor and Collateral Agency
Agreement. In connection with the execution of
the master shelf agreement in June 2003, the lenders under the
bank credit facility and the initial purchasers of the senior
secured notes entered into an Intercreditor and Collateral
Agency Agreement, which was acknowledged and agreed to by the
Partnerships operating partnership and its subsidiaries.
As amended in 2005, this agreement appoints Bank of America,
N.A. to act as collateral agent and authorized the bank to
execute various security documents on behalf of the lenders
under the bank credit facility and the purchases of the senior
secured notes. This agreement specifies various rights and
obligations of lenders under the bank credit facility, holders
of senior secured notes and the other parties thereto in respect
of the collateral securing Crosstex Energy Services, L.P.s
obligations under the bank credit facility and the master shelf
agreement.
49
Inflation
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our results of
operations for the years ended December 31, 2004, 2005 or
2006. Although the impact of inflation has been insignificant in
recent years, it is still a factor in the United States economy
and may increase the cost to acquire or replace property, plant
and equipment and may increase the costs of labor and supplies.
To the extent permitted by competition, regulation and the
Partnerships existing agreements, it has and will continue
to pass along increased costs to our customers in the form of
higher fees.
Environmental
and Other Contingencies
The Partnerships operations are subject to environmental
laws and regulations adopted by various governmental authorities
in the jurisdictions in which these operations are conducted.
The Partnership believes it is in material compliance with all
applicable laws and regulations. For a more complete discussion
of the environmental laws and regulations that impact us. See
Item 1. Business Environmental
Matters.
Recent
Accounting Pronouncements
In June 2006, the Financial Accounting Standards Board, or FASB,
issued FASB Interpretation No. 48
(FIN 48), Accounting for Uncertainty
in Income Taxes. FIN 48 is an interpretation of
FASB Statement No. 109, Accounting for Income
Taxes and must be adopted no later than
January 1, 2007. FIN 48 prescribes a comprehensive
model for recognizing, measuring, presenting and disclosing in
the financial statements uncertain tax positions taken or
expected to be taken.
On September 13, 2006, the Securities Exchange Commission,
or SEC issued Staff Accounting Bulletin No. 108
(SAB 108), which establishes an approach that
requires quantification of financial statement errors based on
the effects of the error on each of the companys financial
statements and the related disclosures. SAB 108 requires
the use of a balance sheet and an income statement approach to
evaluate whether either of these approaches results in
quantifying a misstatement that, when all relevant quantitative
and qualitative factors are considered, is material.
Disclosure
Regarding Forward-Looking Statements
This Annual Report on
Form 10-K
contains forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as
amended, that are based on information currently available to
management as well as managements assumptions and beliefs.
All statements, other than statements of historical fact,
included in this
Form 10-K
constitute forward-looking statements, including but not limited
to statements identified by the words may,
will, should, plan,
predict, anticipate,
believe, intend, estimate
and expect and similar expressions. Such statements
reflect our current views with respect to future events, based
on what we believe are reasonable assumptions; however, such
statements are subject to certain risks and uncertainties. In
addition to the specific uncertainties discussed elsewhere in
this
Form 10-K,
the risk factors set forth in Item 1A. Risk
Factors may affect our performance and results of
operations. Should one or more of these risks or uncertainties
materialize, or should underlying assumptions prove incorrect,
actual results may differ materially from those in the
forward-looking statements. We disclaim any intention or
obligation to update or review any forward-looking statements or
information, whether as a result of new information, future
events or otherwise.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
Market risk is the risk of loss arising from adverse changes in
market rates and prices. The Partnerships primary market
risk is the risk related to changes in the prices of natural gas
and natural gas liquids. In addition, it is also exposed to the
risk of changes in interest rates on its floating rate debt.
50
Interest
Rate Risk
The Partnership is exposed to interest rate risk on short-term
and long-term debt carrying variable interest rates. At
December 31, 2006 and 2005, the Partnerships variable
rate debt had a carrying value of $488.6 million and
$322.7 million, respectively, which approximated its fair
value, and the Partnerships fixed rate debt had a carrying
value of $498.5 million and $200.0 million,
respectively, and an approximately fair value of
$503.9 million and $203.9 million, respectively. The
Partnership attempts to balance variable rate debt, fixed rate
debt and debt maturities to manage interest cost, interest rate
volatility and financing risk. This is accomplished through a
mix of bank debt with short-term variable rates and fixed rate
senior and subordinated debt. In addition, the Partnership
entered into an interest rate swap in November 2006 covering
$50.0 million of the variable rate debt for a period of
three years.
The following table shows the carrying amount and fair value of
long-term debt and the hypothetical change in fair value that
would result from a 100-basis point change in interest rates.
Unless otherwise noted, the hypothetical change in fair value
could be a gain or a loss depending on whether interest rates
increase or decrease.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hypothetical
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Change in
|
|
|
|
Amount
|
|
|
Value(a)
|
|
|
Fair Value
|
|
|
|
(In millions)
|
|
|
December 31, 2006 Long-term
debt
|
|
$
|
(987.1
|
)
|
|
$
|
(996.9
|
)
|
|
$
|
9.8
|
|
December 31, 2005 Long-term
debt
|
|
$
|
(522.7
|
)
|
|
$
|
(529.8
|
)
|
|
$
|
7.1
|
|
|
|
|
(a) |
|
Fair value is based upon current market quotes and is the
estimated amount required to purchase our long-term debt on the
open market. This estimated value does not include any
redemption premium. |
Commodity
Price Risk
Approximately 5.9% of the natural gas the Partnership markets is
purchased at a percentage of the relevant natural gas index
price, as opposed to a fixed discount to that price. As a result
of purchasing the natural gas at a percentage of the index
price, the Partnerships resale margins are higher during
periods of high natural gas prices and lower during periods of
lower natural gas prices. As of December 31, 2006, the
Partnership has hedged approximately 78% of its exposure to
natural gas price fluctuations through December 2007 and
approximately 70% of its exposure to gas price fluctuations for
the first quarter of 2008. The Partnership also has hedges in
place covering at least 100% of the minimum liquid volumes it
expects to receive through the end of 2007 and approximately 25%
for the first quarter of 2008 at its south Louisiana assets, and
81% of the liquids at its other assets in 2007 and 40% for the
first quarter of 2008.
Another price risk the Partnership faces is the risk of
mismatching volumes of gas bought or sold on a monthly price
versus volumes bought or sold on a daily price. The Partnership
enters each month with a balanced book of gas bought and sold on
the same basis. However, it is normal to experience fluctuations
in the volumes of gas bought or sold under either basis, which
leaves it with short or long positions that must be covered. The
Partnership uses financial swaps to mitigate the exposure at the
time it is created to maintain a balanced position.
The Partnership has commodity price risk associated with its
processed volumes of natural gas. The Partnership currently
processes gas under four main types of contractual arrangements:
1. Keep-whole contracts: Under this type of contract, the
Partnership pays the producer for the full amount of inlet gas
to the plant, and makes a margin based on the difference between
the value of liquids recovered from the processed natural gas as
compared to the value of the natural gas volumes lost
(shrink) in processing. The Partnerships
margins from these contracts are high during periods of high
liquids prices relative to natural gas prices, and can be
negative during periods of high natural gas prices relative to
liquids prices. The Partnership controls its risk on our current
keep-whole contracts through its ability to bypass processing
when it is not profitable.
2. Percent of proceeds contracts: Under these contracts,
The Partnership receives a fee in the form of a percentage of
the liquids recovered, and the producer bears all the cost of
the natural gas shrink. Therefore, its margins from these
contracts are greater during periods of high liquids prices. The
Partnerships margins from
51
processing cannot become negative under percent of proceeds
contracts, but decline during periods of low NGL prices.
3. Theoretical processing contracts: Under these contracts,
the Partnership stipulates with the producer the assumptions
under which it will assume processing economics for settlement
purposes, independent of actual processing results or whether
the stream was actually processed. These contracts tend to have
an inverse result to the keep-whole contracts, with better
margins as processing economics worsen.
4. Fee-based contracts: Under these contracts the
Partnership has no commodity price exposure, and is paid a fixed
fee per unit of volume that is treated or conditioned.
The Partnerships primary commodity risk management
objective is to reduce volatility in its cash flows. The
Partnership maintains a Risk Management Committee, including
members of senior management, which oversees all hedging
activity. The Partnership enters into hedges for natural gas and
NGLs using NYMEX futures or
over-the-counter
derivative financial instruments with only certain
well-capitalized counterparties which have been approved by its
Risk Management Committee.
The use of financial instruments may expose the Partnership to
the risk of financial loss in certain circumstances, including
instances when (1) sales volumes are less than expected
requiring market purchases to meet commitments or
(2) counterparties fail to purchase the contracted
quantities of natural gas or otherwise fail to perform. To the
extent that the Partnership engages in hedging activities it may
be prevented from realizing the benefits of favorable price
changes in the physical market. However, the Partnership is
similarly insulated against unfavorable changes in such prices.
The Partnership manages its price risk related to future
physical purchase or sale commitments for its producer services
activities by entering into either corresponding physical
delivery contracts or financial instruments with an objective to
balance its future commitments and significantly reduce its risk
to the movement in natural gas prices. However, the Partnership
is subject to counterparty risk for both the physical and
financial contracts. The Partnership accounts for certain of its
producer services natural gas marketing activities as energy
trading contracts or derivatives. These energy-trading contracts
are recorded at fair value with changes in fair value reported
in earnings. Accordingly, any gain or loss associated with
changes in the fair value of derivatives and physical delivery
contracts relating to its producer services natural gas
marketing activities are recognized in earnings as profit or
loss on energy trading contracts immediately.
For each reporting period, we record the fair value of open
energy trading contracts based on the difference between the
quoted market price and the contract price. Accordingly, the
change in fair value from the previous period is reported as a
gain or loss on derivatives in the statement of operations.
Realized gains and losses from settled contracts accounted for
as cash flow hedges are recorded in Midstream Revenue. As of
December 31, 2006, outstanding natural gas swap agreements,
NGL swap agreements, swing swap agreements, storage swap
agreements and other derivative instruments were a net fair
value asset of $10.4 million, excluding the fair value
asset of $1.7 million associated with the natural gas
liquids puts. The aggregate effect of a hypothetical 10%
increase in gas and NGLs prices would result in a decrease of
approximately $4.8 million in the net fair value asset of
these contracts as of December 31, 2006. The value of the
natural gas liquids puts would also decrease as a result of an
increase in NGLs prices but we are unable to determine the
impact of a 10% price change. Our maximum loss on these puts is
the remaining $1.7 million recorded fair value for the puts.
Credit
Risk
The Partnership is diligent in attempting to ensure that it
issues credit to only credit-worthy customers. However, its
purchase and resale of gas exposes it to significant 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 the Partnerships overall
profitability.
52
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
The Report of Independent Registered Public Accounting Firm,
Consolidated Financial Statements and supplementary financial
data required by this Item are set forth on pages F-1 through
F-46 of this Report and are incorporated herein by reference.
|
|
Item 9.
|
Changes
in and Disagreements With Accountants on Accounting and
Financial Disclosure
|
None.
|
|
Item 9A.
|
Controls
and Procedures
|
|
|
(a)
|
Evaluation
of Disclosure Controls and Procedures
|
We carried out an evaluation, under the supervision and with the
participation of our management, including our Chief Executive
Officer and Chief Financial Officer, of the design and operating
effectiveness of our disclosure controls and procedures as of
the end of the period covered by this report pursuant to
Exchange Act
Rules 13a-15
and 15d-15.
Based on that evaluation, our Chief Executive Officer and Chief
Financial Officer concluded that our disclosure controls and
procedures were effective as of December 31, 2006 in
alerting them in a timely manner to material information
required to be disclosed in our reports filed with the
Securities and Exchange Commission.
|
|
(b)
|
Changes
in Internal Control over Financial Reporting
|
There has been no change in our internal controls over financial
reporting that occurred in the three months ended
December 31, 2006 that has materially affected, or is
reasonably likely to materially affect, our internal controls
over financial reporting.
Internal
Control over Financial Reporting
See Managements Report on Internal Control over
Financial Reporting on
page F-2.
|
|
Item 9B.
|
Other
Information
|
None.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
The following table shows information about our executive
officers. Executive officers serve until their successors are
elected or appointed.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position with Crosstex Energy GP, LLC
|
|
Barry E. Davis(1)
|
|
|
45
|
|
|
President, Chief Executive Officer
and Director
|
Robert S. Purgason
|
|
|
50
|
|
|
Executive Vice
President Chief Operating Officer
|
James R. Wales
|
|
|
53
|
|
|
Executive Vice
President Commercial
|
A. Chris Aulds
|
|
|
45
|
|
|
Executive Vice
President Public and Governmental Affairs
|
Jack M. Lafield
|
|
|
56
|
|
|
Executive Vice
President Corporate Development
|
William W. Davis(1)
|
|
|
53
|
|
|
Executive Vice President and Chief
Financial Officer
|
Joe A. Davis(1)
|
|
|
46
|
|
|
Executive Vice President, General
Counsel and Secretary
|
Danny Thompson
|
|
|
57
|
|
|
Senior Vice President
Engineering and Operations
|
53
Barry E. Davis, President, Chief Executive Officer and
Director, led the management buyout of the midstream assets of
Comstock Natural Gas, Inc. in December 1996, which transaction
resulted in the formation of our predecessor. Mr. Davis was
President and Chief Operating Officer of Comstock Natural Gas
and founder of Ventana Natural Gas, a gas marketing and pipeline
company that was purchased by Comstock Natural Gas.
Mr. Davis started Ventana Natural Gas in June 1992. Prior
to starting Ventana, he was Vice President of Marketing and
Project Development for Endevco, Inc. Before joining Endevco,
Mr. Davis was employed by Enserch Exploration in the
marketing group. Mr. Davis also serves as a director of
Crosstex Energy GP, LLC, the general partner of the general
partner of the Partnership. Mr. Davis holds a B.B.A. in
Finance from Texas Christian University.
Robert S. Purgason, Executive Vice President
Chief Operating Officer, joined Crosstex in October 2004 to lead
the Treating Division and was promoted to Executive Vice
President Chief Operating Officer in November 2006.
Prior to joining Crosstex, Mr. Purgason spent 19 years
with Williams Companies in various senior business development
and operational roles. He was most recently Vice President of
the Gulf Coast Region Midstream Business Unit. Mr. Purgason
began his career at Perry Gas Companies in Odessa working in all
facets of the treating business. Mr. Purgason received a
B.S. degree in Chemical Engineering with honors from the
University of Oklahoma.
James R. Wales, Executive Vice President Commercial,
joined our predecessor in December 1996. As one of the founders
of Sunrise Energy Services, Inc., he helped build Sunrise into a
major national independent natural gas marketing company, with
sales and service volumes in excess of 600,000 MMBtu/d.
Mr. Wales started his career as an engineer with Union
Carbide. In 1981, he joined Producers Gas Company, a subsidiary
of Lear Petroleum Corp., and served as manager of its
Mid-Continent office. In 1986, he joined Sunrise as Executive
Vice President of Supply, Marketing and Transportation. From
1993 to 1994, Mr. Wales was the Chief Operating Officer of
Triumph Natural Gas, Inc., a private midstream business. Prior
to joining Crosstex, Mr. Wales was Vice President for
Teco Gas Marketing Company. Mr. Wales holds a B.S.
degree in Civil Engineering from the University of Michigan, and
a Law degree from South Texas College of Law.
A. Chris Aulds, Executive Vice President Public and
Governmental Affairs, together with Barry E. Davis, participated
in the management buyout of Comstock Natural Gas in December
1996. Mr. Aulds joined Comstock Natural Gas, Inc. in
October 1994 as a result of the acquisition by Comstock of the
assets and operations of Victoria Gas Corporation.
Mr. Aulds joined Victoria in 1990 as Vice President
responsible for gas supply, marketing and new business
development and was directly involved in the providing of risk
management services to gas producers. Prior to joining Victoria,
Mr. Aulds was employed by Mobil Oil Corporation as a
production engineer before being transferred to Mobils gas
marketing division in 1989. There he assisted in the creation
and implementation of Mobils third- party gas supply
business segment. Mr. Aulds holds a B.S. degree in
Petroleum Engineering from Texas Tech University.
Jack M. Lafield, Executive Vice President Corporate
Development, joined our predecessor in August 2000. For five
years prior to joining Crosstex, Mr. Lafield was Managing
Director of Avia Energy, an energy consulting group, and was
involved in all phases of acquiring, building, owning and
operating midstream assets and natural gas reserves. He also
provided project development and consulting in domestic and
international energy projects to major industry and financing
organizations, including development, engineering, financing,
implementation and operations. Prior to consulting,
Mr. Lafield held positions of President and Chief Executive
Officer of Triumph Natural Gas, a private midstream business he
founded, President and Chief Operating Officer of Nagasco, Inc.
(a joint venture with Apache Corporation), President of
Producers Gas Company, and Senior Vice President of Lear
Petroleum Corp. Mr. Lafield holds a B.S. degree in Chemical
Engineering from Texas A&M University, and is a graduate of
the Executive Program at Stanford University.
William W. Davis, Executive Vice President and Chief
Financial Officer, joined our predecessor in September 2001, and
has 25 years of finance and accounting experience. Prior to
joining our predecessor, Mr. Davis held various positions
with Sunshine Mining and Refining Company from 1983 to September
2001, including Vice President-Financial Analysis from 1983
to 1986, Senior Vice President and Chief Accounting Officer from
1986 to 1991 and Executive Vice President and Chief Financial
Officer from 1991 to 2001. In addition, Mr. Davis served as
Chief Operating Officer in 2000 and 2001. Mr. Davis
graduated magna cum laude from Texas A&M University with a
B.B.A. in Accounting and is a Certified Public Accountant.
54
Joe A. Davis, Executive Vice President, General Counsel
and Secretary joined Crosstex in October 2005. He began his
legal career with the Dallas firm of Worsham Forsythe, which
merged with the international law firm of Hunton &
Williams in 2002. Most recently, he served as a partner in the
firms Energy Practice Group, and served on the firms
Executive Committee. Mr. Davis specialized in facility
development, sales, acquisitions and financing for the energy
industry, representing entrepreneurial start up/development
companies, growth companies, large public corporations and large
electric and gas utilities. He received his J.D. from Baylor Law
School in Waco and his bachelor of science from the University
of Texas in Dallas.
Danny L. Thompson, Senior Vice President
Engineering and Operations, has held various leadership
positions within the midstream energy industry. From March 2005
until August 2005 when he became an employee of Crosstex, he
worked with Crosstex as a consultant. Prior to joining Crosstex,
he worked for Cantera Natural Gas L.L.C. as vice president,
operations and engineering and CMS Field Services as director of
engineering and operations. Mr. Thompson holds a
bachelors degree in chemical engineering from Texas
A&I University in Kingsville, and he is a registered
professional engineer in Texas.
Code of
Ethics
We adopted a Code of Business Conduct and Ethics applicable to
all of our employees, including all officers, and including our
independent directors, who are not employees, with regard to
company-related activities. The Code of Business Conduct and
Ethics incorporates guidelines designed to deter wrongdoing and
to promote honest and ethical conduct and compliance with
applicable laws and regulations. The Code also incorporates our
expectations of our employees that enable us to provide accurate
and timely disclosure in our filings with the Securities and
Exchange Commission and other public communications. A copy of
our Code of Business Conduct and Ethics will be provided to any
person, without charge, upon request. Contact Denise LeFevre at
214-721-9245
to request a copy of a charter or send your request to Crosstex
Energy, Inc., Attn: Denise LeFevre, 2501 Cedar Springs, Dallas,
Texas 75201. If any substantive amendments are made to the Code
of Business Conduct and Ethics or if we grant any waiver,
including any implicit waiver, from a provision of the code to
any of our executive officers and directors, we will disclose
the nature of such amendment or waiver in a report on
Form 8-K.
Other
The sections entitled Election of Directors,
Additional Information Regarding the Board of
Directors, Section 16(a) Beneficial Ownership
Reporting Compliance, and Stockholder Proposals and
Other Matters that appear in our proxy statement for the
2007 annual meeting of stockholders (see 2007 Proxy
Statement), set forth certain information with respect to
our directors and with respect to reporting under
Section 16(a) of the Securities Exchange Act of 1934, and
are incorporated herein by reference.
|
|
Item 11.
|
Executive
Compensation
|
The section entitled Executive Compensation that
appears in the 2007 Proxy Statement sets forth certain
information with respect to the compensation of our management,
and, except for the report of the Compensation Committee of our
board of directors on executive compensation, is incorporated
herein by reference.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
The sections entitled Security Ownership of Certain
Beneficial Owners and Management that appears in the 2007
Proxy Statement set forth certain information with respect to
securities authorized for issuance under equity compensation
plans and the ownership of voting securities and equity
securities of us, and are incorporated herein by reference.
|
|
Item 13.
|
Certain
Relationships and Related Transactions and Director
Independence
|
The section entitled Certain Relationships and Related
Party Transactions that appears in the 2007 Proxy
Statement sets forth certain information with respect to certain
relationships and related party transactions, and is
incorporated herein by reference.
55
|
|
Item 14.
|
Principal
Accounting Fees and Services
|
The section entitled Auditors that appears in the
2007 Proxy Statement sets forth certain information with respect
to accounting fees and services, and is incorporated herein by
reference.
PART IV
|
|
Item 15.
|
Exhibits
and Financial Statement Schedules
|
(a) Financial Statements and Schedules
(1) See the Index to Financial Statements on
page F-1.
(2) See Schedule I Parent Company
Statements on
page F-40
and Schedule II Valuation and Qualifying
Accounts on
Page F-46.
(3) Exhibits
The exhibits filed as part of this report are as follows
(exhibits incorporated by reference are set forth with the name
of the registrant, the type of report and registration number or
last date of the period for which it was filed, and the exhibit
number in such filing):
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
3
|
.1
|
|
|
|
Amended and Restated Certificate
of Incorporation of Crosstex Energy, Inc. (incorporated by
reference from Exhibit 3.1 to Crosstex Energy, Inc.s
Current Report on
Form 8-K
dated October 26, 2006, filed with the Commission on
October 31, 2006).
|
|
3
|
.2
|
|
|
|
Third Amended and Restated Bylaws
of Crosstex Energy, Inc. (incorporated by reference from
Exhibit 3.1 to Crosstex Energy, Inc.s Current Report
on
Form 8-K
dated March 22, 2006, filed with the Commission on
March 28, 2006).
|
|
3
|
.3
|
|
|
|
Certificate of Limited Partnership
of Crosstex Energy, L.P. (incorporated by reference from
Exhibit 3.1 to Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file No.
333-97779).
|
|
3
|
.4
|
|
|
|
Fifth Amended and Restated
Agreement of Limited Partnership of Crosstex Energy Services,
L.P., dated as of June 29, 2006 (incorporated by reference
to Exhibit 3.1 to Crosstex Energy, L.P.s Current
Report on
Form 8-K
dated June 29, 2006, filed with the Commission on
July 6, 2006).
|
|
3
|
.5
|
|
|
|
Certificate of Limited Partnership
of Crosstex Energy Services, L.P. (incorporated by reference
from Exhibit 3.3 to Crosstex Energy, L.P.s
Registration Statement on
Form S-1,
file No.
333-97779).
|
|
3
|
.6
|
|
|
|
Second Amended and Restated
Agreement of Limited Partnership of Crosstex Energy Services,
L.P., dated as of April 1, 2004 (incorporated by reference
from Exhibit 3.5 to Crosstex Energy, L.P.s Quarterly
Report on
Form 10-Q
for the quarterly period ended March 31, 2004).
|
|
3
|
.7
|
|
|
|
Certificate of Limited Partnership
of Crosstex Energy GP, L.P. (incorporated by reference from
Exhibit 3.5 to Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file No.
333-97779).
|
|
3
|
.8
|
|
|
|
Agreement of Limited Partnership
of Crosstex Energy GP, L.P., dated as of July 12, 2002
(incorporated by reference from Exhibit 3.6 to Crosstex
Energy L.P.s Registration Statement on
Form S-1,
file
No. 333-97779).
|
|
3
|
.9
|
|
|
|
Certificate of Formation of
Crosstex Energy GP, LLC (incorporated by reference from
Exhibit 3.7 from Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file
No. 333-97779).
|
|
3
|
.10
|
|
|
|
Amended and Restated Limited
Liability Company Agreement of Crosstex Energy GP, LLC, dated as
of December 17, 2002 (incorporated by reference from
Exhibit 3.8 from Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file No.
333-106927).
|
|
3
|
.11
|
|
|
|
Amended and Restated Certificate
of Formation of Crosstex Holdings GP, LLC (incorporated by
reference from Exhibit 3.11 to Crosstex Energy, Inc.s
Registration Statement on
Form S-1,
file
No. 333-110095).
|
|
3
|
.12
|
|
|
|
Limited Liability Company
Agreement of Crosstex Holdings GP, LLC, dated as of
October 27, 2003 (incorporated by reference from
Exhibit 3.12 to Crosstex Energy, Inc.s Registration
Statement on
Form S-1,
file
No. 333-110095).
|
56
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
3
|
.13
|
|
|
|
Certificate of Formation of
Crosstex Holdings LP, LLC (incorporated by reference from
Exhibit 3.13 to Crosstex Energy, Inc.s Registration
Statement on
Form S-1,
file
No. 333-110095).
|
|
3
|
.14
|
|
|
|
Limited Liability Company
Agreement of Crosstex Holdings LP, LLC, dated as of
November 4, 2003 (incorporated by reference from
Exhibit 3.14 to Crosstex Energy, Inc.s Registration
Statement on
Form S-1,
file
No. 333-110095).
|
|
3
|
.15
|
|
|
|
Amended and Restated Certificate
of Limited Partnership of Crosstex Holdings, L.P. (incorporated
by reference from Exhibit 3.15 to Crosstex Energy,
Inc.s Registration Statement on
Form S-1,
file
No. 333-110095).
|
|
3
|
.16
|
|
|
|
Agreement of Limited Partnership
of Crosstex Holdings, L.P., dated as of November 4, 2003
(incorporated by reference from Exhibit 3.16 to Crosstex
Energy, Inc.s Registration Statement on
Form S-1,
file
No. 333-110095).
|
|
4
|
.1
|
|
|
|
Specimen Certificate representing
shares of common stock (incorporated by reference from
Exhibit 4.1 to Crosstex Energy, Inc.s Registration
Statement on
Form S-1,
file No.
333-110095).
|
|
4
|
.2
|
|
|
|
Registration Rights Agreement,
dated as of June 29, 2006, by and among Crosstex Energy,
Inc., Chieftain Capital Management, Inc., Kayne Anderson MLP
Investment Company, Kayne Anderson Energy Total Return Fund,
Inc., LB I Group Inc., Lubar Equity Fund, LLC and Tortoise North
American Energy Corp. (incorporated by reference to
Exhibit 4.1 to our Current Report on Form 8-K dated
June 29, 2006, filed with the Commission on July 6,
2006).
|
|
10
|
.1
|
|
|
|
Omnibus Agreement dated
December 17, 2002, among Crosstex Energy, Inc. and certain
other parties (incorporated by reference from Exhibit 10.5
to Crosstex Energy, L.P.s Annual Report on
Form 10-K
for the year ended December 31, 2002, file No. 000-50067).
|
|
10
|
.2
|
|
|
|
Form of Indemnity Agreement
(incorporated by reference from Exhibit 10.2 to Crosstex
Energy, Inc.s Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
10
|
.3
|
|
|
|
Crosstex Energy GP, LLC Long-Term
Incentive Plan dated July 12, 2002 (incorporated by
reference from Exhibit 10.4 to Crosstex Energy, L.P.s
Annual Report on
Form 10-K,
file No. 000-50067).
|
|
10
|
.4
|
|
|
|
Amendment to Crosstex Energy GP,
LLC Long-Term Incentive Plan, dated May 2, 2005
(incorporated by reference to Exhibit 10.1 to Crosstex
Energy, L.P.s Current Report on
Form 8-K
dated May 2, 2005, filed with the Commission on May 6,
2005).
|
|
10
|
.5
|
|
|
|
Agreement Regarding 2003
Registration Rights Agreement and Termination of
Stockholders Agreement, dated October 27, 2003
(incorporated by reference from Exhibit 10.4 to Crosstex
Energy, Inc.s Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
10
|
.6
|
|
|
|
Crosstex Energy, Inc. Amended and
Restated Long-Term Incentive Plan effective as of
September 6, 2006 (incorporated by reference to
Exhibit 10.1 to Crosstex Energy, Inc.s Current Report
on
Form 8-K
dated October 26, 2006, filed with the Commission on
October 31, 2006).
|
|
10
|
.7
|
|
|
|
Registration Rights Agreement,
dated December 31, 2003 (incorporated by reference from
Exhibit 10.6 to Crosstex Energy, Inc.s Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
10
|
.8
|
|
|
|
Fourth Amended and Restated Credit
Agreement, dated November 1, 2005, among Crosstex Energy
Services, L.P., Bank of America, N.A. and certain other parties
(incorporated by reference to Exhibit 10.1 to Crosstex
Energy, L.P.s Current Report on
Form 8-K
dated November 1, 2005, filed with the Commission on
November 3, 2005).
|
|
10
|
.9
|
|
|
|
First Amendment to Fourth Amended
and Restated Credit Agreement, dated as of February 24,
2006, among Crosstex Energy, L.P., Bank of America, N.A. and
certain other parties (incorporated by reference to
Exhibit 10.2 to Crosstex Energy, L.P.s Current Report
on
Form 8-K
dated March 13, 2006, filed with the Commission on
March 16, 2006).
|
|
10
|
.10
|
|
|
|
Second Amendment to Fourth Amended
and Restated Credit Agreement, dated as of June 29, 2006,
among Crosstex Energy, L.P., Bank of America, N.A. and certain
other parties (incorporated by reference to Exhibit 10.1 to
Crosstex Energy, L.P.s Current Report on
Form 8-K
dated June 29, 2006, filed with the Commission on
July 6, 2006).
|
|
10
|
.11
|
|
|
|
Amended and Restated Note Purchase
Agreement, dated as of July 25, 2006, among Crosstex
Energy, L.P. and the Purchasers listed on the Purchaser Schedule
attached thereto (incorporated by reference to Exhibit 10.1
to Crosstex Energy, L.P.s Current Report on
Form 8-K
dated July 25, 2006, filed with the Commission on
July 28, 2006).
|
57
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
10
|
.12
|
|
|
|
Purchase and Sale Agreement, dated
as of May 1, 2006, by and between Crosstex Energy Services,
L.P., Chief Holdings LLC and the other parties named therein
(incorporated by reference to Exhibit 10.1 to Crosstex
Energy, L.P.s Current Report on
Form 8-K
dated May 1, 2006, filed with the Commission on May 4,
2006).
|
|
10
|
.13
|
|
|
|
Seminole Gas Processing Plant
Gaines County, Texas Joint Operating Agreement dated
January 1, 1993 (incorporated by reference to
Exhibit 10.10 to Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file
No. 333-106927).
|
|
10
|
.14
|
|
|
|
Stock Purchase Agreement, dated as
of May 16, 2006, by and among Crosstex Energy, L.P. and
each of the Purchasers set forth on Schedule A thereto
(incorporated by reference to Exhibit 10.2 to our Current
Report on Form 8-K dated May 16, 2006, filed with the
Commission on May 17, 2006).
|
|
10
|
.15
|
|
|
|
Senior Subordinated Series C
Unit Purchase Agreement, dated May 16, 2006, by and among
Crosstex Energy, L.P. and each of the Purchasers set forth on
Schedule A thereto (incorporated by reference to
Exhibit 10.1 to our Current Report on Form 8-K dated
May 16, 2006, filed with the Commission on May 17,
2006).
|
|
10
|
.16
|
|
|
|
Registration Rights Agreement,
dated as of June 29, 2006, by and among Crosstex Energy,
L.P., Chieftain Capital Management, Inc., Energy Income and
Growth Fund, Fiduciary/Claymore MLP Opportunity Fund, Kayne
Anderson MLP Investment Company, Kayne Anderson Energy Total
Return Fund, Inc., LB I Group Inc., Tortoise Energy
Infrastructure Corporation, Lubar Equity Fund, LLC and Crosstex
Energy, Inc. (incorporated by reference to Exhibit 4.1 to
Crosstex Energy, L.P.s Current Report on Form 8-K
dated June 29, 2006, filed with the Commission on
July 6, 2006).
|
|
21
|
.1*
|
|
|
|
List of Subsidiaries.
|
|
23
|
.1*
|
|
|
|
Consent of KPMG LLP.
|
|
31
|
.1*
|
|
|
|
Certification of the Principal
Executive Officer.
|
|
31
|
.2*
|
|
|
|
Certification of the Principal
Financial Officer.
|
|
32
|
.1*
|
|
|
|
Certification of the Principal
Executive Officer and the Principal Financial Officer of the
Company pursuant to 18 U.S.C. Section 1350.
|
|
|
|
* |
|
Filed herewith. |
|
|
|
As required by Item 14(a)(3), this exhibit is identified as
a compensatory benefit plan or arrangement |
58
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of
the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized, on the 28th day of
February 2007.
CROSSTEX ENERGY, INC.
Barry E. Davis,
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the Registrant and in the capacities and on
the dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
/s/ BARRY
E. DAVIS
Barry
E. Davis
|
|
President, Chief Executive Officer
and Director (Principal Executive Officer)
|
|
February 28, 2007
|
|
|
|
|
|
/s/ FRANK
M. BURKE
Frank
M. Burke
|
|
Director
|
|
February 28, 2007
|
|
|
|
|
|
/s/ JAMES
C. CRAIN
James
C. Crain
|
|
Director
|
|
February 28, 2007
|
|
|
|
|
|
/s/ BRYAN
H. LAWRENCE
Bryan
H. Lawrence
|
|
Chairman of the Board
|
|
February 28, 2007
|
|
|
|
|
|
/s/ SHELDON
B. LUBAR
Sheldon
B. Lubar
|
|
Director
|
|
February 28, 2007
|
|
|
|
|
|
/s/ CECIL
E. MARTIN
Cecil
E. Martin
|
|
Director
|
|
February 28, 2007
|
|
|
|
|
|
/s/ ROBERT
F. MURCHISON
Robert
F. Murchison
|
|
Director
|
|
February 28, 2007
|
|
|
|
|
|
/s/ WILLIAM
W. DAVIS
William
W. Davis
|
|
Executive Vice President and
Chief
Financial Officer (Principal Financial and Accounting Officer)
|
|
February 28, 2007
|
59
INDEX TO
FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page
|
|
Crosstex Energy, Inc. Consolidated
Financial Statements:
|
|
|
|
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
|
|
|
F-7
|
|
|
|
|
F-8
|
|
|
|
|
F-9
|
|
|
|
|
F-10
|
|
Crosstex Energy, Inc. Financial
Statement Schedules:
|
|
|
|
|
Schedule I Parent
Company Statements:
|
|
|
|
|
|
|
|
F-43
|
|
|
|
|
F-44
|
|
|
|
|
F-45
|
|
Schedule II
Valuation and Qualifying Accounts:
|
|
|
|
|
|
|
|
F-46
|
|
F-1
MANAGEMENTS
REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Crosstex Energy, Inc. is responsible for
establishing and maintaining adequate internal control over
financial reporting
(Rule 13a-15(f)
under the Securities Exchange Act of 1934, as amended) and for
the assessment of the effectiveness of internal control over
financial reporting for Crosstex Energy, Inc. (the
Company). As defined by the Securities and Exchange
Commission
(Rule 13a-15(f)
under the Securities Exchange Act of 1934, as amended), internal
control over financial reporting is a process designed by, or
under the supervision of Crosstex Energy, Inc.s principal
executive and principal financial officers and effected by its
Board of Directors, management and other personnel, to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of the consolidated financial
statements in accordance with U.S. generally accepted
accounting principles.
The Companys internal control over financial reporting is
supported by written policies and procedures that
(1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the
Companys transactions and dispositions of the
Companys assets; (2) provide reasonable assurance
that transactions are recorded as necessary to permit
preparation of the consolidated financial statements in
accordance with U.S. generally accepted accounting
principles, and that receipts and expenditures of the
Partnership are being made only in accordance with authorization
of the Companys management and directors; and
(3) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use or disposition
of the Companys assets that could have a material effect
on the consolidated financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In connection with the preparation of the Companys annual
consolidate financial statements, management has undertaken an
assessment of the effectiveness of the Companys internal
control over financial reporting as of December 31, 2006,
based on criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO Framework).
Managements assessment included an evaluation of the
design of the Companys internal control over financial
reporting and testing of the operational effectiveness of those
controls.
Based on this assessment, management has concluded that as of
December 31, 2006, the Companys internal control over
financial reporting was effective to provide reasonable
assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in
accordance with U.S. generally accepted accounting
principles.
KPMG LLP, the independent registered public accounting firm that
audited the Companys consolidated financial statements
included in this report, has issued an attestation report on
managements assessment of internal control over financial
reporting, a copy of which appears on
page F-4
of this Annual Report on
Form 10-K.
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and the Stockholders of Crosstex
Energy, Inc.:
We have audited the accompanying consolidated balance sheets of
Crosstex Energy, Inc. (a Delaware corporation) and subsidiaries
as of December 31, 2006 and 2005, and the related
consolidated statements of operations, changes in
stockholders equity, comprehensive income, and cash flows
for each of the years in the three-year period ended
December 31, 2006. In connection with our audits of the
consolidated financial statements, we also have audited the
accompanying financial statement schedules. These consolidated
financial statements and financial statement schedules are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these consolidated
financial statements and financial statement schedules based on
our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Crosstex Energy, Inc. and subsidiaries as of
December 31, 2006 and 2005, and the results of their
operations, comprehensive income, and their cash flows for each
of the years in the three-year period ended December 31,
2006, in conformity with U.S. generally accepted accounting
principles. Also in our opinion, the related financial statement
schedules, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly, in all
material respects, the information set forth therein.
As discussed in note 2 to the consolidated financial
statements, effective January 1, 2006, Crosstex Energy,
Inc. and subsidiaries adopted the provisions of Statement of
Financial Accounting Standards No. 123 (revised 2004),
Share Based Payment.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Crosstex Energy, Inc.s internal control
over financial reporting as of December 31, 2006, based on
criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), and our report dated
February 28, 2007, expressed an unqualified opinion on
managements assessment of, and the effective operation of,
internal control over financial reporting.
KPMG LLP
Dallas, Texas
February 28, 2007
F-3
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Crosstex Energy, Inc.:
We have audited managements assessment, included in the
accompanying Managements Report on Internal Control Over
Financial Reporting, that Crosstex Energy, Inc. and subsidiaries
(a Delaware corporation) maintained effective internal control
over financial reporting as of December 31, 2006, based on
criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Companys management is
responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness
of internal control over financial reporting. Our responsibility
is to express an opinion on managements assessment and an
opinion on the effectiveness of the Partnerships internal
control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, evaluating
managements assessment, testing and evaluating the design
and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that Crosstex
Energy, Inc. and subsidiaries maintained effective internal
control over financial reporting as of December 31, 2006,
is fairly stated, in all material respects, based on criteria
established in Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Also, in our opinion, the Company maintained,
in all material respects, effective internal control over
financial reporting as of December 31, 2006, based on
criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations (COSO).
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Crosstex Energy, Inc. and
subsidiaries as of December 31, 2006 and 2005, and the
related consolidated statements of operations, changes in
stockholders equity, comprehensive income, and cash flows
for each of the years in the three-year period ended
December 31, 2006, and our report dated February 28,
2007 expressed an unqualified opinion on those consolidated
financial statements.
Dallas, Texas
February 28, 2007
F-4
CROSSTEX
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
10,635
|
|
|
$
|
12,904
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade, net of allowance for bad
debts of $618 and $260, respectively
|
|
|
35,787
|
|
|
|
60,067
|
|
Accrued revenues
|
|
|
331,236
|
|
|
|
368,860
|
|
Imbalances
|
|
|
5,159
|
|
|
|
7,834
|
|
Note receivable
|
|
|
926
|
|
|
|
845
|
|
Other
|
|
|
2,864
|
|
|
|
4,896
|
|
Fair value of derivative assets
|
|
|
23,048
|
|
|
|
12,205
|
|
Natural gas and natural gas
liquids, prepaid expenses and other
|
|
|
10,574
|
|
|
|
28,772
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
420,229
|
|
|
|
496,383
|
|
Property and equipment:
|
|
|
|
|
|
|
|
|
Transmission assets
|
|
|
335,599
|
|
|
|
194,235
|
|
Gathering systems
|
|
|
285,706
|
|
|
|
36,653
|
|
Gas plants
|
|
|
460,822
|
|
|
|
389,083
|
|
Other property and equipment
|
|
|
32,304
|
|
|
|
27,770
|
|
Construction in process
|
|
|
129,373
|
|
|
|
98,142
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment
|
|
|
1,243,804
|
|
|
|
745,883
|
|
Accumulated depreciation
|
|
|
(136,562
|
)
|
|
|
(77,251
|
)
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
1,107,242
|
|
|
|
668,632
|
|
Account receivable from Enron
|
|
|
|
|
|
|
1,068
|
|
Fair value of derivative assets
|
|
|
3,812
|
|
|
|
7,633
|
|
Intangible assets, net of
accumulated amortization of $31,673 and $7,674, respectively
|
|
|
638,602
|
|
|
|
255,197
|
|
Goodwill
|
|
|
25,396
|
|
|
|
7,570
|
|
Other assets, net
|
|
|
11,417
|
|
|
|
8,842
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,206,698
|
|
|
$
|
1,445,325
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Drafts payable
|
|
$
|
47,948
|
|
|
$
|
29,855
|
|
Accounts payable
|
|
|
31,764
|
|
|
|
16,574
|
|
Accrued gas purchases
|
|
|
325,151
|
|
|
|
360,458
|
|
Accrued imbalances payable
|
|
|
2,855
|
|
|
|
30,515
|
|
Accrued construction in process
costs
|
|
|
29,942
|
|
|
|
10,545
|
|
Fair value of derivative liabilities
|
|
|
12,141
|
|
|
|
14,782
|
|
Current portion of long-term debt
|
|
|
10,012
|
|
|
|
6,521
|
|
Other current liabilities
|
|
|
30,507
|
|
|
|
22,260
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
490,320
|
|
|
|
491,510
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative liabilities
|
|
|
2,558
|
|
|
|
3,577
|
|
Deferred tax liability
|
|
|
66,186
|
|
|
|
58,136
|
|
Long-term debt
|
|
|
977,118
|
|
|
|
516,129
|
|
Interest of non-controlling
partners in the Partnership
|
|
|
391,103
|
|
|
|
241,726
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock
(150,000,000 shares authorized, $.01 par value,
45,941,187 and 12,760,158 issued and outstanding in 2006 and
2005, respectively)
|
|
|
463
|
|
|
|
127
|
|
Additional paid-in capital
|
|
|
263,264
|
|
|
|
80,187
|
|
Retained earnings
|
|
|
13,535
|
|
|
|
31,747
|
|
Accumulated other comprehensive
income
|
|
|
2,151
|
|
|
|
(814
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
279,413
|
|
|
|
111,247
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
stockholders equity
|
|
$
|
2,206,698
|
|
|
$
|
1,445,325
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
F-5
CROSSTEX
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream
|
|
$
|
3,073,069
|
|
|
$
|
2,982,874
|
|
|
$
|
1,948,021
|
|
Treating
|
|
|
66,225
|
|
|
|
48,606
|
|
|
|
30,755
|
|
Profit on energy trading activities
|
|
|
2,510
|
|
|
|
1,568
|
|
|
|
2,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
3,141,804
|
|
|
|
3,033,048
|
|
|
|
1,981,004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream purchased gas
|
|
|
2,859,815
|
|
|
|
2,860,823
|
|
|
|
1,861,204
|
|
Treating purchased gas
|
|
|
9,463
|
|
|
|
9,706
|
|
|
|
5,274
|
|
Operating expenses
|
|
|
101,036
|
|
|
|
56,768
|
|
|
|
38,396
|
|
General and administrative
|
|
|
47,707
|
|
|
|
34,145
|
|
|
|
22,005
|
|
Impairments
|
|
|
|
|
|
|
|
|
|
|
981
|
|
(Gain) loss on derivatives
|
|
|
(1,599
|
)
|
|
|
9,968
|
|
|
|
(279
|
)
|
Gain on sale of property
|
|
|
(2,108
|
)
|
|
|
(8,138
|
)
|
|
|
(12
|
)
|
Depreciation and amortization
|
|
|
82,792
|
|
|
|
36,070
|
|
|
|
23,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
3,097,106
|
|
|
|
2,999,342
|
|
|
|
1,950,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
44,698
|
|
|
|
33,706
|
|
|
|
30,401
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net of interest
income
|
|
|
(51,051
|
)
|
|
|
(15,332
|
)
|
|
|
(9,115
|
)
|
Other income
|
|
|
1,774
|
|
|
|
391
|
|
|
|
802
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(49,277
|
)
|
|
|
(14,941
|
)
|
|
|
(8,313
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before gain on issuance of
units by the Partnership, income taxes and interest of
non-controlling partners in the Partnerships net income
|
|
|
(4,579
|
)
|
|
|
18,765
|
|
|
|
22,088
|
|
Gain on issuance of units of the
Partnership
|
|
|
18,955
|
|
|
|
65,070
|
|
|
|
|
|
Income tax provision
|
|
|
(11,118
|
)
|
|
|
(30,047
|
)
|
|
|
(5,149
|
)
|
Interest of non-controlling
partners in the Partnerships net income (loss)
|
|
|
13,027
|
|
|
|
(4,652
|
)
|
|
|
(8,239
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect
of change in accounting principle
|
|
|
16,285
|
|
|
|
49,136
|
|
|
|
8,700
|
|
Cumulative effect of change in
accounting principle
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,455
|
|
|
$
|
49,136
|
|
|
$
|
8,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
$
|
132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common
|
|
$
|
16,455
|
|
|
$
|
49,136
|
|
|
$
|
8,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect
of change in accounting principle per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.39
|
|
|
$
|
1.29
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.39
|
|
|
$
|
1.26
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in
accounting principle per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.39
|
|
|
$
|
1.29
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.39
|
|
|
$
|
1.26
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
42,168
|
|
|
|
37,956
|
|
|
|
35,547
|
|
Diluted
|
|
|
42,666
|
|
|
|
38,871
|
|
|
|
38,697
|
|
Dividends per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
$
|
0.807
|
|
|
$
|
0.563
|
|
|
$
|
0.327
|
|
Preferred
|
|
|
|
|
|
|
|
|
|
$
|
0.327
|
|
See accompanying notes to consolidated financial statements.
F-6
CROSSTEX
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
Total
|
|
|
|
Preferred Stock
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Treasury
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
Notes
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amt
|
|
|
Shares
|
|
|
Amt
|
|
|
Capital
|
|
|
Stock
|
|
|
Earnings
|
|
|
Income
|
|
|
Receivable
|
|
|
Equity
|
|
|
|
(In thousands, except share data)
|
|
|
Balance, December 31, 2003
|
|
|
4,123,642
|
|
|
$
|
42
|
|
|
|
1,743,032
|
|
|
$
|
19
|
|
|
$
|
68,934
|
|
|
$
|
(2,500
|
)
|
|
$
|
7,549
|
|
|
$
|
506
|
|
|
$
|
(5,284
|
)
|
|
$
|
69,266
|
|
Conversion of preferred to common
|
|
|
(4,123,642
|
)
|
|
|
(42
|
)
|
|
|
8,247,284
|
|
|
|
82
|
|
|
|
(40
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Two-for-one
common stock split
|
|
|
|
|
|
|
|
|
|
|
1,743,032
|
|
|
|
16
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cancellation of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,500
|
)
|
|
|
2,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common units in public
offering, net of offering costs of $1,512
|
|
|
|
|
|
|
|
|
|
|
345,900
|
|
|
|
3
|
|
|
|
4,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,797
|
|
Proceeds from exercise of stock
options
|
|
|
|
|
|
|
|
|
|
|
177,642
|
|
|
|
2
|
|
|
|
947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
949
|
|
Repayment of notes receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,284
|
|
|
|
5,284
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
474
|
|
Preferred dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(132
|
)
|
|
|
|
|
|
|
|
|
|
|
(132
|
)
|
Common dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,903
|
)
|
|
|
|
|
|
|
|
|
|
|
(11,903
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,700
|
|
|
|
|
|
|
|
|
|
|
|
8,700
|
|
Hedging gains or losses
reclassified to earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,469
|
)
|
|
|
|
|
|
|
(1,469
|
)
|
Adjustment in fair value of
derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
967
|
|
|
|
|
|
|
|
967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
12,256,890
|
|
|
|
122
|
|
|
|
72,593
|
|
|
|
|
|
|
|
4,214
|
|
|
|
4
|
|
|
|
|
|
|
$
|
76,933
|
|
Proceeds from exercise of stock
options
|
|
|
|
|
|
|
|
|
|
|
681,039
|
|
|
|
7
|
|
|
|
3,803
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,810
|
|
Shares repurchased and cancelled
|
|
|
|
|
|
|
|
|
|
|
(177,771
|
)
|
|
|
(2
|
)
|
|
|
(8,232
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,234
|
)
|
Capital contribution related to
deferred tax benefits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,185
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,838
|
|
Common dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,603
|
)
|
|
|
|
|
|
|
|
|
|
|
(21,603
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,136
|
|
|
|
|
|
|
|
|
|
|
|
49,136
|
|
Non-controlling partners
share of other comprehensive income in Partnership
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
552
|
|
|
|
|
|
|
|
552
|
|
Hedging gains or losses
reclassified to earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,748
|
|
|
|
|
|
|
|
2,748
|
|
Adjustment in fair value of
derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,118
|
)
|
|
|
|
|
|
|
(4,118
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
12,760,158
|
|
|
|
127
|
|
|
|
80,187
|
|
|
|
|
|
|
|
31,747
|
|
|
|
(814
|
)
|
|
|
|
|
|
|
111,247
|
|
Three-for-one
common stock split
|
|
|
|
|
|
|
|
|
|
|
30,627,458
|
|
|
|
309
|
|
|
|
(309
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock, net of
offering costs of $282
|
|
|
|
|
|
|
|
|
|
|
2,550,260
|
|
|
|
26
|
|
|
|
179,694
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
179,720
|
|
Proceeds from exercise of stock
options
|
|
|
|
|
|
|
|
|
|
|
3,311
|
|
|
|
1
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,567
|
|
Common dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(34,667
|
)
|
|
|
|
|
|
|
|
|
|
|
(34,667
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,455
|
|
|
|
|
|
|
|
|
|
|
|
16,455
|
|
Hedging gains or losses
reclassified to earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,361
|
)
|
|
|
|
|
|
|
(1,361
|
)
|
Adjustment in fair value of
derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,326
|
|
|
|
|
|
|
|
4,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
45,941,187
|
|
|
$
|
463
|
|
|
$
|
263,264
|
|
|
|
|
|
|
$
|
13,535
|
|
|
$
|
2,151
|
|
|
|
|
|
|
$
|
279,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-7
CROSSTEX
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Net income
|
|
$
|
16,455
|
|
|
$
|
49,136
|
|
|
$
|
8,700
|
|
Non-controlling partners
share of other comprehensive income in the Partnership, net of
taxes of $0, $315 and $0, respectively
|
|
|
|
|
|
|
552
|
|
|
|
|
|
Hedging gains or losses
reclassified to earnings, net of taxes of $(779), $1,572 and
$(826), respectively
|
|
|
(1,361
|
)
|
|
|
2,748
|
|
|
|
(1,469
|
)
|
Adjustment in fair value of
derivatives, net of taxes of $2,460, $2,352 and $544,
respectively
|
|
|
4,326
|
|
|
|
(4,118
|
)
|
|
|
967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
19,420
|
|
|
$
|
48,318
|
|
|
$
|
8,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-8
CROSSTEX
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,455
|
|
|
$
|
49,136
|
|
|
$
|
8,700
|
|
Adjustments to reconcile net income
to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
82,792
|
|
|
|
36,070
|
|
|
|
23,034
|
|
Impairments
|
|
|
|
|
|
|
|
|
|
|
981
|
|
Gain on sale of property
|
|
|
(2,108
|
)
|
|
|
(8,138
|
)
|
|
|
(12
|
)
|
Cumulative effect of change in
accounting principle
|
|
|
(170
|
)
|
|
|
|
|
|
|
|
|
Gain on issuance of units of the
Partnership
|
|
|
(18,955
|
)
|
|
|
(65,070
|
)
|
|
|
|
|
Interest of non-controlling
partners in the Partnership net income
|
|
|
(13,027
|
)
|
|
|
4,652
|
|
|
|
8,239
|
|
Deferred tax expense
|
|
|
11,386
|
|
|
|
30,047
|
|
|
|
4,802
|
|
Non-cash stock based compensation
|
|
|
8,579
|
|
|
|
3,672
|
|
|
|
982
|
|
Amortization of debt issue costs
|
|
|
2,694
|
|
|
|
1,127
|
|
|
|
1,015
|
|
Loss on investment in affiliated
partnerships
|
|
|
|
|
|
|
|
|
|
|
(304
|
)
|
Non-cash derivatives loss
|
|
|
550
|
|
|
|
10,208
|
|
|
|
(279
|
)
|
Changes in assets and liabilities
net of acquisition effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable and accrued
revenue
|
|
|
77,324
|
|
|
|
(166,300
|
)
|
|
|
(48,140
|
)
|
Natural gas storage, prepaid
expenses and other
|
|
|
12,999
|
|
|
|
(1,570
|
)
|
|
|
(2,817
|
)
|
Accounts payable, accrued gas
purchased, and other accrued liabilities
|
|
|
(65,694
|
)
|
|
|
132,975
|
|
|
|
50,684
|
|
Fair value of derivatives
|
|
|
|
|
|
|
(13,967
|
)
|
|
|
(473
|
)
|
Other
|
|
|
1,014
|
|
|
|
|
|
|
|
(73
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
113,839
|
|
|
|
12,842
|
|
|
|
46,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment
|
|
|
(314,766
|
)
|
|
|
(120,539
|
)
|
|
|
(45,984
|
)
|
Acquisitions and asset purchases
|
|
|
(576,110
|
)
|
|
|
(505,518
|
)
|
|
|
(78,895
|
)
|
Proceeds from sale of property
|
|
|
5,051
|
|
|
|
10,991
|
|
|
|
611
|
|
(Increase) decrease to other
non-current assets
|
|
|
|
|
|
|
244
|
|
|
|
(115
|
)
|
Distributions from (contributions
to) affiliated partnerships
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(885,825
|
)
|
|
|
(614,822
|
)
|
|
|
(124,371
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from borrowings
|
|
|
1,708,500
|
|
|
|
1,798,250
|
|
|
|
491,500
|
|
Payments on borrowings
|
|
|
(1,244,021
|
)
|
|
|
(1,424,300
|
)
|
|
|
(403,550
|
)
|
Increase (decrease) in drafts
payable
|
|
|
18,094
|
|
|
|
(8,812
|
)
|
|
|
28,221
|
|
Distributions to non-controlling
partners in the Partnership
|
|
|
(34,902
|
)
|
|
|
(15,213
|
)
|
|
|
(12,143
|
)
|
Preferred dividends paid
|
|
|
|
|
|
|
|
|
|
|
(3,603
|
)
|
Common dividends paid
|
|
|
(34,667
|
)
|
|
|
(21,603
|
)
|
|
|
(11,903
|
)
|
Debt refinancing and offering costs
|
|
|
(5,646
|
)
|
|
|
(6,919
|
)
|
|
|
(1,370
|
)
|
Net proceeds from issuance of units
of the Partnership
|
|
|
179,185
|
|
|
|
273,255
|
|
|
|
|
|
Contributions from minority
interest party
|
|
|
|
|
|
|
786
|
|
|
|
|
|
Treasury stock purchased
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock repurchased and
cancelled
|
|
|
|
|
|
|
(8,234
|
)
|
|
|
|
|
Proceeds from exercise of common
stock options
|
|
|
126
|
|
|
|
3,810
|
|
|
|
949
|
|
Proceeds from exercise of
Partnership unit options
|
|
|
3,328
|
|
|
|
1,345
|
|
|
|
425
|
|
Repayment of shareholder notes
|
|
|
|
|
|
|
|
|
|
|
5,284
|
|
Net proceeds from sale of common
and preferred stock
|
|
|
179,720
|
|
|
|
|
|
|
|
5,262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
769,717
|
|
|
|
592,365
|
|
|
|
99,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and
cash equivalents
|
|
|
(2,269
|
)
|
|
|
(9,615
|
)
|
|
|
21,040
|
|
Cash and cash equivalents,
beginning of period
|
|
|
12,904
|
|
|
|
22,519
|
|
|
|
1,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of
period
|
|
$
|
10,635
|
|
|
$
|
12,904
|
|
|
$
|
22,519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
46,794
|
|
|
$
|
14,598
|
|
|
$
|
7,556
|
|
Cash paid for income taxes
|
|
$
|
(847
|
)
|
|
$
|
496
|
|
|
$
|
549
|
|
See accompanying notes to consolidated financial statements.
F-9
CROSSTEX
ENERGY, INC.
December 31, 2006 and 2005
|
|
1.
|
Organization
and Summary of Significant Agreements:
|
|
|
(a)
|
Description
of Business
|
Crosstex Energy, Inc. (the Company and formerly Crosstex Energy
Holdings Inc.), a Delaware corporation formed on April 28,
2000, is engaged, through its subsidiaries, in the gathering,
transmission, treating, processing and marketing of natural gas
and NGLs. The Company connects the wells of natural gas
producers in the geographic areas of its gathering systems in
order to purchase the gas production, treats natural gas to
remove impurities to ensure that it meets pipeline quality
specifications, processes natural gas for the removal of natural
gas liquids or NGLs, transports natural gas and ultimately
provides an aggregated supply of natural gas to a variety of
markets. In addition, the Company purchases natural gas from
producers not connected to its gathering systems for resale and
sells natural gas on behalf of producers for a fee.
|
|
(b)
|
Organization,
Public Offering of Units in CELP and Public Offering of the
Company
|
On July 12, 2002, the Company formed Crosstex Energy, L.P.
(herein referred to as the Partnership or CELP), a Delaware
limited partnership. Crosstex Energy GP, L.P., a wholly owned
subsidiary of the Company, is the general partner of the
Partnership. The Company also owned 7,001,000 subordinated
units, 6,414,830 senior subordinated series C units, and
2,999,000 common units in the Partnership through its
wholly-owned subsidiaries on December 31, 2006 which
represented 42.0% of the limited partner interests in the
Partnership. In February 2007, 2,333,000 of the
Partnerships subordinated units held by the Company
converted to common units so the Companys ownership of
subordinated units is 4,668,000 and common units is 5,332,000
upon this conversion.
In January 2004, the Company completed an initial public
offering of its common stock. In conjunction with the public
offering, the Company converted all of its preferred stock to
common stock, cancelled its treasury stock and made a
two-for-one
stock split, effected in the form of a stock dividend. The
Companys existing shareholders sold 6,918,000 common
shares and the Company issued 1,037,700 common shares at a
public offering price of $6.50 per common share. The
Company received net proceeds of approximately $4.8 million
from the common stock issuance. The Companys existing
stockholders also repaid approximately $4.9 million in
stockholder notes receivable in connection with the public
offering. As of December 31, 2006, Yorktown owns 5.0% of
the Companys outstanding common shares, Company management
and directors own 14.2% of its common shares and the remaining
64.1% is held publicly. Common shares and public offering price
are revised to reflect the
two-for-one
stock split in January 2004 and the
three-for-one
stock split in December 2006.
|
|
(c)
|
Basis
of Presentation
|
The accompanying consolidated financial statements include the
assets, liabilities and results of operations of the Company and
its majority owned subsidiaries, including the Partnership. The
Company proportionately consolidates the Partnerships
undivided 12.4% interest in a carbon dioxide processing plant
acquired by the Partnership in June 2004 and its undivided
59.27% interest in a gas processing plant acquired by the
Partnership in November 2005 (23.85%) and May 2006 (35.42%). In
January 2004, the Company adopted FASB Interpretation
No. 46R, Consolidation of Variable Interest Entities
(FIN No. 46R) and began consolidating its joint
venture interest in Crosstex DC Gathering, J.V. (CDC) as
discussed more fully in Note 5. The consolidated operations
are hereafter referred to collectively as the Company. All
material intercompany balances and transactions have been
eliminated. Certain reclassifications have been made to the
consolidated financial statements for the prior years to conform
to the current presentation.
F-10
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
2.
|
Significant
Accounting Policies
|
|
|
(a)
|
Managements
Use of Estimates
|
The preparation of financial statements in accordance with
accounting principles generally accepted in the United States of
America requires management of the Company to make estimates and
assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts
of revenues and expenses during the period. Actual results could
differ from these estimates.
|
|
(b)
|
Cash
and Cash Equivalents
|
The Company considers all highly liquid investments with an
original maturity of three months or less to be cash equivalents.
|
|
(c)
|
Natural
Gas and Natural Gas Liquids Inventory
|
Inventories of products consist of natural gas and natural gas
liquids. The Company reports these assets at the lower of cost
or market.
|
|
(d)
|
Property,
Plant, and Equipment
|
Property, plant and equipment consists of intrastate gas
transmission systems, gas gathering systems, industrial supply
pipelines, natural gas liquids pipelines, natural gas processing
plants, natural gas liquids (NGLs) fractionation plants, an
undivided 12.4% interest in a carbon dioxide processing plant,
and gas treating plants.
Other property and equipment is primarily comprised of computer
software and equipment, furniture, fixtures, leasehold
improvements and office equipment. Such items are depreciated
over their estimated useful life of three to seven years.
Property, plant and equipment are recorded at cost. Repairs and
maintenance are charged against income when incurred. Renewals
and betterments, which extend the useful life of the properties,
are capitalized. Interest costs are capitalized to property,
plant and equipment during the period the assets are undergoing
preparation for intended use. Interests costs totaling
$5.4 million and $0.9 million were capitalized for the
years ended December 31, 2006 and 2005, respectively. No
interest costs were capitalized in 2004.
Depreciation is provided using the straight-line method based on
the estimated useful life of each asset, as follows:
|
|
|
|
|
|
|
Useful Lives
|
|
|
Transmission assets
|
|
|
15-25 years
|
|
Gathering systems
|
|
|
7-15 years
|
|
Gas treating, gas processing and
carbon dioxide plants
|
|
|
15 years
|
|
Other property and equipment
|
|
|
3-7 years
|
|
Depreciation expense of $68.9 million, $31.7 million
and $21.8 million was recorded for the years ended
December 31, 2006, 2005 and 2004, respectively.
Statement of Financial Accounting Standards No. 144
(SFAS No. 144), Accounting for the Impairment or
Disposal of Long-Lived Assets, requires long-lived assets to
be reviewed whenever events or changes in circumstances indicate
that the carrying value of such assets may not be recoverable.
In order to determine whether an impairment has occurred, the
Company compares the net book value of the asset to the
undiscounted expected future net cash flows. If an impairment
has occurred, the amount of such impairment is determined based
on the expected future net cash flows discounted using a rate
commensurate with the risk associated with the asset. An
impairment of $1.0 million was recorded in the year ended
December 31, 2004. The impairment recorded in 2004 related
to a processing plant owned directly by the Company. This plant
has been inactive since late 2002 when the
F-11
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
operator of the wells behind the plant cancelled its drilling
plan for the area. An impairment on the contracts associated
with the plant was recorded in 2002 but the value of the plant
was not impaired because the Company intended to restart or
relocate the plant. Drilling activity had increased in the area
near the plant and processing margins had improved during 2004
so management decided to more fully evaluate the cost of
restarting this idle plant. During 2004 management determined
that it would be more commercially feasible to put a new plant
at the plant site than to invest the capital necessary to
restart the plant. If the Company does not restart the plant,
our engineers estimate that the plant would receive very little,
if any, value upon the sale of the plant. Therefore, the Company
impaired the full value of the plant during 2004 under
SFAS No. 144.
When determining whether impairment of one of our long-lived
assets has occurred, we must estimate the undiscounted cash
flows attributable to the asset. The Companys estimate of
cash flows is based on assumptions regarding the purchase and
resale margins on natural gas, volume of gas available to the
asset, markets available to the asset, operating expenses, and
future natural gas prices and NGL product prices. The amount of
availability of gas to an asset is sometimes based on
assumptions regarding future drilling activity, which may be
dependent in part on natural gas prices. Projections of gas
volumes and future commodity prices are inherently subjective
and contingent upon a number of variable factors. Any
significant variance in any of the above assumptions or factors
could materially affect our cash flows, which could require us
to record an impairment of an asset.
|
|
(e)
|
Goodwill
and Intangibles
|
The Company has approximately $25.4 million and
$7.6 million of goodwill at December 31, 2006 and
2005, respectively. During the formation of the Partnership in
May 2001, $5.4 million of goodwill was created and later
amortized by $0.5 million. Approximately $1.7 million
and $1.4 million of goodwill resulted from the Cardinal
acquisitions in May 2005 and October 2006, respectively.
Approximately $16.5 million of goodwill resulted from the
Hanover acquisition in February 2006. The goodwill related to
the formation of the Partnership has been allocated to the
Midstream segment and the goodwill resulting from the Cardinal
and Hanover acquisitions is allocated to the Treating segment.
Goodwill is assessed at least annually for impairment. During
the fourth quarter of 2006, the Company completed the annual
impairment testing of goodwill and no impairment was incurred.
Intangible assets consist of customer relationships and the
value of the dedicated and non-dedicated acreage attributable to
pipeline, gathering and processing systems. The El Paso
acquisition as discussed in Note (4) included
$254.0 million of such intangibles. The Chief acquisition,
as discussed in Note (4), included $396.0 million of such
intangibles, including the Devon Energy Corporation (Devon) gas
gathering agreement. Intangible assets other than the
intangibles associated with the Chief acquisition are amortized
on a straight-line basis over the expected period of benefits of
the customer relationships, which range from three to
15 years. The intangible assets associated with the Chief
acquisition are being amortized using the units of throughput
method of amortization. The weighted average amortization period
for intangible assets is 17.7 years. Amortization of
intangibles was approximately $13.9 million,
$4.3 million and $1.2 million for the years ended
December 31, 2006, 2005 and 2004, respectively. As of
December 31, 2006, accumulated amortization of intangible
assets was $31.7 million.
The following table summarizes the Companys estimated
aggregate amortization expense for the next five years (in
thousands):
|
|
|
|
|
2007
|
|
$
|
29,702
|
|
2008
|
|
|
37,513
|
|
2009
|
|
|
42,462
|
|
2010
|
|
|
45,758
|
|
2011
|
|
|
47,558
|
|
Thereafter
|
|
|
435,609
|
|
|
|
|
|
|
Total
|
|
$
|
638,602
|
|
|
|
|
|
|
F-12
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
Unamortized debt issuance costs totaling $11.4 million and
$8.4 million as of December 31, 2006 and 2005,
respectively, are included in other non-current assets. Debt
issuance costs are amortized into interest expense over the term
of the related debt. Debt issuance costs are amortized into
interest expense using the effective-interest method over the
term of the debt for the senior secured notes. Debt issuance
costs are amortized using the straight-line method over the term
of the debt for the bank credit facility because borrowings
under the bank credit facility cannot be forecasted for an
effective-interest computation. Other assets as of
December 31, 2005 also included the noncurrent portion of
the note receivable of $0.4 million from RLAC Gathering
Group, L.P., the minority interest partner in the CDC joint
venture discussed in Note 5.
|
|
(g)
|
Gas
Imbalance Accounting
|
Quantities of natural gas over-delivered or under-delivered
related to imbalance agreements are recorded monthly as
receivables or payables using weighted average prices at the
time of the imbalance. These imbalances are typically settled
with deliveries of natural gas. The Company had an imbalance
payable of $2.9 million and $30.5 million at
December 31, 2006 and 2005, respectively, which
approximates the fair value for these imbalances. The Company
had an imbalance receivable of $5.2 million and
$7.8 million at December 31, 2006 and 2005,
respectively, which are carried at the lower of cost or market
value.
|
|
(h)
|
Asset
Retirement Obligations
|
In March 2005, the FASB issued Interpretation No. 47,
Accounting for Conditional Asset Retirement
Obligations (FIN 47) which became effective
at December 31, 2005. FIN 47 clarifies that the term
conditional asset retirement obligation as used in
FASB Statement 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 on a future event that may
or may not be within the control of the entity. Since the
obligation to perform the asset retirement activity is
unconditional, FIN 47 provides that a liability for the
fair value of a conditional asset retirement activity should be
recognized if that fair value can be reasonably estimated, even
though uncertainty exists about the timing
and/or
method of settlement. FIN 47 also clarifies when an entity
would have sufficient information to reasonably estimate the
fair value of an asset retirement obligation under FASB
Statement No. 143. The Company did not provide any asset
retirement obligations as of December 31, 2006 or 2005
because it does not have sufficient information as set forth in
FIN 47 to reasonably estimate such obligations and the
Company has no current intention of discontinuing use of any
significant assets.
The Company recognizes revenue for sales or services at the time
the natural gas or NGLs are delivered or at the time the service
is performed. The Company generally accrues one to two months of
sales and the related gas purchases and reverses these accruals
when the sales and purchases are actually invoiced and recorded
in the subsequent months. Actual results could differ from the
accrual estimates. See discussion of accounting for energy
trading activities in note 2(k).
The Company accounts for taxes collected from customers
attributable to revenue transactions and remitted to government
authorities on a net basis (excluded from revenues).
F-13
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
(j)
|
Commodity
Risk Management
|
The Company engages in price risk management activities in order
to minimize the risk from market fluctuations in the price of
natural gas, oil and NGLs. To qualify as a hedge, the price
movements in the commodity derivatives must be highly correlated
with the underlying hedged commodity. Gains and losses related
to commodity derivatives which qualify as hedges are recognized
in income when the underlying hedged physical transaction closes
and are included in the consolidated statements of operations as
a cost of gas purchased.
The Company recognizes all derivative and hedging instruments in
the statements of financial position as either assets or
liabilities and measures them at fair value in accordance with
Statement of Financial Accounting Standards No. 133
(SFAS No. 133), Accounting for Derivative
Instruments and Hedging Activities. If a derivative does not
qualify for hedge accounting, it must be adjusted to fair value
through earnings. However, if a derivative does qualify for
hedge accounting, depending on the nature of the hedge, changes
in fair value can be offset against the change in fair value of
the hedged item through earnings or recognized in other
comprehensive income until such time as the hedged item is
recognized in earnings. To qualify for cash flow hedge
accounting, the cash flows from the hedging instrument must be
highly effective in offsetting changes in cash flows due to
changes in the underlying item being hedged. In addition, all
hedging relationship s must be designated, documented and
reassessed periodically.
Currently, some of the derivative financial instruments that
qualify for hedge accounting are designated as cash flow hedges.
The cash flow hedge instruments hedge the exposure of
variability in expected future cash flows that is attributable
to a particular risk. The effective portion of the gain or loss
on these derivative instruments is recorded in other
comprehensive income in stockholders equity and
reclassified into earnings in the same period in which the
hedged transaction closes. The asset or liability related to the
derivative instruments is recorded on the balance sheet in fair
value of derivative assets or liabilities. Any ineffective
portion of the gain or loss is recognized in earnings
immediately.
Certain derivative financial instruments that qualify for hedge
accounting are not designated as cash flow hedges. These
financial instruments and their physical quantities are marked
to market, and recorded on the balance sheet in fair value of
derivative assets or liabilities with related earnings impact
recorded in the period the transactions are entered into.
|
|
(k)
|
Energy
Trading Activities
|
The Company conducts off-system gas marketing
operations as a service to producers on systems that the Company
does not own. The Company refers to these activities as part of
its energy trading activities. In some cases, the Company earns
an agency fee from the producer for arranging the marketing of
the producers natural gas. In other cases, the Company
purchases the natural gas from the producer and enters into a
sales contract with another party to sell the natural gas.
The Company manages its price risk related to future physical
purchase or sale commitments for its energy trading activities
by entering into either corresponding physical delivery
contracts or financial instruments with an objective to balance
the Companys future commitments and significantly reduce
its risk to the movement in natural gas prices. However, the
Company is subject to counterparty risk for both the physical
and financial contracts. The Companys energy trading
contracts qualify as derivatives, and accordingly, the Company
continues to use
mark-to-market
accounting for both physical and financial contracts of its
energy trading activities. Accordingly, any gain or loss
associated with changes in the fair value of derivatives and
physical delivery contracts relating to the Companys
energy trading activities are recognized in earnings as gain or
loss on derivatives immediately.
For each reporting period, the Company records the fair value of
open energy trading contracts based on the difference between
the quoted market price and the contract price. Accordingly, the
change in fair value from the previous period, in addition to
the net realized gains or losses on settled contracts, is
reported as net gain or loss on derivatives in the statements of
operations.
F-14
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
Margins earned on settled contracts from its commercial services
activities included in profit on energy trading contracts in the
consolidated statement of operations was $2.5 million,
$1.6 million, and $2.2 million for the years ended
December 31, 2006, 2005 and 2004, respectively.
Energy trading contract volumes that were physically settled
were as follows (in MMBTUs):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Volumes purchased and sold
|
|
|
50,563,000
|
|
|
|
66,065,000
|
|
|
|
76,576,000
|
|
|
|
(l)
|
Comprehensive
Income (Loss)
|
Comprehensive income includes net income and other comprehensive
income, which includes, but is not limited to, unrealized gains
and losses on marketable securities, foreign currency
translation adjustments, minimum pension liability adjustments,
and unrealized gains and losses on derivative financial
instruments.
Pursuant to SFAS No. 133, the Company records deferred
hedge gains and losses on its derivative financial instruments
that qualify as cash flow hedges, net of income tax and minority
interest, as other comprehensive income.
|
|
(m)
|
Legal
Costs Expected to be Incurred in Connection with a Loss
contingency
|
Legal costs incurred in connection with a loss contingency are
expensed as incurred.
|
|
(n)
|
Concentrations
of Credit Risk
|
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist primarily of trade
accounts receivable and derivative financial instruments.
Management believes the risk is limited as the Companys
customers represent a broad and diverse group of energy
marketers and end users. In addition, the Company continually
monitors and reviews credit exposure to its marketing
counterparties and letters of credit or other appropriate
security are obtained as considered necessary to limit the risk
of loss. See Note 10 for further discussion. The Company
records reserves for uncollectible accounts on a specific
identification basis since there is not a large volume of late
paying customers. The Company had a reserve for uncollectible
receivables as of December 31, 2006, 2005 and 2004 of
$0.6 million, $0.3 million and $0.1 million,
respectively.
During 2006 and 2005, Dow Hydrocarbons accounted for 13.4% and
Formosa Hydrocarbons accounted for 10.6%, respectively, of the
consolidated revenue of the Company. During 2004, Kinder Morgan
accounted for 10.2% of the consolidated revenue of the Company.
As the Company continues to grow and expand, this relationship
between individual customer sales and consolidated total sales
is expected to continue to change. While these customers
represent a significant percentage of revenues, the loss of
either would not have a material adverse impact on the
Companys results of operations.
Environmental expenditures are expensed or capitalized as
appropriate, depending on the nature of the expenditures and
their future economic benefit. Expenditures that related to an
existing condition caused by past operations that do not
contribute to current or future revenue generation are expensed.
Liabilities for these expenditures are recorded on an
undiscounted basis (or a discounted basis when the obligation
can be settled at fixed and determinable amounts) when
environmental assessments or
clean-ups
are probable and the costs can be reasonably estimated. For the
years ended December 31, 2006, 2005 and 2004, such
expenditures were not significant.
F-15
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
Effective January 1, 2006, the Company adopted the
provisions of SFAS No. 123R, Share-Based
Payment (SFAS No. 123R) which requires
compensation related to all stock-based awards, including stock
options, be recognized in the consolidated financial statements.
The Company applied the provisions of Accounting Principles
Board Opinion No. 25, Accounting for Stock Issued
to Employees (APB No. 25), for periods prior to
January 1, 2006. In accordance with APB No. 25 for
fixed stock and unit options, compensation expense was recorded
prior to 2006 to the extent the market value of the stock or
unit exceeded the exercise price of the option at the
measurement date. Compensation expense for fixed awards with pro
rata vesting was recognized on a straight-line basis over the
vesting period. In addition, compensation expense was recorded
for variable options based on the difference between fair value
of the stock or unit and exercise price of the options at period
end.
The Company elected to use the modified-prospective transition
method for adopting SFAS No. 123R. Under the
modified-prospective method, awards that are granted, modified,
repurchased, or canceled after the date of adoption are measured
and accounted for under SFAS No. 123R. The unvested
portion of awards that were granted prior to the effective date
are also accounted for in accordance with
SFAS No. 123R. The Company adjusted compensation cost
for actual forfeitures as they occurred under APB No. 25
for periods prior to January 1, 2006. Under
SFAS No. 123R, the Partnership is required to estimate
forfeitures in determining periodic compensation cost. The
cumulative effect of the adoption of SFAS No. 123R
recognized on January 1, 2006 was an increase in net
income, net of taxes and minority interest, of $0.2 million
due to the reduction in previously recognized compensation costs
associated with the estimation of forfeitures.
The Company and the Partnership each have similar unit or
share-based payment plans for employees, which are described
below. Amounts recognized in the consolidated financial
statements with respect to these plans are as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Cost of share-based compensation
charged to general and administrative expense
|
|
$
|
7,448
|
|
|
$
|
3,660
|
|
|
$
|
830
|
|
Cost of share-based compensation
charged to operating expense
|
|
|
1,131
|
|
|
|
398
|
|
|
|
198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total amount charged to income
before cumulative effect of accounting change
|
|
$
|
8,579
|
|
|
$
|
4,058
|
|
|
$
|
1,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest of non-controlling
partners in share-based compensation
|
|
$
|
2,857
|
|
|
$
|
869
|
|
|
$
|
340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of related income tax
benefit recognized in income
|
|
$
|
2,121
|
|
|
$
|
1,116
|
|
|
$
|
241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation expense recorded in 2005 included
$0.5 million related to the accelerated vesting of 7,060
common unit options of the Partnership and 10,000 common share
options of the Company.
F-16
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
Had compensation cost for the Company been determined based on
the fair value at the grant date for awards in accordance with
SFAS No. 123, Accounting for Stock Based
Compensation for the years ended December 31, 2005 and
2004, the Companys net income (loss) would have been as
follows (in thousands except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
2005
|
|
|
2004
|
|
|
Net income as reported
|
|
$
|
49,136
|
|
|
$
|
8,700
|
|
Add: Stock-based employee
compensation expense included in reported net income, net of tax
|
|
|
2,027
|
|
|
|
376
|
|
Deduct: Total stock-based employee
compensation expense determined under fair value based method
for all awards, net of tax
|
|
|
(2,252
|
)
|
|
|
(477
|
)
|
|
|
|
|
|
|
|
|
|
Pro forma net income (loss)
|
|
$
|
48,911
|
|
|
$
|
8,599
|
|
|
|
|
|
|
|
|
|
|
Net income per common share, as
reported:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.29
|
|
|
$
|
0.24
|
|
Diluted
|
|
$
|
1.26
|
|
|
$
|
0.22
|
|
Pro forma net income per common
share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.29
|
|
|
$
|
0.24
|
|
Diluted
|
|
$
|
1.27
|
|
|
$
|
0.22
|
|
The fair value of each option is estimated on the date of grant
using the Black Scholes option-pricing model as disclosed in
Note (9) Employee Incentive Plans.
|
|
(q)
|
Sales
of Securities by Subsidiaries
|
The Company recognizes gains and losses in the consolidated
statements of income resulting from subsidiary sales of
additional equity interest, including exercises of stock options
and CELP limited partnership units, to unrelated parties as
discussed in Note 3(a).
|
|
(r)
|
Recent
Accounting Pronouncements
|
In June 2006, the Financial Accounting Standards Board (FASB)
issued FASB Interpretation No. 48 (FIN 48),
Accounting for Uncertainty in Income Taxes.
FIN 48 is an interpretation of FASB Statement No. 109,
Accounting for Income Taxes and must be
adopted by the Partnership no later than January 1, 2007.
FIN 48 prescribes a comprehensive model for recognizing,
measuring, presenting and disclosing in the financial statements
uncertain tax positions that the Company has taken or expects to
take in its returns. The Company is evaluating the impact of
adopting FIN 48 and does not anticipate a significant
impact on its financial statements.
On September 13, 2006, the Securities Exchange Commission
(SEC) issued Staff Accounting Bulleting No. 108
(SAB 108), which establishes an approach that requires
quantification of financial statement errors based on the
effects of the error on each of the companys financial
statements and the related disclosures. SAB 108 requires
the use of a balance sheet and an income statement approach to
evaluate whether either of these approaches results in
quantifying a misstatement that, when all relevant quantitative
and qualitative factors are considered, is material.
SAB 108 is not expected to have a material impact on the
Company.
F-17
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
3.
|
Public
Offerings of Units by CELP and Certain Provisions of the
Partnership Agreement
|
|
|
(a)
|
Issuance
of Common Units, Senior Subordinated Units and Senior
Subordinated Series B Units
|
The Crosstex Energy, L.P. partnership agreement contains
specific provisions for the allocation of net earnings and
losses to the partners for purposes of maintaining the partner
capital accounts. Net income is allocated to the general partner
based on incentive distributions earned for the period plus 2%
of remaining net income. In June 2005, the Partnership amended
its partnership agreement to allocate the expenses attributable
to the Companys stock options and restricted stock awarded
to employees and directors of the Partnership all to the general
partner to make the related general partner contribution.
On June 24, 2005, the Partnership issued 1,495,410 senior
subordinated units in a private equity offering for net proceeds
of $51.1 million, including our $1.1 million general
partner contribution. The senior subordinated units were issued
at $33.44 per unit, which represents a discount of 13.7% to
the market value of common units on such date, and automatically
converted to common units on a
one-for-one
basis on February 24, 2006. The senior subordinated units
received no distributions until their conversion to common
units. As a result of this offering, upon the conversion of
these units to common units in the first quarter of 2006, the
Company recognized a gain of $19.0 million due to the
Partnership issuing additional units at prices per unit greater
than the Companys equivalent carrying value.
On November 1, 2005, the Partnership issued 2,850,165
senior subordinated series B units in a private placement
for a purchase price of $36.84 per unit. It received net
proceeds of approximately $107.1 million, including our
$2.1 million general partner contribution and net of
expenses associated with the sale. The senior subordinated
series B units automatically converted into common units on
November 14, 2005 at a ratio of one common unit for each
senior subordinated series B unit. The senior subordinated
series B units were not entitled to distributions paid on
November 14, 2005. The net proceeds were used to fund a
portion of the El Paso acquisition. As a result of this
offering, the Company recognized a gain of $37.5 million
due to the Partnership issuing additional units at prices per
unit greater than the Companys equivalent carrying value.
In November and December 2005, the Partnership issued 3,731,050
additional common units to the public at $33.25 per unit.
The offering resulted in net proceeds to the Partnership of
approximately $120.9 million including our
$2.5 million general partner contribution and net of
expenses associated with the offering. The net proceeds from
this offering were used to fund a portion of the El Paso
acquisition. As a result of this offering, the Company
recognized a gain of $27.6 million due to the Partnership
issuing additional units at prices per unit greater than the
Companys equivalent carrying value.
On June 29, 2006, the Partnership issued an aggregate of
12,829,650 senior subordinated series C units representing
limited partner interests of the Partnership in a private equity
offering for net proceeds of approximately $359.3 million.
The senior subordinated series C units were issued at
$28.06 per unit, which represented a discount of 25% to the
market value of common units on such date. The Company purchased
6,414,830 of the senior subordinated series C units for a
total of $180.0 million. In addition, the Company made a
general partner contribution of $9.0 million in connection
with this issuance to maintain its 2% general partner interest.
The senior subordinated series C units will automatically
convert into common units representing limited partner interests
of the Partnership on the first date on or after
February 16, 2008 that conversion is permitted by its
partnership agreement at a ratio of one common unit for each
senior subordinated series C unit. The partnership
agreement will permit the conversion of the senior subordinated
series C units to common units once the subordination
period ends or if the issuance is in connection with an
acquisition that increases cash flow from operations per unit on
a pro forma basis. If not able to convert on February 16,
2008, then the holders of such units will have the right to
receive, after payment of the minimum quarterly distribution on
the Partnerships common units but prior to any payment on
the Partnerships subordinated units, distributions equal
to 110% of the quarterly cash distribution amount payable on
common units. The senior subordinated series C units are
not entitled to distributions of available cash from the
Partnership until February 16, 2008. The Company may
recognize a gain
F-18
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
associated with the senior subordinated series C units
purchased by non-controlling partners when such units convert to
common units based on the Companys carrying value upon
conversion.
|
|
(b)
|
Limitation
of Issuance of Additional Common Units
|
During the subordination period, the Partnership may issue up to
2,633,000 additional common units or an equivalent number of
securities ranking on parity with the common units without
obtaining unitholder approval. The Partnership may also issue an
unlimited number of common units during the subordination period
for acquisitions, capital improvements or debt repayments that
increase cash flow from operations per unit on a pro forma basis.
The subordination period will end once the Partnership meets the
financial tests in the partnership agreement, but it generally
cannot end before December 31, 2007 except as discussed in
(d) below. When the subordination period ends, each
remaining subordinated unit will convert into one common unit
and the common units will no longer be entitled to arrearages.
|
|
(d)
|
Early
Conversion of Subordinated Units
|
If the Partnership meets the applicable financial tests in the
partnership agreement for the three consecutive four-quarter
periods ending on December 31, 2005 or December 31,
2006, up to 4,666,000 of the subordinated units may be converted
into common units prior to December 31, 2007. The
Partnership met the financial tests for three consecutive
four-quarter periods ended December 31, 2005, so 2,333,000
subordinated units converted to common units upon the payment of
the fourth quarter distribution on February 15, 2006. The
Partnership also met the financial tests for the three
consecutive four-quarter period ended December 31, 2006, so
an additional 2,333,000 of the subordinated units converted to
common units upon payment of the fourth quarter distribution on
February 15, 2007.
In accordance with the partnership agreement, the Partnership
must make distributions of 100% of available cash, as defined in
the partnership agreement, within 45 days following the end
of each quarter commencing with the quarter ending on
March 31, 2003. Distributions will generally be made 98% to
the common and subordinated unit-holders and 2% to the general
partner, subject to the payment of incentive distributions as
described below to the extent that certain target levels of cash
distributions are achieved. The Partnerships senior
secured credit facility prohibits the Partnership from declaring
distributions to unitholders if any event of default exists or
would result from the declaration of distributions. See Note
(6) for a description of the bank credit facility covenants.
Under the quarterly incentive distribution provisions, generally
its general partner is entitled to 13% of amounts the
Partnership distributes in excess of $0.25 per unit, 23% of
the amounts the Partnership distributes in excess of
$0.3125 per unit and 48% of amounts the Partnership
distributes in excess of $0.375 per unit. Incentive
distributions totaling $20.4 million, $10.7 million
and $5.6 million were earned by the Company for the years
ended December 31, 2006, 2005 and 2004, respectively. To
the extent there is sufficient available cash, the holders of
common units are entitled to receive the minimum quarterly
distribution of $0.25 per unit, plus arrearages, prior to
any distribution of available cash to the holders of
subordinated units. Subordinated units will not accrue any
arrearages with respect to distributions for any quarter. The
Partnership paid annual per common unit distributions of $2.18,
$1.93, and $1.70 for the years ended December 31, 2006,
2005 and 2004, respectively.
F-19
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
(f)
|
Allocation
of Partnership Income
|
Net income is allocated to Crosstex Energy GP, L.P., a
wholly-owned subsidiary of the Company, as the
Partnerships general partner in an amount equal to its
incentive distributions as described in Note 2(e) above. In
June 2005, the Partnership amended its partnership agreement to
allocate the expenses attributable to the Companys stock
options and restricted stock all to the general partner to match
the related general partner contribution for such items.
Therefore, beginning in the second quarter of 2005, the general
partners share of the Partnerships net income is
reduced by stock-based compensation expense attributed to the
Companys stock options and restricted stock awarded to
officers and employees of the Partnership. The remaining net
income after incentive distributions and Company-related
stock-based compensation is allocated pro rata between the 2%
general partner interest, the subordinated units (excluding
senior subordinated units), and the common units. The following
table reflects the Companys general partner share of the
Partnerships net income (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Income allocation for incentive
distributions
|
|
$
|
20,422
|
|
|
$
|
10,660
|
|
|
$
|
5,550
|
|
Stock-based compensation
attributable to CEIs stock options and restricted shares
|
|
|
(3,545
|
)
|
|
|
(2,223
|
)
|
|
|
|
|
2% general partner interest in net
income (loss)
|
|
|
(421
|
)
|
|
|
215
|
|
|
|
363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General Partner Share of Net Income
|
|
$
|
16,456
|
|
|
$
|
8,652
|
|
|
$
|
5,913
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company also owns limited partner common units, limited
partner subordinated units and limited partner senior
subordinated series C units in the Partnership. The
Companys share of the Partnerships net income
attributable to its limited partner common and subordinated
units was a net loss of $7.4 million for the year ended
December 31, 2006 and net income of $6.3 million and
$9.8 million for years ended December 31, 2005 and
2004, respectively.
|
|
4.
|
Significant
Asset Purchases and Acquisitions
|
In April 2004, the Partnership acquired, through its
wholly-owned subsidiary Crosstex Louisiana Energy, L.P., the LIG
Pipeline Company and its subsidiaries (LIG Inc., Louisiana
Intrastate Gas Company, L.L.C., LIG Chemical Company, LIG
Liquids Company, L.L.C. and Tuscaloosa Pipeline Company)
(collectively, referred to as LIG) from American Electric Power
(AEP) in a negotiated transaction for $73.7 million. LIG
consists of approximately 2,000 miles of gas gathering and
transmission systems located in 32 parishes extending from
northwest and north-central Louisiana through the center of the
state to south and southeast Louisiana. The Partnership financed
the acquisition through borrowings under its amended bank credit
facility. The Partnership utilized the purchase method of
accounting for this acquisition with an acquisition date of
April 1, 2004.
In November 2005, the Partnership acquired El Paso
Corporations processing and natural gas liquids business
in south Louisiana for $481.0 million. The assets acquired
include 2.3 billion cubic feet per day of processing
capacity, 66,000 barrels per day of fractionation capacity,
2.4 million barrels of underground storage and
400 miles of liquids transport lines. The Partnership
financed the acquisition with net proceeds totaling
$228.0 million from the issuance of common units and senior
subordinated series B units (including the 2% general
partner contributions totaling $4.7 million) and borrowings
under its bank credit facility for the remaining balance.
F-20
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
The Partnership has utilized the purchase method of accounting
for this acquisition with an acquisition date of
November 1, 2005. The purchase price and our allocation
thereof are as follows (in thousands):
|
|
|
|
|
Cash paid to El Paso
Corporation (net of estimated working capital adjustment)
|
|
$
|
477,851
|
|
Direct acquisition costs
|
|
|
3,125
|
|
|
|
|
|
|
Total Purchase Price
|
|
$
|
480,976
|
|
|
|
|
|
|
Assets acquired:
|
|
|
|
|
Current assets
|
|
$
|
49,693
|
|
Property, plant &
equipment
|
|
|
235,599
|
|
Intangible assets
|
|
|
253,775
|
|
Liabilities assumed:
|
|
|
|
|
Current liabilities
|
|
|
(58,091
|
)
|
|
|
|
|
|
Total Purchase Price
|
|
$
|
480,976
|
|
|
|
|
|
|
Intangible assets relate to customer relationships and are being
amortized over 15 years. In 2006, the purchase price for
El Paso was increased by $3.1 million due to changes
in assets and liabilities assumed with the purchase.
On June 29, 2006, the Partnership acquired certain natural
gas gathering pipeline systems and related facilities in the
Barnett Shale (the North Texas Gathering, NTG assets) from Chief
Holdings LLC (Chief) for a purchase price of approximately
$475.3 million (the Chief Acquisition). The NTG assets
include five gathering systems, located in parts of Parker,
Tarrant, Denton, Palo Pinto, Erath, Hood, Somervell, Hill and
Johnson counties in Texas. The NTG assets also included a
125 million cubic feet per day carbon dioxide treating
plant and compression facilities with 26,000 horsepower. The gas
gathering systems consisted of approximately 250 miles of
existing gathering pipelines, ranging from four inches to twelve
inches in diameter. The Partnership plans to build up to an
additional 400 miles of pipelines as production in the area
is drilled and developed. The gathering systems had the capacity
to deliver approximately 250,000 MMBtu/d at the date of
acquisition.
Simultaneously with the Chief Acquisition, the Partnership
entered into a gas gathering agreement with Devon Energy
Corporation (Devon) whereby the Partnership has agreed to
gather, and Devon has agreed to dedicate and deliver, the future
production on acreage that Devon acquired from Chief
(approximately 160,000 net acres). Under the agreement,
Devon has committed to deliver all of the production from the
dedicated acreage into the gathering system, including
production from current wells and wells that it drills in the
future. The Partnership will expand the gathering system to
reach the new wells as they are drilled. The agreement has a
15-year term
and provides for market-based gathering fees over the term. In
addition to the Devon agreement, approximately 60,000 additional
net acres are dedicated to the Midstream Assets under agreements
with other producers.
F-21
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
The Partnership utilized the purchase method of accounting for
the acquisition of the Midstream Assets with an acquisition date
of June 29, 2006. The Partnership will recognize the
gathering fee income received from Devon and other producers who
deliver gas into the Midstream Assets as revenue at the time the
natural gas is delivered. The purchase price and our preliminary
allocation thereof are as follows (in thousands):
|
|
|
|
|
Cash paid to Chief
|
|
$
|
474,858
|
|
Direct acquisition costs
|
|
|
429
|
|
|
|
|
|
|
Total purchase price
|
|
$
|
475,287
|
|
|
|
|
|
|
Assets acquired:
|
|
|
|
|
Current assets
|
|
$
|
18,833
|
|
Property, plant and equipment
|
|
|
115,728
|
|
Intangible assets
|
|
|
395,604
|
|
Liabilities assumed:
|
|
|
|
|
Current liabilities
|
|
|
(54,878
|
)
|
|
|
|
|
|
Total purchase price
|
|
$
|
475,287
|
|
|
|
|
|
|
Intangibles relate primarily to the value of the dedicated and
non-dedicated acreage attributable to the system, including the
agreement with Devon, and are being amortized using the units of
throughput method of amortization. The preliminary purchase
price allocation has not been finalized because the Partnership
is still in the process of determining the allocation of costs
between tangible and intangible assets and finalizing working
capital settlements.
The Partnership financed the Chief Acquisition with borrowings
of approximately $105.0 million under its bank credit
facility, net proceeds of approximately $368.3 million from
the private placement of senior subordinated series C
units, including approximately $9.0 million of equity
contributions from Crosstex Energy GP, L.P., the general partner
of the Partnership and an indirect subsidiary of CEI, and
$6.0 million of cash.
Operating results for the El Paso assets have been included
in the consolidated statements of operations since
November 1, 2005. Operating results for the Midstream
Assets have been included in the consolidated statements of
operations since June 29, 2006. The following unaudited pro
forma results of operations assume that the El Paso and
Midstream Asset acquisitions occurred on January 1, 2005
(in thousands, except per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Unaudited)
|
|
|
Revenue
|
|
$
|
3,155,854
|
|
|
$
|
3,320,474
|
|
Net income
|
|
$
|
15,295
|
|
|
$
|
45,205
|
|
Net income (loss) per limited
partner unit
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.33
|
|
|
$
|
1.19
|
|
Diluted
|
|
$
|
0.33
|
|
|
$
|
1.16
|
|
Weighted average common shares
outstanding
|
|
|
|
|
|
|
|
|
Basic
|
|
|
45,941
|
|
|
|
12,652
|
|
Diluted
|
|
|
46,439
|
|
|
|
19,957
|
|
There are substantial differences in the way Chief operated the
Midstream Assets during pre-acquisition periods and the way the
Partnership operates these assets post-acquisition. The
historical operating results for the El Paso assets only
reflected direct revenues and expenses for such assets and did
not include any general and administrative expenses because such
expenses were not separately allocated to the acquired
companies. Although
F-22
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
the unaudited pro forma results of operations include
adjustments to reflect the significant effects of the
acquisitions, these pro forma results do not purport to present
the results of operations had the acquisitions actually been
completed as of January 1, 2005.
|
|
5.
|
Investment
in Limited Partnerships and Note Receivable
|
The Partnership owns a 50% interest in CDC and consolidates its
investment in CDC pursuant to FIN No. 46R. The
Partnership manages the business affairs of CDC. The other 50%
joint venture partner (the CDC partner) is an unrelated third
party who owns and operates a natural gas field located in
Denton County.
In connection with the formation of CDC, the Partnership agreed
to loan the CDC Partner up to $1.5 million for their
initial capital contribution. The loan bears interest at an
annual rate of prime plus 2%. CDC makes payments directly to the
Partnership attributable to CDC Partners 50% share of
distributable cash flow to repay the loan. Any balance remaining
on the note is due in August 2007. The balance remaining on the
note of $0.9 million is included in current notes
receivable as of December 31, 2006.
Until December 31, 2004, the Partnership owned a 7.86%
weighted average interest as the general partner in the five
gathering systems of Crosstex Pipeline Partners, L.P., or CPP,
and a 20.31% interest as a limited partner in CPP. The Company
accounted for its investment in CPP under the equity method for
the year ended December 31, 2004 because it exercised
significant influence in operating decisions as a general
partner in CPP.
Effective December 31, 2004, the Partnership acquired all
of the outside limited and general partner interests of CPP for
$5.1 million. This acquisition makes the Partnership the
sole limited partner and general partner of CPP, so the
Partnership began consolidating its investment in CPP effective
December 31, 2004.
As of December 31, 2006 and 2005, long-term debt consisted
of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Bank credit facility, interest
based on Prime or LIBOR plus an applicable margin, interest
rates at December 31, 2006 and 2005 were 7.20% and 6.69%,
respectively
|
|
$
|
488,000
|
|
|
$
|
322,000
|
|
Senior secured notes, weighted
average interest rates at December 31, 2006 and 2005 of
6.76% and 6.64%, respectively
|
|
|
498,530
|
|
|
|
200,000
|
|
Note payable to Florida Gas
Transmission Company
|
|
|
600
|
|
|
|
650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
987,130
|
|
|
|
522,650
|
|
Less current portion
|
|
|
(10,012
|
)
|
|
|
(6,521
|
)
|
|
|
|
|
|
|
|
|
|
Debt classified as long-term
|
|
$
|
977,118
|
|
|
$
|
516,129
|
|
|
|
|
|
|
|
|
|
|
Credit Facility. On June 29, 2006, the
Partnership amended its bank credit facility, increasing
availability under the facility to $1.0 billion and
extending the maturity date from November 2010 to June 2011. The
bank credit agreement includes procedures for additional
financial institutions selected by the Partnership to become
lenders under the agreement, or for any existing lender to
increase its commitment in an amount approved by the Partnership
and the lender, subject to a maximum of $300 million for
all such increases in commitments of new or existing lenders.
The facility was used for the 2005 El Paso acquisition and
the 2006 Chief, Hanover and Cardinal acquisitions and will be
used to finance the acquisition and development of gas
gathering, treating, and processing facilities, as well as
working capital, letters of credit, distributions and other
general partnership purposes. At December 31, 2006,
$564.3 million was outstanding under the facility,
including $76.3 million of letters of credit, leaving
approximately $435.7 million available for future
borrowings. The facility will mature in June 2011, at which time
F-23
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
it will terminate and all outstanding amounts shall be due and
payable. Amounts borrowed and repaid under the credit facility
may be re-borrowed.
Obligations under the credit facility are secured by first
priority liens on all of the Partnerships material
pipeline, gas gathering and processing assets, all material
working capital assets and a pledge of all of the
Partnerships equity interests in certain of its
subsidiaries, and ranks pari passu in right of payment
with the senior secured notes. The credit agreement is
guaranteed by certain of its subsidiaries. The Partnership may
prepay all loans under the credit facility at any time without
premium or penalty (other than customary LIBOR breakage costs),
subject to certain notice requirements.
Under the amended credit agreement, borrowings bear interest at
the Partnerships option at the administrative agents
reference rate plus 0% to 0.25% or LIBOR plus 1.00% to 1.75%.
The applicable margin varies quarterly based on the
Partnerships leverage ratio. The fees charged for letters
of credit range from 1.00% to 1.75% per annum, plus a
fronting fee of 0.125% per annum. The Partnership will
incur quarterly commitment fees ranging from 0.20% to 0.375% on
the unused amount of the credit facilities.
The credit agreement prohibits the Partnership from declaring
distributions to unit-holders if any event of default, as
defined in the credit agreement, exists or would result from the
declaration of distributions. In addition, the bank credit
facility contains various covenants that, among other
restrictions, limit the Partnerships ability to:
|
|
|
|
|
incur indebtedness;
|
|
|
|
grant or assume liens;
|
|
|
|
make certain investments;
|
|
|
|
sell, transfer, assign or convey assets, or engage in certain
mergers or acquisitions;
|
|
|
|
make distributions;
|
|
|
|
change the nature of the Partnerships business;
|
|
|
|
enter into certain commodity contracts;
|
|
|
|
make certain amendments to the Partnerships or its
operating partnerships partnership agreement; and
|
|
|
|
engage in transactions with affiliates.
|
The credit facility contains the following covenants requiring
the Partnership to maintain:
|
|
|
|
|
an initial ratio of total funded debt to consolidated earnings
before interest, taxes, depreciation and amortization (each as
defined in the credit agreement), measured quarterly on a
rolling four-quarter basis, of 5.25 to 1.00, pro forma for any
asset acquisitions. The maximum leverage ratio is reduced to
4.75 to 1.00 beginning July 1, 2007 and further reduces to
4.25 to 1.00 on January 1, 2008. The maximum ratio is
increased to 5.25 to 1.00 during an acquisition period, as
defined in the credit agreement; and
|
|
|
|
a minimum interest coverage ratio (as defined in the credit
agreement), measured quarterly on a rolling four-quarter basis,
equal to 3.0 to 1.0.
|
Each of the following will be an event of default under the bank
credit facility:
|
|
|
|
|
failure to pay any principal, interest, fees, expenses or other
amounts when due;
|
|
|
|
failure to observe any agreement, obligation, or covenant in the
credit agreement, subject to cure periods for certain failures;
|
|
|
|
certain judgments against the Partnership or any of its
subsidiaries, in excess of certain allowances;
|
|
|
|
certain ERISA events involving the Partnership or its
subsidiaries;
|
F-24
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
a change in control (as defined in the credit
agreement); and
|
|
|
|
the failure of any representation or warranty to be materially
true and correct when made.
|
In November 2006, the Partnership entered into an interest rate
swap covering a principal amount of $50.0 million under the
credit facility for a period of three years. The Partnership is
subject to interest rate risk on its credit facility. The
interest rate swap reduces this risk by fixing the LIBOR rate,
prior to credit margin, at 4.95%, on $50.0 million of
related debt outstanding over the term of the swap agreement
which expires on November 30, 2009. The Partnership has
elected not to designate this swap as a cash flow hedge for
FAS 133 accounting treatment. Accordingly, unrealized gains
or losses relating to the swap flow through the Consolidated
Statement of Operations as adjustments to interest expense over
the period hedged. The fair value of the interest rate swap at
December 31, 2006 was a $0.1 million asset.
Senior Secured Notes. The Partnership entered
into a master shelf agreement with an institutional lender in
2003 that was amended in subsequent years to increase
availability under the agreement to $510.0 million,
pursuant to which it issued the following senior secured notes
(dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
|
|
|
|
Month Issued
|
|
Amount
|
|
|
Rate
|
|
|
Maturity
|
|
|
Principal Payment Terms
|
|
June 2003
|
|
$
|
30,000
|
|
|
|
6.95
|
%
|
|
|
7 years
|
|
|
Quarterly payments of $1,765 from
June 2006-June 2010
|
July 2003
|
|
|
10,000
|
|
|
|
6.88
|
%
|
|
|
7 years
|
|
|
Quarterly payments of $588 from
July 2006-July 2010
|
June 2004
|
|
|
75,000
|
|
|
|
6.96
|
%
|
|
|
10 years
|
|
|
Annual payments of $15,000 from
July 2010-July 2014
|
November 2005
|
|
|
85,000
|
|
|
|
6.23
|
%
|
|
|
10 years
|
|
|
Annual payments of $17,000 from
November 2010-December 2014
|
March 2006
|
|
|
60,000
|
|
|
|
6.32
|
%
|
|
|
10 years
|
|
|
Annual payments of $12,000 from
March 2012-March 2016
|
July 2006
|
|
|
245,000
|
|
|
|
6.96
|
%
|
|
|
10 years
|
|
|
Annual payments of $49,000 from
July 2012-July 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Issued
|
|
|
505,000
|
|
|
|
|
|
|
|
|
|
|
|
Principal repaid
|
|
|
(6,470
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31,
2006
|
|
$
|
498,530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
These notes represent senior secured obligations of the
Partnership and will rank at least pari passu in right of
payment with the bank credit facility. The notes are secured, on
an equal and ratable basis with obligations of the Partnership
under the credit facility, by first priority liens on all of its
material pipeline, gas gathering and processing assets, all
material working capital assets and a pledge of all its equity
interests in certain of its subsidiaries. The senior secured
notes are guaranteed by the Partnerships subsidiaries.
The $40.0 million of senior secured notes issued in 2003
are redeemable, at the Partnerships option and subject to
certain notice requirements, at a purchase price equal to 100%
of the principal amount together with accrued interest, plus a
make-whole amount determined in accordance with the master shelf
agreement. The senior secured notes issued in 2004, 2005 and
2006 provide for a call premium of 103.5% of par beginning three
years after issuance at rates declining from 103.5% to 100.0%.
The notes are not callable prior to three years after issuance.
During 2007 the notes may also incur an additional fee ranging
from 0.08% to 0.15% per annum on the outstanding borrowings
if the Partnerships leverage ratio, as defined in the
agreement, exceeds certain levels during such quarterly period.
F-25
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
The master shelf agreement relating to the notes contains
substantially the same covenants and events of default as the
bank credit facility.
If an event of default resulting from bankruptcy or other
insolvency events occurs, the senior secured notes will become
immediately due and payable. If any other event of default
occurs and is continuing, holders of at least 50.1% in principal
amount of the outstanding notes may at any time declare all the
notes then outstanding to be immediately due and payable. If an
event of default relating to the nonpayment of principal,
make-whole amounts or interest occurs, any holder of outstanding
notes affected by such event of default may declare all the
notes held by such holder to be immediately due and payable.
The Partnership was in compliance with all debt covenants at
December 31, 2006 and 2005 and expects to be in compliance
with debt covenants for the next twelve months.
Intercreditor and Collateral Agency
Agreement. In connection with the execution of
the master shelf agreement, the lenders under the bank credit
facility and the purchasers of the senior secured notes have
entered into an Intercreditor and Collateral Agency Agreement,
which has been acknowledged and agreed to by the Partnership and
its subsidiaries. This agreement appointed Bank of America, N.A.
to act as collateral agent and authorized Bank of America to
execute various security documents on behalf of the lenders
under the bank credit facility and the purchasers of the senior
secured notes. This agreement specifies various rights and
obligations of lenders under the bank credit facility, holders
of senior secured notes and the other parties thereto in respect
of the collateral securing the Partnerships obligations
under the bank credit facility and the master shelf agreement.
Other Note Payable. In June 2002, as part
of the purchase price of Florida Gas Transmission Company
(FGTC), the Partnership issued a note payable for
$0.8 million to FGTC that is payable in $0.1 million
annual increments through June 2006 with a final payment of
$0.6 million due in June 2007. The note bears interest
payable annually at LIBOR plus 1%.
Maturities: Maturities for the long-term debt
as of December 31, 2006 are as follows (in thousands):
|
|
|
|
|
2007
|
|
$
|
10,012
|
|
2008
|
|
|
9,412
|
|
2009
|
|
|
9,412
|
|
2010
|
|
|
20,294
|
|
2011
|
|
|
520,000
|
|
Thereafter
|
|
|
418,000
|
|
The Company provides for income taxes using the liability
method. Accordingly, deferred taxes are recorded for the
differences between the tax and book basis that will reverse in
future periods (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Current tax provision
|
|
$
|
(268
|
)
|
|
$
|
0
|
|
|
$
|
347
|
|
Deferred tax provision
|
|
|
11,386
|
|
|
|
30,047
|
|
|
|
4,802
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
11,118
|
|
|
$
|
30,047
|
|
|
$
|
5,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-26
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
A reconciliation of the provision for income taxes is as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Federal income tax at statutory
rate (35%)
|
|
$
|
9,591
|
|
|
$
|
27,714
|
|
|
$
|
4,848
|
|
State income taxes, net
|
|
|
567
|
|
|
|
1,639
|
|
|
|
193
|
|
Tax basis adjustment in
Partnership related to issuance of common units
|
|
|
1,151
|
|
|
|
993
|
|
|
|
|
|
Non-deductible expenses
|
|
|
88
|
|
|
|
9
|
|
|
|
91
|
|
Other
|
|
|
(279
|
)
|
|
|
(308
|
)
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax provision
|
|
$
|
11,118
|
|
|
$
|
30,047
|
|
|
$
|
5,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The principal components of the Companys net deferred tax
liability are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss
carryforward current
|
|
$
|
718
|
|
|
$
|
5,902
|
|
Net operating loss
carryforward non-current
|
|
|
23,788
|
|
|
|
7,997
|
|
Enron reserve
|
|
|
|
|
|
|
156
|
|
Investment in the Partnership
|
|
|
6,983
|
|
|
|
5,832
|
|
Other comprehensive income
|
|
|
|
|
|
|
462
|
|
Other
|
|
|
100
|
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,589
|
|
|
|
20,390
|
|
Less: valuation allowance
|
|
|
(6,983
|
)
|
|
|
(5,832
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
24,606
|
|
|
|
14,558
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities:
|
|
|
|
|
|
|
|
|
Property, plant, equipment, and
intangible assets current
|
|
|
(501
|
)
|
|
|
(496
|
)
|
Property, plant, equipment, and
intangible assets non-current
|
|
|
(88,778
|
)
|
|
|
(66,762
|
)
|
Other comprehensive income
|
|
|
(1,231
|
)
|
|
|
|
|
Other
|
|
|
(65
|
)
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(90,575
|
)
|
|
|
(67,288
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(65,969
|
)
|
|
$
|
(52,730
|
)
|
|
|
|
|
|
|
|
|
|
At December 31, 2006, the Company had a net operating loss
carryforward of approximately $64.4 million that expires
from 2021 through 2026. The Company also has various state net
operating loss carryforwards of approximately $24.1 million
which will begin expiring in 2019. Management believes that it
is more likely than not that the future results of operations
will generate sufficient taxable income to utilize these net
operating loss carryforwards before they expire. Although the
Company has generated net operating losses in the past and the
Company expects to have significant amounts of future taxable
income from its investment in the Partnership, particularly
because of the remedial allocations of income among the
unitholders and the allocation of income based on the
Companys incentive distribution rights.
The Company generated federal income tax deductions of
$3.5 million and $26.9 million during 2004 and 2005,
respectively, attributable to the exercise of the Companys
stock options which contributed to its net operating loss
carryforward. The Company reduced its deferred tax liability and
recognized a capital contribution of $10.2 million related
to the tax benefits attributable to the stock option deductions.
F-27
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
Deferred tax liabilities relating to property, plant, equipment
and intangible assets represent, primarily, the Companys
share of the book basis in excess of tax basis for assets inside
of the Partnership. The Company has also recorded a deferred tax
asset in the amount of $7.0 million relating to the
difference between its book and tax basis of its investment in
the Partnership. Because the Company can only realize this
deferred tax asset upon the liquidation of the Partnership and
to the extent of capital gains, the Company has provided a full
valuation allowance against this deferred tax asset. The
valuation allowance increased $1.2 million from 2005 to
2006 due to the issuance of Partnership common units.
Effective January 1, 2007, the Company will be subject to
the gross margin tax enacted by the state of Texas on
May 1, 2006. The new tax law had so significant impact on
the Companys net deferred tax liability.
The Company sponsors a single employer 401(k) plan for employees
who become eligible upon the date of hire. The Partnership makes
contributions at each compensation calculation period based on
the annual discretionary contribution rate. Contributions to the
plan for the years ended December 31, 2006, 2005 and 2004
were $1.1 million, $0.6 million and $0.5 million,
respectively.
|
|
9.
|
Employee
Incentive Plans
|
|
|
(a)
|
Long-Term
Incentive Plan
|
In December 2002, the Partnership adopted a long-term incentive
plan for its employees, directors, and affiliates who perform
services for the Partnership. The plan currently permits the
grant of awards covering an aggregate of 2,600,000 common unit
options and restricted units. The plan is administered by the
compensation committee of the Partnerships board of
directors.
|
|
(b)
|
Partnership
Restricted Units
|
A restricted unit is a phantom unit that entitles
the grantee to receive a common unit upon the vesting of the
phantom unit, or in the discretion of the compensation
committee, cash equivalent to the value of a common unit. In
addition, the restricted units will become exercisable upon a
change of control of the Partnership, its general partner, or
its general partners general partner.
The restricted units are intended to serve as a means of
incentive compensation for performance and not primarily as an
opportunity to participate in the equity appreciation of the
common units. Therefore, plan participants will not pay any
consideration for the common units they receive and the
Partnership will receive no remuneration for the units. The
restricted units include a tandem award that entitles the
participant to receive cash payments equal to the cash
distributions made by the Partnership with respect to its
outstanding common units until the restriction period is
terminated or the restricted units are forfeited. The restricted
units granted prior to 2005 generally vest based on five years
of service (25% in years 3 and 4 and 50% in year 5) and the
restricted units granted in 2005 and 2006 generally cliff vest
after three years of service.
F-28
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
The restricted units are valued at their fair value at the date
of grant which is equal to the market value of common units on
such date. A summary of the restricted unit activity for the
year ended December 31, 2006 is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Grant-Date
|
|
Crosstex Energy, L.P. Restricted Units:
|
|
Units
|
|
|
Fair Value
|
|
|
Non-vested, beginning of period
|
|
|
247,648
|
|
|
$
|
28.33
|
|
Granted
|
|
|
130,008
|
|
|
|
35.01
|
|
Vested
|
|
|
(19,500
|
)
|
|
|
12.99
|
|
Forfeited
|
|
|
(21,652
|
)
|
|
|
25.69
|
|
|
|
|
|
|
|
|
|
|
Non-vested, end of period
|
|
|
336,504
|
|
|
$
|
31.97
|
|
|
|
|
|
|
|
|
|
|
Aggregate intrinsic value, end of
period (in thousands)
|
|
$
|
13,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted units totaling 163,934 were granted in 2005 with a
weighted average grant-date fair value of $36.66 per unit.
No restricted units were granted in 2004.
The aggregate intrinsic value of vested units during the year
ended December 31, 2006 was $0.7 million. As of
December 31, 2006, there was $5.8 million of
unrecognized compensation cost related to non-vested restricted
units. That cost is expected to be recognized over a
weighted-average period of 1.8 years. The Partnership
recognized stock-based compensation expense of $1.2 million
and $0.3 million related to the amortization of restricted
units in 2005 and 2004, respectively, in accordance with APB
No. 25.
|
|
(c)
|
Partnership
Unit Options
|
Unit options will have an exercise price that is not less than
the fair market value of the units on the date of grant. In
general, unit options granted will become exercisable over a
period determined by the compensation committee. In addition,
unit options will become exercisable upon a change in control of
the Partnership, its general partner or its general
partners general partner.
The fair value of each unit option award is estimated at the
date of grant using the Black-Scholes-Merton model. This model
is based on the assumptions summarized below. Expected
volatilities are based on historical volatilities of the
Partnerships traded common units. The Partnership has used
historical data to estimate share option exercise and employee
departure behavior. The expected life of unit options represents
the period of time that unit options granted are expected to be
outstanding. The risk-free interest rate for periods within the
contractual term of the unit option is based on the
U.S. Treasury yield curve in effect at the time of the
grant.
Unit options are generally awarded with an exercise price equal
to the market price of the Partnerships common units at
the date of grant, although a substantial portion of the unit
options granted during 2004 and 2005 were granted during the
second quarter of each fiscal year with an exercise price equal
to the market price at the beginning of the fiscal year,
resulting in an exercise price that was less than the market
price at grant. In accordance with APB No. 25, compensation
expense was recorded during 2004 and 2005 to the extent the
market value of the unit exceeded the exercise price of the unit
option at the measurement date. The unit options granted prior
to 2005 generally vest based on five years of service (25% in
years 3 and 4 and 50% in year 5) and the unit options
granted in 2005 and 2006
F-29
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
generally vest based on 3 years of service (one-third after
each year of service). The following weighted average
assumptions were used for the Black-Scholes option-pricing model
for grants in 2006, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
Crosstex Energy, L.P. Unit Options Granted:
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Weighted average distribution yield
|
|
|
5.5
|
%
|
|
|
5.5
|
%
|
|
|
6.4
|
%
|
Weighted average expected
volatility
|
|
|
33.0
|
%
|
|
|
33.0
|
%
|
|
|
29.0
|
%
|
Weighted average risk free
interest rate
|
|
|
4.80
|
%
|
|
|
3.83
|
%
|
|
|
3.25
|
%
|
Weighted average expected life
|
|
|
6 years
|
|
|
|
5.0 years
|
|
|
|
4.9 years
|
|
Weighted average contractual life
|
|
|
10 years
|
|
|
|
10 years
|
|
|
|
10 years
|
|
Weighted average of fair value of
unit options granted
|
|
$
|
7.45
|
|
|
$
|
8.42
|
|
|
$
|
4.00
|
|
A summary of the unit option activity for the years ended
December 31, 2006, 2005 and 2004 is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
|
|
Units
|
|
|
Price
|
|
|
Units
|
|
|
Price
|
|
|
Units
|
|
|
Price
|
|
|
Outstanding, beginning of period
|
|
|
1,039,832
|
|
|
$
|
18.88
|
|
|
|
1,043,865
|
|
|
$
|
15.58
|
|
|
|
643,272
|
|
|
$
|
10.28
|
|
Granted
|
|
|
286,403
|
|
|
|
34.62
|
|
|
|
193,511
|
|
|
|
32.78
|
|
|
|
466,296
|
|
|
|
22.52
|
|
Exercised
|
|
|
(304,936
|
)
|
|
|
11.19
|
|
|
|
(127,097
|
)
|
|
|
10.57
|
|
|
|
(39,066
|
)
|
|
|
11.00
|
|
Forfeited
|
|
|
(95,143
|
)
|
|
|
24.56
|
|
|
|
(70,447
|
)
|
|
|
23.15
|
|
|
|
(26,637
|
)
|
|
|
15.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
926,156
|
|
|
$
|
25.70
|
|
|
|
1,039,832
|
|
|
$
|
18.88
|
|
|
|
1,043,865
|
|
|
$
|
15.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at end of
period
|
|
|
121,131
|
|
|
$
|
23.58
|
|
|
|
308,455
|
|
|
$
|
11.34
|
|
|
|
263,078
|
|
|
$
|
10.36
|
|
Weighted average contractual term
(years) end of period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding
|
|
|
7.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable
|
|
|
7.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate intrinsic value end of
period (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding
|
|
$
|
13,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable
|
|
$
|
1,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value of
options granted with an exercise price equal to market price at
grant
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
|
|
|
|
|
|
|
|
116,902
|
|
|
$
|
4.91
|
|
Weighted average fair value of
options granted with an exercise price less than market price at
grant
|
|
|
(a
|
)
|
|
|
(a
|
)
|
|
|
193,511
|
|
|
$
|
8.42
|
|
|
|
349,394
|
|
|
$
|
3.70
|
|
|
|
|
(a) |
|
Disclosure not required under FAS No. 123R. No options
were granted with an exercise price less than market value at
grant during 2006. |
The total intrinsic value of unit options exercised during the
years ended December 31, 2006, 2005 and 2004 was
$7.6 million, $3.5 million and $0.5 million,
respectively. As of December 31, 2006, there was
$2.6 million of unrecognized compensation cost related to
non-vested unit options. That cost is expected to be recognized
over a weighted-average period of 1.8 years.
F-30
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
(d)
|
Crosstex
Energy, Inc.s Option Plan and Restricted
Stock
|
The Company has one stock-based compensation plan, the Crosstex
Energy, Inc. Long-Term Incentive Plan. Prior to
September 6, 2006, the plan permitted the grant of awards
covering an aggregate of 1,200,000 options for common stock and
restricted shares. On September 6, 2006, the Companys
board of directors adopted, subject to stockholder approval, an
Amended and Restated Long-Term Incentive Plan that increased the
number of shares of common stock authorized for issuance under
the plan to 1,530,000 shares. The Companys
stockholders approved the plan on October 26, 2006. The
plan is administered by the compensation committee of the
Companys board of directors. The shares issued upon
exercise or vesting are newly issued common shares.
The Companys restricted shares are included at their fair
value at the date of grant which is equal to the market value of
the common stock on such date. The Companys restricted
stock granted prior to 2005 generally vests based on five years
of service (25% in years 3 and 4 and 50% in year 5) and
restricted stock granted in 2005 and 2006 generally cliff vest
after three years of service. A summary of the restricted stock
activity for the year ended December 31, 2006 is provided
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Grant-Date
|
|
Crosstex Energy, Inc. Restricted Shares:
|
|
Shares(a)
|
|
|
Fair Value(a)
|
|
|
Non-vested, beginning of period
|
|
|
589,641
|
|
|
$
|
14.46
|
|
Granted
|
|
|
186,840
|
|
|
|
25.05
|
|
Vested
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(24,732
|
)
|
|
|
16.39
|
|
|
|
|
|
|
|
|
|
|
Non-vested, end of period
|
|
|
751,749
|
|
|
$
|
17.03
|
|
|
|
|
|
|
|
|
|
|
Aggregate intrinsic value, end of
period (in thousands)
|
|
$
|
23,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Adjusted to reflect
three-for-one
stock split. |
Restricted shares totaling 404,640 were issued in 2005 with a
weighted-average grant-date fair value of $16.73 per share.
No restricted shares were granted in 2004.
The following assumptions were used for the Black-Scholes
option-pricing model for the grants in 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
2004
|
|
|
Weighted average distribution yield
|
|
|
3.2
|
%
|
|
|
5.4
|
%
|
Weighted average expected
volatility
|
|
|
36.0
|
%
|
|
|
30.0
|
%
|
Weighted average risk free
interest rate
|
|
|
3.67
|
%
|
|
|
3.26
|
%
|
Weighted average expected life
|
|
|
4.7 years
|
|
|
|
4.5 years
|
|
Weighted average contractual life
|
|
|
10 years
|
|
|
|
10 years
|
|
Weighted average of fair value of
unit options granted (post stock split)
|
|
$
|
3.68
|
|
|
$
|
1.59
|
|
No stock options were granted to any directors, officers or
employees during 2006.
F-31
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
A summary of the stock option activity for the years ended
December 31, 2006, 2005 and 2004, is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
Number
|
|
|
Exercise
|
|
|
Number
|
|
|
Exercise
|
|
|
Number of
|
|
|
Exercise
|
|
|
|
of Shares
|
|
|
Price
|
|
|
of Shares(a)
|
|
|
Price(a)
|
|
|
Shares(a)
|
|
|
Price(a)
|
|
|
Outstanding, beginning of period
|
|
|
159,933
|
|
|
$
|
9.53
|
|
|
|
2,161,152
|
|
|
$
|
2.22
|
|
|
|
2,587,170
|
|
|
$
|
1.81
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
68,958
|
|
|
|
13.85
|
|
|
|
130,908
|
|
|
|
8.48
|
|
Cancelled
|
|
|
|
|
|
|
|
|
|
|
(27,060
|
)
|
|
|
15.23
|
|
|
|
(24,000
|
)
|
|
|
1.71
|
|
Exercised
|
|
|
(9,933
|
)
|
|
|
12.58
|
|
|
|
(2,043,117
|
)
|
|
|
1.87
|
|
|
|
(532,926
|
)
|
|
|
1.78
|
|
Forfeited
|
|
|
(30,000
|
)
|
|
|
13.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
120,000
|
|
|
$
|
8.21
|
|
|
|
159,933
|
|
|
$
|
9.53
|
|
|
|
2,161,152
|
|
|
$
|
2.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at end of
period
|
|
|
|
|
|
|
|
|
|
|
9,933
|
|
|
$
|
12.58
|
|
|
|
1,986,249
|
|
|
$
|
1.85
|
|
Weighted average fair value of
options granted with an exercise price equal to market price at
grant(a)
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
68,958
|
|
|
$
|
3.68
|
|
|
|
120,000
|
|
|
$
|
1.50
|
|
Weighted average fair value of
options granted with an exercise price less than market at
grant(a)
|
|
|
(b
|
)
|
|
|
(b
|
)
|
|
|
|
|
|
|
|
|
|
|
10,908
|
|
|
$
|
2.53
|
|
|
|
|
(a) |
|
Adjusted to reflect
three-for-one
stock split. |
|
(b) |
|
Disclosure not required under FAS No. 123R. No options
were granted with an exercise price less than market value at
grant during 2006. |
The total intrinsic value of stock options exercised by
directors, officers and employees during the years ended
December 31, 2006, 2005 and 2004 was $0.1 million,
$27.0 million and $6.2 million, respectively.
As of December 31, 2006, there was $6.9 million of
unrecognized compensation costs related to non-vested CEI
restricted stock and CEIs stock options. The cost is
expected to be recognized over a weighted average period of
1.8 years.
|
|
(e)
|
Earnings
per share and anti-dilutive computations
|
Basic earnings per common share was computed by dividing net
income by the weighted-average number of common shares
outstanding for the periods presented. The computation of
diluted earnings per common share further assumes the dilutive
effect of common share options and restricted shares.
In December 2006, the Company affected a
three-for-one
stock split. In conjunction with the Companys initial
public offering in January 2004, the Company affected a
two-for-one
split. All share amounts for prior periods presented herein have
been restated to reflect these stock splits.
F-32
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following are the share amounts used to compute the basic
and diluted earnings per share for the years ended
December 31, 2006, 2005 and 2004 (in thousands, except
per-share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding
|
|
|
42,168
|
|
|
|
37,956
|
|
|
|
35,547
|
|
Dilutive earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding
|
|
|
42,168
|
|
|
|
37,956
|
|
|
|
35,547
|
|
Dilutive effect of restricted
shares
|
|
|
410
|
|
|
|
432
|
|
|
|
219
|
|
Dilutive effect of exercise of
options
|
|
|
88
|
|
|
|
483
|
|
|
|
2,118
|
|
Dilutive effect of exercise of
preferred stock conversion to common shares
|
|
|
|
|
|
|
|
|
|
|
813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive units
|
|
|
42,666
|
|
|
|
38,871
|
|
|
|
38,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.
|
Fair
Value of Financial Instruments
|
The estimated fair value of the Companys financial
instruments has been determined by the Company using available
market information and valuation methodologies. Considerable
judgment is required to develop the estimates of fair value;
thus, the estimates provided below are not necessarily
indicative of the amount the Company could realize upon the sale
or refinancing of such financial instruments (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
December 31, 2005
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Value
|
|
|
Value
|
|
|
Value
|
|
|
Value
|
|
|
Cash and cash equivalents
|
|
$
|
10,635
|
|
|
$
|
10,635
|
|
|
$
|
12,904
|
|
|
$
|
12,904
|
|
Trade accounts receivable and
accrued revenues
|
|
|
367,023
|
|
|
|
367,023
|
|
|
|
428,927
|
|
|
|
428,927
|
|
Fair value of derivative assets
|
|
|
26,860
|
|
|
|
26,860
|
|
|
|
19,838
|
|
|
|
19,838
|
|
Account receivable from Enron
|
|
|
|
|
|
|
|
|
|
|
1,068
|
|
|
|
1,068
|
|
Note receivable
|
|
|
926
|
|
|
|
926
|
|
|
|
1,276
|
|
|
|
1,276
|
|
Accounts payable, drafts payable
and accrued gas purchases
|
|
|
404,863
|
|
|
|
404,863
|
|
|
|
406,887
|
|
|
|
406,887
|
|
Current portion, long-term debt
|
|
|
10,012
|
|
|
|
10,012
|
|
|
|
6,521
|
|
|
|
6,521
|
|
Long-term debt
|
|
|
977,118
|
|
|
|
981,914
|
|
|
|
516,129
|
|
|
|
520,005
|
|
Fair value of derivative
liabilities
|
|
|
14,699
|
|
|
|
14,699
|
|
|
|
18,359
|
|
|
|
18,359
|
|
The carrying amounts of the Companys cash and cash
equivalents, accounts receivable, and accounts payable
approximate fair value due to the short-term maturities of these
assets and liabilities. The 2005 carrying amount of the account
receivable from Enron approximates the fair value based on the
estimated recoverable value for our claim in their bankruptcy
proceedings as discussed in Note 11. The carrying value for
the note receivable approximates the fair value because this
note earns interest based on the current prime rate.
The Partnerships long-term debt was comprised of
borrowings under a revolving credit facility totaling
$488.0 million and $322.0 million as of
December 31, 2006 and 2005, respectively, which accrues
interest under a floating interest rate structure. Accordingly,
the carrying value of such indebtedness approximates fair value
for the amounts outstanding under the credit facility. As of
December 31, 2006, the Partnership also had borrowings
totaling $498.5 million under senior secured notes with a
weighted average interest rate of 6.76%. The fair value of these
borrowings as of December 31, 2006 and 2005 were adjusted
to reflect to current market interest rate for such borrowings
as of December 31, 2006 and 2005, respectively.
F-33
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
The fair value of derivative contracts included in assets or
liabilities for risk management activities represents the amount
at which the instruments could be exchanged in a current
arms-length transaction.
The Partnership manages its exposure to fluctuations in
commodity prices by hedging the impact of market fluctuations.
Swaps are used to manage and hedge prices and location risk
related to these market exposures. Swaps are also used to manage
margins on offsetting fixed-price purchase or sale commitments
for physical quantities of natural gas and NGLs.
The Partnership commonly enters into various derivative
financial transactions which it does not designate as hedges.
These transactions include swing swaps, third
party on-system financial swaps, marketing financial
swaps, storage swaps and basis
swaps. Swing swaps are generally short-term in nature (one
month), and are usually entered into to protect against changes
in the volume of daily versus
first-of-month
index priced gas supplies or markets. Third party on-system
financial swaps are hedges that the Partnership enters into on
behalf of its customers who are connected to its systems,
wherein the Partnership fixes a supply or market price for a
period of time for its customers, and simultaneously enters into
the derivative transaction. Marketing financial swaps are
similar to on-system financial swaps, but are entered into for
customers not connected to the Partnerships systems.
Storage swaps transactions protect against changes in the value
of gas that the Partnership has stored to serve various
operational requirements. Basis swaps are used to hedge basis
location price risk due to buying gas into one of the
Partnerships systems on one index and selling gas off that
same system on a different index.
In August 2005 the Partnership acquired puts, or rights to sell
a portion of the liquids from the plants at a fixed price over a
two-year period beginning January 1, 2006 for a premium of
$18.7 million as part of the overall risk management plan
related to the acquisition of the El Paso assets which
closed on November 1, 2005. In December 2005 the
Partnership sold a portion of those puts for $4.3 million.
The Partnership did not designate these put options to obtain
hedge accounting and therefore, these put options were marked to
market through our consolidated statement of operations for the
years ended December 31, 2005 and 2006. The puts represent
options, but not obligations, to sell the related underlying
liquids volumes at a fixed price.
The components of gain/loss on derivatives in the consolidated
statements of operations are (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Change in fair value of derivates
that do not qualify for hedge accounting
|
|
$
|
713
|
|
|
$
|
10,169
|
|
|
$
|
769
|
|
Realized (gains) losses on
derivatives
|
|
|
(2,238
|
)
|
|
|
(240
|
)
|
|
|
(1,031
|
)
|
Ineffective portion of derivatives
qualifying for hedge accounting
|
|
|
(74
|
)
|
|
|
39
|
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,599
|
)
|
|
$
|
9,968
|
|
|
$
|
(279
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of derivative assets and liabilities, excluding
the interest rate swap, are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Fair value of derivative
assets current
|
|
$
|
22,959
|
|
|
$
|
12,205
|
|
Fair value of derivative
assets long term
|
|
|
3,812
|
|
|
|
7,633
|
|
Fair value of derivative
liabilities current
|
|
|
(12,141
|
)
|
|
|
(14,782
|
)
|
Fair value of derivative
liabilities long term
|
|
|
(2,558
|
)
|
|
|
(3,577
|
)
|
|
|
|
|
|
|
|
|
|
Net fair value of derivatives
|
|
$
|
12,072
|
|
|
$
|
1,479
|
|
|
|
|
|
|
|
|
|
|
F-34
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
Set forth below is the summarized notional amount and terms of
all instruments held for price risk management purposes at
December 31, 2006 (all quantities are expressed in British
Thermal Units and liquids are expressed in gallons). The
remaining term of the contracts extend no later than March 2008
for derivatives, excluding third-party on-system financial
swaps, and extend to June 2010 for third-party on-system
financial swaps. The Partnerships counterparties to
derivative contracts include BP Corporation, Total
Gas & Power, Fortis, UBS Energy, Morgan Stanley and J.
Aron & Co., a subsidiary of Goldman Sachs. Changes in
the fair value of the Partnerships derivatives related to
third-party producers and customers gas marketing activities are
recorded in earnings in the period the transaction is entered
into. The effective portion of changes in the fair value of cash
flow hedges is recorded in accumulated other comprehensive
income until the related anticipated future cash flow is
recognized in earnings and the ineffective portion is recorded
in earnings.
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
|
Total
|
|
|
|
|
Remaining Term
|
|
|
|
Transaction type
|
|
Volume
|
|
|
Pricing Terms
|
|
of Contracts
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Cash Flow Hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas swaps
|
|
|
171,000
|
|
|
NYMEX less a basis of $0.785 to
NYMEX less a
|
|
January 2007 June 2007
|
|
$
|
73
|
|
Natural gas swaps
|
|
|
(3,117,000
|
)
|
|
basis of $0.575 or fixed prices
ranging from $8.20 to $10.855 settling against various Inside
FERC Index prices
|
|
January 2007 March
2008
|
|
|
6,191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas swaps designated
as cash flow hedges
|
|
$
|
6,264
|
|
|
|
|
|
|
Liquids swaps
|
|
|
(26,747,768
|
)
|
|
Fixed prices ranging from $0.61 to
$1.6275 settling against Mt. Belvieu Average of daily postings
(non-TET)
|
|
January 2007 March
2008
|
|
$
|
1,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liquids swaps designated as
cash flow hedges
|
|
$
|
1,766
|
|
|
|
|
|
|
Mark to Market
Derivatives:
|
|
|
|
|
|
|
|
|
Swing swaps
|
|
|
1,685,625
|
|
|
Prices ranging from Inside FERC
Index less
|
|
January 2007
|
|
$
|
(2
|
)
|
Swing swaps
|
|
|
(651,000
|
)
|
|
$0.0275 to Inside FERC Index plus
$0.01 or a fixed price of $5.93 settling against various Gas
Daily Index prices
|
|
January 2007
|
|
|
(12
|
)
|
Total swing swaps
|
|
$
|
(14
|
)
|
|
|
|
|
|
Physical offset to swing swap
transactions
|
|
|
651,000
|
|
|
Prices of various Inside FERC
Index prices
|
|
January 2007
|
|
|
|
|
Physical offset to swing swap
transactions
|
|
|
(1,685,625
|
)
|
|
settling against various Gas Daily
Index prices
|
|
January 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total physical offset to swing
swaps
|
|
$
|
|
|
|
|
|
|
|
F-35
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
|
Total
|
|
|
|
|
Remaining Term
|
|
|
|
Transaction type
|
|
Volume
|
|
|
Pricing Terms
|
|
of Contracts
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Basis swaps
|
|
|
31,040,000
|
|
|
NYMEX less a basis of $0.785 to
NYMEX plus
|
|
January 2007 March
2008
|
|
$
|
(31
|
)
|
Basis swaps
|
|
|
(31,414,000
|
)
|
|
a basis of $0.145 or prices
ranging from $7.31 to $10.505 settling against various Inside
FERC Index prices.
|
|
January 2007 March
2008
|
|
|
(137
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total basis swaps
|
|
$
|
(168
|
)
|
|
|
|
|
|
Physical offset to basis swap
transactions
|
|
|
5,090,000
|
|
|
Prices ranging from Inside FERC
Index less $0.09 to Inside FERC
|
|
January 2007 March
2007
|
|
$
|
(30,417
|
)
|
Physical offset to basis swap
transactions
|
|
|
(4,935,000
|
)
|
|
Index plus $0.0175 or a fixed
price of $7.31 settling against various Inside FERC Index prices
|
|
January 2007 March
2007
|
|
|
30,891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total physical offset to basis
swap transactions
|
|
$
|
474
|
|
|
|
|
|
|
Third party on-system financial
swaps
|
|
|
8,415,800
|
|
|
Fixed prices ranging from $5.659
to $11.91 settling against various Inside FERC Index prices
|
|
January 2007 June 2010
|
|
$
|
(9,420
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total third party on-system
financial swaps
|
|
$
|
(9,420
|
)
|
|
|
|
|
|
Physical offset to third party
on-system transactions
|
|
|
(8,415,800
|
)
|
|
Fixed prices ranging from $5.71 to
$11.96 settling against various Inside FERC Index prices
|
|
January 2007 June 2010
|
|
$
|
10,176
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total physical offset to third
party on-system swaps
|
|
$
|
10,176
|
|
|
|
|
|
|
Storage swap
transactions:
|
|
|
|
|
Storage swap transactions
|
|
|
(355,000
|
)
|
|
Fixed price of $10.065 settling
against various Inside FERC Henry Hub Index price
|
|
February 2007
|
|
$
|
1,333
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial storage swap
transactions
|
|
$
|
1,333
|
|
|
|
|
|
|
Natural gas liquid
puts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquid put options (purchased)
|
|
|
80,497,830
|
|
|
Fixed prices ranging from $0.565
to $1.26
|
|
January 2007 December
2007
|
|
$
|
3,117
|
|
Liquid put options (sold)
|
|
|
(37,713,696
|
)
|
|
settling against Mount Belvieu
Average Daily Index
|
|
January 2007 December
2007
|
|
|
(1,456
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas liquid puts
|
|
$
|
1,661
|
|
|
|
|
|
|
F-36
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
On all transactions where the
Partnership is exposed to counterparty risk, the Partnership
analyzes the counterpartys financial condition prior to
entering into an agreement, establishes limits, and monitors the
appropriateness of these limits on an ongoing basis
|
Impact
of Cash Flow Hedges
Natural
Gas
For the year ended December 31, 2006, net gains on futures
and basis swap hedge contracts increased gas revenue by
$5.9 million. For the year ended December 31, 2005,
net losses on futures and basis swap hedge contracts decreased
gas revenue by $7.0 million. As of December 31, 2006,
an unrealized pre-tax derivative fair value gain of
$6.3 million, related to cash flow hedges of gas price
risk, was recorded in accumulated other comprehensive income. Of
this amount, $5.4 million is expected to be reclassified
into earnings through December 2007. The actual reclassification
to earnings will be based on
mark-to-market
prices at the contract settlement date, along with the
realization of the gain or loss on the related physical volume,
which amount is not reflected above.
The settlement of futures contracts and basis swap agreements
related to January 2007 gas production increased gas revenue by
approximately $0.7 million.
Liquids
For the year ended December 31, 2006, net gains on liquids
swap hedge contracts increased liquids revenue by approximately
$1.5 million. For the year ended December 31, 2005,
net losses on liquids swap hedge contracts decreased liquids
revenue by approximately $1.2 million. For the year ended
December 31, 2006, an unrealized pre-tax derivative fair
value gain of $1.8 million related to cash flow hedges of
liquids price risk was recorded in accumulated other
comprehensive income. Of this amount, $1.5 million is
expected to be reclassified into earnings through December 2007.
The actual reclassification to earnings will be based on
mark-to-market
prices at the contract settlement date, along with the
realization of the gain or loss on the related physical volume,
which amount is not reflected above.
Assets and liabilities related to third party derivative
contracts, swing swaps, storage swaps and puts are included in
the fair value of derivative assets and liabilities and the
profit and loss on the mark to market value of these contracts
are recorded on a net basis as gain (loss) on derivatives in the
consolidated statement of operations. The Partnership estimates
the fair value of all of its energy trading contracts using
actively quoted prices. The estimated fair value of energy
trading contracts by maturity date was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity Periods
|
|
|
|
Less Than One Year
|
|
|
One to Two Years
|
|
|
More Than Two Years
|
|
|
Total Fair Value
|
|
|
December 31, 2006
|
|
$
|
3,872
|
|
|
$
|
49
|
|
|
$
|
121
|
|
|
$
|
4,042
|
|
Account
Receivable from Enron
On December 2, 2001, Enron Corp. and certain subsidiaries,
including Enron North America Corp. (Enron), each
filed voluntary petitions for relief under Chapter 11 of
Title 11 of the United States Bankruptcy Code. The Company
had allowed unsecured claims in the Enron bankruptcy matter
which total approximately $7.8 million. The Company wrote
these claims down to $1.3 million at December 31,
2004. During the year ending December 31, 2005 and 2006, we
received payments on the Enron receivable in the amount of
$0.2 million and $2.7 million, respectively, and
recognized other income of $1.6 million in 2006 for the
amount collected in excess of the carrying value.
F-37
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
|
|
12.
|
Transactions
with Related Parties
|
The Partnership treats gas for and purchases gas from, Camden
Resources, Inc. (Camden) and treats gas for Erskine Energy
Corporation (Erskine) and Approach Resources, Inc. (Approach).
All three entities are affiliates of the Partnership by way of
equity investments made by Yorktown, a major shareholder in CEI.
During the years ended December 31, 2006, 2005 and 2004,
the Partnership purchased natural gas from Camden in the amount
of approximately $32.5 million, $67.2 million, and
$38.4 million, respectively, and received approximately
$2.6 million, $2.6 million, and $2.4 million,
respectively, in treating fees from Camden. During the year
ended December 31, 2006, the Partnership received treating
fees of $1.3 million and $0.3 million from Erskine and
Approach, respectively.
During the year ended December 31, 2004, the Partnership
was the general partner and a limited partner in CPP as
discussed in Note 5. The Partnership had related-party
transactions with CPP, as summarized below:
|
|
|
|
|
During the year ended December 31, 2004, the Partnership
bought natural gas from CPP in the amount of approximately
$11.6 million and paid approximately $51,000 for
transportation to CPP.
|
|
|
|
During the year ended December 31, 2004, the Partnership
received a management fee from CPP in the amount of
approximately $125,000.
|
|
|
|
During the year ended December 31, 2004, the Partnership
received distributions from CPP in the amount of approximately
$159,000.
|
Effective December 31, 2004, the Partnership acquired all
of the outside limited and general partner interests of the CPP
Partnership for $5.1 million. This acquisition makes the
Partnership the sole limited partner and general partner of CPP,
so the Partnership began consolidating its investment in CPP
effective December 31, 2004.
|
|
13.
|
Commitments
and Contingencies
|
The Partnership has operating leases for office space, office
and field equipment and the Eunice plant. The Eunice plant
operating lease acquired in the El Paso acquisition
provides for annual lease payments of $12.2 million with a
lease term extending to April 15, 2012. At the end of the
lease term we have the option to purchase the plant for
$66.3 million, or to renew the lease for up to an
additional 9.5 years at 50% of the lease payments under the
current lease.
The following table summarizes our remaining non-cancelable
future payments under operating leases for leased office space
and office and field equipment with initial or remaining
non-cancelable lease terms in excess of one year (in millions):
|
|
|
|
|
2007
|
|
$
|
18.7
|
|
2008
|
|
|
17.8
|
|
2009
|
|
|
17.1
|
|
2010
|
|
|
16.0
|
|
2011
|
|
|
16.0
|
|
Thereafter
|
|
|
17.6
|
|
|
|
|
|
|
|
|
$
|
103.2
|
|
|
|
|
|
|
Operating lease rental expense for the years ended
December 31, 2006, 2005 and 2004 was approximately
$23.8 million, $3.4 million and $2.8 million,
respectively.
F-38
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
During 2006 the Company leased approximately 54 of its treating
plants and 33 of its dew point control plants to customers under
operating leases. The initial terms on these leases are
generally 24 months at which time the leases revert to
30-day
cancelable leases. As of December 31, 2006, the Company
only had 29 treating plants under operating leases with
remaining non-cancelable lease terms in excess of one year. The
future minimum lease rentals are $10.6 million and
$6.7 million for the years ended December 31, 2007 and
2008, respectively. These leased treating plants have a cost of
$35.0 million and accumulated depreciation of
$6.6 million as of December 31, 2006.
|
|
(c)
|
Employment
Agreements
|
Certain members of management of the Company are parties to
employment contacts with the general partner. The employment
agreements provide each member of senior management with
severance payments in certain circumstances and prohibit each
such person from competing with the general partner or its
affiliates for a certain period of time following the
termination of such persons employment.
The Partnership acquired the South Louisiana Processing Assets
from the El Paso Corporation in November 2005. One of the
acquired locations, the Cow Island Gas Processing Facility, has
a known active remediation project for benzene contaminated
groundwater. The cause of contamination was attributed to a
leaking natural gas condensate storage tank. The site
investigation and active remediation being conducted at this
location is under the guidance of the Louisiana Department of
Environmental Quality (LDEQ) based on the Risk-Evaluation and
Corrective Action Plan Program (RECAP) rules. In addition, the
Partnership is working with both the LDEQ and the Louisiana
State University, Louisiana Water Resources Research Institute,
on the development and implementation of a new remediation
technology that will drastically reduce the remediation time as
well as the costs associated with such remediation projects. The
estimated remediation costs are expected to be approximately
$0.5 million. Since this remediation project is a result of
previous owners operation and the actual contamination
occurred prior to the Partnerships ownership, these costs
were accrued as part of the purchase price.
The Partnership acquired LIG Pipeline Company and its
subsidiaries on April 1, 2004. Contamination from
historical operations has been identified at a number of sites
within the acquired properties. The seller, AEP, has indemnified
the Partnership for these identified sites. Moreover, AEP has
entered into an agreement with a third-party company pursuant to
which the remediation costs associated with these sites have
been assumed by this third-party company that specializes in
remediation work. The Company does not expect to incur any
material liability with these sites. The Partnership has
disclosed these deficiencies to Louisiana Department of
Environmental Quality and is working with the department to
correct permit conditions and address modifications to
facilities to bring them into compliance. The Company does not
expect to incur any material environmental liability associated
with these issues.
The Partnership acquired assets from DEFS in June 2003 that have
environmental contamination, including a gas plant in Montgomery
County near Conroe, Texas. At Conroe, contamination from
historical operations has been identified at levels that exceed
the applicable state action levels. Consequently, site
investigation
and/or
remediation are underway to address those impacts. The
remediation cost for the Conroe plant site is currently
estimated to be approximately $3.2 million. Under the
purchase agreement, DEFS has retained liability for cleanup of
the Conroe site. Moreover, DEFS has entered into an agreement
with a third-party company pursuant to which the remediation
costs associated with the Conroe site have been assumed by this
third-party company that specializes in remediation work.
F-39
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
The Partnership is involved in various litigation and
administrative proceedings arising in the normal course of
business. In the opinion of management, any liabilities that may
result from these claims would not individually or in the
aggregate have a material adverse effect on its financial
position or results of operations.
On December 15, 2006, the Company made a
three-for-one
stock split in the form of a stock dividend.
In October 2006, the Companys stockholders approved an
increase in the number of authorized shares of capital stock
from 20 million shares, consisting of 19 million
shares of common stock and 1 million shares of preferred
stock, to 150 million shares, consisting of
140 million shares of common stock and 10 million
shares of preferred stock. In January 2004, the Company made a
two-for-one
stock split in conjunction with its initial public offering
discussed in Note 1(b).
|
|
(b)
|
Sale
of Capital Stock
|
On June 29, 2006, the Company issued 7,650,780 shares
of common stock in a private placement for total net proceeds of
$179.9 million. Lubar Equity Fund, LLC, an affiliate of one
of the Companys directors, purchased 468,210 of the shares
at a purchase price of $25.633 per share and unrelated
third-parties purchased 7,182,570 shares at a purchase
price of $23.39. The Company used the proceeds of the stock
issuance to purchase $180.0 million of senior subordinated
series C units representing limited partner interests of
the Partnership.
In January 2004, $4.9 million in stockholder notes
receivable were repaid in conjunction with the Companys
initial public offering discussed in Note 1(b) and the
remaining notes receivable were repaid in December 2004.
Identification of operating segments is based principally upon
differences in the types and distribution channel of products.
The Companys reportable segments consist of Midstream and
Treating. The Midstream division consists of the Companys
natural gas gathering and transmission operations and includes
the south Louisiana processing and liquids assets, the gathering
and transmission assets located in north and south Texas, the
LIG pipelines and processing plants located in Louisiana, the
Mississippi System, the Arkoma System in Oklahoma and various
other small systems. Also included in the Midstream division are
the Companys energy trading operations. The operations in
the Midstream segment are similar in the nature of the products
and services, the nature of the production processes, the type
of customer, the methods used for distribution of products and
services and the nature of the regulatory environment. The
Treating division generates fees from its plants either through
volume-based treating contracts or though fixed monthly
payments. The Seminole carbon dioxide processing plant located
in Gaines County, Texas is included in the Treating division.
The accounting policies of the operating segments are the same
as those described in note 2 of the Notes to Consolidated
Financial Statements. The Company evaluates the performance of
its operating segments based on operating revenues and segment
profits. Corporate expenses include, general corporate expenses
associated with managing the operating segments. Corporate
assets consist principally of property and equipment, including
software, for general corporate support, working capital and
debt refinancing costs. Intersegment sales are at cost.
F-40
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
Summarized financial information concerning the Companys
reportable segments is shown in the following table. There are
no other significant non-cash items.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream
|
|
|
Treating
|
|
|
Corporate
|
|
|
Totals
|
|
|
|
(In thousands)
|
|
|
Year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to external customers
|
|
$
|
3,073,069
|
|
|
$
|
66,225
|
|
|
$
|
|
|
|
$
|
3,139,294
|
|
Profit on energy trading activities
|
|
|
2,510
|
|
|
|
|
|
|
|
|
|
|
|
2,510
|
|
Purchased gas
|
|
|
(2,859,815
|
)
|
|
|
(9,463
|
)
|
|
|
|
|
|
|
(2,869,278
|
)
|
Operating expenses
|
|
|
(80,988
|
)
|
|
|
(20,048
|
)
|
|
|
|
|
|
|
(101,036
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
134,776
|
|
|
$
|
36,714
|
|
|
$
|
|
|
|
$
|
171,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inter-segment sales
|
|
$
|
10,520
|
|
|
$
|
(10,520
|
)
|
|
$
|
|
|
|
$
|
|
|
Gain (loss) on derivatives
|
|
$
|
1,591
|
|
|
$
|
8
|
|
|
$
|
|
|
|
$
|
1,599
|
|
Depreciation and amortization
|
|
$
|
(63,409
|
)
|
|
$
|
(15,800
|
)
|
|
$
|
(3,583
|
)
|
|
$
|
(82,792
|
)
|
Capital expenditures (excluding
acquisitions)
|
|
$
|
294,597
|
|
|
$
|
31,463
|
|
|
$
|
8,184
|
|
|
$
|
334,244
|
|
Identifiable assets
|
|
$
|
1,962,543
|
|
|
$
|
203,528
|
|
|
$
|
40,627
|
|
|
$
|
2,206,698
|
|
Year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to external customers
|
|
$
|
2,982,874
|
|
|
$
|
48,606
|
|
|
$
|
|
|
|
$
|
3,031,480
|
|
Profit on energy trading activities
|
|
|
1,568
|
|
|
|
|
|
|
|
|
|
|
|
1,568
|
|
Purchased gas
|
|
|
(2,860,823
|
)
|
|
|
(9,706
|
)
|
|
|
|
|
|
|
(2,870,529
|
)
|
Operating expenses
|
|
|
(41,997
|
)
|
|
|
(14,771
|
)
|
|
|
|
|
|
|
(56,768
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
81,622
|
|
|
$
|
24,129
|
|
|
$
|
|
|
|
$
|
105,751
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inter-segment sales
|
|
$
|
10,003
|
|
|
$
|
(10,003
|
)
|
|
$
|
|
|
|
$
|
|
|
Gain (loss) on derivatives(a)
|
|
$
|
(9,968
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(9,968
|
)
|
Depreciation and amortization
|
|
$
|
(23,289
|
)
|
|
$
|
(10,646
|
)
|
|
$
|
(2,135
|
)
|
|
$
|
(36,070
|
)
|
Capital expenditures (excluding
acquisitions)
|
|
$
|
98,284
|
|
|
$
|
22,886
|
|
|
$
|
6,512
|
|
|
$
|
127,682
|
|
Identifiable assets
|
|
$
|
1,281,576
|
|
|
$
|
130,435
|
|
|
$
|
33,314
|
|
|
$
|
1,445,325
|
|
Year ended December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to external customers
|
|
$
|
1,948,021
|
|
|
$
|
30,755
|
|
|
$
|
|
|
|
$
|
1,978,776
|
|
Profit on energy trading activities
|
|
|
2,228
|
|
|
|
|
|
|
|
|
|
|
|
2,228
|
|
Purchased gas
|
|
|
(1,861,204
|
)
|
|
|
(5,274
|
)
|
|
|
|
|
|
|
(1,866,478
|
)
|
Operating expenses
|
|
|
(29,540
|
)
|
|
|
(8,856
|
)
|
|
|
|
|
|
|
(38,396
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
59,505
|
|
|
$
|
16,625
|
|
|
$
|
|
|
|
$
|
76,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inter-segment sales
|
|
$
|
6,360
|
|
|
$
|
(6,360
|
)
|
|
$
|
|
|
|
$
|
|
|
Gain (loss) on derivatives
|
|
$
|
279
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
279
|
|
Impairments
|
|
$
|
(981
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(981
|
)
|
Depreciation and amortization
|
|
$
|
(15,106
|
)
|
|
$
|
(7,272
|
)
|
|
$
|
(656
|
)
|
|
$
|
(23,034
|
)
|
Capital expenditures (excluding
acquisitions)
|
|
$
|
17,405
|
|
|
$
|
25,141
|
|
|
$
|
3,438
|
|
|
$
|
45,984
|
|
Identifiable assets
|
|
$
|
491,275
|
|
|
$
|
90,287
|
|
|
$
|
25,206
|
|
|
$
|
606,768
|
|
|
|
|
(a) |
|
Midstream segment profit is net of non-cash derivative loss of
$10.2 million. |
F-41
CROSSTEX
ENERGY, INC.
Notes to
Consolidated Financial
Statements (Continued)
The following table reconciles the segment profits reported
above to the operating income as reported in the consolidated
statements of operations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Segment profits
|
|
$
|
171,490
|
|
|
$
|
105,751
|
|
|
$
|
76,130
|
|
General and administrative expenses
|
|
|
(47,707
|
)
|
|
|
(34,145
|
)
|
|
|
(20,005
|
)
|
Impairments
|
|
|
|
|
|
|
|
|
|
|
(981
|
)
|
Gain (loss) on derivatives
|
|
|
1,599
|
|
|
|
(9,968
|
)
|
|
|
279
|
|
Gain on sale of property
|
|
|
2,108
|
|
|
|
8,138
|
|
|
|
12
|
|
Depreciation and amortization
|
|
|
(82,792
|
)
|
|
|
(36,070
|
)
|
|
|
(23,034
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
44,698
|
|
|
$
|
33,706
|
|
|
$
|
30,401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16.
|
Quarterly
Financial Data (Unaudited)
|
Summarized unaudited quarterly financial data is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Total
|
|
|
|
(In thousands, except per share amount)
|
|
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
817,119
|
|
|
$
|
744,655
|
|
|
$
|
855,285
|
|
|
$
|
724,745
|
|
|
$
|
3,141,804
|
|
Operating income
|
|
|
10,355
|
|
|
|
9,344
|
|
|
|
14,866
|
|
|
|
10,133
|
|
|
|
44,698
|
|
Net income
|
|
|
12,832
|
|
|
|
1,642
|
|
|
|
1,516
|
|
|
|
465
|
|
|
|
16,455
|
|
Basic earnings per common share
|
|
$
|
0.34
|
|
|
$
|
0.04
|
|
|
$
|
0.03
|
|
|
$
|
0.01
|
|
|
$
|
0.39
|
|
Diluted earnings per common share
|
|
$
|
0.33
|
|
|
$
|
0.04
|
|
|
$
|
0.03
|
|
|
$
|
0.01
|
|
|
$
|
0.39
|
|
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
549,989
|
|
|
$
|
630,805
|
|
|
$
|
782,757
|
|
|
$
|
1,069,497
|
|
|
$
|
3,033,048
|
|
Operating income
|
|
|
6,477
|
|
|
|
7,087
|
|
|
|
3,614
|
|
|
|
16,528
|
|
|
|
33,706
|
|
Net income
|
|
|
1,572
|
|
|
|
1,746
|
|
|
|
755
|
|
|
|
45,063
|
|
|
|
49,136
|
|
Basic earnings per common share
|
|
$
|
0.04
|
|
|
$
|
0.05
|
|
|
$
|
0.02
|
|
|
$
|
1.18
|
|
|
$
|
1.29
|
|
Diluted earnings per common share
|
|
$
|
0.04
|
|
|
$
|
0.05
|
|
|
$
|
0.02
|
|
|
$
|
1.16
|
|
|
$
|
1.26
|
|
F-42
SCHEDULE I
CROSSTEX
ENERGY, INC. (PARENT COMPANY)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
9,812
|
|
|
$
|
11,499
|
|
Deferred tax asset
|
|
|
|
|
|
|
5,190
|
|
Prepaid expenses and other
|
|
|
104
|
|
|
|
91
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
9,916
|
|
|
|
16,780
|
|
|
|
|
|
|
|
|
|
|
Investment in the Partnership
|
|
|
326,760
|
|
|
|
143,324
|
|
Investment in subsidiary
|
|
|
|
|
|
|
1,068
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
336,676
|
|
|
$
|
161,172
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Payable to the Partnership
|
|
$
|
23
|
|
|
$
|
173
|
|
Other accrued liabilities
|
|
|
50
|
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
73
|
|
|
|
226
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liability
|
|
|
57,190
|
|
|
|
49,699
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
463
|
|
|
|
127
|
|
Additional paid-in capital
|
|
|
263,264
|
|
|
|
80,187
|
|
Retained earnings
|
|
|
13,535
|
|
|
|
31,747
|
|
Accumulated other comprehensive
income
|
|
|
2,151
|
|
|
|
(814
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
279,413
|
|
|
|
111,247
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
stockholders equity
|
|
$
|
336,676
|
|
|
$
|
161,172
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements of
Crosstex Energy, Inc. included in this report.
F-43
CROSSTEX
ENERGY, INC. (PARENT COMPANY)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands except share data)
|
|
|
Operating income and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from investment in the
Partnership
|
|
$
|
8,324
|
|
|
$
|
14,943
|
|
|
$
|
15,754
|
|
Income (Loss) from investment in
subsidiary
|
|
|
1,000
|
|
|
|
(400
|
)
|
|
|
(1,044
|
)
|
General and administrative expense
|
|
|
(1,476
|
)
|
|
|
(1,077
|
)
|
|
|
(1,096
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
7,848
|
|
|
|
13,466
|
|
|
|
13,614
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income
|
|
|
378
|
|
|
|
432
|
|
|
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before gain on issuance of
units by the Partnership and income taxes
|
|
|
8,226
|
|
|
|
13,898
|
|
|
|
13,687
|
|
Gain on issuance of units in the
Partnership
|
|
|
18,955
|
|
|
|
65,070
|
|
|
|
|
|
Income tax provision expense
|
|
|
(10,896
|
)
|
|
|
(29,832
|
)
|
|
|
(4,987
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative
effect of change in accounting principle
|
|
|
16,285
|
|
|
|
49,136
|
|
|
|
8,700
|
|
Cumulative effect of change in
accounting principle from investment in the Partnership
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,455
|
|
|
$
|
49,136
|
|
|
$
|
8,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative
effect of change in accounting principle per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.39
|
|
|
$
|
1.29
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.39
|
|
|
$
|
1.26
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in
accounting principle per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.39
|
|
|
$
|
1.29
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.39
|
|
|
$
|
1.26
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
42,168
|
|
|
|
37,956
|
|
|
|
35,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
42,666
|
|
|
|
38,871
|
|
|
|
38,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements of
Crosstex Energy, Inc. included in this report.
F-44
CROSSTEX
ENERGY, INC. (PARENT COMPANY)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
16,455
|
|
|
$
|
49,136
|
|
|
$
|
8,700
|
|
Adjustments to reconcile net
income (loss) to net cash flow provided by (used in) operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from investment in the
Partnership
|
|
|
(8,324
|
)
|
|
|
(14,943
|
)
|
|
|
(15,754
|
)
|
(Income) loss from investment in
subsidiary
|
|
|
(1,000
|
)
|
|
|
400
|
|
|
|
1,044
|
|
Deferred taxes
|
|
|
10,896
|
|
|
|
29,832
|
|
|
|
4,992
|
|
Stock-based compensation
|
|
|
22
|
|
|
|
|
|
|
|
28
|
|
Gain on issuance of units in the
Partnership
|
|
|
(18,955
|
)
|
|
|
(65,070
|
)
|
|
|
|
|
Cumulative effect of change in
accounting principle from investment in the Partnership
|
|
|
(170
|
)
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
(38
|
)
|
|
|
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
|
|
|
|
(57
|
)
|
|
|
|
|
Prepaid expenses and other
|
|
|
(13
|
)
|
|
|
139
|
|
|
|
(97
|
)
|
Accounts payable and other accrued
liabilities
|
|
|
(153
|
)
|
|
|
(377
|
)
|
|
|
(333
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
operating activities
|
|
|
(1,242
|
)
|
|
|
(978
|
)
|
|
|
(1,420
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in the Partnership
|
|
|
(189,407
|
)
|
|
|
(6,317
|
)
|
|
|
|
|
Distributions from the Partnership
|
|
|
41,711
|
|
|
|
28,093
|
|
|
|
21,184
|
|
Dividends from subsidiary
|
|
|
2,072
|
|
|
|
19
|
|
|
|
4,927
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
investing activities
|
|
|
(145,624
|
)
|
|
|
21,795
|
|
|
|
26,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of common and
preferred stock
|
|
|
179,720
|
|
|
|
|
|
|
|
5,262
|
|
Proceeds from exercise of common
stock options
|
|
|
126
|
|
|
|
3,810
|
|
|
|
949
|
|
Common stock repurchased and
cancelled
|
|
|
|
|
|
|
(8,234
|
)
|
|
|
|
|
Preferred dividends paid
|
|
|
|
|
|
|
|
|
|
|
(3,603
|
)
|
Common dividends paid
|
|
|
(34,667
|
)
|
|
|
(21,603
|
)
|
|
|
(11,903
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in)
financing activities
|
|
|
145,179
|
|
|
|
(26,027
|
)
|
|
|
(9,295
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
(1,687
|
)
|
|
|
(5,210
|
)
|
|
|
15,396
|
|
Cash, beginning of year
|
|
|
11,499
|
|
|
|
16,709
|
|
|
|
1,313
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of year
|
|
$
|
9,812
|
|
|
$
|
11,499
|
|
|
$
|
16,709
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements of
Crosstex Energy, Inc. included in this report.
F-45
SCHEDULE II
CROSSTEX
ENERGY, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
Charged to
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning
|
|
|
Costs and
|
|
|
Other
|
|
|
|
|
|
End of
|
|
|
|
of Period
|
|
|
Expenses
|
|
|
Accounts
|
|
|
Deductions
|
|
|
Period
|
|
|
|
(In thousands)
|
|
|
Year Ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For doubtful receivables
classified as non-current assets
|
|
$
|
259
|
|
|
$
|
359
|
|
|
|
|
|
|
|
|
|
|
$
|
618
|
|
Year Ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For doubtful receivables
classified as non-current assets
|
|
$
|
59
|
|
|
|
200
|
|
|
|
|
|
|
|
|
|
|
$
|
259
|
|
Year Ended December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For doubtful receivables
classified as non-current assets
|
|
$
|
6,931
|
|
|
|
|
|
|
|
|
|
|
$
|
(6,931
|
)(a)
|
|
|
|
|
|
|
|
(a) |
|
The allowance for doubtful receivables for the Enron claims was
written off against the receivable balance in 2004 pursuant to
the Companys allowed claim in Enrons bankruptcy
proceedings. |
F-46
EXHIBIT
INDEX
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
3
|
.1
|
|
|
|
Amended and Restated Certificate
of Incorporation of Crosstex Energy, Inc. (incorporated by
reference from Exhibit 3.1 to Crosstex Energy, Inc.s
Current Report on
Form 8-K
dated October 26, 2006, filed with the Commission on
October 31, 2006).
|
|
3
|
.2
|
|
|
|
Third Amended and Restated Bylaws
of Crosstex Energy, Inc. (incorporated by reference from
Exhibit 3.1 to Crosstex Energy, Inc.s Current Report
on
Form 8-K
dated March 22, 2006, filed with the Commission on
March 28, 2006).
|
|
3
|
.3
|
|
|
|
Certificate of Limited Partnership
of Crosstex Energy, L.P. (incorporated by reference from
Exhibit 3.1 to Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file No.
333-97779).
|
|
3
|
.4
|
|
|
|
Fifth Amended and Restated
Agreement of Limited Partnership of Crosstex Energy Services,
L.P., dated as of June 29, 2006 (incorporated by reference
to Exhibit 3.1 to Crosstex Energy, L.P.s Current
Report on
Form 8-K
dated June 29, 2006, filed with the Commission on
July 6, 2006).
|
|
3
|
.5
|
|
|
|
Certificate of Limited Partnership
of Crosstex Energy Services, L.P. (incorporated by reference
from Exhibit 3.3 to Crosstex Energy, L.P.s
Registration Statement on
Form S-1,
file No.
333-97779).
|
|
3
|
.6
|
|
|
|
Second Amended and Restated
Agreement of Limited Partnership of Crosstex Energy Services,
L.P., dated as of April 1, 2004 (incorporated by reference
from Exhibit 3.5 to Crosstex Energy, L.P.s Quarterly
Report on
Form 10-Q
for the quarterly period ended March 31, 2004).
|
|
3
|
.7
|
|
|
|
Certificate of Limited Partnership
of Crosstex Energy GP, L.P. (incorporated by reference from
Exhibit 3.5 to Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file No.
333-97779).
|
|
3
|
.8
|
|
|
|
Agreement of Limited Partnership
of Crosstex Energy GP, L.P., dated as of July 12, 2002
(incorporated by reference from Exhibit 3.6 to Crosstex
Energy L.P.s Registration Statement on
Form S-1,
file
No. 333-97779).
|
|
3
|
.9
|
|
|
|
Certificate of Formation of
Crosstex Energy GP, LLC (incorporated by reference from
Exhibit 3.7 from Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file
No. 333-97779).
|
|
3
|
.10
|
|
|
|
Amended and Restated Limited
Liability Company Agreement of Crosstex Energy GP, LLC, dated as
of December 17, 2002 (incorporated by reference from
Exhibit 3.8 from Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file No.
333-106927).
|
|
3
|
.11
|
|
|
|
Amended and Restated Certificate
of Formation of Crosstex Holdings GP, LLC (incorporated by
reference from Exhibit 3.11 to Crosstex Energy, Inc.s
Registration Statement on
Form S-1,
file
No. 333-110095).
|
|
3
|
.12
|
|
|
|
Limited Liability Company
Agreement of Crosstex Holdings GP, LLC, dated as of
October 27, 2003 (incorporated by reference from
Exhibit 3.12 to Crosstex Energy, Inc.s Registration
Statement on
Form S-1,
file
No. 333-110095).
|
|
3
|
.13
|
|
|
|
Certificate of Formation of
Crosstex Holdings LP, LLC (incorporated by reference from
Exhibit 3.13 to Crosstex Energy, Inc.s Registration
Statement on
Form S-1,
file
No. 333-110095).
|
|
3
|
.14
|
|
|
|
Limited Liability Company
Agreement of Crosstex Holdings LP, LLC, dated as of
November 4, 2003 (incorporated by reference from
Exhibit 3.14 to Crosstex Energy, Inc.s Registration
Statement on
Form S-1,
file
No. 333-110095).
|
|
3
|
.15
|
|
|
|
Amended and Restated Certificate
of Limited Partnership of Crosstex Holdings, L.P. (incorporated
by reference from Exhibit 3.15 to Crosstex Energy,
Inc.s Registration Statement on
Form S-1,
file
No. 333-110095).
|
|
3
|
.16
|
|
|
|
Agreement of Limited Partnership
of Crosstex Holdings, L.P., dated as of November 4, 2003
(incorporated by reference from Exhibit 3.16 to Crosstex
Energy, Inc.s Registration Statement on
Form S-1,
file
No. 333-110095).
|
|
4
|
.1
|
|
|
|
Specimen Certificate representing
shares of common stock (incorporated by reference from
Exhibit 4.1 to Crosstex Energy, Inc.s Registration
Statement on
Form S-1,
file No.
333-110095).
|
|
4
|
.2
|
|
|
|
Registration Rights Agreement,
dated as of June 29, 2006, by and among Crosstex Energy,
Inc., Chieftain Capital Management, Inc., Kayne Anderson MLP
Investment Company, Kayne Anderson Energy Total Return Fund,
Inc., LB I Group Inc., Lubar Equity Fund, LLC and Tortoise North
American Energy Corp. (incorporated by reference to
Exhibit 4.1 to our Current Report on Form 8-K dated
June 29, 2006, filed with the Commission on July 6,
2006).
|
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
10
|
.1
|
|
|
|
Omnibus Agreement dated
December 17, 2002, among Crosstex Energy, Inc. and certain
other parties (incorporated by reference from Exhibit 10.5
to Crosstex Energy, L.P.s Annual Report on
Form 10-K
for the year ended December 31, 2002, file No. 000-50067).
|
|
10
|
.2
|
|
|
|
Form of Indemnity Agreement
(incorporated by reference from Exhibit 10.2 to Crosstex
Energy, Inc.s Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
10
|
.3
|
|
|
|
Crosstex Energy GP, LLC Long-Term
Incentive Plan dated July 12, 2002 (incorporated by
reference from Exhibit 10.4 to Crosstex Energy, L.P.s
Annual Report on
Form 10-K,
file No. 000-50067).
|
|
10
|
.4
|
|
|
|
Amendment to Crosstex Energy GP,
LLC Long-Term Incentive Plan, dated May 2, 2005
(incorporated by reference to Exhibit 10.1 to Crosstex
Energy, L.P.s Current Report on
Form 8-K
dated May 2, 2005, filed with the Commission on May 6,
2005).
|
|
10
|
.5
|
|
|
|
Agreement Regarding 2003
Registration Rights Agreement and Termination of
Stockholders Agreement, dated October 27, 2003
(incorporated by reference from Exhibit 10.4 to Crosstex
Energy, Inc.s Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
10
|
.6
|
|
|
|
Crosstex Energy, Inc. Amended and
Restated Long-Term Incentive Plan effective as of
September 6, 2006 (incorporated by reference to
Exhibit 10.1 to Crosstex Energy, Inc.s Current Report
on
Form 8-K
dated October 26, 2006, filed with the Commission on
October 31, 2006).
|
|
10
|
.7
|
|
|
|
Registration Rights Agreement,
dated December 31, 2003 (incorporated by reference from
Exhibit 10.6 to Crosstex Energy, Inc.s Annual Report on
Form 10-K
for the year ended December 31, 2003).
|
|
10
|
.8
|
|
|
|
Fourth Amended and Restated Credit
Agreement, dated November 1, 2005, among Crosstex Energy
Services, L.P., Bank of America, N.A. and certain other parties
(incorporated by reference to Exhibit 10.1 to Crosstex
Energy, L.P.s Current Report on
Form 8-K
dated November 1, 2005, filed with the Commission on
November 3, 2005).
|
|
10
|
.9
|
|
|
|
First Amendment to Fourth Amended
and Restated Credit Agreement, dated as of February 24,
2006, among Crosstex Energy, L.P., Bank of America, N.A. and
certain other parties (incorporated by reference to
Exhibit 10.2 to Crosstex Energy, L.P.s Current Report
on
Form 8-K
dated March 13, 2006, filed with the Commission on
March 16, 2006).
|
|
10
|
.10
|
|
|
|
Second Amendment to Fourth Amended
and Restated Credit Agreement, dated as of June 29, 2006,
among Crosstex Energy, L.P., Bank of America, N.A. and certain
other parties (incorporated by reference to Exhibit 10.1 to
Crosstex Energy, L.P.s Current Report on
Form 8-K
dated June 29, 2006, filed with the Commission on
July 6, 2006).
|
|
10
|
.11
|
|
|
|
Amended and Restated Note Purchase
Agreement, dated as of July 25, 2006, among Crosstex
Energy, L.P. and the Purchasers listed on the Purchaser Schedule
attached thereto (incorporated by reference to Exhibit 10.1
to Crosstex Energy, L.P.s Current Report on
Form 8-K
dated July 25, 2006, filed with the Commission on
July 28, 2006).
|
|
10
|
.12
|
|
|
|
Purchase and Sale Agreement, dated
as of May 1, 2006, by and between Crosstex Energy Services,
L.P., Chief Holdings LLC and the other parties named therein
(incorporated by reference to Exhibit 10.1 to Crosstex
Energy, L.P.s Current Report on
Form 8-K
dated May 1, 2006, filed with the Commission on May 4,
2006).
|
|
10
|
.13
|
|
|
|
Seminole Gas Processing Plant
Gaines County, Texas Joint Operating Agreement dated
January 1, 1993 (incorporated by reference to
Exhibit 10.10 to Crosstex Energy, L.P.s Registration
Statement on
Form S-1,
file
No. 333-106927).
|
|
10
|
.14
|
|
|
|
Stock Purchase Agreement, dated as
of May 16, 2006, by and among Crosstex Energy, L.P. and
each of the Purchasers set forth on Schedule A thereto
(incorporated by reference to Exhibit 10.2 to our Current
Report on Form 8-K dated May 16, 2006, filed with the
Commission on May 17, 2006).
|
|
10
|
.15
|
|
|
|
Senior Subordinated Series C
Unit Purchase Agreement, dated May 16, 2006 by and among
Crosstex Energy, L.P. and each of the Purchasers set forth on
Schedule A thereto (incorporated by reference to
Exhibit 10.1 to our Current Report on Form 8-K dated
May 16, 2006, filed with the Commission on May 17,
2006).
|
|
10
|
.16
|
|
|
|
Registration Rights Agreement,
dated as of June 29, 2006, by and among Crosstex Energy,
L.P., Chieftain Capital Management, Inc., Energy Income and
Growth Fund, Fiduciary/Claymore MLP Opportunity Fund, Kayne
Anderson MLP Investment Company, Kayne Anderson Energy Total
Return Fund, Inc., LB I Group Inc., Tortoise Energy
Infrastructure Corporation, Lubar Equity Fund, LLC and Crosstex
Energy, Inc. (incorporated by reference to Exhibit 4.1 to
Crosstex Energy, L.P.s Current Report on Form 8-K
dated June 29, 2006, filed with the Commission on
July 6, 2006).
|
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
21
|
.1*
|
|
|
|
List of Subsidiaries.
|
|
23
|
.1*
|
|
|
|
Consent of KPMG LLP.
|
|
31
|
.1*
|
|
|
|
Certification of the Principal
Executive Officer.
|
|
31
|
.2*
|
|
|
|
Certification of the Principal
Financial Officer.
|
|
32
|
.1*
|
|
|
|
Certification of the Principal
Executive Officer and the Principal Financial Officer of the
Company pursuant to 18 U.S.C. Section 1350.
|
|
|
|
* |
|
Filed herewith. |
|
|
|
As required by Item 14(a)(3), this exhibit is identified as
a compensatory benefit plan or arrangement |
EX-21.1
2
d43870exv21w1.htm
LIST OF SUBSIDIARIES
exv21w1
Exhibit 21.1
LIST OF SUBSIDIARIES
|
|
|
|
|
State of |
Name of Subsidiary |
|
Organization |
Crosstex
Energy, L.P. |
|
Delaware |
Crosstex
Energy GP, LLC
|
|
Delaware |
Crosstex
Energy GP, L.P.
|
|
Delaware |
Crosstex
Holdings, L.P.
|
|
Delaware |
Crosstex Operating GP, LLC
|
|
Delaware |
Crosstex Energy Services GP, LLC
|
|
Delaware |
Crosstex Energy Services, L.P.
|
|
Delaware |
Crosstex Pipeline, LLC
|
|
Texas |
Crosstex Pipeline Partners, Ltd.
|
|
Texas |
Crosstex Gulf Coast Transmission Ltd.
|
|
Texas |
Crosstex Gulf Coast Marketing Ltd.
|
|
Texas |
Crosstex CCNG Gathering, Ltd.
|
|
Texas |
Crosstex CCNG Transmission, Ltd.
|
|
Texas |
Crosstex CCNG Processing, Ltd.
|
|
Texas |
Crosstex Treating Services, L.P.
|
|
Delaware |
Crosstex Alabama Gathering System, L.P.
|
|
Delaware |
Crosstex Mississippi Industrial Gas Sales, L.P.
|
|
Delaware |
Crosstex Mississippi Pipeline, L.P.
|
|
Delaware |
Crosstex Seminole Gas, L.P.
|
|
Delaware |
Crosstex Acquisition Management, L.P.
|
|
Delaware |
Crosstex Louisiana Energy, L.P.
|
|
Delaware |
LIG Chemical GP, LLC
|
|
Delaware |
LIG Chemical, L.P.
|
|
Delaware |
LIG Liquids Holdings, L.P.
|
|
Delaware |
Crosstex LIG, LLC
|
|
Louisiana |
Crosstex Tuscaloosa, LLC
|
|
Louisiana |
Crosstex LIG Liquids, LLC
|
|
Louisiana |
Crosstex DC Gathering Company, J.V.
|
|
Texas |
Crosstex North Texas Pipeline, L.P.
|
|
Texas |
Crosstex North Texas Gathering, L.P.
|
|
Texas |
Crosstex Processing Services, LLC
|
|
Delaware |
Crosstex Pelican, LLC
|
|
Delaware |
Crosstex NGL Marketing, L.P.
|
|
Texas |
Sabine Pass Plant Facility, J.V.
|
|
Texas |
EX-23.1
3
d43870exv23w1.htm
CONSENT OF KPMG LLP
exv23w1
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Crosstex Energy, Inc.
We consent to the incorporation by reference in the registration statements No. 333-134713 and
333-136734 on Forms S-3 and Form S-8 of
Crosstex Energy, Inc. and subsidiaries (No. 333-114014) of our reports dated February 28, 2007, with respect to the
consolidated balance sheets of Crosstex Energy, Inc. and subsidiaries as of December 31, 2006 and 2005, and the
related consolidated statements of operations, changes in stockholders equity, comprehensive
income, and cash flows for each of the years in the three-year period ended December 31, 2006, and
all related financial statement schedules, managements assessment of the effectiveness of internal
control over financial reporting as of December 31, 2006 and the effectiveness of internal control
over financial reporting as of December 31, 2006, which reports appear in the December 31, 2006
annual report on Form 10-K of Crosstex Energy, Inc.
As
discussed in Note 2 to the consolidated financial statements, effective
January 1, 2006, Crosstex Energy, Inc. and subsidiaries adopted
the provisions of Statement of Financial Accounting Standards
No. 123 (revised 2004), Share Based Payment.
/s/ KPMG LLP
Dallas, Texas
February 28, 2007
EX-31.1
4
d43870exv31w1.htm
CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER
exv31w1
Exhibit 31.1
CERTIFICATIONS
I, Barry E. Davis, President and Chief Executive Officer of Crosstex Energy, Inc., certify that:
1. I have reviewed this annual report on Form 10-K of Crosstex Energy, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused the disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrants internal control over financial
reporting that occurred during the registrants most recent fiscal quarter (the registrants
fourth fiscal quarter in case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrants internal control over financial
reporting; and
5. The registrants other certifying officer(s) and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect the
registrants ability to record, process, summarize and report financial data information; and
(b) Any fraud, whether or not material, that involves management or other employees who
have a significant role in the registrants internal controls over financial reporting.
|
|
|
|
|
|
|
/s/ Barry E. Davis |
|
|
|
|
Barry E. Davis,
|
|
|
|
|
President and Chief Executive Officer |
|
|
|
|
(principal executive officer) |
|
|
Date: February 28, 2007 |
|
|
|
|
EX-31.2
5
d43870exv31w2.htm
CERTIFICATION OF THE PRINCIPAL FINANCIAL OFFICER
exv31w2
Exhibit 31.2
CERTIFICATIONS
I, William W. Davis, Executive Vice President and Chief Financial Officer of Crosstex Energy, Inc.,
certify that:
1. I have reviewed this annual report on Form 10-K of Crosstex Energy, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused the disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrants internal control over financial
reporting that occurred during the registrants most recent fiscal quarter (the registrants
fourth fiscal quarter in case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrants internal control over financial
reporting; and
5. The registrants other certifying officer(s) and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect the
registrants ability to record, process, summarize and report financial data information; and
(b) Any fraud, whether or not material, that involves management or other employees who
have a significant role in the registrants internal controls over financial reporting.
|
|
|
|
|
|
|
/s/ William W. Davis |
|
|
|
|
William W. Davis,
|
|
|
|
|
Executive Vice President and Chief Financial Officer |
|
|
|
|
(principal financial and accounting officer) |
|
|
Date: February 28, 2007 |
|
|
|
|
EX-32.1
6
d43870exv32w1.htm
CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER & PRINCIPAL FINANCIAL OFFICER
exv32w1
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Crosstex Energy, Inc. (the Registrant) on Form 10-K
for the year ended December 31, 2006 as filed with the Securities and Exchange Commission on the
date hereof (the Report), each of the undersigned, Barry E. Davis, Chief Executive Officer of
Crosstex Energy, Inc. and William W. Davis, Chief Financial Officer
of Crosstex Energy Inc. certifies,
pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of
2002, that to his knowledge:
|
(1) |
|
The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and |
|
|
(2) |
|
The information contained in the Report fairly presents, in all
material respects, the financial condition and result of operations of the
Registrant. |
|
|
|
|
|
Date: February 28, 2007
|
|
/s/ Barry E. Davis |
|
|
|
|
Barry E. Davis
|
|
|
|
|
President and Chief Executive Officer |
|
|
|
|
|
|
|
Date: February 28, 2007
|
|
/s/ William W. Davis |
|
|
|
|
William W. Davis
|
|
|
|
|
Executive Vice President and |
|
|
|
|
Chief Financial Officer |
|
|
A signed original of this written statement required by Section 906 has been provided to the
Registrant and will be retained by the Registrant and furnished to the Securities and Exchange
Commission or its staff upon request. The foregoing certification is being furnished to the
Securities and Exchange Commission as an exhibit to the Report.
GRAPHIC
7
d43870d4387000.gif
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