UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2008
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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
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52-2235832
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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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
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No
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Indicate by check mark if registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes
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No
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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
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No
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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.
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Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated filer
or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated
filer
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Accelerated
filer
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Non-accelerated
filer
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Smaller
reporting
company
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes
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No
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The aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant was
approximately $803,616,085 on June 30, 2008, based on
$34.66 per share, the closing price of the Common Stock as
reported on the NASDAQ Global Select Market on such date.
At February 16, 2009, there were 46,420,305 shares of
common stock outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE:
Portions of the Registrants Proxy Statement relating to
its 2009 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
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CROSSTEX
ENERGY, INC.
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 and natural gas liquids, or NGLs. These
partnership interests consist of the following:
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16,414,830 common units representing an aggregate 34.0% 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.
Quarterly distributions by the Partnership steadily increased
from the first distribution of $0.25 per unit for the quarter
ended March 31, 2003 to $0.63 per unit for the quarter
ended June 30, 2008. However, the distribution for third
quarter of 2008 operating results was reduced to $0.50 per unit
followed by a further reduction to $0.25 per unit for the fourth
quarter of 2008 (paid in February 2009). The Partnerships
distributions were reduced during the last half of 2008 as a
result of a decline in its cash flows from operations due to
declines in natural gas and NGL prices during the last half of
2008, gross margin losses due to hurricanes Ike and Gustav and
the declines in the global financial markets and economic
conditions as discussed under Crosstex Energy,
L.P. Recent Developments and Crosstex
Energy, L.P. Business Strategies.
In response to the recent developments, the Partnership has
adjusted its business strategy for 2009 to focus on maximizing
liquidity, maintaining a stable asset base, improving the
profitability of its assets by increasing their utilization
while controlling costs and reducing capital expenditures as
discussed under Crosstex Energy, L.P. Business
Strategies. One of the strategies included amending the
Partnerships bank credit facility and its senior note
agreements to negotiate terms with its creditors that will allow
continued operation of its assets during the
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current difficult economic conditions. The amended terms of the
credit facility and senior secured note agreement prohibit the
Partnership from making distributions unless its leverage ratio
is below certain levels and the PIK notes, as defined below,
have been repaid. The Partnership does not expect that it will
will meet these conditions in 2009. Since our cash flows consist
almost exclusively of distributions from the Partnership on the
partnership interests we own, we do not expect to receive any
significant cash flows until the Partnership is able to improve
its leverage ratio and begin making distributions again. As of
December 31, 2008, we have cash of $14.0 million which
we expect to be sufficient to pay our expenses and federal
income taxes over the next several years based on our forecasted
cash flows. We do not anticipate making any future dividend
payments after the dividend payment in February 2009 with
respect to fourth quarter 2008 operating results until we begin
receiving distributions from the Partnership again.
Historically we have paid dividends to our stockholders on a
quarterly basis 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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cash reserves our board of directors believed were prudent to
maintain.
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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 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.
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
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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 consumers,
other marketers and pipelines. 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 over 5,700 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 225 natural gas
amine-treating plants and 56 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 18 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, 2004.
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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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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
Bbls = barrels
Bcf = billion cubic feet
Btu = British thermal units
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Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet
NGL = natural gas liquid
Capacity volumes for the Partnerships facilities are
measured based on physical volume and stated in cubic feet (Bcf,
Mcf or MMcf). Throughput volumes are measured based on energy
content and stated in British thermal units (Btu or MMBtu). A
volume capacity of 100 MMcf generally correlates to volume
throughput of 100,000 MMBtu.
Recent
Developments
Global financial markets and economic conditions have been, and
continue to be, disrupted and volatile. Numerous events during
2008 have severely restricted current liquidity in the capital
markets throughout the United States and around the world. The
ability to raise money in the debt and equity markets has
diminished significantly and, if available, the cost of funds
has increased substantially. One of the features driving
investments in master limited partnerships (MLPs),
such as our investment in CELP, over the past few years has been
the distribution growth offered by MLPs due to liquidity in the
financial markets for capital investments to grow distributable
cash flow through development projects and acquisitions. Future
growth opportunities have been and are expected to continue to
be constrained by the lack of liquidity in the financial markets.
In addition, the Partnerships business has been
significantly impacted by the substantial decline in crude oil
prices during the last half of 2008 from a high of approximately
$145 per Bbl in July 2008 to a low of approximately $34 per Bbl
in December 2008 (based on NYMEX futures daily close prices for
the prompt month), a 76.7% decline, and the related 78.2%
decline in NGL prices from a high of $2.19 per gallon in July
2008 to a low of $0.48 per gallon in December 2008 (based on the
OPIS Mt. Belvieu daily average spot liquids prices). Crude oil
prices reflected on NYMEX during January and February 2009 have
fluctuated, to a lesser extent, between $49 per Bbl and $35 per
Bbl while the OPIS Mt. Belvieu NGL prices have improved slightly
ranging from $0.81 per gallon and $0.62 per gallon. The declines
in NGL prices have negatively impacted the Partnerships
gross margin for the fourth quarter of 2008 and could continue
to negatively impact our gross margin (revenue less cost of gas
purchased) in 2009. A significant percentage of inlet gas at its
processing plants is settled under percent of liquids
(POL) agreements or fractionation margin (margin)
contracts. Over the past two years the inlet processing volumes
associated with POL and margin contracts were approximately 70%,
on a combined basis, of the total volume of gas processed. The
POL fees are denominated in the form of a share of the liquids
extracted. Therefore, fee revenue under a POL agreement is
directly impacted by NGL prices and the decline of these prices
in 2008 contributed to a significant decline in gross margin
from processing. Under the POL settlement terms, the Partnership
is not responsible for the fuel or shrink associated with
processing. Under margin contracts the Partnership realizes a
gross margin from processing based upon the difference in the
value of NGLs extracted from the gas less the value of the
product in its gaseous state and the cost of fuel to extract.
This is often referred to as the fractionation
spread. During the last half of 2008 the fractionation
spread narrowed significantly as the value of NGLs decreased
more than the value of the gas and fuel associated with the
processed gas. Thus the gross margin realized under these margin
contracts was also negatively impacted due to the commodity
price environment. If the current weakness in the economy
continues for a prolonged period, it would likely further reduce
demand for gas and for NGL products, such as ethane, a primary
feedstock for the petrochemical and manufacturing industries,
and result in continued lower natural gas and NGL prices.
Although the Partnership has seen some improvement in NGL prices
and the fractionation spread in the early months of 2009 over
the levels experienced in December 2008, the Partnership
believes that its processing margins in 2009 will be
substantially lower than the processing margins realized in 2008
based on current market indicators. For the year ended
December 31, 2008, approximately 38.7% of the
Partnerships gross margin was attributable to gas
processing as compared to 46.1% of its gross margin for the year
ended December 31, 2007. See Item 7A.
Quantitative and Qualitative Disclosures about Market
Risk-Commodity Price Risk for a description of the
contractual processing arrangements used by the Partnership.
Natural gas prices have declined by approximately 61.0%, from a
high of $13.58 per MMBtu in July 2008 to a low of $5.29 per
MMBtu in December 2008 (based on the NYMEX futures daily close
prices for the prompt month). Natural gas prices have declined
even further during January and February 2009 with prices
ranging from $6.07 in
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early January to $4.01 in mid-February. Many of the
Partnerships customers finance their drilling activity
with cash flow from operations, which have been negatively
impacted by the declines in natural gas and crude oil prices, or
through the incurrence of debt or issuance of equity, which
markets have been adversely impacted by global financial market
conditions. The Partnership believes that the adverse price
changes coupled with the overall downturn in the economy and the
constrained capital markets will put downward pressure on
drilling budgets for gas producers which could result in lower
volumes being transported on its pipeline and gathering systems
and processed through its processing plants. The Partnership has
seen a decline in drilling activity by gas producers in its
areas of operation during the fourth quarter of 2008. In
addition, industry drilling rig count surveys published in early
2009 show substantial declines in rigs in operation as compared
to 2008. Several of the Partnerships customers, including
one of its largest customers in the Barnett Shale, have recently
announced drilling plans for 2009 that are substantially below
their drilling levels during 2008.
The Partnerships business was also negatively impacted by
hurricanes Gustav and Ike, which came ashore in the Gulf Coast
in September 2008. Although the majority of its assets in Texas
and Louisiana sustained minimal physical damage from these
hurricanes and promptly resumed operations, several offshore
production platforms and pipelines that transport gas production
to its Pelican, Eunice, Sabine Pass and Blue Water processing
plants in south Louisiana were damaged by the storms. Some of
the repairs to these offshore facilities were completed during
the fourth quarter of 2008 but the Partnership does not
anticipate that gas production to its south Louisiana plants
will recover to pre-hurricane levels until mid-2009, when all
repairs are expected to be complete. Additionally, one of the
Partnerships south Louisiana processing plants, the Sabine
Pass processing plant, which is located on the shoreline of the
Louisiana Gulf Coast, sustained some physical damage. The Sabine
Pass processing plant was repaired during the fourth quarter of
2008 and the plant was returned to service in early January
2009. Operations in north Texas were also impacted by these
hurricanes because operations at Mt. Belvieu, Texas, a central
distribution point for NGL sales where several fractionators are
located which fractionate NGLs from the entire United States,
were interrupted as a result of these storms. These storms
resulted in an adverse impact to the Partnerships gross
margin of approximately $22.9 million.
Two of the Partnerships facilities, one in south Louisiana
and one in north Texas, were also partially damaged by fires
during 2008. Although substantially all of the property repairs
were covered by insurance, the Sabine Pass processing plant in
south Louisiana was out of service for approximately one month.
The loss of operating income due to the fire at the Godley
compressor station in north Texas was minimal because the
Partnership was successful in rerouting the gas to its other
facilities in the area until the damaged compressor was
replaced. The estimated loss in gross margin as a result of
these fires was $0.9 million.
Business
Strategy
Until the occurrence of the recent developments described above,
the Partnerships long-term strategy has been to increase
distributable cash flow per unit by accomplishing economies of
scale through new construction or expansion in core operating
areas and making accretive acquisitions of assets that are
essential to the production, transportation and marketing of
natural gas and NGLs. In response to these recent events, the
Partnership adjusted its business strategy in the fourth quarter
2008 and for 2009 to focus on maximizing liquidity, maintaining
a stable asset base, improving the profitability of its assets
by increasing their utilization while controlling costs and
reducing capital expenditures. The Partnership has undertaking
the following steps to implement the strategy:
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The Partnership intends to operate its existing asset base to
enhance profitability by undertaking initiatives to maximize
utilization and by improving operations, reducing operating
costs and renegotiating contracts, when appropriate, to improve
the economics. The Partnership has a solid base of assets,
including midstream and treating assets that are well located to
benefit from the continued growth in the Barnett Shale in north
Texas and the new growth anticipated from the Haynesville Shale
located in northern Louisiana and eastern Texas.
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The Partnership amended its bank credit facility and its senior
secured note agreements in November 2008 and again in February
2009 to negotiate terms that facilitate its compliance with debt
covenants while it operates its assets during the current
difficult economic conditions. The terms of the amended
agreements allow the Partnership to maintain a higher level of
leverage and to maintain a lower interest coverage ratio;
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however, interest costs will increase and the ability to pay
distributions and incur additional indebtedness will be
restricted when it is operating at higher leverage ratios. The
terms of these agreements are described more fully under
Amendments to Credit Documents below and in
Item 7, Managements Discussion and Analysis of
Financial Condition and Results of Operations.
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The Partnership has lowered its distribution level from $0.63
per unit for the second quarter of 2008 to $0.25 per unit for
the fourth quarter of 2008. The amended terms of the credit
facility and senior secured note agreement prohibit the
Partnership from making distributions unless its leverage ratio
is below certain levels and the PIK notes have been repaid as
discussed more fully under Amendments to Credit
Documents. The Partnership does not expect that it will
meet these conditions in 2009.
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The Partnership sold certain non-strategic assets in November
2008 and used the proceeds from such sales to reduce its
outstanding borrowings under its bank credit facility. The
Partnership received $85.0 million for the sale of its
12.4% interest in the Seminole gas processing plant to an
unaffiliated third party and it received $20.0 million for
the assignment of a transportation contract right to another
unaffiliated third party. The Partnership may consider selling
other non-strategic assets during 2009 and use the proceeds to
further reduce its indebtedness if it is able to obtain
attractive offers for such assets.
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The Partnership has reduced budgeted capital expenditures
significantly for 2009. Total growth capital investments in the
calendar year 2009 are currently anticipated to be approximately
$100.0 million and primarily relate to capital projects in
north Texas and Louisiana pursuant to contract obligations with
producers. The Partnerships ability to grow its asset base
through the continued development of its north Texas and
Louisiana assets or through acquisitions will be limited due to
its lack of access to capital markets and due to restrictions
under its debt agreements. The Partnership will use cash flow
from operations and existing capacity under its bank credit
facility to fund its reduced capital spending plan during 2009.
Capital expenditures in future periods will be limited to cash
flow from operating activities and to existing capacity under
the bank credit facility.
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The Partnership has reduced general and administrative expenses
by reducing its work force by approximately 8.0% through the
elimination of open positions and certain corporate positions
and minimizing all non-essential costs. It has also reduced
operating expenses by reducing overtime and renegotiating
certain contracts to reduce monthly costs and by eliminating
certain equipment rentals.
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Amendments
to Credit Documents
On November 7, 2008, the Partnership amended its bank
credit facility and the senior secured note agreement to, among
other things, revise the leverage ratio and interest coverage
ratio requirements to ease the covenant restrictions under the
agreements and to permit the Partnership to sell certain assets,
including the non-strategic asset dispositions described in
Business Strategy above. The amendments also
included provisions that increased the interest rates under both
the bank credit facility and the senior note agreement by 1.25%
per annum and increased the other fees associated with the bank
credit facility.
Due to the continued decline in commodity prices and the
deterioration in processing margins, the Partnership determined
that there was a significant risk that the amended terms
negotiated in November would not be sufficient to allow
continued operation during 2009 without triggering a covenant
default under the Partnerships bank credit facility and
the senior secured note agreement. On February 27, 2009,
the Partnership amended its bank credit facility and the senior
secured note agreements to include revised terms that facilitate
compliance with debt covenants while the Partnership continues
to operate its assets during the current difficult economic
conditions. In general terms, the amended agreement allows the
Partnership to maintain a higher level of leverage and to
maintain a lower interest coverage ratio; however, interest
costs will increase, the ability to incur additional
indebtedness will be restricted when it is operating at higher
leverage ratios and the Partnerships ability to pay
distributions will be prohibited until its leverage ratio is
significantly lower and it repays the PIK notes.
Under the amended bank credit facility, if the Partnership is
operating at higher leverage ratios, its interest margin over
the London Interbank Offering Rate (LIBOR) on its
LIBOR borrowings will generally increase to 4.00% per annum
which represents an increase of 2.25% over the comparative
interest rate under the credit
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agreement prior to the November and February amendments. The
fees charged for letters of credit will also increase by 2.25%.
The interest margin on the LIBOR borrowings will decline from
the maximum level of 4.00% to a low of 2.75% when the
Partnership leverage ratios are at the lower end of the range.
The amendment also sets a floor for the LIBOR interest rate of
2.75% per annum, which means, effective as of February 27,
2009, borrowings under the bank credit facility accrue interest
at the rate of 6.75% based on the LIBOR rate in effect on such
date and the Partnerships current leverage ratio. The
interest rates and leverage ratios under the amended agreement
are described more fully in Item 7, Managements
Discussion and Analysis of Financial Condition and Results of
OperationsDescription of Indebtedness.
Commencing February 27, 2009, the interest rate the
Partnership pays on all of the senior secured notes will
increase by 2.25% per annum over the comparative interest rates
under the senior note agreement prior to the November and
February amendments. As a result of this rate increase, the
weighted average cash interest rate on the outstanding balance
on the senior secured notes is approximately 9.25% as of
February 2009.
Under the amended senior note agreement, the senior secured
notes will accrue additional interest of 1.25% in the form of an
increase in the principal amount of the senior secured notes
(the PIK notes), unless the leverage ratio is less
than 4.25 to 1.00 as of the end of any fiscal quarter. All PIK
interest will be payable 180 days after the maturity of the bank
credit facility.
Per the terms of the amended senior secured note agreement,
commencing on the date the Partnership refinances its bank
credit facility, the interest rate payable in cash on its senior
secured notes will increase by 1.25% per annum for any quarter
if our leverage ratio as of the most recently ended fiscal
quarter was greater than or equal to 4.25 to 1.00. In addition,
commencing on June 30, 2012, the interest rate payable in
cash on the Partnerships senior secured notes will
increase by 0.50% per annum for any quarter if its leverage as
of the most recently ended fiscal quarter was greater than or
equal to 4.00 to 1.00, but this incremental interest will not
accrue if the Partnership is paying the incremental 1.25% per
annum of interest described in the preceding sentence.
Under the Partnerships amended bank credit facility and
senior secured note agreement, it must pay a leverage fee if it
does not prepay debt and permanently reduce the banks
commitments by the cumulative amounts of $100.0 million on
September 30, 2009, $200.0 million on
December 31, 2009, and $300.0 million on
March 31, 2010. If the Partnership fails to meet any
de-leveraging target, it must pay a leverage fee on such date,
equal to the product of the aggregate commitments outstanding
under its bank credit facility and the outstanding amount of
senior secured note agreement on such date, and 1.0% on
September 30, 2009, 1.0% on December 31, 2009, and
2.0% on March 31, 2010. This leverage fee will accrue on
the applicable date, but not be payable until the Partnership
refinances its bank credit facility.
Under the amended bank credit facility and senior secured note
agreement, the Partnership may not make quarterly distributions
to its unitholders unless the PIK notes have been repaid and the
leverage ratio, as defined in the agreements, is less than 4.25
to 1.00. If the leverage ratio is between 4.00 to 1.00 and 4.25
to 1.00, it may make the minimum quarterly distribution of up to
$0.25 per unit if the PIK notes have been repaid. If the
leverage ratio is less than 4.00 to 1.00, it may make quarterly
distributions to unitholders from available cash as provided by
its partnership agreement if the PIK notes have been repaid. The
PIK notes are due six months after the earlier of the
refinancing or maturity of the Partnerships bank credit
facility. Based on the Partnerships forecasted leverage
ratios for 2009, it does not anticipate making quarterly
distributions in 2009 other than the distribution paid in
February 2009 related to fourth quarter 2008 operating results.
The Partnership will not be able to make distributions to its
unitholders in future periods if the leverage ratio does not
improve and the PIK notes are not first repaid.
The amended credit facility and senior note agreement also limit
the Partnerships annual capital expenditures (excluding
maintenance capital expenditures) to $120.0 million in 2009
and $75.0 million in 2010 (with unused amounts in any year
being carried forward to the next year). It is unlikely that the
Partnership will be able to make any acquisitions based on the
terms of its credit facility and the current condition of the
capital markets because, as discussed below, the Partnership may
only use a portion of the proceeds from the incurrence of
unsecured debt and the issuance of equity to make such
acquisitions.
8
The amended credit facility and senior secured note agreement
also require the Partnership to repay outstanding indebtedness
from proceeds from asset sales and debt and equity issuances.
All proceeds from asset sales must be used to prepay
indebtedness. All proceeds from the incurrence of unsecured debt
and 50% of the proceeds from equity issuances must be used to
prepay indebtedness if its leverage ratio exceeds 4.50 to 1.00.
If the leverage ratio is less than 4.50 to 1.00 but greater than
3.50 to 1.00, 50% of the debt proceeds and 25% of the equity
proceeds must be used to prepay indebtedness. If the leverage
ratio is less than 3.50 to 1.00, there are no prepayment
requirements from debt and equity issuances. The prepayments are
to be applied pro-rata based on total debt (including letter of
credit obligations) outstanding under the bank credit agreement
and the total debt outstanding under the note agreements
described below. Any prepayments of advances on the bank credit
facility from proceeds from asset sales, debt or equity
issuances will permanently reduce the borrowing capacity or
commitment under the facility in an amount equal to 100% of the
amount of the prepayment. Any such commitment reduction will not
reduce the banks $300.0 million commitment to issue
letters of credit under the Partnerships bank credit
facility.
The Partnership was in compliance with all debt covenants at
December 31, 2008 and 2007 and expects to be in compliance
with debt covenants for the next twelve months.
For more information on the amendments to the Partnerships
bank credit facility and senior note agreement, see Item 7,
Managements Discussion and Analysis of Financial
Condition and Analysis of Financial Condition and Results of
OperationsDescription of Indebtedness.
Acquisitions
and Expansion in Recent Years
North Texas Assets.
The Partnerships
North Texas Pipeline, or NTP, which commenced service in April
2006, consists of a
133-mile
pipeline and associated gathering lines from an area near
Fort Worth, Texas to a point near Paris, Texas. The initial
capacity of the NTP was approximately
250 MMcf/d.
In 2007, the Partnership expanded the capacity on the NTP to a
total of approximately
375 MMcf/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, Kinder Morgan, Houston Pipeline, or HPL, Atmos
and other markets. As of December 2008, the total throughput on
the NTP was approximately 300,000 MMBtu/d. The NTP also
will interconnect with a new interstate gas pipeline under
construction by Boardwalk Pipeline Partners, L.P. known as the
Gulf Crossing Pipeline, which is expected to be in service in
March 2009. The Gulf Crossing Pipeline is expected to provide
the Partnerships customers access to premium midwest and
east coast markets.
On June 29, 2006, the Partnership expanded its operations
in the north Texas area through its acquisition of the natural
gas gathering pipeline systems and related facilities of Chief
Holdings, LLC, or Chief, in the Barnett Shale for
$475.3 million. The acquired systems, which it refers to in
conjunction with the NTP and its other facilities in the area as
the North Texas Assets, included gathering pipeline, a
125 MMcf/d
carbon dioxide treating plant and compression facilities with
26,000 horsepower. At the closing of that acquisition,
approximately 160,000 net acres previously owned by Chief
and acquired by Devon Energy Corporation, or 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, the Partnership began expanding its north
Texas pipeline gathering system. The continued expansion of the
north Texas gathering systems to handle the growing production
in the Barnett Shale was one of the Partnerships core
areas for internal growth during 2007 and 2008 and will continue
to be a core area during 2009. Since the date of the acquisition
through December 31, 2008, the Partnership has connected
444 new wells to its gathering system and significantly
increased the dedicated acreage owned by other producers. The
Partnerships processing capacity in the Barnett Shale is
280 MMcf/d
including the Silver Creek plant, which is a
200 MMcf/d
cryogenic processing plant, the Azle plant, which is a
50 MMcf/d
cryogenic processing plant and the Goforth plant, which is a
30 MMcf/d
processing plant. In 2007 and 2008, the Partnership constructed
a
29-mile
expansion in north Johnson County to its north Texas gathering
systems. The first phase of the expansion commenced operation in
September 2007. The last two phases of the expansion commenced
operation in May and July of 2008. The total gathering capacity
of this
29-mile
expansion is currently
235 MMcf/d
and is expected to increase to approximately
400 MMcf/d
in April 2009 by the addition of compression. The Partnership
has also installed two 40 gallon per minute and one 100 gallon
per minute amine treating plants to provide carbon dioxide
removal capability. As of December 2008, the capacity of the
north Texas gathering system was approximately
1,100 MMcf/d
and total throughput on the north Texas gathering systems,
including the north
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Johnson County expansion, had increased from approximately
115,000 MMBtu/d at the time of the Chief acquisition to
approximately 796,000 MMBtu/d.
In April 2008, the Partnership commenced construction of an
$80.0 million natural gas processing facility called Bear
Creek in Hood County near its existing North Texas Assets. The
new plant will have a gas processing capacity of
200 MMcf/d.
Due to the recent decline in commodity prices and the
corresponding decline in drilling activity, the Partnership does
not anticipate that the additional processing capacity provided
by the Bear Creek plant will be needed until late 2010 or in
2011. Therefore, it has decided to put this construction project
on hold until the demand for this processing capacity returns,
at which time it will seek to obtain financing for this project.
As of December 31, 2008, the Partnership has spent
approximately $20.2 million on this project for
construction of a portion of the plant that will be utilized
when the plant is completed in the future.
The Partnership has budgeted approximately $57.0 million
for continued development of its north Texas assets during 2009.
These capital projects represent system expansions that are
planned to handle volume growth as well as projects required
pursuant to existing obligations with producers to connect new
wells to its gathering systems in north Texas. Several of the
Partnerships customers, including one of its largest
customers in the Barnett Shale, have recently announced drilling
plans for 2009 that are substantially below their drilling
levels during 2008. As a result capital expenditures related to
well connections during 2009 may be less than budgeted.
North Louisiana Expansion Project.
In April
2007, the Partnership completed construction and commenced
operations on its north Louisiana expansion, which is an
extension of its LIG system designed to increase take-away
pipeline capacity to the producers developing natural gas in the
fields south of Shreveport, Louisiana. The north Louisiana
expansion consists of approximately 63 miles of 24
mainline with 9 miles of 16 gathering lateral
pipeline and 10,000 horsepower of new compression referred to as
the Red River lateral. The Red River lateral bisects the
developing Haynesville Shale gas play in north Louisiana. The
Red River lateral was operating at near capacity during 2008 so
the Partnership added
35 MMcf/d
of capacity by adding compression during the third quarter of
2008, bringing the total capacity of the Red River lateral to
approximately
275 MMcf/d.
As of December 31, 2008, the Red River lateral was flowing
at approximately 225,000 MMBtu/d. Interconnects on the
north Louisiana expansion include connections with the
interstate pipelines of ANR Pipeline, Columbia Gulf
Transmission, Texas Gas Transmission and Trunkline Gas.
The Partnership has budgeted approximately $31.0 million
for continued expansion in north Louisiana during 2009 with
additional compression providing approximately
100 MMcf/d
of increased capacity to producers in the Haynesville Shale gas
play. The expansion is scheduled to be completed in July 2009.
The Partnership has 10 year firm transportation contracts
subscribing to all the capacity on this project with four large
producers.
Other
Developments
Partnerships Issuance of Common
Units.
On April 9, 2008, the Partnership
issued 3,333,334 common units in a private offering at $30.00
per unit, which represented an approximate 7% discount from the
market price. Net proceeds from the issuance, including our
general partner contribution less expenses associated with the
issuance, were approximately $102.0 million.
Conversion of Subordinated and Senior Subordinated
Series C Units.
The subordination period for
the Partnerships subordinated units ended and the
remaining 4,668,000 subordinated units converted into common
units representing limited partner interests of the Partnership
effective February 16, 2008. We own all 4,668,000 of the
units that converted.
The 12,829,650 senior subordinated series C units of the
Partnership also converted into common units representing
limited partner interests of the Partnership effective
February 16, 2008. We own 6,414,830 of the series C
units that converted to common units.
Senior Subordinated Series D Units.
On
March 23, 2007, the Partnership issued an aggregate of
3,875,340 senior subordinated series D units representing
limited partner interests of the Partnership in a private
offering. The senior subordinated series D units will
convert to common units representing limited partner interests
of the Partnership on March 23, 2009. Since the Partnership
did not make distributions of available cash from operating
surplus, as defined in the partnership agreement, of at least
$0.62 per unit on each outstanding common unit for the
10
quarter ending December 31, 2008 and did not generate
adjusted operating surplus, as defined in the partnership
agreement, of at least $0.62 per unit on each outstanding common
unit for the quarter ending December 31, 2008, each senior
subordinated series D unit will convert into 1.05 common
units. We do not own any of the senior subordinated
series D units.
Midstream
Segment
Gathering, Processing and Transmission.
The
Partnerships primary Midstream assets include its north
Texas assets, south Texas assets, Louisiana assets and
Mississippi assets. These systems, in the aggregate, consist of
over 5,700 miles of pipeline, 12 natural gas processing
plants and four fractionators and contributed approximately
88.0% of gross margin in 2008 and 2007.
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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 included gathering pipeline, a
125 MMcf/d
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, the Partnership began
expanding its north Texas pipeline gathering system.
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Gathering System.
Since the date of the
acquisition through December 31, 2008, the Partnership has
connected 444 new wells to its north Texas gathering system and
significantly increased the dedicated acreage owned by other
producers. During May and July 2008, the Partnership completed
the 29 mile expansion in north Johnson County to its north
Texas gathering systems with a current gathering capacity of
235 MMcf/d
which will be increased to
400 MMcf/d
in April 2009 by adding compression. As of December 31,
2008, total capacity on the north Texas gathering system,
including the north Johnson County expansion, was approximately
1,100 MMcf/d
and total throughput was approximately 796,000 MMBtu/d.
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Processing Facilities.
Since 2006, the
Partnership has constructed three gas processing plants with a
total processing capacity in the Barnett Shale of
280 MMcf/d
including its Silver Creek plant, which is a
200 MMcf/d
cryogenic processing plant, its Azle plant, which is a
50 MMcf/d
cryogenic processing plant and its Goforth plant, which is a
30 MMcf/d
processing plant. The Partnership has also installed two 40
gallon per minute and one 100 gallon per minute amine treating
plants to provide carbon dioxide removal capability.
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North Texas Pipeline (NTP).
The Partnership
expanded its NTP system in the second quarter of 2007 to a total
capacity of approximately
375 MMcf/d.
The NTP will also interconnect with a new interstate pipeline
that is being constructed by Boardwalk Pipeline Partners, L.P.
known as the Gulf Crossing Pipeline which is expected to provide
the Partnerships customers access to premium midwest and
east coast markets.
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South Texas Assets.
The Partnership has
assembled a highly-integrated south Texas system comprised of
approximately 1,400 miles of intrastate gathering and
transmission pipelines, processing plants with a processing
capacity of approximately
150 MMcf/d
and a contract with a third party to process gas from our
Vanderbilt system. 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, 2008 was
approximately 423,000 MMBtu/d, and average throughput for
the Gregory and Vanderbilt processing assets was approximately
187,000 MMBtu/d. 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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Louisiana Assets.
The Partnerships
Louisiana assets include its LIG intrastate pipeline system and
its gas processing and liquids business in south Louisiana,
referred to as the south Louisiana processing assets.
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LIG System.
The LIG system is the largest
intrastate pipeline system in Louisiana, consisting of
approximately 2,000 miles of gathering and transmission
pipeline, with an average throughput of approximately
960,000 MMBtu/d for the year ended December 31, 2008.
The system also includes two operating, on-system processing
plants, the Plaquemine and Gibson plants, with an average
throughput of 311,000 MMBtu/d for the year ended
December 31, 2008. The system has access to both rich and
lean gas supplies. These supplies reach from north Louisiana to
new onshore production in south central and 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. In 2007, the Partnership extended its LIG system to
the north to reach additional productive areas. This extension,
referred to as the north Louisiana expansion or Red River
lateral, consists of 63 miles of 24 mainline with
9 miles of gathering lateral pipeline and 10,000 horsepower
of compression. The Red River lateral bisects the developing
Haynesville Shale gas play in north Louisiana. The Red River
lateral was operating at near capacity during 2008 so the
Partnership added
35 MMcf/d
of capacity by adding compression during the third quarter of
2008 bringing the total capacity of the Red River lateral to
approximately
275 MMcf/d.
As of December 31, 2008, the Red River lateral was flowing
at approximately 225,000 MMBtu/d.
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South Louisiana Processing Assets.
Natural gas
processing capacity available to the Gulf Coast producers
continues to exceed demand. During 2007 and 2008, the
Partnership completed a number of operational changes at its
Eunice facility and other plants to idle certain equipment,
reduce operating expenses and reconfigure operations to manage
the lower utilization. In addition, the Partnership has
increased its focus on upstream markets and opportunities
through integration of the LIG system and south Louisiana
processing assets to improve overall performance. In 2008, the
south Louisiana assets were negatively impacted by hurricanes
Gustav and Ike, which came ashore in September 2008. Most of the
south Louisiana assets, other than the Sabine Pass processing
plant, sustained minimal physical damage and promptly resumed
operations. The repairs to the Sabine Pass processing plant were
completed during the fourth quarter of 2008 and the plant
returned to service in January 2009. In addition, several
offshore platforms and pipelines owned by third parties
transporting gas production to the Pelican, Eunice, Sabine Pass
and Blue Water processing plants were damaged by the storms and
repair to these offshore facilities continued during the fourth
quarter of 2008. The Partnership anticipates that production
levels will not recover to pre-hurricane levels until mid-2009,
when all repairs are expected to be complete. The south
Louisiana processing assets include the following:
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Eunice Processing Plant and Fractionation
Facility.
The Eunice processing plant has a
capacity of 1.2 Bcf/d and processed approximately
521,000 MMBtu/d for the year ended December 31, 2008.
The plant is connected to onshore gas supply, as well as
continental shelf and deepwater gas production and has
downstream connections to the ANR Pipeline, Florida Gas
Transmission and Texas Gas Transmission, or TGT. TGT modified
its system operations in early 2007 in a manner that
significantly reduced the volumes available from TGT for
processing at the Eunice plant. The Eunice fractionation
facility, which was idled in August 2007, has a capacity of
36,000 Bbls/d of liquid products. Beginning in August 2007,
the liquids from the Eunice processing plant were transported
through the Cajun Sibon pipeline system to the Riverside plant
for fractionation. If liquid volumes exceed Riversides
fractionation capacity, the liquids are delivered to a third
party for fractionation. This operational change improved
overall operating income because of operating cost reductions at
the Eunice plant. The facility continues to maintain a truck
unloading rack where approximately 10 trucks per day are
unloaded and the raw make is sent to the Riverside plant for
fractionation. Eunice also has 190,000 Bbls of above-ground
storage capacity. The Eunice fractionation facility, when
operational, 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.
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Pelican Processing Plant.
The Pelican
processing plant complex is located in Patterson, Louisiana and
has a capacity of
600 MMcf/d
of natural gas. For the year ended December 31, 2008, the
plant
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processed approximately 266,000 MMBtu/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 east of the Sabine River at
Johnsons Bayou, Louisiana and has a capacity of
300 MMcf/d
of natural gas. The Sabine Pass plant is connected to
continental shelf and deepwater gas production with downstream
connections to Florida Gas Transmission, Tennessee Gas Pipeline
(TGP) and Transco. For the first seven months of 2008, this
facility was processing at full capacity. In early August 2008,
the Sabine Pass processing plant sustained fire damage which
occurred during an attempt to bring the plant back on line
following a tropical storm. The plant was repaired and ready to
return to service when it was hit by hurricanes Gustav and Ike
in early September 2008. The plant has been repaired and was
placed back in service in early January 2009.
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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
capacity to the interest of
186 MMcf/d.
For the year ended December 31, 2008, this facility
processed approximately 110,000 MMBtu/d net to the
Partnerships 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. The facility also performs liquid
natural gas (LNG) conditioning services for the Excelerate
Energy LNG tanker unloading facility. Downstream connections
from this plant include TGP and Columbia Gulf Transmission.
During 2008, TGP acquired Columbia Gulf Transmissions
ownership share in the Blue Water pipeline. In January 2009, TGP
reversed the flow of the gas on the pipeline thereby removing
access to all the gas processed at the Blue Water plant from the
Blue Water offshore system and the plant is not currently in
operation. At this time, the Partnership has not found
alternative sources of new gas for the Blue Water plant but the
Partnership will continue to look for new sources of gas,
including the option of moving gas from the Partnerships
LIG system over to Blue Water plant. The Partnership does not
expect to make a decision on any of these options for the Blue
Water plant in the near term due to the excess processing
capacity in the Gulf Coast and the restricted access to capital.
The Blue Water plant contributed gross margin of
$3.9 million and $4.2 million and incurred operating
expenses of $1.2 million and $1.1 million for the
years ended December 31, 2008 and 2007, respectively. The
Partnership recognized an impairment of $17.8 million for
the year ended December 31, 2008 related to the Blue Water
plant because the plant was idled in January 2009. This
impairment represents the carrying amount of the plant in excess
of its estimated fair value as of December 31, 2008.
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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 Bbls/d of
liquids products and fractionates liquids delivered by the Cajun
Sibon pipeline system from Eunice, Pelican, Blue Water and Cow
Island plants or by truck. The Riverside facility has
above-ground storage capacity of approximately 102,000 Bbls.
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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 Bbls 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 Bbls/d. The pipeline transports
unfractionated NGLs, referred to as raw make, from the Eunice,
Pelican and Blue Water plants to either the Riverside
fractionator or the Napoleonville storage facility. Alternate
deliveries can be made to the Eunice plant.
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Mississippi Assets.
The Partnerships
Mississippi assets include approximately
600-miles
of
natural gas gathering and transmission pipelines. The system
gathers natural gas from producers, receives and delivers
natural gas from and to several major interstate pipelines,
including Sonat and Transco, and delivers gas to utilities and
industrial end-users. The average system throughput was
approximately 128,000 MMBtu/d for the year ended
December 31, 2008.
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Other Midstream assets and activities include:
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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, 2008, throughput on
the system averaged approximately 22,000 MMBtu/d. This
gathering system was sold in February 2009 to an unrelated third
party for approximately $11.0 million.
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East Texas.
Currently the east Texas system,
made up of natural gas pipelines and compression installations,
gathers and processes natural gas and delivers gas to NGPL,
Regency Gas, and to other intrastate pipeline systems. For the
year ended December 31, 2008, throughput on the system
averaged approximately 42,000 MMBtu/d. The Partnership
expanded this gas gathering system in May 2008 and it has a
current capacity of
100 MMcf/d.
The Partnership is expecting to receive its first delivery of
Haynesville Shale gas into its east Texas system in the first
quarter of 2009.
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Other.
Other Midstream assets consist of a
variety of gathering lines and processing plants with a
processing capacity of approximately
66 MMcf/d.
Total volumes gathered and resold were approximately
16,000 MMBtu/d for the year ended December 31, 2008.
Total volumes processed were approximately 16,000 MMBtu/d
in the same period.
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Off-System Services.
The Partnership offers
natural gas marketing services on behalf of producers of natural
gas that is not gathered, transmitted, treated or processed by
its assets. They market this gas on a number of interstate and
intrastate pipelines. These volumes averaged approximately
85,000 MMBtu/d in 2008.
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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.
Its treating division contributed approximately 12.0% of the
gross margin in 2008 and 2007. At December 31, 2008, the
Partnership had approximately 200 treating and dew point control
plants in operation. 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 the Partnerships 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 charges a
fixed monthly fee.
All of the shale reservoirs being developed today have
concentrations of carbon dioxide above the normal pipeline
quality specifications of 2.0%. The Haynesville Shale in
northern Louisiana is still experiencing some robust development
because of the higher success in completing these wells. The
Partnership believes that its Treating business strategy is well
suited to the producers in the Haynesville Shale especially
during this time of relatively lower gas prices. The lower gas
prices create an incentive for producers to use equipment
supplied by others as opposed to buying their own equipment
because it is more efficient use of their capital.
The Partnerships treating growth strategy is to utilize
its existing fleet of amine plants to support growth in the
Haynesville Shale gas play. The Partnership believes its track
record of reliability, current availability of equipment and
strategy of sourcing new equipment provide a significant
advantage in competing for new treating business.
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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.
Sale of Interest in the Seminole Plant.
In
November 2008, the Partnership sold its undivided 12.4% interest
in the Seminole gas processing plant to an unrelated third party
for $85.0 million and realized a gain on the sale of
$49.8 million. CELP acquired its non-operating interest in
this carbon dioxide processing plant in June 2003.
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 follows 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.
Compression.
Gathering systems are operated at
pressures that will maximize the total throughput from all
connected wells. Because wells produce at progressively lower
field pressures as they age, it becomes increasingly difficult
to deliver the remaining production in the ground against the
higher pressure that exists in the connected gathering system.
Natural gas compression is a mechanical process in which a
volume of gas at an existing pressure is compressed to a desired
higher pressure, allowing gas that no longer naturally flows
into a higher-pressure downstream pipeline to be brought to
market. Field compression is typically used to allow a gathering
system to operate at a lower pressure or provide sufficient
discharge pressure to deliver gas into a higher-pressure
downstream pipeline. If field compression is not installed, then
the remaining natural gas in the ground will not be produced
because it will be unable to overcome the higher gathering
system pressure. In contrast, if field compression is installed,
a declining well can continue delivering natural gas.
Natural gas treating.
The composition of
natural gas varies depending on the field, the formation and the
reservoir from which it is produced. Natural gas from certain
formations is high in carbon dioxide. Treating plants are placed
at or near a well and remove carbon dioxide and hydrogen sulfide
from natural gas before it is introduced into gathering systems
and transmission pipelines to ensure that it meets pipeline
quality specifications.
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Natural gas processing.
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. Natural gas produced by a well may not be 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.
Fractionation is the
process by which NGLs are further separated into individual,
more valuable components. NGL fractionation facilitates separate
mixed NGL streams into discrete NGL products: ethane, propane,
isobutane, normal butane, natural gasoline and stabilized
condensate. Ethane is primarily used in the petrochemical
industry as feedstock for ethylene, one of the basic building
blocks for a wide range of plastics and other chemical products.
Propane is used both as a petrochemical feedstock in the
production of ethylene and propylene and as a heating fuel, an
engine fuel and industrial fuel. Isobutane is used principally
to enhance the octane content of motor gasoline. Normal butane
is used as a petrochemical feedstock in the production of
ethylene and butylene (a key ingredient in synthetic rubber), as
a blend stock for motor gasoline and to derive isobutene through
isomerization. Natural gasoline, a mixture of pentanes and
heavier hydrocarbons, is used primarily as motor gasoline blend
stock or petrochemical feedstock.
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 establishes a
margin normally by selling natural gas for physical delivery to
third-party users. The Partnership can also use over-the-counter
derivative instruments or enter into future delivery obligations
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. The
Partnerships 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 gathering, transmission, treating,
processing and marketing services for natural gas and NGLs is
highly competitive. The Partnership faces strong competition in
obtaining natural gas supplies and in the marketing and
transportation of natural gas and NGLs. Its competitors include
major integrated oil companies, natural gas producers,
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 the Partnerships
competitors offer more services or have greater financial
resources and access to larger natural gas supplies than it
does. The Partnerships competition differs 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 it. It also faces competition
from vendors of used equipment that occasionally operate plants
for producers. In addition, CELP 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, which is a pipeline companys
ability to waive quality specifications and allow producers to
deliver their contaminated gas untreated. This is generally
referred to as blending because of the receiving
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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 and gas companies, and local and
national natural gas producers, 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 Partnerships marketing
operations.
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 the Partnerships competitors have greater
financial resources or lower capital costs, or are willing to
accept lower returns or greater risks. The 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 has ample supplies of natural gas in excess of the
volumes required for these systems. In connection with the
construction and acquisition of its gathering systems, the
Partnership evaluated well and reservoir data publicly available
or furnished by producers or other service providers 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 Partnerships
investment. Based on these facts, the Partnership believes that
there should be adequate natural gas supply to recoup its
investment with an adequate rate of return. The Partnership 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 the systems or the
anticipated life of such producing reserves.
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 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 its overall profitability.
During the year ended December 31, 2008, the Partnership
had one customer that accounted for approximately 11.0% of its
consolidated revenues. While this customer represents a
significant percentage of consolidated revenues, the loss of
this customer would not have a material impact on 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 the Partnerships 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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While the Partnership does not own any interstate pipelines, it
does transport some gas in interstate commerce. The rates, terms
and conditions of service under which the Partnership transports
natural gas in its pipeline systems in interstate commerce is
subject to FERC jurisdiction under Section 311 of the
Natural Gas Policy Act, or NGPA. In addition, FERC has adopted,
or is in the process of adopting, various regulations concerning
natural gas market transparency that will apply to some of the
pipeline operations. The maximum 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 FERC or by an
appropriate state agency. Rates for interstate services provided
under NGPA Section 311 on the Partnerships NTP and
Mississippi systems are currently under review. The filed rates,
which are based on the respective systems cost of service
and constitute the maximum rates that can be charged on those
systems for interstate service, are slightly lower than the
rates previously charged. Rate reviews on the Louisiana and
south Texas pipeline systems are scheduled for March and April
2009, respectively.
Intrastate Pipeline Regulation.
The
Partnerships intrastate natural gas pipeline operations
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 it believes 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 some 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.
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. Its 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. The
Partnership cannot predict the ultimate impact of these
regulatory changes on its natural gas marketing operations but
does not believe that it will be affected by any such FERC
action materially differently than other natural gas marketers
with whom it competes.
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.
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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. We believe that the Partnership currently holds all
material governmental approvals required to operate its major
facilities. As part of the regular overall evaluation of its
operations, the Partnership has implemented procedures to review
and update governmental approvals as 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 any
such upsets, releases, or spills. In the event of future
increases in environmental 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 losses related to the event are not insured, subject
the Partnership to substantial expense, including both the cost
to comply with applicable laws and regulations and to pay fines
or penalties that may be assessed 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 prevent
and control pollution. These 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. Potentially liable 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 potentially
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. However, there are other laws and regulations
that can create liability for releases of petroleum, natural gas
or NGLs. Moreover, the Partnership may be responsible under
CERCLA or other laws 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 federal or 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. 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. 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. Moreover, it is
possible that some wastes generated by
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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
management and 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 take action 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. The Partnership has completed the
remediation work on this site pending the final review and
approval of reports by LDEQ. As of December 31, 2008, the
Partnership had incurred approximately $0.5 million in such
remediation costs. 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 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. This remediation work is nearing completion. The
Partnership does not expect to incur any material liability in
connection with the remediation associated with this site;
however, there can be no assurance that the third parties who
have assumed responsibility for remediation of site conditions
will fulfill their obligations.
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
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; however, there can be no assurance that the
third parties who have assumed responsibility for remediation of
site conditions will fulfill their obligations.
Air Emissions.
The Partnerships current
and future operations are subject to the federal Clean Air Act
and comparable state laws and regulations. These laws and
regulations regulate emissions of air pollutants from various
industrial sources, including the Partnerships facilities,
and impose various monitoring and reporting requirements.
Pursuant to these laws and regulations, the Partnership may be
required to obtain environmental agency pre-approval for the
construction or modification of certain projects or facilities
expected to produce air emissions or result in an increase in
existing air emissions, obtain and comply with the terms of air
permits, which include various emission and operational
limitations, or use specific emission control technologies to
limit emissions. The
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Partnership likely will be required to incur certain capital
expenditures in the future for air pollution control equipment
in connection with maintaining or obtaining governmental
approvals addressing air-emission related issues. 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 such requirements will not have a
material adverse effect on the Partnerships financial
condition or operating results, and the requirements are not
expected to be more burdensome to the Partnership than any
similarly situated company.
Climate Change.
In response to concerns
suggesting that emissions of certain gases, commonly referred to
as greenhouse gases (including carbon dioxide and
methane), may be contributing to warming of the Earths
atmosphere, the U.S. Congress is actively considering
legislation to reduce such emissions. In addition, at least
one-third of the states, either individually or through
multi-state regional initiatives, have already taken legal
measures intended to reduce greenhouse gas emissions, primarily
through the planned development of greenhouse gas emission
inventories
and/or
greenhouse gas cap and trade programs. The EPA is separately
considering whether it will regulate greenhouse gases as
air pollutants under the existing federal Clean Air
Act. Passage of climate change legislation or other federal or
state legislative or regulatory initiatives that regulate or
restrict emissions of greenhouse gases in areas in which the
Partnership conducts business could adversely affect the demand
for the products it stores, transports and processes, and
depending on the particular program adopted could increase the
costs of its operations, including costs to operate and maintain
its facilities, install new emission controls on its facilities,
acquire allowances to authorize its greenhouse gas emissions,
pay any taxes related to its greenhouse gas emissions
and/or
administer and manage a greenhouse gas emissions program. The
Partnership may be unable to recover any such lost revenues or
increased costs in the rates it charges its customers, and any
such recovery may depend on events beyond its control, including
the outcome of future rate proceedings before the FERC or state
regulatory agencies and the provisions of any final legislation
or regulations. Reductions in the Partnerships revenues or
increases in its expenses as a result of climate control
initiatives could have adverse effects on its business,
financial position, results of operations and prospects.
Clean Water Act.
The Federal Water Pollution
Control Act, also known as the Clean Water Act, and comparable
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.
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
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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 Railroad Commission of
Texas, or 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
We occupy approximately 95,400 square feet of space at our
executive offices in Dallas, Texas under a lease expiring in
June 2014, approximately 25,100 square feet of office space
for the Partnerships south Louisiana operations in
Houston, Texas with lease terms expiring in January 2013 and
approximately 11,800 square feet of office space for its
north Texas operations in Fort Worth, Texas, with lease
terms expiring in April 2013.
During 2008 the Partnership leased approximately
115,000 square feet of additional office space at
2828 N. Harwood Street, Dallas, Texas. This space was
intended to accommodate the corporate office expansion required
by the continued growth of the business. Due to the economic
downturn in the fourth quarter of 2008, it was determined the
relocation of the corporate offices would not take place and the
lease, which was originally set up to run through January 2012,
was terminated on December 29, 2008 with an effective
termination date of January 2010. A portion of this leased
space is currently occupied by the Partnerships computer
hardware and will continue to be occupied through December 2009.
Employees
As of December 31, 2008, the Partnership (through its
subsidiaries) employed approximately 780 full-time
employees. Approximately 270 of the employees were general and
administrative, engineering, accounting and commercial personnel
and the remainders 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 occur, 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 Partnerships bank
credit facility and senior secured note agreement contain
covenants limiting its ability to make distributions to
unitholders so long as it does not meet certain financial ratios
and tests. Under the amended bank credit facility and senior
secured note agreement, it may not make quarterly distributions
to its unitholders unless the PIK notes have been repaid and the
leverage ratio, as defined in the agreements, is less than 4.25
to 1.00. If the leverage ratio is between 4.00 to 1.00 and 4.25
to 1.00, it may make the minimum quarterly distribution of up to
$0.25 unit if the PIK notes have been repaid. If the
leverage ratio is less than 4.00 to 1.00, it may make quarterly
distributions to unitholders from available cash as provided by
its partnership agreement if the PIK notes have been
22
repaid. The PIK notes are due six months after the earlier of
the refinancing or maturity of its bank credit facility. In
order to repay the PIK notes prior to their scheduled maturity,
the Partnership will need to amend or refinance its bank credit
facility.
Based on the amended provisions in the Partnerships credit
facility, its current anticipated cash flows for 2009 and
current economic conditions, it does not currently expect to be
able to pay distributions to its unitholders in 2009 other than
the distribution paid in February 2009 related to fourth quarter
2008 operating results. Even if it does not pay a distribution
to unitholders, its unitholders, including us, may be liable for
taxes on their share of the Partnerships taxable income.
We do not anticipate making any future dividend payments after
the dividend payment in February 2009 with respect to fourth
quarter 2008 operating results until we begin receiving
distributions from the Partnership again.
In addition, even if the Partnerships credit documents do
not prohibit it from making distributions, the Partnership still
may not have sufficient available cash each quarter to pay
distributions to unitholders. 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;
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its level of operating costs; and
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restrictions on distributions contained in its bank credit
facility.
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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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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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Because of these factors, even if the Partnerships credit
documents do not prohibit it from making distributions, the
Partnership still may not be able, or may not have sufficient
available cash to pay distributions to unitholders each quarter.
Furthermore, you should also be aware that the amount of cash
the Partnership has available for distribution depends primarily
upon its cash flow, including cash flow from financial reserves
and working capital borrowings, and is not solely a function of
profitability, which will be affected by non-cash items. As a
result, the Partnership may make cash distributions during
periods when it records losses and may not make cash
distributions during periods when it records net income.
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
23
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 certain
stockholders.
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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any 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.
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
24
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.
The
Partnership may not be able to obtain funding or obtain funding
on acceptable terms because of the deterioration of the credit
and capital markets. This may hinder or prevent the Partnership
from meeting its future capital needs.
Global financial markets and economic conditions have been, and
continue to be, disrupted and volatile, which has caused a
substantial deterioration in the credit and capital markets.
These conditions, along with significant write-offs in the
financial services sector and the re-pricing of credit risk,
have made, and will likely continue to make it, difficult to
obtain funding for capital needs.
Beginning in the second half of 2008, the cost of raising money
in the debt and equity capital markets has increased
substantially while the availability of funds from those markets
has diminished significantly. In particular, as a result of
concerns about the stability of financial markets generally and
the solvency of lending counterparties specifically, the cost of
obtaining money from the credit markets generally has increased
as many lenders and institutional investors have increased
interest rates, enacted tighter lending standards, refused to
refinance existing debt at maturity at all or on terms similar
to borrowers current debt and reduced and, in some cases,
ceased to provide funding to borrowers.
Due to these factors, we cannot be certain that new debt or
equity financing will be available to us or to the Partnership
on acceptable terms or at all. If funding is not available when
needed, or is available only on unfavorable terms, we and the
Partnership may be unable to meet our obligations as they come
due. Moreover, without adequate funding, the Partnership may be
unable to execute its growth strategy, complete future
acquisitions or future construction projects or other capital
expenditures, take advantage of other business opportunities or
respond to competitive pressures, any of which could have a
material adverse effect on revenues and results of operations.
Further, the Partnerships customers may increase
collateral requirements or reduce the business the customers
transact with the Partnership to reduce credit exposure.
Due to
current economic conditions, the Partnerships ability to
obtain funding under its bank credit facility could be
impaired.
The Partnership operates in a capital-intensive industry and
relies on its bank credit facility to finance a significant
portion of its capital expenditures. Its ability to borrow under
the bank credit facility may be impaired because of the recent
downturn in the financial markets, including issues surrounding
the solvency of many institutional lenders and recent failures
of several banks.
Specifically, the Partnership may be unable to obtain adequate
funding under its bank credit facility because:
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one or more of its lenders may be unable or otherwise fail to
meet its funding obligations;
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the lenders do not have to provide funding if there is a default
under the bank credit facility, or if any of the representations
or warranties included in the agreement are false in any
material respect; and
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if any lender refuses to fund its commitment for any reason,
whether or not valid, the other lenders are not required to
provide additional funding to make up for the unfunded portion.
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On February 27, 2009, the Partnership entered into an
amendment to its bank credit facility, revising certain
financial and other restrictive covenants under this facility
through its maturity date. See Item 1,
Business Amendments to Credit Documents.
There can be no assurance that the Partnership will be able to
comply with any newly-negotiated covenants in the future or that
it will be able to obtain waivers or amendments of these
covenants in the event of future noncompliance. If the
Partnership is not in compliance with these covenants, and if it
is unable to secure necessary waivers or other amendments from
the counterparties, it will not have access to the bank credit
facility, which could significantly affect its ability to meet
expenses and operate its business. Further, such noncompliance
could cause a default under the bank credit facility, which
could result in acceleration of the Partnerships
outstanding debt.
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If the Partnership is unable to access funds under its bank
credit facility, it will need to meet capital requirements,
including some of its short-term capital requirements, using
other sources. Due to current economic conditions, alternative
sources of liquidity may not be available on acceptable terms,
if at all. If the cash generated from operations or the funds
the Partnership is able to obtain under its bank credit facility
or other sources of liquidity are not sufficient to meet capital
requirements, then the Partnership may need to delay or abandon
capital projects or other business opportunities, which could
have a material adverse effect on its results of operations and
financial condition. Furthermore, if the current pressures on
credit continue or worsen, the Partnership may not be able to
refinance its then-outstanding debt or replace its
then-outstanding letters of credit when due, which could have a
material adverse effect on its business.
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 Partnerships business is subject to significant risks
due to fluctuations in commodity prices. Its exposure to these
risks is primarily in the gas processing component of its
business. A large percentage of the processing fees are realized
under percent of liquids (POL) contracts that are directly
impacted by the market price of NGLs. It also realizes
processing gross margins under fractionation margin (margin)
contracts. These settlements are impacted by the relationship
between NGL prices and the underlying natural gas prices, which
is also referred to as the fractionation spread.
A significant volume of inlet gas at the Partnerships
south Louisiana and north Texas processing plants is settled
under POL agreements. The POL fees are denominated in the form
of a share of the liquids extracted and the Partnership is not
responsible for the fuel or shrink associated with processing.
Therefore, fee revenue under a POL agreement is directly
impacted by NGL prices, and the decline of these prices in 2008
contributed to a significant decline in the Partnerships
gross margin from processing. The Partnership has a number of
margin contracts on its Plaquemine and Gibson processing plants
that expose it to the fractionation spread. Under these margin
contracts our gross margin is based upon the difference in the
value of NGLs extracted from the gas less the value of the
product in its gaseous state and the cost of fuel to extract
during processing. During the last half of 2008, the
fractionation spread narrowed significantly as the value of NGLs
decreased more than the value of the gas and fuel associated
with the processed gas. Thus the gross margin realized under
these margin contracts was negatively impacted due to the
commodity price environment. The significant decline in crude
oil prices and a related decline in NGL prices during the last
half of 2008 had a significant negative impact on the
Partnerships margins, and may negatively impact its gross
margin further if such declines continue.
In the past, the prices of natural gas and NGLs have been
extremely volatile and the Partnership expects this volatility
to continue. For example, in 2007, the NYMEX settlement price
for natural gas for the prompt month contract ranged from a high
of $7.59 per MMBtu to a low of $5.43 per MMBtu. In 2008, the
same index ranged from $6.46 per MMBtu to $13.10 per MMBtu. A
composite of the OPIS Mt. Belvieu monthly average liquids price
based upon the Partnerships average liquids composition in
2007 ranged from a high of approximately $1.58 per gallon to a
low of approximately $0.92 per gallon. In 2008, the same
composite ranged from approximately $2.01 per gallon to
approximately $0.56 per gallon.
The Partnership may not be successful in balancing its 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 more or less than contracted
volumes. Any of these actions could cause purchases and sales
not to be balanced. If purchases and sales are not balanced, the
Partnership will face increased exposure to commodity price
risks and could have increased volatility in its 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 fluctuates
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, natural gas and NGLs;
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international demand for oil and NGLs;
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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 of downstream NGL fractionation facilities;
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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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Changes in commodity prices may also indirectly impact the
Partnerships profitability by influencing drilling
activity and well operations, and thus the volume of gas it can
gather and process. This volatility may cause the Partnership
gross margin and cash flows to vary widely from period to
period. Hedging strategies may not be sufficient to offset price
volatility risk and, in any event, do not cover all of the
Partnership throughput volumes. Moreover, hedges are subject to
inherent risks, which we describe in The
Partnerships use of derivative financial instruments does
not eliminate its exposure to fluctuations in commodity prices
and interest rates and has in the past and could in the future
result in financial losses or reduced income. For a
discussion of our risk management activities, please read
Item 7A, Quantitative and Qualitative Disclosures
about Market Risk.
Due to
the Partnerships lack of asset diversification, adverse
developments in its gathering, transmission, treating,
processing and producer services businesses would materially
impact its financial condition.
The Partnership relies exclusively on the revenues generated
from its gathering, transmission, treating, processing and
producer services businesses, and as a result its financial
condition depends upon prices of, and continued demand for,
natural gas and NGLs. Due to the Partnerships lack of
asset diversification, an adverse development in one of these
businesses would have a significantly greater impact on its
financial condition and results of operations than if it
maintained more diverse assets.
Many
of the Partnerships customers drilling activity
levels and spending for transportation on its pipeline system or
gathering and processing at its facilities may be impacted by
the current deterioration in the credit markets.
Many of the Partnerships customers finance their drilling
activities through cash flow from operations, the incurrence of
debt or the issuance of equity. Recently, there has been a
significant decline in the credit markets and the availability
of credit. Additionally, many of its customers equity
values have substantially declined. Adverse price changes,
coupled with the overall downturn in the economy and the
constrained capital markets, put downward pressure on drilling
budgets for gas producers which could result in lower volumes
being transported on the Partnerships pipeline and
gathering systems and processing through its processing plants.
The Partnership has seen a decline in drilling activity by gas
producers in its areas of operation during the fourth quarter of
2008. In addition, industry drilling rig count surveys published
in early 2009 show substantial declines in rigs in operation as
compared to 2008. Several of its customers, including one of its
largest customers in the Barnett Shale, have recently announced
drilling plans for 2009 that are substantially below their
drilling levels during 2008. A significant reduction in drilling
activity could have a material adverse effect on the Partnership
operations.
The
Partnership is exposed to the credit risk of its customers and
counterparties, and a general increase in the nonpayment and
nonperformance by those customers could have an adverse effect
on financial condition and results of operations.
Risks of nonpayment and nonperformance by the Partnerships
customers are a major concern in its business. The Partnership
is subject to risks of loss resulting from nonpayment or
nonperformance by its customers and other counterparties, such
as lenders and hedging counterparties. Any increase in the
nonpayment and nonperformance by its customers could adversely
affect the results of operations and reduce the
Partnerships ability to make
27
distributions to its unitholders. Many of the Partnerships
customers finance their activities through cash flow from
operations, the incurrence of debt or the issuance of equity.
Recently, there has been a significant decline in the credit
markets and the availability of credit. Additionally, many of
the Partnerships customers equity values have
substantially declined. The combination of reduction of cash
flow resulting from declines in commodity prices, a reduction in
borrowing bases under reserve based credit facilities and the
lack of availability of debt or equity financing may result in a
significant reduction in customers liquidity and ability
to make payment or perform on their obligations to the
Partnership. Furthermore, some of the customers may be highly
leveraged and subject to their own operating and regulatory
risks, which increases the risk that they may default on their
obligations to the Partnership.
The
Partnerships use of derivative financial instruments does
not eliminate exposure to fluctuations in commodity prices and
interest rates and has in the past and could in the future
result in financial losses or reductions in
income.
The Partnerships operations expose it to fluctuations in
commodity prices, and its bank credit facility exposes the
Partnership to fluctuations in interest rates. The Partnership
uses over-the-counter price and basis swaps with other natural
gas merchants and financial institutions and interest rate swaps
with financial institutions. Use of these instruments is
intended to reduce its exposure to short-term volatility in
commodity prices and interest rates. The Partnership has hedged
only portions of its variable-rate debt and expected natural gas
supply, NGL production and natural gas requirements. It
continues to have direct interest rate and commodity price risk
with respect to the unhedged portions. In addition, to the
extent the Partnership hedges commodity price and interest rate
risks using swap instruments, it will forego the benefits of
favorable changes in commodity prices or interest rates.
Even though monitored by management, the Partnerships
hedging activities may fail to protect it and could reduce
earnings and cash flow. Its hedging activity may be ineffective
or adversely affect cash flow and earnings because, among other
factors:
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hedging can be expensive, particularly during periods of
volatile prices;
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the Partnerships counterparty in the hedging transaction
may default on its obligation to pay or otherwise fail to
perform; and
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available hedges may not correspond directly with the risks
against which the Partnership seeks protection. For example:
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the duration of a hedge may not match the duration of the risk
against which it seeks protection;
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variations in the index used to price a commodity hedge may not
adequately correlate with variations in the index used to sell
the physical commodity (known as basis risk); and
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the Partnership may not produce or process sufficient volumes to
cover swap arrangements entered into for a given period. If its
actual volumes are lower than the volumes it estimated when
entering into a swap for the period, the Partnership might be
forced to satisfy all or a portion of its derivative obligation
without the benefit of cash flow from its sale or purchase of
the underlying physical commodity, which could adversely affect
liquidity.
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The Partnerships financial statements may reflect gains or
losses arising from exposure to commodity prices or interest
rates for which it is unable to enter into fully economically
effective hedges. In addition, the standards for cash flow hedge
accounting are rigorous. Even when the Partnership engages in
hedging transactions that are effective economically, these
transactions may not be considered effective cash flow hedges
for accounting purposes. Partnership earnings could be subject
to increased volatility to the extent its derivatives do not
continue to qualify as cash flow hedges, and, if the Partnership
assumes derivatives as part of an acquisition, to the extent it
cannot obtain or choose not to seek cash flow hedge accounting
for the derivatives it assumes. Please read Item 7A,
Quantitative and Qualitative Disclosures about Market
Risk, for a summary of the Partnership hedging activities.
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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, The
Partnerships business and financial results could be
materially, adversely affected. In addition, its 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 its currently connected supplies.
In order to maintain or increase throughput levels in the
Partnerships natural gas gathering systems and asset
utilization rates at the Partnerships 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 its 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. For example, as
oil and natural gas prices have recently decreased, there has
been a corresponding decrease in drilling activity. Tax policy
changes could also 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 the Partnerships
principal geographic areas for a prolonged period, as a result
of depressed commodity prices or otherwise, likely would have a
material adverse effect on results of operations and financial
position.
The
Partnership is vulnerable to operational, regulatory and other
risks associated with its assets including, with respect to its
south Louisiana and the Gulf of Mexico assets, the effects of
adverse weather conditions such as hurricanes.
The Partnership operations and revenues will be significantly
impacted by conditions in south Louisiana and the Gulf of Mexico
because it has a significant portion of its assets located in
south Louisiana and the Gulf of Mexico. In the third and fourth
quarters of 2008, the Partnerships business was negatively
impacted by hurricanes Gustav and Ike, which came ashore in the
Gulf Coast in September. Although the majority of the
Partnerships assets in Texas and Louisiana sustained
minimal physical damage from these hurricanes and promptly
resumed operations, several offshore production platforms and
pipelines owned by third parties that transport gas production
to the Partnerships Pelican, Eunice, Sabine Pass and Blue
Water processing plants in south Louisiana were damaged by the
storms. Some of the repairs to these offshore facilities were
completed during the fourth quarter of 2008, but the Partnership
does not anticipate that gas production to its south Louisiana
plants will recover to pre-hurricane levels until mid-2009, when
all repairs are expected to be complete. Additionally, one of
the Partnerships south Louisiana processing plants, the
Sabine Pass processing plant, which is located on the shoreline
of the Louisiana Gulf Coast, sustained some physical damage. The
Sabine Pass processing plant was repaired during the fourth
quarter of 2008 and the plant was returned to service in early
January 2009. The Partnerships operations in north Texas
were also impacted by these hurricanes because operations at Mt.
Belvieu, Texas, a central distribution point for NGL sales where
several fractionators are located which fractionate NGLs from
the entire United States, were interrupted as a result of these
storms. These storms resulted in an adverse impact to the
Partnerships gross margin of approximately
$22.9 million in the last half of 2008.
The Partnerships concentration of activity in Louisiana
and the Gulf of Mexico makes us more vulnerable than many of its
competitors to the risks associated with these areas, 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 its
results of operations than they might have on other midstream
companies who have operations in more diversified geographic
areas.
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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.
A
substantial portion of the Partnerships assets is
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 its gathering systems and its treating plants, is
dedicated to certain natural gas reserves and wells for which
the production will naturally decline over time. Accordingly,
the Partnerships 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, the
Partnership cash flows may decline.
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 and complying with local ordinances.
One of the ways the Partnership intends to grow business is
through the construction of 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 and local permits and complying with city
ordinances, particularly as it expands operations into more
urban, populated areas such as the Barnett Shale.
Acquisitions
typically increase the Partnerships debt and subject it to
other substantial risks, which could adversely affect its
results of operations.
From time to time, the Partnership may evaluate and seek to
acquire assets or businesses that it believes complement
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 recently 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 our indebtedness; and
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potential environmental or regulatory liabilities and title
problems.
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The Partnerships 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
30
the economic, financial and other relevant information that it
will consider in determining the application of these funds and
other resources.
Additionally, the Partnerships ability to grow its asset
base in the near future through acquisitions will be limited due
to its lack of access to capital markets and due to restrictions
under its borrowing agreements.
The
Partnership expects to encounter significant competition in any
new geographic areas into which it seeks to expand and its
ability to enter such markets may be limited.
If 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
its results of operations could be adversely affected.
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 the
Partnerships customers at rates sufficient to maintain
current revenues and cash flows depends on a number of factors
beyond its 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, 2008, approximately 46.0%
of Partnership sales of gas which were transported using its
physical facilities were to industrial end-users and utilities.
As a consequence of the increase in 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 it often
competes in the end-user and utilities markets primarily on the
basis of price. The inability of management to renew or replace
current contracts as they expire and to respond appropriately to
changing market conditions could have a negative effect on
profitability.
The
Partnership depends on certain key customers, and the loss of
any of those key customers could adversely affect 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 were able to make comparably profitable
arrangements with other customers. Several of the
Partnerships customers, including one of its largest
customers in the Barnett Shale, have recently announced drilling
plans for 2009 that are substantially below their drilling
levels during 2008. 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:
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damage to pipelines, related equipment and surrounding
properties caused by hurricanes, floods, fires and other natural
disasters and acts of terrorism;
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inadvertent damage from construction and farm equipment;
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leaks of natural gas, NGLs and other hydrocarbons; and
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31
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 Partnership 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. The Partnerships business interruption
insurance covers only its 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 Partnership 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.
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. Its insurance policies
now generally exclude acts of terrorism. Such insurance is not
available at what management believes 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 the FERC generally does not regulate the
Partnerships operations, it influences certain aspects of
the Partnerships business and the market for its products.
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 regulation under the
Section 311 of the NGPA. Not only are the Partnerships
intrastate natural gas pipeline operations subject to limited
rate regulation by FERC, but they are also subject to regulation
by various agencies of the states in which they are located.
Should FERC or any of these state agencies determine that rates
for Section 311 transportation service or intrastate
transportation service should be lowered the Partnerships
business could be adversely affected.
The Partnerships natural gas gathering activities
generally are exempt from FERC regulation under the 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 its 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. The Partnership cannot
predict what effect, if any, such changes might have on its
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 some 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,
32
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 will contract 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 the Partnership 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 its 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
United States Department of Transportation in December of 2003
or those issued by the TRRC 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
at $3.2 million, $1.2 million, and $1.1 million
for the years ended December 31, 2008, 2007, and 2006,
respectively. The Partnership expects the costs for compliance
with TRRC and DOT regulations to be approximately
$3.6 million during 2009. If the Partnership pipelines fail
to meet the safety standards mandated by the TRRC or the DOT
regulations, then it may be required to repair or replace
sections of such pipelines, the cost of which cannot be
estimated at this time.
As the Partnerships operations continue to expand into and
around urban, or more populated areas, such as the Barnett
Shale, it may incur additional expenses to mitigate noise, odor
and light that may be emitted in our operations, and expenses
related to the appearance of its facilities. Municipal and other
local or state regulations are imposing various obligations,
including, among other things, regulating the location of the
Partnerships facilities, imposing limitations on the noise
levels of its facilities and requiring certain other
improvements that increase the cost of its facilities. The
Partnership is also subject to claims by neighboring landowners
for nuisance related to the construction and operation of its
facilities, which could subject it to damages for declines in
neighboring property values due to its construction and
operation of facilities.
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
south Louisiana processing assets, are subject to significant
federal, state and local environmental laws and regulations. The
obligations imposed by these laws and regulations include
obligations related to air emissions and discharge of pollutants
from 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 releases of contaminants 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 its operations,
33
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 compliance
costs and the cost of any remediation that may become necessary.
The Partnership may incur material environmental costs and
liabilities. Furthermore, its insurance may not provide
sufficient coverage in the event an environmental claim is made
against it.
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 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 profitability.
The
Partnerships success depends on key members of its
management, the loss or replacement of whom could disrupt
business operations.
The Partnership depends on the continued employment and
performance of the officers of the general partner of our
general partner and key operational personnel. The general
partner of our general partner has entered 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.
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Item 1B.
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Unresolved
Staff Comments
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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.
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Item 3.
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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. Additionally, as the Partnership continues
to expand operations into more urban, populated areas, such as
the Barnett Shale, it may see an increase in claims brought by
area landowners, such as nuisance claims and other claims based
on property rights. Except as otherwise set forth herein, 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
34
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.
On November 15, 2007, Crosstex CCNG Processing Ltd.
(Crosstex Processing), the Partnerships
wholly-owned subsidiary, received a demand letter from Denbury
Onshore, LLC (Denbury), asserting a claim for breach
of contract and seeking payment of approximately
$11.4 million in damages. The claim arises from a contract
under which Crosstex Processing processed natural gas owned or
controlled by Denbury in north Texas. Denbury contends that
Crosstex Processing breached the processing contract (the
Processing Contract) by failing to build a
processing plant of a certain size and design, resulting in
Crosstex Processings failure to properly process the gas
over a ten month period. Denbury also alleges that Crosstex
Processing failed to provide specific notices required under the
Processing Contract. On December 4, 2007 and again on
February 14, 2008, Denbury sent Crosstex CCNG letters
demanding that its claim be arbitrated pursuant to an
arbitration provision in the Processing Contract. Denbury
subsequently requested that the parties attempt to mediate the
matter before any arbitration proceeding is initiated. On
April 15, 2008, the parties mediated the matter
unsuccessfully. On December 4, 2008, Denbury initiated
formal arbitration proceedings in Dallas, Texas against Crosstex
Processing, Crosstex Energy Services, L.P., Crosstex North Texas
Gathering, L.P., and Crosstex Gulf Coast Marketing, Ltd.,
seeking $11.4 million and additional unspecified damages.
On December 23, 2008, Crosstex Processing filed an answer
denying Denburys allegations and a counterclaim seeking a
declaratory judgment that its processing plant is uneconomic
pursuant to the terms of the Processing Contract, allowing
cancellation of the contract. Crosstex Energy, Crosstex
Marketing, and Crosstex Gathering also filed an answer denying
Denburys allegations and asserting that they are improper
parties as Denburys claim is for breach of the Processing
Contract and none of these entities is a party to that
agreement. Crosstex Gathering also filed a counterclaim seeking
approximately $40.0 million in damages for the value of the
NGLs it is entitled to under its Gas Gathering Agreement with
Denbury. Once the three-person arbitration panel has been named
and cleared conflicts, the arbitration panel will hold a
preliminary conference with the parties to set a date for the
final hearing and other case deadlines and to establish
discovery limits. Although it is not possible to predict with
certainty the ultimate outcome of this matter, the Partnership
does not believe this will have a material adverse effect on its
consolidated results of operations or financial position.
During 2007 and 2008 eleven lawsuits were filed against the
Partnership and its subsidiaries by owners of property located
near processing facilities or compression facilities constructed
by it as part of its systems in north Texas. The actions are
pending in state court in Parker County and Denton County,
Texas. The suits generally allege that the facilities create a
private nuisance and have damaged the value of surrounding
property. Claims of this nature have arisen as a result of the
industrial development of natural gas gathering, processing and
treating facilities in urban and occupied rural areas. The
property owners are seeking compensatory and punitive damages,
attorneys fees, inverse condemnation and injunctive
relief. At this time, five cases are set for trial during 2009,
three of which have pending settlements, and one new case has
been filed in February 2009. The remaining cases have not yet
been set for trial. Discovery is underway. Although it is not
possible to predict the ultimate outcomes of these matters, the
Partnership does not believe that these claims will have a
material adverse impact on its consolidated results of
operations or financial condition.
On July 22, 2008, SemStream, L.P. and certain of its
subsidiaries filed voluntary petitions in the
U.S. Bankruptcy Court for the District of Delaware for
reorganization under Chapter 11 of the U.S. Bankruptcy
Code. As of July 22, 2008, SemStream, L.P. owed us
approximately $6.2 million, including approximately
$3.9 million for June 2008 sales and approximately
$2.2 million for July 2008 sales. The Partnership believes
the July sales of $2.2 million will receive
administrative claim status in the bankruptcy
proceeding. The debtors schedules acknowledge its
obligation to the Partnership for an administrative claim in the
amount of approximately $2.2 million but the allowance of
the administrative claim status is still subject to approval of
the bankruptcy court in accordance with the administrative claim
allowance procedures order in the case. The Partnership
evaluated these receivables for collectability and provided a
valuation allowance of $3.1 million during 2008.
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Item 4.
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Submission
of Matters to a Vote of Security Holders
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No matters were submitted to security holders during the fourth
quarter of the year ended December 31, 2008.
35
PART II
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Item 5.
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Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
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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 17, 2009, the
closing market price for our common stock was $3.00 per share
and there were approximately 18,500 record holders and
beneficial owners (held in street name) of the shares of our
common stock.
The following table shows the high and low closing sales prices
per share, as reported by the NASDAQ Global Select Market, for
the periods indicated:
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Common Stock
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Price Range
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Cash Dividends
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High
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Low
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Paid per Share
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2008:
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Quarter Ended December 31
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$
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20.93
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$
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2.19
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$
|
0.090
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Quarter Ended September 30
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34.13
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24.26
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0.320
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Quarter Ended June 30
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36.79
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33.54
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|
0.380
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Quarter Ended March 31
|
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37.37
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31.55
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0.360
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2007:
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Quarter Ended December 31
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$
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39.28
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$
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35.18
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$
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0.260
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Quarter Ended September 30
|
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|
38.03
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28.91
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0.240
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|
Quarter Ended June 30
|
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30.90
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|
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28.24
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|
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|
0.230
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|
Quarter Ended March 31
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33.54
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27.45
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0.220
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Historically, we have paid 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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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 ability to
make distributions is contractually restricted by the terms of
its credit facility. Its credit facility contains covenants
requiring it to maintain certain financial ratios. If its
leverage ratio, as defined in the credit facility, falls below a
certain level it will be prohibited from making distributions or
from making more than the minimum quarterly distributions. Based
on the Partnerships forecasted leverage ratios for 2009,
it does not anticipate making quarterly distributions during
2009 other than the distribution paid in February 2009 related
to fourth quarter 2008 operating results. See Item 1,
Business Amendments to Credit Documents.
Additionally, the Partnership is prohibited from making any
distributions to unitholders if the distribution would cause an
event of default, or an event of default existing, under its
credit facility. Please read Item 7,
Managements Discussion and Analysis of Financial
Condition and Results of Operations Description of
Indebtedness. We do not anticipate making any future
dividend payments after the dividend payment in February 2009
with respect to fourth quarter 2008 operating results until we
begin receiving distributions from the Partnership again.
36
Equity
Compensation Plan Information
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Number of Securities
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Remaining Available for
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Number of Securities to be
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Future Issuance Under
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Issued Upon Exercise of
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Weighted-Average Price of
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Equity Compensation Plans
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Outstanding Options,
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Outstanding Options,
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(Excluding Securities
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Plan Category
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Warrants and Rights
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Warrants and Rights
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Reflected in Column(a))
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(a)
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(b)
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(c)
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Equity Compensation Plans Approved By Security Holders(1)
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824,851
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(2)
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$
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9.54
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(3)
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626,453
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Equity Compensation Plans Not Approved By Security Holders
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N/A
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N/A
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N/A
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(1)
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|
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 (i) 538,731 restricted
shares that have been granted under our long-term incentive plan
that have not vested, and (ii) 218,620 performance shares
which could result in grants of restricted shares in the future.
|
|
(3)
|
|
The exercise prices for outstanding options under the plan as of
December 31, 2008 range from $6.50 to $13.33 per share.
|
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, 2008. The chart
assumes that $100 was invested on January 12, 2004, with
dividends reinvested. The peer group includes Atlas Pipeline
Holdings, L.P., Inergy Holdings, L.P., Enterprise GP Holdings,
L.P., Alliance Holdings GP, L.P. and Magellan Midstream
Holdings, L.P. (Inergy Holdings, L.P.s initial public
offering was in June 2005, Enterprise GP Holdings L.P.s
initial public offering was in August 2005, Atlas Pipeline
Holdings, L.P.s initial public offering was in July 2006,
Alliance Holdings GP, L.P.s initial public offering was in
May 2006, and Magellan Midstream Holdings, L.P.s initial
public offering was in February 2006, and it has been assumed
that these companies performed in accordance with the peer group
average prior to such dates).
37
|
|
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 data
include the results of operations of 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 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crosstex Energy, Inc.
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream
|
|
$
|
4,838,747
|
|
|
$
|
3,791,316
|
|
|
$
|
3,075,481
|
|
|
$
|
2,982,874
|
|
|
$
|
1,948,021
|
|
Treating
|
|
|
64,953
|
|
|
|
53,682
|
|
|
|
52,095
|
|
|
|
38,838
|
|
|
|
24,871
|
|
Profit on energy trading activities
|
|
|
3,349
|
|
|
|
4,090
|
|
|
|
2,510
|
|
|
|
1,568
|
|
|
|
2,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
4,907,049
|
|
|
|
3,849,088
|
|
|
|
3,130,086
|
|
|
|
3,023,280
|
|
|
|
1,975,120
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream purchased gas
|
|
|
4,471,308
|
|
|
|
3,468,924
|
|
|
|
2,859,815
|
|
|
|
2,860,823
|
|
|
|
1,861,204
|
|
Treating purchased gas
|
|
|
14,579
|
|
|
|
7,892
|
|
|
|
9,463
|
|
|
|
9,706
|
|
|
|
5,274
|
|
Operating expenses
|
|
|
169,056
|
|
|
|
125,184
|
|
|
|
98,839
|
|
|
|
54,689
|
|
|
|
38,396
|
|
General and administrative
|
|
|
74,518
|
|
|
|
64,304
|
|
|
|
47,707
|
|
|
|
34,145
|
|
|
|
22,005
|
|
(Gain) loss on derivatives
|
|
|
(12,203
|
)
|
|
|
(6,628
|
)
|
|
|
(1,591
|
)
|
|
|
9,966
|
|
|
|
(414
|
)
|
Gain on sale of property
|
|
|
(1,519
|
)
|
|
|
(1,667
|
)
|
|
|
(2,108
|
)
|
|
|
(8,138
|
)
|
|
|
(12
|
)
|
Impairments
|
|
|
31,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
981
|
|
Depreciation and amortization
|
|
|
131,318
|
|
|
|
106,685
|
|
|
|
80,579
|
|
|
|
33,887
|
|
|
|
20,855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,878,297
|
|
|
|
3,764,694
|
|
|
|
3,092,704
|
|
|
|
2,995,078
|
|
|
|
1,948,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
28,752
|
|
|
|
84,394
|
|
|
|
37,382
|
|
|
|
28,202
|
|
|
|
26,831
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(102,565
|
)
|
|
|
(78,993
|
)
|
|
|
(51,051
|
)
|
|
|
(15,332
|
)
|
|
|
(9,115
|
)
|
Other income (expense)
|
|
|
27,885
|
|
|
|
683
|
|
|
|
1,774
|
|
|
|
391
|
|
|
|
802
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(74,680
|
)
|
|
|
(78,310
|
)
|
|
|
(49,277
|
)
|
|
|
(14,941
|
)
|
|
|
(8,313
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes,
gain on issuance of Partnership units and interest of
non-controlling partners in the Partnerships net income
(loss)
|
|
|
(45,928
|
)
|
|
|
6,084
|
|
|
|
(11,895
|
)
|
|
|
13,261
|
|
|
|
18,518
|
|
Income tax provision
|
|
|
(2,410
|
)
|
|
|
(10,147
|
)
|
|
|
(9,958
|
)
|
|
|
(29,261
|
)
|
|
|
(4,447
|
)
|
Gain on issuance of Partnership units(1)
|
|
|
14,748
|
|
|
|
7,461
|
|
|
|
18,955
|
|
|
|
65,070
|
|
|
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crosstex Energy, Inc.
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Interest of non-controlling partners in the Partnerships
net income (loss) from continuing operations
|
|
|
45,593
|
|
|
|
7,246
|
|
|
|
17,213
|
|
|
|
(1,309
|
)
|
|
|
(6,675
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before discontinued
operations and cumulative effect of change in accounting
principle
|
|
|
12,003
|
|
|
|
10,644
|
|
|
|
14,315
|
|
|
|
47,761
|
|
|
|
7,396
|
|
Discontinued Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued
operations-net
of tax and net of minority interest
|
|
|
1,266
|
|
|
|
1,532
|
|
|
|
1,970
|
|
|
|
1,375
|
|
|
|
1,304
|
|
Gain on sale of discontinued
operations-net
of tax and net of minority interest
|
|
|
10,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations-net
of tax and net of minority interest
|
|
|
12,230
|
|
|
|
1,532
|
|
|
|
1,970
|
|
|
|
1,375
|
|
|
|
1,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect of change in accounting
principle
|
|
|
24,233
|
|
|
|
12,176
|
|
|
|
16,285
|
|
|
|
49,136
|
|
|
|
8,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
170
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
24,233
|
|
|
$
|
12,176
|
|
|
$
|
16,455
|
|
|
$
|
49,136
|
|
|
$
|
8,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share-basic(2)
|
|
$
|
0.52
|
|
|
$
|
0.26
|
|
|
$
|
0.39
|
|
|
$
|
1.29
|
|
|
$
|
0.24
|
|
Net income per common share-diluted(2)
|
|
$
|
0.52
|
|
|
$
|
0.26
|
|
|
$
|
0.39
|
|
|
$
|
1.26
|
|
|
$
|
0.22
|
|
Dividends per share(2)(3):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
$
|
1.32
|
|
|
$
|
0.91
|
|
|
$
|
0.807
|
|
|
$
|
0.563
|
|
|
$
|
0.327
|
|
Preferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.327
|
|
Balance Sheet Data (end of period):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital surplus (deficit)
|
|
$
|
(20,431
|
)
|
|
$
|
(39,330
|
)
|
|
$
|
(70,091
|
)
|
|
$
|
4,872
|
|
|
$
|
(18,265
|
)
|
Property and equipment, net
|
|
|
1,528,490
|
|
|
|
1,426,546
|
|
|
|
1,107,242
|
|
|
|
668,632
|
|
|
|
325,653
|
|
Total assets
|
|
|
2,546,743
|
|
|
|
2,602,829
|
|
|
|
2,206,698
|
|
|
|
1,445,325
|
|
|
|
606,768
|
|
Long-term debt
|
|
|
1,263,706
|
|
|
|
1,223,118
|
|
|
|
987,130
|
|
|
|
522,650
|
|
|
|
148,700
|
|
Interest of non-controlling partners in the partnership
|
|
|
522,961
|
|
|
|
489,034
|
|
|
|
391,103
|
|
|
|
264,726
|
|
|
|
65,399
|
|
Stockholders equity
|
|
|
215,429
|
|
|
|
246,366
|
|
|
|
279,413
|
|
|
|
111,247
|
|
|
|
76,933
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
170,154
|
|
|
$
|
112,578
|
|
|
$
|
113,839
|
|
|
$
|
12,842
|
|
|
$
|
46,339
|
|
Investing activities
|
|
|
(186,768
|
)
|
|
|
(411,382
|
)
|
|
|
(885,825
|
)
|
|
|
(614,822
|
)
|
|
|
(124,371
|
)
|
Financing activities
|
|
|
22,720
|
|
|
|
296,022
|
|
|
|
769,717
|
|
|
|
592,365
|
|
|
|
99,072
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crosstex Energy, Inc.
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream gross margin
|
|
$
|
370,778
|
|
|
$
|
326,482
|
|
|
$
|
218,176
|
|
|
$
|
123,619
|
|
|
$
|
89,045
|
|
Treating gross margin
|
|
|
50,374
|
|
|
|
45,790
|
|
|
|
42,632
|
|
|
|
29,132
|
|
|
|
19,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross margin(4)
|
|
$
|
421,162
|
|
|
$
|
372,272
|
|
|
$
|
260,808
|
|
|
$
|
152,751
|
|
|
$
|
108,642
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline throughput (MMBtu/d)
|
|
|
2,608,000
|
|
|
|
2,114,000
|
|
|
|
1,356,000
|
|
|
|
1,126,000
|
|
|
|
1,289,000
|
|
Natural gas processed (MMBtu/d)(5)
|
|
|
1,812,000
|
|
|
|
2,057,000
|
|
|
|
2,032,000
|
|
|
|
1,921,000
|
|
|
|
425,000
|
|
Producer services (MMBtu/d)
|
|
|
85,000
|
|
|
|
94,000
|
|
|
|
138,000
|
|
|
|
175,000
|
|
|
|
210,000
|
|
|
|
|
(1)
|
|
We recognized gains of $14.7 million in 2008,
$7.5 million in 2007, $19.0 million in 2006 and
$65.1 million in 2005 as a result of the Partnership
issuing additional units 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)
|
|
Dividends paid.
|
|
(4)
|
|
Gross margin is defined as revenue, including treating fee
revenues and profit on energy trading activities, less related
cost of purchased gas.
|
|
(5)
|
|
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) 16,414,830 common
units, representing approximately 34.0% 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.
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.
40
Quarterly distributions by the Partnership had steadily
increased from the first distribution of $0.25 per unit for the
quarter ended March 31, 2003 to $0.63 per unit for the
quarter ended June 30, 2008. The distribution for third
quarter of 2008 operating results was reduced to $0.50 per unit
followed by a further reduction to $0.25 per unit for the fourth
quarter of 2008 (paid in February 2009). The Partnerships
distributions were reduced during the last half of 2008 as a
result of a decline in its cash flows from operations due to
declines in natural gas and NGL prices during the last half of
2008, gross margin losses due to hurricanes Ike and Gustav and
the declines in the global financial markets and economic
conditions as discussed under Item 1.
Business Crosstex Energy, L.P. Recent
Developments and Business
Strategy. Our distributions from the Partnership pursuant
to our ownership of common units and 2.0% general partner
interest, including our incentive distribution rights (IDRs),
during 2008 were as follows:
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quarter ended March 31, 2008 (paid in May 2008)
$20.8 million (including $11.8 million with respect to
our IDRs)
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quarter ended June 30, 2008 (paid in August
2008) $23.4 million (including
$12.3 million with respect to our IDRs)
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quarter ended September 30, 2008 (paid in November
2008) $15.5 million (including
$6.7 million with respect to our IDRs), and
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quarter ended December 31, 2008 (paid in February
2009) $4.3 million (no IDR distributions).
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In response to the recent developments, the Partnership has
adjusted its business strategy for 2009 to focus on maximizing
liquidity, maintaining a stable asset base, improving the
profitability of its assets by increasing their utilization
while controlling costs and reducing capital expenditures as
discussed under Crosstex Energy, L.P. Business
Strategies. One of the strategies included amending the
Partnerships bank credit facility and its senior note
agreement to negotiate terms with its creditors that will allow
continued operation of its assets during the current difficult
economic conditions. The amended terms of the credit facility
and senior secured note agreement prohibit the Partnership from
making distributions unless its leverage ratio is below certain
levels and the PIK notes have been repaid. The Partnership does
not expect that it will meet these conditions in 2009. Since our
cash flows consist almost exclusively of distributions from the
Partnership on the partnership interests we own, we do not
expect to receive any significant cash flows until the
Partnership is able to improve its leverage ratio and begin
making distributions again. As of December 31, 2008, we
have $14.0 million of cash which we expect to be sufficient
to pay our expenses and federal income taxes over the next
several years based on our forecasted cash flows. We do not
anticipate making any future dividend payments after the
dividend payment in February 2009 with respect to fourth quarter
2008 operating results until we begin receiving distributions
from the Partnership again.
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 Louisiana and
Mississippi. 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, 2008,
approximately 88.0% 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 operations because its business is generally to
41
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 on gas
sales. In addition, the Partnership receives certain fees for
processing based on a percentage of the liquids produced and
enters into hedge contracts for its expected share of the
liquids produced to protect margins from changes in liquids
prices.
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, 2004 through December 31,
2008, it has invested over $2.3 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 NGLs handled at its
fractionation facilities. Treating segment margins are largely a
function of the number and size of treating plants in operation.
The Partnership generates Midstream revenues from six primary
sources:
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purchasing and reselling or transporting natural gas on the
pipeline systems it owns;
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processing natural gas at its processing plants and
fractionating and marketing the recovered NGLs;
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treating natural gas at its treating plants;
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providing compression services; and
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providing off-system marketing services for producers.
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With respect to the Partnerships Midstream services, it
generally gathers or transports gas owned by others through its
facilities for a fee, or it buys natural gas from a producer,
plant or shipper at either a fixed discount to a market index or
a percentage of the market index, then transport and resell the
natural gas. In the Partnerships purchase/sale
transactions, 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 it 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.
The Partnership also realizes margins in its Midstream segment
from processing services primarily through three different
contract arrangements: processing margins (margin), percentage
of liquids (POL) or fee based. Under the margin and POL contract
arrangements the Partnerships margins are higher during periods
of high liquid prices relative to natural gas prices. Under fee
based contracts its margins are driven by throughput volume. See
Commodity Price Risk.
The Partnership generates Treating revenues under three types of
arrangements:
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a volumetric fee based on the amount of gas treated, which
accounted for approximately 11.0% of operating income in the
Treating division for the years ended December 31, 2008 and
2007;
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a fixed fee for operating a plant for a certain period, which
accounted for approximately 62.0% and 59.0% of operating income
in the Treating division for the years ended December 31,
2008 and 2007, respectively; and
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a fee arrangement in which the producer operates the plant,
which accounted for approximately 27.0% and 30.0% of operating
income in the Treating division for the years ended
December 31, 2008 and 2007, respectively.
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42
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.
Recent
Developments
Global financial markets and economic conditions have been, and
continue to be, disrupted and volatile. Numerous events during
2008 have severely restricted current liquidity in the capital
markets throughout the United States and around the world. The
ability to raise money in the debt and equity markets has
diminished significantly and, if available, the cost of funds
has increased substantially. One of the features driving
investments in MLPs, such as our investment in CELP, over the
past few years has been the distribution growth offered by MLPs
due to liquidity in the financial markets for capital
investments to grow distributable cash flow through development
projects and acquisitions. Future growth opportunities have been
and are expected to continue to be constrained by the lack of
liquidity in the financial markets.
In addition, the Partnerships business has been
significantly impacted by the substantial decline in crude oil
prices during the last half of 2008 from a high of approximately
$145 per Bbl in July 2008 to a low of approximately $34 per Bbl
in December 2008 (based on NYMEX futures daily close prices for
the prompt month), a 76.7% decline, and the related 78.2%
decline in NGL prices from a high of $2.19 per gallon in July
2008 to a low of $0.48 in December 2008 (based on the OPIS Mt.
Belvieu daily average spot liquids prices). Crude oil prices
reflected on NYMEX during January and February 2009 have
fluctuated, to a lesser extent, between $49 per Bbl and $35 per
Bbl while the OPIS Mt. Belvieu NGL prices have improved slightly
ranging from $0.81 per gallon and $0.62 per gallon. The declines
in NGL prices have negatively impacted the Partnerships
gross margin for the fourth quarter of 2008 and could continue
to negatively impact our gross margin (revenue less cost of gas
purchases) in 2009. A significant percentage of inlet gas at its
processing plants is settled under percent of liquids (POL)
agreements or fractionation margin (margin) contracts. Over the
past two years the inlet processing volumes associated with POL
and margin contracts were approximately 70%, on a combined
basis, of the total volume of gas processed. The POL fees are
denominated in the form of a share of the liquids extracted.
Therefore, fee revenue under a POL agreement is directly
impacted by NGL prices and the decline of these prices in 2008
contributed to a significant decline in gross margin from
processing. Under the POL settlement terms, the Partnership is
not responsible for the fuel or shrink associated with
processing. Under margin contracts the Partnership realizes a
gross margin from processing based upon the difference in the
value of NGLs extracted from the gas less the value of the
product in its gaseous state and the cost of fuel to extract.
This is often referred to as the fractionation
spread. During the last half of 2008 the fractionation
spread narrowed significantly as the value of NGLs decreased
more than the value of the gas and fuel associated with the
processed gas. Thus the gross margin realized under these margin
contracts was also negatively impacted due to the commodity
price environment. If the current weakness in the economy
continues for a prolonged period, it would likely further reduce
demand for gas and for NGL products, such as ethane, a primary
feedstock for the petrochemical and manufacturing industries,
and result in continued lower natural gas and NGL prices.
Although the Partnership has seen some improvement in NGL prices
and the fractionation spread in the early months of 2009 over
the levels experienced in December 2008, the Partnership
believes that its processing margins in 2009 will be
substantially lower than the processing margins realized in 2008
based on current market indicators. For the year ended
December 31, 2008, approximately 38.7% of the
Partnerships gross margin was attributable to gas
processing as compared to 46.1% of its gross margin for the year
ended December 31, 2007. See Item 7A,
Quantitative and Qualitative Disclosures about Market
Risk-Commodity Price Risk for a description of the
contractual processing arrangements used by the Partnership.
Natural gas prices have declined by approximately 61.0%, from a
high of $13.58 per MMBtu in July 2008 to a low of $5.29 per
MMBtu in December 2008 (based on the NYMEX futures daily close
prices for the prompt month). Natural gas prices have declined
even further during January and February 2009 with prices
ranging from $6.07 in early January to $4.01 in mid-February.
Many of the Partnerships customers finance their drilling
activity with cash flow from operations, which have been
negatively impacted by the declines in natural gas and crude oil
prices, or through the incurrence of debt or issuance of equity,
which markets have been adversely impacted by global
43
financial market conditions. The Partnership believes that the
adverse price changes coupled with the overall downturn in the
economy and the constrained capital markets will put downward
pressure on drilling budgets for gas producers which could
result in lower volumes being transported on its pipeline and
gathering systems and processing through its processing plants.
The Partnership has seen a decline in drilling activity by gas
producers in its areas of operation during the fourth quarter of
2008. In addition, industry drilling rig count surveys published
in early 2009 show substantial declines in rigs in operation as
compared to 2008. Several of the Partnerships customers,
including one of its largest customers in the Barnett Shale,
have recently announced drilling plans for 2009 that are
substantially below their drilling levels during 2008.
The Partnerships business was also negatively impacted by
hurricanes Gustav and Ike, which came ashore in the Gulf Coast
in September 2008. Although the majority of its assets in Texas
and Louisiana sustained minimal physical damage from these
hurricanes and promptly resumed operations, several offshore
production platforms and pipelines that transport gas production
to its Pelican, Eunice, Sabine Pass and Blue Water processing
plants in south Louisiana were damaged by the storms. Some of
the repairs to these offshore facilities were completed during
the fourth quarter of 2008 but the Partnership does not
anticipate that gas production to its south Louisiana plants
will recover to pre-hurricane levels until mid-2009, when all
repairs are expected to be complete. Additionally, one of the
Partnerships south Louisiana processing plants, the Sabine
Pass processing plant, which is located on the shoreline of the
Louisiana Gulf Coast, sustained some physical damage. The Sabine
Pass processing plant was repaired during the fourth quarter of
2008 and the plant was returned to service in early January
2009. Operations in north Texas were also impacted by these
hurricanes because operations at Mt. Belvieu, Texas a central
distribution point for NGL sales, where several fractionators
are located which fractionate NGLs from the entire United States
were interrupted as a result of these storms. These storms
resulted in an adverse impact to the Partnerships gross
margin of approximately $22.9 million.
Two of the Partnerships facilities, one in south Louisiana
and one in north Texas, were also partially damaged by fires
during 2008. Although substantially all of the property repairs
were covered by insurance, the Sabine Pass processing plant in
south Louisiana was out of service for approximately one month.
The loss of operating income due to the fire at the Godley
compressor station in north Texas was minimal because the
Partnership was successful in rerouting the gas to our other
facilities in the area until the damaged compressor was
replaced. The estimated loss in gross margin as a result of
these fires is $0.9 million.
Acquisitions
and Expansion
The Partnership has grown significantly through asset purchases
and construction and expansion projects in recent years. This
growth creates many of the major differences when comparing
operating results from one period to another. The most
significant asset purchases since January 2006 were the
acquisition of midstream assets from Chief in June 2006, the
Hanover Compression Company treating assets in February 2006 and
the amine-treating business of Cardinal Gas Solutions L.P. in
October 2006. In addition, internal expansion projects in north
Texas and Louisiana have contributed to the increase in the
Partnerships business during 2006, 2007 and 2008.
On June 29, 2006, the Partnership expanded its operations
in the north Texas area through the acquisition of the natural
gas gathering pipeline systems and related facilities of Chief
in the Barnett Shale for $475.3 million. The acquired
systems included gathering pipeline, a
125 MMcf/d
carbon dioxide treating plant and compression facilities with
26,000 horsepower. At the closing of that acquisition,
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, the
Partnership began expanding its north Texas pipeline gathering
system. The continued expansion of the north Texas gathering
systems to handle the growing production in the Barnett Shale
was one of the Partnerships core areas for internal growth
during 2006, 2007 and 2008 and will continue to be a core area
during 2009. Since the date of the acquisition through
December 31, 2008, the Partnership has connected 444 new
wells to its gathering system and significantly increased the
dedicated acreage owned by other producers. The
Partnerships processing capacity in the Barnett Shale is
280 MMcf/d
including the Silver Creek plant, which is a
200 MMcf/d
cryogenic processing plant, the Azle plant, which is a
50 MMcf/d
cryogenic processing plant, and the Goforth plant, which is a
30 MMcf/d
processing plant. In 2007 and 2008, the Partnership constructed
a
29-mile
expansion in north Johnson County to its north Texas gathering
systems. The first phase of the expansion
44
commenced operation in September 2007. The last two phases of
the expansion commenced operation in May and July of 2008. The
total gathering capacity of this
29-mile
expansion is currently
235 MMcf/d
and is expected to be increased to approximately
400 MMcf/d
in April 2009 by the addition of compression. The Partnership
has also installed two 40 gallon per minute and one 100 gallon
per minute amine treating plants to provide carbon dioxide
removal capability. As of December 2008, the capacity of the
north Texas gathering system was approximately
1,100 MMcf/d
and total throughput on the north Texas gathering systems,
including the north Johnson County expansion, had increased from
approximately 115,000 MMBtu/d at the time of the Chief
acquisition to approximately 796,000 MMBtu/d.
In April 2008, the Partnership commenced construction of an
$80.0 million natural gas processing facility called Bear
Creek in Hood County near its existing North Texas Assets. The
new plant will have a gas processing capacity of
200 MMcf/d.
Due to the recent decline in commodity prices and the
corresponding decline in drilling activity, the Partnership does
not anticipate that the additional processing capacity provided
by the Bear Creek plant will be needed until late 2010 or in
2011. Therefore, it has decided to put this construction project
on hold until the demand for this processing capacity returns,
at which time it will seek to obtain financing for the project.
As of December 31, 2008, the Partnership has spent
approximately $20.2 million on this project for the
construction of a portion of the plant that will be utilized
when the plant is completed in the future.
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 L.P. for
$6.3 million. The acquisition added 10 dew point control
plants and 50% of seven amine-treating plants to our plant
portfolio. On March 28, 2007, it acquired the remaining 50%
interest in the amine-treating plants for approximately
$1.5 million.
The Partnerships NTP, which commenced service in April
2006, consists of a
133-mile
pipeline and associated gathering lines from an area near
Fort Worth, Texas to a point near Paris, Texas. The initial
capacity of the NTP was approximately
250 MMcf/d.
In 2007, the Partnership expanded the capacity on the NTP to a
total of approximately
375 MMcf/d.
The NTP connects production from the Barnett Shale to markets in
north Texas and to markets accessed by NGPL, Kinder Morgan, HPL,
Atmos and other markets. As of December 2008, the total
throughput on the NTP was approximately 300,000 MMBtu/d.
The NTP also will interconnect with a new interstate gas
pipeline under construction by Boardwalk Pipeline Partners, L.P.
known as the Gulf Crossing Pipeline which is expected to be in
service in March 2009. The Gulf Crossing Pipeline is expected to
provide the Partnerships customers access to premium
mid-west and east coast markets.
In April 2007, the Partnership completed construction and
commenced operations on its north Louisiana expansion, which is
an extension of the LIG system designed to increase take-away
pipeline capacity to the producers developing natural gas in the
fields south of Shreveport, Louisiana. The north Louisiana
expansion consists of approximately 63 miles of 24
mainline with 9 miles of 16 gathering lateral
pipeline and 10,000 horsepower of new compression referred to as
the Red River lateral. The Red River lateral bisects the
developing Haynesville Shale gas play in north Louisiana. The
Red River lateral was operating at near capacity during 2008 so
the Partnership added
35 MMcf/d
of capacity by adding compression during the third quarter of
2008 bringing the total capacity of the Red River lateral to
approximately
275 MMcf/d.
As of December 31, 2008, the Red River lateral was flowing
at approximately 225,000 MMBtu/d. Interconnects on the
north Louisiana expansion include connections with the
interstate pipelines of ANR Pipeline, Columbia Gulf
Transmission, Texas Gas Transmission and Trunkline Gas.
Other
Assets
We owned two inactive gas plants in addition to our limited and
general partner interests in the Partnership. These two gas
plants are the Jonesville processing plant and the Clarkson
plant. During 2008 these two plants were transferred to the
Partnership at net book value for a cash price of
$0.4 million which represented the fair value of the plants.
45
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
taxable 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. Taxable
income allocated to us by the Partnership will increase over the
years as the results of operation increase and as the ratio of
income to distributions increases for all of the unitholders.
As of December 31, 2008 we have a net operating loss carry
forward of $108.6 million for federal income taxes and
state loss carry forwards of $46.4 million. We believe it
is more likely than not that our future results of operations
will generate sufficient taxable income to utilize these net
operating loss carry forwards before they expire. Once these net
operating loss carry forwards are fully utilized, we will have
to pay tax on our federal taxable income at a maximum rate of
35.0% under current law.
Our use of this net operating loss carry forward will be limited
if there is a greater than 50.0% change in our stock ownership
over a three year period.
Commodity
Price Risk
The Partnerships business is subject to significant risks
due to fluctuations in commodity prices. Its exposure to these
risks is primarily in the gas processing component of its
business. A large percentage of the processing fees are realized
under POL contracts that are directly impacted by the market
price of NGLs. It also realizes processing gross margins under
margin contracts. These settlements are impacted by the
relationship between NGL prices and the underlying natural gas
prices, which is also referred to as the fractionation spread.
A significant volume of inlet gas at the Partnerships
south Louisiana and north Texas processing plants is settled
under POL agreements. The POL fees are denominated in the form
of a share of the liquids extracted and the Partnership is not
responsible for the fuel or shrink associated with processing.
Therefore, fee revenue under a POL agreement is directly
impacted by NGL prices, and the decline of these prices in 2008
contributed to a significant decline in gross margin from
processing. The Partnership has a number of fractionation margin
contracts on its Plaquemine and Gibson processing plants that
expose it to the fractionation spread. Under these margin
contracts its gross margin is based upon the difference in the
value of NGLs extracted from the gas less the value of the
product in its gaseous state and the cost of fuel to extract
during processing. During the last half of 2008 the
fractionation spread narrowed significantly as the value of NGLs
decreased more than the value of the gas and fuel associated
with the processed gas. Thus the gross margin realized under
these margin contracts was negatively impacted due to the
commodity price environment. The significant decline in crude
oil prices and a related decline in NGL prices during the last
half of 2008 had a significant negative impact on the
Partnerships margins, and may negatively impact its gross
margin further if such declines continue.
The Partnership is also subject to price risk to a lesser extent
for fluctuations in natural gas prices with respect to a portion
of its gathering and transportation services. Approximately 4.0%
of the natural gas it 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, resale margins are
higher during periods of high natural gas prices and lower
during periods of lower natural gas prices.
See Item 7A Quantitative and Qualitative Disclosures
about Market Risk Commodity Price Risk for
additional information on Commodity Price Risk.
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.
46
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Years Ended December 31,
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2008
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2007
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2006
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(dollars in millions)
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Midstream revenues
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$
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4,838.7
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$
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3,791.3
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$
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3,075.5
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Midstream purchased gas
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(4,471.3
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)
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(3,468.9
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)
|
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|
(2,859.8
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)
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Profits on energy trading activities
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|
|
3.4
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|
|
|
4.1
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2.5
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|
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|
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|
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Midstream gross margin
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370.8
|
|
|
|
326.5
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218.2
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Treating revenues
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65.0
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|
|
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53.7
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52.1
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Treating purchased gas
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(14.6
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)
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(7.9
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)
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(9.5
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)
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Treating gross margin
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50.4
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|
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45.8
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42.6
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|
|
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Total gross margin
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$
|
421.2
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|
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$
|
372.3
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|
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$
|
260.8
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream Volumes (MMBtu/d):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation
|
|
|
2,608,000
|
|
|
|
2,114,000
|
|
|
|
1,356,000
|
|
Processing
|
|
|
1,812,000
|
|
|
|
2,057,000
|
|
|
|
2,032,000
|
|
Producer services
|
|
|
85,000
|
|
|
|
94,000
|
|
|
|
138,000
|
|
Treating Plants in Operation at Year End
|
|
|
200
|
|
|
|
190
|
|
|
|
190
|
|
Year
Ended December 31, 2008 Compared to Year Ended
December 31, 2007
Gross Margin and Profit on Energy Trading
Activities.
Midstream gross margin was
$370.8 million for the year ended December 31, 2008
compared to $326.5 million for the year ended
December 31, 2007, an increase of $44.3 million, or
13.6%. The increase was primarily due to system expansion
projects and increased throughput on our gathering and
transmission systems. These increases were partially offset by
margin decreases in the processing business due to a less
favorable NGL market and operating downtime resulting from the
impact of hurricanes in the last half of the year. Profit on
energy trading activities decreased for the comparative periods
by approximately $0.7 million.
System expansion in the north Texas region and increased
throughput on the NTP contributed $58.9 million of gross
margin growth for the year ended December 31, 2008 over the
same period in 2007. The Partnerships gathering systems in
the region and NTP accounted for $41.3 million and
$9.1 million of this increase, respectively. The
Partnerships processing facilities in the region
contributed an additional $8.5 million of gross margin
increase. System expansion and volume increases on the LIG
system contributed margin growth of $8.2 million during the
year ended December 31, 2008 over the same period in 2007.
Processing plants in Louisiana experienced a margin decline of
$20.2 million for the comparative twelve-month period in
2008 due to a less favorable NGL processing environment in the
last half of the year and business interruptions resulting from
the impact of hurricanes along the Gulf Coast. These unfavorable
processing conditions also contributed to margin declines in
south Texas on the Vanderbilt system and Gregory Processing
facility of $2.9 million and $1.8 million,
respectively. A throughput decline on the Gregory Gathering
system resulted in a gross margin decrease of $1.6 million.
These declines were partially offset by a gross margin increase
on the CCNG system of $1.9 million due to an increase in
throughput. The Mississippi system had a margin increase of
$1.2 million due to increased throughput, and an expansion
of the east Texas system contributed to a margin increase of
$0.9 million for the comparable periods.
The Partnerships processing and gathering systems were
negatively impacted by events beyond our control during the
third quarter that had a significant effect on gross margin
results for the year ended December 31, 2008. Hurricanes
Gustav and Ike came ashore along the Gulf coast in September
2008. The Partnership estimates that these storms resulted in
approximately $22.9 million gross margin decrease for the
year. The lost margin was primarily experienced at gas
processing facilities along the Gulf coast. However, processing
facilities further inland in Louisiana and north Texas were
indirectly impacted due to disruption in the NGL markets. In
addition, approximately $0.9 million in gross margin was
lost at the Sabine Pass plant in August 2008 due to downtime
from fire damage. The fire occurred during an attempt to bring
the plant back on line following tropical storm Edouard.
47
Treating gross margin was $50.4 million for the year ended
December 31, 2008 compared to $45.8 million for the
year ended December 31, 2007, an increase of
$4.6 million, or 10.0%. The Partnership had approximately
200 and 190 treating plants, dew point control plants, and
related equipment in service at December 31, 2008 and 2007,
respectively. Gross margin growth for the period of
$3.2 million is attributable primarily to the increase in
the number of plants and an increase in throughput on the volume
based plants. Field services provided to producers also
contributed gross margin growth of $1.4 million for the
comparable periods.
Operating Expenses.
Operating expenses were
$169.1 million for the year ended December 31, 2008
compared to $125.2 million for the year ended
December 31, 2007, an increase of $43.9 million, or
35.0%. The increase is primarily attributable to the following
factors:
|
|
|
|
|
$35.8 million increase in Midstream operating expenses
resulting primarily from growth and expansion in the NTP, NTG,
north Louisiana and east Texas areas. Contractor services and
labor costs increased $14.1 million, chemicals and
materials increased $7.8 million, equipment rental
increased $7.4 million and ad valorem taxes increased
$2.4 million;
|
|
|
|
$7.3 million increase in Treating operating expenses,
including $2.6 million for materials and supplies,
contractor services costs of $2.8 million to support
maintenance projects, labor costs of $1.4 million as a
result of market adjustments for field service employees and
additional headcount and auto-related expenses of
$0.5 million; and
|
|
|
|
$0.7 million increase in technical services operating
expense.
|
General and Administrative Expenses.
General
and administrative expenses were $74.5 million for the year
ended December 31, 2008 compared to $64.3 million for
the year ended December 31, 2007, an increase of
$10.2 million, or 15.9%. The increase is primarily
attributable to the following factors:
|
|
|
|
|
$5.5 million increase in rental expense resulting primarily
from additional office rent and including $3.4 million
related to lease termination fees for the cancelled relocation
of our corporate headquarters;
|
|
|
|
$3.1 million increase in bad debt expense due to the
SemStream, L.P. bankruptcy;
|
|
|
|
$2.5 million increase in other expenses, including
professional fees and services and labor and benefit
expenses; and
|
|
|
|
$0.9 million decrease in stock-based compensation expense
resulting primarily from the reduction of estimated
performance-based restricted units and restricted shares.
|
Gain/Loss on Derivatives.
We had a gain on
derivatives of $12.2 million for the year ended
December 31, 2008 compared to a gain of $6.6 million
for the year ended December 31, 2007. The derivative
transaction types contributing to the net gain are as follows
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
Total
|
|
|
Realized
|
|
|
Total
|
|
|
Realized
|
|
|
(Gain)/Loss on Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps
|
|
$
|
(7.2
|
)
|
|
$
|
(7.3
|
)
|
|
$
|
(8.1
|
)
|
|
$
|
(7.0
|
)
|
Processing margin hedges
|
|
|
(3.6
|
)
|
|
|
(3.6
|
)
|
|
|
1.3
|
|
|
|
1.3
|
|
Storage
|
|
|
(0.7
|
)
|
|
|
(0.1
|
)
|
|
|
(0.5
|
)
|
|
|
(1.6
|
)
|
Third-party on-system swaps
|
|
|
(0.6
|
)
|
|
|
(0.8
|
)
|
|
|
(0.2
|
)
|
|
|
(0.6
|
)
|
Puts
|
|
|
|
|
|
|
|
|
|
|
0.8
|
|
|
|
|
|
Other
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(12.2
|
)
|
|
$
|
(11.8
|
)
|
|
$
|
(6.6
|
)
|
|
$
|
(7.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain/Loss on Sale of Property.
Assets sold
during the year ended December 31, 2008 generated a net
gain of $1.5 million as compared to a gain of
$1.7 million during the year ended December 31, 2007.
The 2008 gain was
48
primarily generated from the disposition of various small
Treating and Midstream assets. The 2007 gain was primarily
generated from the disposition of unused catalyst material and
the disposition of a treating plant.
Impairments.
During the year ended
December 31, 2008, we had an impairment expense of
$31.2 million compared to no impairment expense for the
year ended December 31, 2007. The impairment expense is
comprised of:
|
|
|
|
|
$17.8 million related to the Blue Water gas processing
plant located in south Louisiana The impairment on
our 59.27% interest in the Blue Water gas processing plant was
recognized because the pipeline company which owns the offshore
Blue Water system and supplies gas to the Partnerships
Blue Water plant reversed the flow of the gas on its pipeline in
early January 2009 thereby removing access to all the gas
processed at the Blue Water plant from the Blue Water offshore
system. At this time, the Partnership has not found an
alternative source of new gas for the Blue Water plant so the
plant ceased operation in January 2009. An impairment of
$17.8 million was recognized for the carrying amount of the
plant in excess of the estimated fair value of the plant as of
December 31, 2008.
|
|
|
|
$5.7 million related to goodwill We determined
that the carrying amount of goodwill attributable to the
Partnerships Midstream segment was impaired because of the
significant decline in its Midstream operations due to negative
impacts on cash flows caused by the significant declines in
natural gas and NGL prices during the last half of 2008 coupled
with the global economic decline.
|
|
|
|
$4.1 million related to leasehold improvements
We had planned to relocate our corporate headquarters during
2008 to a larger office facility. We had leased office space and
were close to completing the renovation of this office space
when the global economic decline began impacting our operations
in October 2008. On December 31, 2008, the decision was
made to cancel the new office lease and not relocate the
corporate offices from our existing office location. The
impairment relates to the leasehold improvements on the office
space for the cancelled lease.
|
|
|
|
$2.6 million related to the Arkoma gathering
system The impairment on the Arkoma gathering system
was recognized because the Partnership sold this asset in
February 2009 for $11.0 million and the carrying amount of
the plant exceeded the sale price by approximately
$2.6 million.
|
|
|
|
$1.0 million related to unused treating
equipment The impairment relates to older equipment
in the Treating division that will not be used in the
Partnerships future operations.
|
Depreciation and Amortization.
Depreciation
and amortization expenses were $131.3 million for the year
ended December 31, 2008 compared to $106.7 million for
the year ended December 31, 2007, an increase of
$24.6 million, or 23.1%. Midstream depreciation and
amortization increased $23.0 million due to the NTP, NTG
and north Louisiana expansion project assets. Accelerated
depreciation of the Dallas office leasehold due to the planned,
but subsequently cancelled, relocation accounted for an increase
between periods of $1.4 million.
Interest Expense.
Interest expense was
$102.6 million for the year ended December 31, 2008
compared to $79.0 million for the year ended
December 31, 2007, an increase of 23.6 million, or
29.8%. The increase relates primarily to the negative impact of
declining interest rates on interest rate swaps. Net interest
expense consists of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Senior notes
|
|
$
|
33.1
|
|
|
$
|
33.4
|
|
Credit facility
|
|
|
39.4
|
|
|
|
47.2
|
|
Capitalized interest
|
|
|
(2.7
|
)
|
|
|
(4.8
|
)
|
Mark to market interest rate swaps
|
|
|
22.1
|
|
|
|
1.1
|
|
Realized interest rate swaps
|
|
|
4.6
|
|
|
|
(0.7
|
)
|
Interest income
|
|
|
(0.4
|
)
|
|
|
(1.1
|
)
|
Other
|
|
|
6.5
|
|
|
|
3.9
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
102.6
|
|
|
$
|
79.0
|
|
|
|
|
|
|
|
|
|
|
49
Other Income.
Other income was
$27.9 million for the year ended December 31, 2008
compared to $0.7 million for the year ended
December 31, 2007. In November 2008, the Partnership sold a
contract right for firm transportation capacity on a third party
pipeline to an unaffiliated third party for $20.0 million.
The entire amount of such proceeds is reflected in other income
because the Partnership had no basis in this contract right. In
February 2008, the Partnership recorded $7.0 million from
the settlement of disputed liabilities that were assumed with an
acquisition.
Gain on Issuance of Units of the
Partnership.
As a result of the Partnership
issuing common units in April 2008 to unrelated parties at a
price per unit greater than our equivalent carrying value, our
share of net assets of the Partnership increased by
$14.7 million and we recognized a gain on issuance of such
units.
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 $2.4 million and $10.1 million for the
years ended December 31, 2008 and 2007, respectively, a
decrease of $7.7 million related to a decrease in income
generated by operations and the $5.2 million decrease in
the valuation allowance for investment in the Partnership.
Interest of Non-Controlling Partners in the
Partnerships Net Income (Loss) from Continuing
Operations.
The interest of non-controlling
partners in the Partnerships net loss increased by
$38.3 million to a loss of $45.6 million for the year
ended December 31, 2008 compared to a loss of
$7.3 million for the year ended December 31, 2007 due
to the changes shown in the following summary (in millions):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Net income (loss) from continuing operations for the Partnership
|
|
$
|
(44.8
|
)
|
|
$
|
7.4
|
|
(Income) allocation to CEI for the general partner incentive
distribution
|
|
|
(30.8
|
)
|
|
|
(24.8
|
)
|
Stock-based compensation costs allocated to CEI for its stock
options and restricted stock granted to Partnership officers,
employees and directors
|
|
|
4.7
|
|
|
|
5.4
|
|
Loss allocation to CEI for its 2% general partner share of
Partnership loss
|
|
|
0.8
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
Net loss allocable to limited partners
|
|
|
(70.1
|
)
|
|
|
(11.8
|
)
|
Less: CEIs share of net loss allocable to limited partners
|
|
|
24.2
|
|
|
|
4.3
|
|
Plus: Non-controlling partners share of net income in
Crosstex Denton County Gathering, J.V
|
|
|
0.3
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
Non-controlling partners share of Partnership net loss
from continuing operations
|
|
$
|
(45.6
|
)
|
|
$
|
(7.3
|
)
|
|
|
|
|
|
|
|
|
|
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.
Discontinued Operations.
Discontinued
operations were $12.2 million for the year ended
December 31, 2008 compared to $1.5 million for the year
ended December 31, 2007. In November 2008, the Partnership
sold its undivided 12.4% interest in the Seminole gas processing
plant to an unrelated third party. The Company realized a gain
on the sale of $11.0 million net of tax and minority
interest.
Year
Ended December 31, 2007 Compared to Year Ended
December 31, 2006
Gross Margin and Profit on Energy Trading
Activities.
Midstream gross margin was
$326.5 million for the year ended December 31, 2007
compared to $218.2 million for the year ended
December 31, 2006, an increase of $108.3 million, or
49.6%. This increase was primarily due to system expansions,
increased system throughput and a favorable processing
environment for natural gas and NGLs.
The Partnership acquired the NTG assets from Chief in June 2006.
System expansion in the north Texas region and increased
throughput on the NTP contributed $64.5 million of gross
margin growth during the year ended December 31, 2007 over
the same period in 2006. The NTG and NTP assets accounted for
$34.1 million and $16.6 million of this increase,
respectively. The processing facilities in the region
contributed an additional $13.3 million of this gross
margin increase. Operational improvements, system expansion and
increased volume on the LIG system coupled with optimization and
integration with the south Louisiana processing assets
contributed margin growth of $22.6 million for 2007. Volume
increases on the Mississippi system contributed gross margin
50
growth of $5.7 million. The Plaquemine and Gibson plants
contributed margin growth of $9.9 million due to a
favorable gas processing environment. The favorable gas
processing margin also led to a combined $5.3 million
margin increase on the Vanderbilt and Gulf Coast systems.
The favorable processing margins the Partnership realized during
2007 at several of its processing facilities may be higher than
margins it currently is realizing or may realize during future
periods due to the current economic environment and NGL prices.
As discussed above under
Commodity Price
Risk
, the Partnership receives as a processing fee a
percentage of the liquids recovered as on a substantial portion
of the gas processed by these plants. Also, during periods when
processing margins are favorable due to liquids prices being
high relative to natural gas prices, as existed during 2007, the
Partnership has the ability to generate higher processing
margins. The Partnership has the ability to bypass certain
volumes when processing is uneconomical so it can avoid negative
processing margins but processing margins will be lower during
these periods.
In addition, the Partnership has the ability to buy gas from and
to sell gas to various gas markets through its pipeline systems.
During 2007, 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.
Treating gross margin was $45.8 million for the year ended
December 31, 2007 compared to $42.6 million for the
year ended December 31, 2006, an increase of
$3.2 million, or 7.4%. There were approximately 190
treating and dew point control plants in service at
December 31, 2007. Although the number of plants in service
was unchanged from December 31, 2006, gross margin growth
for 2007 is attributed to a higher average number of plants in
service each month during 2007 compared to 2006.
Operating Expenses.
Operating expenses were
$125.2 million for the year ended December 31, 2007
compared to $98.8 million for the year ended
December 31, 2006, an increase of $26.3 million, or
26.7%. The increase in operating expenses primarily reflects
costs associated with growth and expansion in the north Texas
assets of $17.5 million, the south Texas assets of
$1.8 million, LIG and the north Louisiana expansion of
$3.7 million and Treating assets of $1.6 million.
Operating expenses included $1.8 million of stock-based
compensation expense in 2007 compared to $1.1 million of
stock-based compensation expense in 2006.
General and Administrative Expenses.
General
and administrative expenses were $64.3 million for the year
ended December 31, 2007 compared to $47.7 million for
the year ended December 31, 2006, an increase of
$16.6 million, or 34.8%. Additions to headcount associated
with the requirements of NTP and NTG assets and the expansion in
north Louisiana accounted for $8.9 million of the increase.
Consulting for system and process improvements resulted in
$2.8 million of the increase. General and administrative
expenses included stock-based compensation expense of
$10.2 million and $7.4 million in 2007 and 2006,
respectively.
Gain/Loss on Derivatives.
We had a gain on
derivatives of $6.6 million for the year ended
December 31, 2007 compared to a gain of $1.6 million
for the year ended December 31, 2006. The derivative
transaction types contributing to the net gain are as follows
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Total
|
|
|
Realized
|
|
|
Total
|
|
|
Realized
|
|
|
(Gain) Loss on Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps
|
|
$
|
(8.1
|
)
|
|
$
|
(7.0
|
)
|
|
$
|
(0.7
|
)
|
|
$
|
(0.4
|
)
|
Processing margin hedges
|
|
|
1.3
|
|
|
|
1.3
|
|
|
|
|
|
|
|
|
|
Storage
|
|
|
(0.5
|
)
|
|
|
(1.6
|
)
|
|
|
(2.9
|
)
|
|
|
(0.7
|
)
|
Third-party on-system swaps
|
|
|
(0.2
|
)
|
|
|
(0.6
|
)
|
|
|
(1.5
|
)
|
|
|
(1.2
|
)
|
Puts
|
|
|
0.8
|
|
|
|
|
|
|
|
3.6
|
|
|
|
|
|
Other
|
|
|
0.1
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(6.6
|
)
|
|
$
|
(7.9
|
)
|
|
$
|
(1.6
|
)
|
|
$
|
(2.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain/Loss on Sale of Property.
Assets sold
during the year ended December 31, 2007 generated a net
gain of $1.7 million as compared to a gain of
$2.1 million during the year ended December 31, 2007.
The 2007 gain was
51
primarily generated from the disposition of unused catalyst
material and the disposition of a treating plant. The gain in
2006 is primarily related to the sale of inactive gas processing
facilities acquired as part of the south Louisiana processing
assets and as part of the LIG acquisition.
Depreciation and Amortization.
Depreciation
and amortization expenses were $106.7 million for the year
ended December 31, 2007 compared to $80.6 million for
the year ended December 31, 2006, an increase of
$26.1 million, or 32.4%. Midstream depreciation and
amortization increased $25.8 million due to the NTP, NTG
and north Louisiana expansion project assets.
Interest Expense.
Interest expense was
$79.0 million for the year ended December 31, 2007
compared to $51.1 million for the year ended
December 31, 2006, an increase of $27.9 million, or
54.7%. The increase relates primarily to an increase in debt
outstanding as a result of acquisitions and other growth
projects. Net interest expense consists of the following (in
millions):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Senior notes
|
|
$
|
33.4
|
|
|
$
|
23.6
|
|
Credit facility
|
|
|
47.2
|
|
|
|
30.1
|
|
Capitalized interest
|
|
|
(4.8
|
)
|
|
|
(5.4
|
)
|
Mark to market interest rate swaps
|
|
|
1.1
|
|
|
|
(0.1
|
)
|
Realized interest rate swaps
|
|
|
(0.7
|
)
|
|
|
|
|
Interest income
|
|
|
(1.1
|
)
|
|
|
(1.4
|
)
|
Other
|
|
|
3.9
|
|
|
|
4.3
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
79.0
|
|
|
$
|
51.1
|
|
|
|
|
|
|
|
|
|
|
Other Income.
Other income was
$0.7 million for the year ended December 31, 2007
compared to $1.8 million for the year ended
December 31, 2006. 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 common units in December 2007 to unrelated parties at a
price per unit greater than our equivalent carrying value, our
share of net assets of the Partnership increased by
$7.5 million and we recognized a gain on issuance of such
units. In 2006, we recognized a $19.0 million gain
associated with the issuance in June 2005 of senior subordinated
units when the senior subordinated units converted to common
units in February 2006.
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 $10.1 million and $10.0 million for the
years ended December 31, 2007 and 2006, respectively.
Interest of Non-Controlling Partners in the
Partnerships Net Income (Loss) from Continuing
Operations.
The interest of non-controlling
partners in the Partnerships net income increased by
$9.9 million to a loss of
52
$7.3 million for the year ended December 31, 2007
compared to a loss of $17.2 million for the year ended
December 31, 2006 due to the changes shown in the following
summary (in millions):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Net income (loss) from continuing operations for the Partnership
|
|
$
|
7.4
|
|
|
$
|
(12.2
|
)
|
(Income) allocation to CEI for the general partner incentive
distribution
|
|
|
(24.8
|
)
|
|
|
(20.4
|
)
|
Stock-based compensation costs allocated to CEI for its stock
options and restricted stock granted to Partnership officers,
employees and directors
|
|
|
5.4
|
|
|
|
3.5
|
|
Loss allocation to CEI for its 2% general partner share of
Partnership loss
|
|
|
0.2
|
|
|
|
0.6
|
|
|
|
|
|
|
|
|
|
|
Net loss allocable to limited partners
|
|
|
(11.8
|
)
|
|
|
(28.5
|
)
|
Less: CEIs share of net loss allocable to limited partners
|
|
|
4.3
|
|
|
|
11.1
|
|
Plus: Non-controlling partners share of net income in
Crosstex Denton County Gathering, J.V.
|
|
|
0.2
|
|
|
|
0.2
|
|
|
|
|
|
|
|
|
|
|
Non-controlling partners share of Partnership net loss
from continuing operations
|
|
$
|
(7.3
|
)
|
|
$
|
(17.2
|
)
|
|
|
|
|
|
|
|
|
|
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.
Discontinued Operations.
Discontinued
operations were $1.5 million for the year ended
December 31, 2007 compared to $2.0 million for the year
ended December 31, 2006. In November 2008, the Partnership
sold its undivided 12.4% interest in the Seminole gas processing
plant to an unrelated third party.
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. See Note 2 of the Notes to Consolidated
Financial Statements for further details on our accounting
policies and a discussion of new accounting pronouncements.
Revenue Recognition and Commodity Risk
Management.
The Partnership recognizes revenue
for sales or services at the time the natural gas or NGLs are
delivered or at the time the service is performed. It 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.
The Partnership utilizes 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. It uses 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 causing actual deliveries
of gas to be different than estimated. The Partnership believes
53
that its 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.
The Partnership uses derivatives to hedge against changes in
cash flows related to product prices and interest rate risk, as
opposed to their use for trading purposes.
SFAS No. 133,
Accounting for Derivative Instruments
and Hedging Activities
, requires that 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 it 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
revenue and cost of sales for these activities are shown net in
the statement of operations.
The Partnership manages its price risk related to future
physical purchase or sale commitments for energy trading
activities by entering into either corresponding physical
delivery contracts or financial instruments with an objective to
balance future commitments and significantly reduce risk related
to the movement in natural gas prices. However, the Partnership
is subject to counter-party risk for both the physical and
financial contracts. The Partnerships energy trading
contracts qualify as derivatives, and it uses mark-to-market
accounting for both physical and financial contracts of the
energy trading business. Accordingly, any gain or loss
associated with changes in the fair value of derivatives and
physical delivery contracts relating to energy trading
activities are recognized in earnings as gain or loss on
derivatives immediately.
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
, the Partnership evaluates 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 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 the
Partnerships long-lived assets has occurred, it must
estimate the undiscounted cash flows attributable to the asset.
The 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;
|
54
|
|
|
|
|
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 the Partnerships cash
flows, which could require us to record an impairment of an
asset.
Depreciation Expense and Cost
Capitalization.
Our assets consist primarily of
natural gas gathering pipelines, processing plants, transmission
pipelines and natural gas treating plants owned by the
Partnership. The Partnership capitalizes all
construction-related direct labor and material costs, as well as
indirect construction costs. Indirect construction costs include
general engineering and the costs of funds used in construction.
Capitalized interest represents the cost of funds used to
finance the construction of new facilities and is expensed over
the life of the constructed assets through the recording of
depreciation expense. The Partnership capitalizes the costs of
renewals and betterments that extend the useful life, while we
expense the costs of repairs, replacements and maintenance
projects as incurred.
The Partnership generally computes depreciation using the
straight-line method over the estimated useful life of the
assets. Certain assets such as land, NGL line pack and natural
gas line pack are non-depreciable. The computation of
depreciation expense requires judgment regarding the estimated
useful lives and salvage value of assets. As circumstances
warrant, depreciation estimates may be reviewed to determine if
any changes are needed. Such changes could involve an increase
or decrease in estimated useful lives or salvage values, which
would impact future depreciation expense.
Liquidity
and Capital Resources
Cash Flows from Operating Activities.
Net cash
provided by operating activities was $170.2 million,
$112.6 million and $113.8 million for the years ended
December 31, 2008, 2007 and 2006, respectively. Income
before non-cash income and expenses and changes in working
capital for 2008, 2007 and 2006 were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Income before non-cash income and expenses
|
|
$
|
157.6
|
|
|
$
|
136.4
|
|
|
$
|
88.2
|
|
Changes in working capital
|
|
|
12.5
|
|
|
|
(23.9
|
)
|
|
|
25.6
|
|
The primary reason for the increased cash flow from income
before non-cash income and expenses of $21.2 million from
2007 to 2008 was increased operating income from the
Partnerships expansion in north Texas and north Louisiana
during 2007 and 2008. The primary reason for the increased cash
flow from income before non-cash income and expenses of
$48.2 million from 2006 to 2007 was increased operating
income from the Partnerships expansion in north Texas
during 2006 and 2007.
Cash Flows from Investing Activities.
Net cash
used in investing activities was $186.8 million,
$411.4 million and $885.8 million for the years ended
December 31, 2008, 2007 and 2006, respectively. Our primary
investing activities for 2008, 2007 and 2006 were capital
expenditures and acquisitions in the Partnership, net of accrued
amounts, as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Growth capital expenditures
|
|
$
|
257.2
|
|
|
$
|
403.7
|
|
|
$
|
308.8
|
|
Acquisitions and asset purchases
|
|
|
|
|
|
|
|
|
|
|
576.1
|
|
Maintenance capital expenditures
|
|
|
18.3
|
|
|
|
10.8
|
|
|
|
6.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
275.5
|
|
|
$
|
414.5
|
|
|
$
|
890.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55
Net cash invested in Midstream assets was $222.4 million
for 2008, $385.8 million for 2007, and $746.7 million
for 2006 (including $475.4 million related to the
acquisition of assets from Chief). Net cash invested in Treating
assets was $41.8 million for 2008, $23.5 million for
2007 and $86.8 million for 2006 (including
$51.5 million related to the acquisition of Hanover
assets). Net cash invested in other corporate assets was
$11.4 million for 2008, $5.2 million for 2007, and
$8.2 million for 2006.
Cash flows from investing activities for the years ended
December 31, 2008, 2007 and 2006 also include proceeds from
property sales of $88.8 million, $3.1 million and
$5.1 million, respectively. Sales in 2008 primarily relate
to the sale of interest in the Seminole gas processing plant.
The 2007 and 2006 sales primarily related to sales of inactive
properties.
Cash Flows from Financing Activities.
Net cash
provided by financing activities was $22.7 million,
$296.0 million and $769.7 million for the years ended
December 31, 2008, 2007 and 2006, respectively. Our
financing activities primarily relate to funding of capital
expenditures and acquisitions in the Partnership. Our financings
have primarily consisted of borrowings under the
Partnerships bank credit facility, borrowings under
capital lease obligations, equity offerings and senior note
issuances in the Partnership for 2008, 2007 and 2006 as follows
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Net borrowings under bank credit facility
|
|
$
|
50.0
|
|
|
$
|
246.0
|
|
|
$
|
166.0
|
|
Senior note issuances (net of repayments)
|
|
|
(9.4
|
)
|
|
|
(9.4
|
)
|
|
|
298.5
|
|
Common unit offerings
|
|
|
101.9
|
|
|
|
58.8
|
|
|
|
|
|
Net borrowings under capital lease obligations
|
|
|
23.9
|
|
|
|
3.6
|
|
|
|
|
|
Senior subordinated unit offerings
|
|
|
|
|
|
|
102.6
|
|
|
|
368.3
|
|
Dividends to shareholders and distributions to non-controlling
partners in the Partnership represent our primary use of cash in
financing activities. Total cash distributions made during the
last three years were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Dividends to shareholders
|
|
$
|
62.0
|
|
|
$
|
42.6
|
|
|
$
|
34.7
|
|
Non-controlling partners
|
|
|
63.2
|
|
|
|
39.0
|
|
|
|
34.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
125.2
|
|
|
$
|
81.6
|
|
|
$
|
69.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In order to reduce our interest costs, the Partnership does not
borrow money to fund outstanding checks until they are presented
to the bank. Fluctuations in drafts payable are caused by timing
of disbursements, cash receipts and draws on our revolving
credit facility. Changes in drafts payable for 2008, 2007 and
2006 were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Increase (decrease) in drafts payable
|
|
$
|
(7.4
|
)
|
|
$
|
(19.0
|
)
|
|
$
|
18.1
|
|
Working Capital Deficit.
We had a working
capital deficit of $20.4 million as of December 31,
2008, primarily due to drafts payable of $21.5 million as
of the same date. Changes in working capital may fluctuate
significantly between periods even though the Partnerships
trade receivables and payables are typically collected and paid
in 30 to 60 day pay cycles. A large volume of its revenues
are collected and a large volume of its gas purchases are paid
near each month end or the first few days of the following month
so receivable and payable balances at any month end may
fluctuate significantly depending on the timing of these
receipts and payments. In addition, although the Partnership
strives to minimize natural gas and NGLs in inventory, these
working inventory balances may fluctuate significantly from
period to period due to operational reasons and due to changes
in natural gas and NGL prices. Working capital also includes
mark to market derivative assets and liabilities associated with
commodity derivatives which may fluctuate significantly due the
changes in natural gas and NGL prices and
56
associated with interest rate swap derivatives which may
fluctuate significantly due to changes in interest rates. The
changes in working capital during the years ended
December 31, 2008, 2007 and 2006 are due to the impact of
the fluctuations discussed above.
Off-Balance Sheet Arrangements.
We had no
off-balance sheet arrangements as of December 31, 2008 and
2007.
April 2008 Sale of Common Units.
On
April 9, 2008, the Partnership issued 3,333,334 common
units in a private offering at $30.00 per unit, which
represented an approximate 7% discount from the market price on
such date. Net proceeds from the issuance, including our general
partner contribution less expenses associated with the issuance,
were approximately $102.0 million.
December 2007 Sale of Common Units.
On
December 19, 2007, the Partnership issued 1,800,000 common
units representing limited partner interests in the Partnership
at a price of $33.28 per unit for net proceeds of
$57.6 million. We made a general partner contribution of
$1.2 million in connection with the issuance to maintain
our 2% general partner interest.
March 2007 Sale of Senior Subordinated Series D
Units.
On March 23, 2007, the Partnership
issued an aggregate of 3,875,340 senior subordinated
series D units representing limited partner interests in a
private offering for net proceeds of approximately
$99.9 million. The senior subordinated series D units
were issued at $25.80 per unit, which represented a discount of
approximately 25% to the market value of common units on such
date. The discount represented an underwriting discount plus the
fact that the units would not receive a distribution nor be
readily transferable for two years. We made a general partner
contribution of $2.7 million in connection with this
issuance to maintain our 2% general partner interest. Due to the
decreased distribution with respect to the fourth quarter of
2008, the senior subordinated series D units will
automatically convert into common units on March 23, 2009
at a ratio of 1.05 common unit for each senior subordinated
series D unit. The senior subordinated series D units
are not entitled to distributions of available cash or
allocations of net income/loss from the Partnership until
March 23, 2009.
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 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 and
made a general partner contribution of $9.0 million in
connection with this issuance to maintain our 2% general partner
interest. The senior subordinated series C units
automatically converted to common units on February 16,
2008 at a ratio of one common unit for each senior subordinated
series C unit. The senior subordinated series C units
were not entitled to distributions of available cash until their
conversion to common units.
Sources
of Liquidity in 2009 and Capital Requirements
Historically the Partnership has been successful in accessing
capital from both the equity market and financial institutions
to fund the growth of its operations. However, due to the lack
of liquidity in the financial and equity markets coupled with
the decline in our Midstream operations, the Partnerships
access to capital is expected to be severely limited in 2009. As
a result the Partnership has significantly reduced its growth
plans during 2009 and 2010 to operate within the existing
capital structure.
One of the first steps the Partnership needed to accomplish to
continue to operate within its existing capital structure was to
amend the terms of its bank credit facility and senior secured
note agreement to allow it to operate with a higher leverage
ratio and a lower interest coverage ratio due to the anticipated
decline in operating income for 2009 and 2010 based on current
economic conditions. The Partnership amended its bank credit
facility and its senior secured note agreement in November 2008
and again in February 2009 to provide for terms that the
Partnership expects will allow it to continue to operate its
assets during the current difficult economic conditions. The
terms of the amended agreements allow the Partnership to
maintain a higher level of leverage and to maintain a lower
interest coverage ratio but its interest costs will increase,
its ability to incur additional indebtedness will be restricted
when operating at higher leverage ratios and the
Partnerships ability to pay distributions will be
57
prohibited until the leverage ratio is significantly lower and
it repays the PIK notes. The PIK notes are due six months after
the earlier of the refinancing or maturity of the bank credit
facility. The terms of these agreements and our PIK notes are
described more fully under Description of
Indebtedness.
The Partnership lowered its distribution level from $0.63 per
unit for the second quarter of 2008 to $0.50 per unit for the
third quarter of 2008 and $0.25 per unit for the fourth quarter
of 2008. As discussed above, the amended terms of its credit
facility and senior secured note agreement restrict its ability
to make distributions unless certain conditions are met. The
Partnership does not expect that it will meet these conditions
in 2009.
The Partnership has reduced budgeted capital expenditures
significantly for 2009. Total growth capital investments in the
calendar year 2009 are currently anticipated to be approximately
$100.0 million and primarily relate to capital projects in
north Texas and Louisiana pursuant to contractual obligations
with producers. The Partnership will use cash flow from
operations and existing capacity under its bank credit facility
to fund its reduced capital spending plan during 2009. Capital
expenditures in future periods will be limited to cash flow from
operating activities and to existing capacity under the bank
credit facility. It is unlikely that the Partnership will be
able to make any acquisitions based on the terms of its credit
facility and senior secured note agreement and the condition of
the capital markets because it may only use Excess Proceeds, as
defined under Amendments to Credit Documents below,
from the incurrence of unsecured debt and the issuance of equity
to make such acquisitions.
The Partnership has reduced general and administrative expenses
by reducing its work force by approximately 8.0% through the
elimination of open positions and elimination of certain
corporate positions and minimizing all non-essential costs. It
also reduced operating expenses by reducing overtime and
renegotiating certain contracts to reduce monthly costs and by
eliminating some equipment rentals.
Total Contractual Cash Obligations.
A summary
of the Partnerships total contractual cash obligations as
of December 31, 2008 is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
Total
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Thereafter
|
|
|
Long-Term Debt
|
|
$
|
1,263.7
|
|
|
$
|
9.4
|
|
|
$
|
20.3
|
|
|
$
|
816.0
|
|
|
$
|
93.0
|
|
|
$
|
93.0
|
|
|
$
|
232.0
|
|
Interest Payable on Fixed Long-Term Debt Obligations
|
|
|
194.6
|
|
|
|
38.0
|
|
|
|
37.0
|
|
|
|
35.6
|
|
|
|
31.3
|
|
|
|
23.9
|
|
|
|
28.8
|
|
Capital Lease Obligations
|
|
|
32.8
|
|
|
|
3.3
|
|
|
|
3.2
|
|
|
|
3.2
|
|
|
|
3.2
|
|
|
|
3.2
|
|
|
|
16.7
|
|
Operating Leases
|
|
|
88.5
|
|
|
|
28.4
|
|
|
|
19.0
|
|
|
|
17.9
|
|
|
|
16.4
|
|
|
|
3.1
|
|
|
|
3.7
|
|
Unconditional Purchase Obligations
|
|
|
13.5
|
|
|
|
13.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN 48 Tax Obligations
|
|
|
1.6
|
|
|
|
1.3
|
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Obligations
|
|
$
|
1,594.7
|
|
|
$
|
93.9
|
|
|
$
|
79.7
|
|
|
$
|
872.8
|
|
|
$
|
143.9
|
|
|
$
|
123.2
|
|
|
$
|
281.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The above table does not include any physical or financial
contract purchase commitments for natural gas.
The Partnerships interest payable under its Credit
Facility is not reflected in the above table because such
amounts depend on outstanding balances and interest rates, which
will vary from time to time. Based on balances outstanding and
rates in effect at December 31, 2008, annual interest
payments would be $30.6 million. The interest amounts also
exclude estimates of the effect of our interest rate swap
contracts.
The unconditional purchase obligations for 2009 relate to
purchase commitments for equipment.
58
Description
of Indebtedness
As of December 31, 2008 and 2007, long-term debt consisted
of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Bank credit facility, interest based on Prime or LIBOR plus an
applicable margin, interest rates at December 31, 2008 and
2007 were 6.33% and 6.71%, respectively
|
|
$
|
784,000
|
|
|
$
|
734,000
|
|
Senior secured notes, weighted average interest rates at
December 31, 2008 and 2007 of 8.0% and 6.75%, respectively
|
|
|
479,706
|
|
|
|
489,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,263,706
|
|
|
|
1,223,118
|
|
Less current portion
|
|
|
(9,412
|
)
|
|
|
(9,412
|
)
|
|
|
|
|
|
|
|
|
|
Debt classified as long-term
|
|
$
|
1,254,294
|
|
|
$
|
1,213,706
|
|
|
|
|
|
|
|
|
|
|
Credit Facility.
In September 2007, the
Partnership increased borrowing capacity under the bank credit
facility to $1.185 billion. The bank credit facility
matures in June 2011. As of December 31, 2008,
$850.4 million was outstanding under the bank credit
facility, including $66.4 million of letters of credit,
leaving approximately $334.6 million available for future
borrowing.
Obligations under the bank 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 its equity
interests in substantially all of its subsidiaries, and rank
pari passu
in right of payment with the senior secured
notes. The bank credit facility is guaranteed by the
Partnerships material 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.
On November 7, 2008, the Partnership entered into the Fifth
Amendment and Consent (the Fifth Amendment) to its
credit facility with Bank of America, N.A., as administrative
agent, and the banks and other parties thereto (the Bank
Lending Group). The Fifth Amendment amended the agreement
governing the credit facility to, among other things,
(i) increase the maximum permitted leverage ratio the
Partnership must maintain for the fiscal quarters ending
December 31, 2008 through September 30, 2009,
(ii) lower the minimum interest coverage ratio the
Partnership must maintain for the fiscal quarter ending
December 31, 2008 and each fiscal quarter thereafter,
(iii) permit the Partnership to sell certain assets,
(iv) increase the interest rate the Partnership pays on the
obligations under the credit facility and (v) lowers the
maximum permitted leverage ratio the Partnership must maintain
if it or its subsidiaries incur unsecured note indebtedness.
Due to the continued decline in commodity prices and the
deterioration in the processing margins, the Partnership
determined that there was a significant risk that the amended
terms negotiated in November 2008 would not be sufficient to
allow it to operate during 2009 without triggering a covenant
default under the bank credit facility and the senior secured
note agreement. On February 27, 2009, the Partnership
entered into the Sixth Amendment to Fourth Amended and Restated
Credit Agreement and Consent (the Sixth Amendment)
to its credit facility with the Bank Lending Group. Under the
Sixth Amendment, borrowings will bear interest at the
Partnerships option at the administrative agents
reference rate plus an applicable margin or LIBOR plus an
applicable margin. The applicable margins for the
Partnerships interest rate and letter of credit fees vary
quarterly based on the Partnerships leverage ratio as
defined by the credit facility (the Leverage Ratio
being generally
59
computed as total funded debt to consolidated earnings before
interest, taxes, depreciation, amortization and certain other
non-cash charges) and are as follows beginning February 27,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank
|
|
|
|
|
|
|
|
|
|
|
|
|
Reference
|
|
|
|
|
|
Letter of
|
|
|
|
|
|
|
Rate
|
|
|
LIBOR Rate
|
|
|
Credit
|
|
|
Commitment
|
|
Leverage Ratio
|
|
Advances(a)
|
|
|
Advances(b)
|
|
|
Fees(c)
|
|
|
Fees(d)
|
|
|
Greater than or equal to 5.00 to 1.00
|
|
|
3.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
0.50
|
%
|
Greater than or equal to 4.25 to 1.00 and less than 5.00 to 1.00
|
|
|
2.50
|
%
|
|
|
3.50
|
%
|
|
|
3.50
|
%
|
|
|
0.50
|
%
|
Greater than or equal to 3.75 to 1.00 and less than 4.25 to 1.00
|
|
|
2.25
|
%
|
|
|
3.25
|
%
|
|
|
3.25
|
%
|
|
|
0.50
|
%
|
Less than 3.75 to 1.00
|
|
|
1.75
|
%
|
|
|
2.75
|
%
|
|
|
2.75
|
%
|
|
|
0.50
|
%
|
|
|
|
(a)
|
|
The applicable margins for the bank reference rate advances
ranged from 0% to 0.25% under the bank credit facility prior to
the Fifth and Sixth Amendments. The applicable margin for the
bank reference rate advances was paid at the maximum rate of
2.00% under the Fifth Amendment from the November 7, 2008
until February 27, 2009.
|
|
(b)
|
|
The applicable margins for the LIBOR rate advances ranged from
1.00% to 1.75% under the bank credit facility prior to the Fifth
and Sixth Amendments. The applicable margin for the bank
reference rate advances was paid at the maximum rate of 3.00%
under the Fifth Amendment from the November 7, 2008 until
February 27, 2009.
|
|
(c)
|
|
The letter of credit fees ranged from 1.00% to 1.75% per annum
plus a fronting fee of 0.125% per annum under the bank credit
facility prior to the Fifth and Sixth Amendments. The letter of
credit fees were paid at the maximum rate of 3.00% per annum in
addition to the fronting fee under the Fifth Amendment from the
November 7, 2008 until February 27, 2009.
|
|
(d)
|
|
The commitment fees ranged from 0.20% to 0.375% per annum on the
unused amount of the credit facility under the bank credit
facility prior to the Fifth and Sixth Amendments. The commitment
fees were paid at the maximum rate of 0.50% per annum under the
Fifth Amendment from the November 7, 2008 until
February 27, 2009.
|
The Sixth Amendment also sets a floor for the LIBOR interest
rate of 2.75% per annum, which means, effective as of
February 27, 2009, borrowings under the bank credit
facility accrue interest at the rate of 6.75% based on the LIBOR
rate in effect on such date and the Partnerships current
leverage ratio. Based on the Partnerships forecasted
leverage ratios for 2009, it expects the applicable margins to
be at the high end of these ranges for interest rate and letter
of credit fees.
Pursuant to the Sixth Amendment, the Partnership must pay a
leverage fee if it does not prepay debt and permanently reduce
the banks commitments by the cumulative amounts of
$100.0 million on September 30, 2009,
$200.0 million on December 31, 2009, and
$300.0 million on March 31, 2010. If it fails to meet
any de-leveraging target, the Partnership must pay a leverage
fee on such date, equal to the product of the total amounts
outstanding under its bank credit facility and the senior
secured note agreement on such date, and 1.0% on
September 30, 2009, 1.0% on December 31, 2009 and 2.0%
on March 31, 2010. This leverage fee will accrue on the
applicable date, but not be payable until the Partnership
refinances its bank credit facility.
Under the Sixth Amendment, the maximum Leverage Ratio (measured
quarterly on a rolling four-quarter basis) is as follows:
|
|
|
|
|
7.25 to 1.00 for the fiscal quarter ending March 31, 2009;
|
|
|
8.25 to 1.00 for the fiscal quarters ending June 30, 2009
and September 30, 2009;
|
|
|
8.50 to 1.00 for the fiscal quarter ending December 31,
2009;
|
|
|
8.00 to 1.00 for the fiscal quarter ending March 31, 2010;
|
|
|
6.65 to 1.00 for the fiscal quarter ending June 30, 2010;
|
|
|
5.25 to 1.00 for the fiscal quarter ending September 30,
2010;
|
|
|
5.00 to 1.00 for the fiscal quarter ending December 31, 2010
|
|
|
4.50 to 1.00 for the fiscal quarters ending March 31, 2011
thru March 31, 2012; and
|
60
|
|
|
|
|
4.25 to 1.00 for the fiscal quarters ending June 20, 2012
and thereafter.
|
The minimum cash interest coverage ratio (as defined in the
agreement, measured quarterly on a rolling four-quarter basis)
is as follows under the Sixth Amendment:
|
|
|
|
|
1.75 to 1.00 for the fiscal quarter ending March 31, 2009;
|
|
|
1.50 to 1.00 for the fiscal quarter ending June 30, 2009;
|
|
|
1.30 to 1.00 for the fiscal quarter ending September 30,
2009;
|
|
|
1.15 to 1.00 for the fiscal quarter ending December 31,
2009;
|
|
|
1.25 to 1.00 for the fiscal quarter ending March 31, 2010;
|
|
|
1.50 to 1.00 for the fiscal quarter ending June 30, 2010;
|
|
|
1.75 to 1.00 for any fiscal quarters ending September 30,
2010 and December 31, 2010;
|
|
|
2.50 to 1.00 for any fiscal quarters ending March 31, 2011,
and thereafter.
|
Under the Sixth Amendment, no quarterly distributions may be
paid to unitholders of the Partnership unless the PIK notes have
been repaid and the Leverage Ratio is less than 4.25 to 1.00. If
the Leverage Ratio is between 4.00 to 1.00 and 4.25 to 1.00, the
Partnership may make the minimum quarterly distribution of up to
$0.25 per unit if the PIK notes have been repaid. If the
Leverage Ratio is less than 4.00 to 1.00, the Partnership may
make quarterly distributions to unitholders from available cash
as provided by the partnership agreement if the PIK notes have
been repaid. The PIK notes are due six months after the earlier
of the refinancing or maturity of its bank credit facility. In
order to repay the PIK notes prior to their scheduled maturity,
the Partnership will need to amend or refinance its bank credit
facility. Based on the Partnerships forecasted leverage
ratios for 2009 and the Partnerships near term ability to
refinance its bank credit facility, it does not anticipate
making quarterly distributions in 2009 other than the
distribution paid in February 2009 related to fourth quarter
2008 operating results.
The Sixth Amendment also limits the Partnerships annual
capital expenditures (excluding maintenance capital
expenditures) to $120.0 million in 2009 and
$75.0 million in 2010 and each year thereafter (with unused
amounts in any year being carried forward to the next year). It
is unlikely that the Partnership will be able to make any
acquisitions based on the terms of its credit facility and the
current condition of the capital markets because the Partnership
may only use a portion of the proceeds from the incurrence of
unsecured debt and the issuance of equity to make such
acquisitions.
The Sixth Amendment also eliminated the accordion in the
Partnerships bank credit facility, which previously had
permitted it to increase commitments thereunder by certain
amounts if any bank was willing to undertake such commitment
increase.
The Sixth Amendment also revised the terms for mandatory
repayment of outstanding indebtedness from asset sales and
proceeds from incurrence of unsecured debt and equity issuances.
Proceeds from debt issuances and from equity issuances not
required to prepay indebtedness are considered to be
Excess Proceeds under the amended bank credit
agreement. The Partnership may retain all Excess Proceeds. The
following table sets forth the amended prepayment terms:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of Net Proceeds from
|
|
|
% of Net Proceeds from
|
|
|
% of Net Proceeds from
|
|
|
|
Asset Sales Required
|
|
|
Debt Issuances Required
|
|
|
Equity Issuance Required
|
|
Leverage Ratio*
|
|
for Prepayment
|
|
|
for Prepayment
|
|
|
for Prepayment
|
|
|
Greater than or equal to 4.50
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
50
|
%
|
Greater or equal to 3.50 and Less Than 4.50
|
|
|
100
|
%
|
|
|
50
|
%
|
|
|
25
|
%
|
Less than 3.50
|
|
|
100
|
%
|
|
|
0
|
%
|
|
|
0
|
%
|
* The Leverage Ratio is to be adjusted to give effect to
proceeds from debt or equity issuance and the use of such
proceeds for each proportional level of Leverage Ratio.
The prepayments are to be applied pro rata based on total debt
(including letter of credit obligations) outstanding under the
bank credit agreement and the total debt outstanding under the
note agreement described
61
below. Any prepayments of advances on the bank credit facility
from proceeds from asset sales, debt or equity issuances will
permanently reduce the borrowing capacity or commitment under
the facility in an amount equal to 100% of the amount of the
prepayment. Any such commitment reduction will not reduce the
banks $300.0 million commitment to issue letters of
credit.
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;
|
|
|
|
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;
|
|
|
|
bankruptcy or other insolvency events;
|
|
|
|
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.
|
If an event of default relating to bankruptcy or other
insolvency events occurs, all indebtedness under the
Partnerships bank credit facility will immediately become
due and payable. If any other event of default exists under the
bank credit facility, the lenders may accelerate the maturity of
the obligations outstanding under the bank credit facility and
exercise other rights and remedies.
The Partnership is subject to interest rate risk on its credit
facility and has entered into interest rate swaps to reduce this
risk. See Note 13 to the financial statements for a
discussion of interest rate swaps.
62
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, pursuant to which it issued
the following senior secured notes (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
|
|
|
|
Month Issued
|
|
Amount
|
|
|
Rate(1)
|
|
|
Maturity
|
|
|
Principal Payment Terms
|
|
June 2003(2)
|
|
$
|
30,000
|
|
|
|
9.45
|
%
|
|
|
7 years
|
|
|
Quarterly payments of $1,765 from June 2006-June 2010
|
July 2003(2)
|
|
|
10,000
|
|
|
|
9.38
|
%
|
|
|
7 years
|
|
|
Quarterly payments of $588 from July 2006-July 2010
|
June 2004
|
|
|
75,000
|
|
|
|
9.46
|
%
|
|
|
10 years
|
|
|
Annual payments of $15,000 from July 2010-July 2014
|
November 2005
|
|
|
85,000
|
|
|
|
8.73
|
%
|
|
|
10 years
|
|
|
Annual payments of $17,000 from November 2010-December 2014
|
March 2006
|
|
|
60,000
|
|
|
|
8.82
|
%
|
|
|
10 years
|
|
|
Annual payments of $12,000 from March 2012-March 2016
|
July 2006
|
|
|
245,000
|
|
|
|
8.46
|
%
|
|
|
10 years
|
|
|
Annual payments of $49,000 from July 2012-July 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Issued
|
|
|
505,000
|
|
|
|
|
|
|
|
|
|
|
|
Principal repaid
|
|
|
(25,294
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
$
|
479,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Interest rates have been adjusted to give effect to the 2%
interest rate increase under the February 27, 2009
amendment described below.
|
|
(2)
|
|
Principle repayments were $19.4 million and
$5.9 million on the June 2003 and July 2003 notes,
respectively.
|
On November 7, 2008, the Partnership amended its senior
secured note agreement governing its senior secured notes to,
among other things, (i) modify the maximum permitted
leverage ratio and lower the minimum interest coverage ratio it
must maintain consistent with the ratios under the Fifth
Amendment to the bank credit facility, (ii) permit it to
sell certain assets and (iii) increase the interest rate it
pays on the senior secured notes. The interest rate the
Partnership paid on the senior secured notes increased by 1.25%
for the fourth quarter of 2008 due to this amendment.
The covenants and terms of default for the senior secured notes
are substantially the same as the covenants and default terms
under the bank credit facility, and therefore the agreement
governing the senior secured notes also required amendment in
2009. On February 27, 2009, the Partnership amended its
senior note agreement to (i) increase the maximum permitted
leverage ratio and to lower the minimum interest coverage ratio
it must maintain consistent with the ratios under the Sixth
Amendment to the bank credit facility, (ii) revise the
mandatory prepayment terms consistent with the terms under the
Sixth Amendment to the bank credit facility, (iii) increase
the interest rate it pays on the senior secured notes and
(iv) provide for the payment of a leverage fee consistent
with the terms of the bank credit facility. Commencing
February 27, 2009 the interest rate the Partnership pays in
cash on all of the senior secured notes will increase by 2.25%
per annum over the comparative interest rates under the senior
note agreement prior to the November and February amendments. As
a result of this rate increase, the weighted average cash
interest rate on the outstanding balance of the senior secured
notes is approximately 9.25% as of February 2009.
Under the amended senior secured note agreement, the senior
secured notes will accrue additional interest of 1.25% per annum
of the senior secured notes (the PIK notes) in the
form of an increase in the principal amount unless the
Partnerships leverage ratio is less than 4.25 to 1.00 as
of the end of any fiscal quarter. All PIK notes will be payable
six months after the maturity of its bank credit facility, which
is currently scheduled to mature in June 2011, or six months
after refinancing of such indebtedness if prior to the maturity
date.
Per the terms of the amended senior note agreement, commencing
on the date the Partnership refinances its bank credit facility,
the interest rate payable in cash on its senior secured notes
will increase by 1.25% per annum for
63
any quarter if its leverage ratio as of the most recently ended
fiscal quarter was greater than or equal to 4.25 to 1.00. In
addition, commencing on June 30, 2012, the interest rate
payable in cash on the Partnerships senior secured notes
will increase by 0.50% per annum for any quarter if its leverage
as of the most recently ended fiscal quarter was greater than or
equal to 4.00 to 1.00, but this incremental interest will not
accrue if the Partnership is paying the incremental 1.25% per
annum of interest described in the preceding sentence.
These notes represent the Partnerships senior secured
obligations and will rank
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 equity
interests in substantially all of the Partnerships
subsidiaries. The senior secured notes are guaranteed by the
Partnerships material subsidiaries.
The 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 senior secured note 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.
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 senior secured note agreement relating to the notes contains
substantially the same covenants and events of default as the
Partnerships bank credit facility.
The Partnership was in compliance with all debt covenants at
December 31, 2008 and 2007 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 senior secured note agreement, the lenders under the
Partnerships 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 Partnerships
bank credit facility and the purchasers of the senior secured
notes. This agreement specifies various rights and obligations
of lenders under the Partnerships bank credit facility,
holders of its senior secured notes and the other parties
thereto in respect of the collateral securing the
Partnerships obligations under the Partnerships bank
credit facility and the senior secured note agreement. On
February 27, 2009, the holders of the Partnerships
senior secured notes and a majority of the banks under its bank
credit facility entered into an amendment to the Intercreditor
and Collateral Agency Agreement, which provides that the PIK
notes and certain treasury management obligations will be
secured by the collateral for its bank credit facility and the
senior secured notes, but only paid with proceeds of collateral
after obligations under its bank credit facility and the senior
secured notes are paid in full.
Credit
Risk
Risks of nonpayment and nonperformance by the Partnerships
customers are a major concern in its business. The Partnership
is subject to risks of loss resulting from nonpayment or
nonperformance by its customers and other counterparties, such
as lenders and hedging counterparties. Any increase in the
nonpayment and nonperformance by its customers could adversely
affect the results of operations and reduce the
Partnerships ability to make distributions to its
unitholders. Many of the Partnerships customers finance
their activities through cash flow from operations, the
incurrence of debt or the issuance of equity. Recently, there
has been a significant decline in the credit markets and the
availability of credit. Additionally, many of the
Partnerships customers equity values have
substantially declined. The combination of reduction of cash
flow resulting from declines in commodity prices, a
64
reduction in borrowing bases under reserve based credit
facilities and the lack of availability of debt or equity
financing may result in a significant reduction in
customers liquidity and ability to make payments or
perform on their obligations to the Partnership. Furthermore,
some of the customers may be highly leveraged and subject to
their own operating and regulatory risks, which increases the
risk that they may default on their obligations to the
Partnership.
Inflation
Inflation in the United States has been relatively low in recent
years in the economy as a whole. The midstream natural gas
industry has experienced an increase in labor and material costs
during the 2007 year and the first half of 2008, although these
increases did not have a material impact on our results of
operations for the periods presented. 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 our existing
agreements, we have and will continue to pass along increased
costs to our customers in the form of higher fees.
Environmental
The Partnerships operations are subject to environmental
laws and regulations adopted by various governmental authorities
in the jurisdictions in which these operations are conducted. We
believe the Partnership 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.
Contingencies
On November 15, 2007, Crosstex Processing received a demand
letter from Denbury asserting a claim for breach of contract and
seeking payment of approximately $11.4 million in damages.
The claim arises from a contract under which Crosstex Processing
processed natural gas owned or controlled by Denbury in north
Texas. Denbury contends that Crosstex Processing breached the
Processing Contract by failing to build a processing plant of a
certain size and design, resulting in Crosstex Processings
failure to properly process the gas over a ten month period.
Denbury also alleges that Crosstex Processing failed to provide
specific notices required under the Processing Contract. On
December 4, 2007 and again on February 14, 2008,
Denbury sent Crosstex Processing letters demanding that its
claim be arbitrated pursuant to an arbitration provision in the
Processing Contract. On April 15, 2008, the parties
mediated the matter unsuccessfully. On December 4, 2008,
Denbury initiated formal arbitration proceedings against
Crosstex Processing, Crosstex Energy Services, L.P., Crosstex
North Texas Gathering, L.P., and Crosstex Gulf Coast Marketing,
Ltd., seeking $11.4 million and additional unspecified
damages. On December 23, 2008, Crosstex Processing filed an
answer denying Denburys allegations and a counterclaim
seeking a declaratory judgment that its processing plant is
uneconomic pursuant to the terms of the Processing Contract,
allowing cancellation of the contract. Crosstex Energy, Crosstex
Marketing, and Crosstex Gathering also filed an answer denying
Denburys allegations and asserting that they are improper
parties as Denburys claim is for breach of the Processing
Contract and none of these entities is a party to that
agreement. Crosstex Gathering also filed a counterclaim seeking
approximately $40.0 million in damages for the value of the
NGLs it is entitled to under its Gas Gathering Agreement with
Denbury. Once the three-person arbitration panel has been named
and cleared conflicts, the arbitration panel will hold a
preliminary conference with the parties to set a date for the
final hearing and other case deadlines and to establish
discovery limits. Although it is not possible to predict with
certainty the ultimate outcome of this matter, the Partnership
does not believe this will have a material adverse effect on its
consolidated results of operations or financial position.
The Partnership (or its subsidiaries) is defending eleven
lawsuits filed by owners of property located near processing
facilities or compression facilities constructed by it as part
of its systems in north Texas. The suits generally allege that
the facilities create a private nuisance and have damaged the
value of surrounding property. Claims of this nature have arisen
as a result of the industrial development of natural gas
gathering, processing and treating facilities in urban and
occupied rural areas. At this time, five cases are set for trial
during 2009. The remaining cases have not yet been set for
trial. Discovery is underway. Although it is not possible to
predict the
65
ultimate outcomes of these matters, the Partnership does not
believe that these claims will have a material adverse impact on
its consolidated results of operations or financial condition.
On July 22, 2008, SemStream, L.P. and certain of its
subsidiaries filed voluntary petitions for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. As of
July 22, 2008, SemStream, L.P. owed us approximately
$6.2 million, including approximately $3.9 million for
June 2008 sales and approximately $2.2 million for
July 2008 sales. The Partnership believes the July sales of
$2.2 million will receive administrative claim
status in the bankruptcy proceeding. The debtors schedules
acknowledge its obligation to the Partnership for an
administrative claim in the amount of approximately
$2.2 million but the allowance of the administrative claim
status is still subject to approval of the bankruptcy court in
accordance with the administrative claim allowance procedures
order in the case. The Partnership evaluated these receivables
for collectability and provided a valuation allowance of
$3.1 million during 2008.
Recent
Accounting Pronouncements
In October 2008, as a result of the recent credit crisis, the
FASB issued FSP
No. FAS 157-3,
Determining the Fair Value of a Financial Asset in a
Market That is Not Active
(FSP
FAS 157-3).
FSP
FAS 157-3
clarifies the application of SFAS No. 157 in a market
that is not active and provides guidance on how observable
market information in a market that is not active should be
considered when measuring fair value, as well as how the use of
market quotes should be considered when assessing the relevance
of observable and unobservable data available to measure fair
value. FSP
FAS 157-3
is effective upon issuance, for companies that have adopted
SFAS No. 157. The Partnership has evaluated the FSP
and determined that this standard has no impact on its results
of operations, cash flows or financial position for this
reporting period.
In June 2008, the Financial Accounting Standards Board
(FASB) issued Staff Position FSP
EITF 03-6-1
(the FSP) which requires unvested share-based
payment awards that contain nonforfeitable rights to dividends
or dividend equivalents to be treated as
participating
securities
as defined in EITF Issue
No. 03-6,
Participating Securities and the Two-Class Method
under FASB Statement No. 128, and, therefore,
included in the earnings allocation in computing earnings per
share under the two-class method described in FASB Statement
No. 128,
Earnings per Share
. The FSP is effective
for financial statements issued for fiscal years beginning after
December 15, 2008 and interim periods within those years.
Upon adoption, the Company will consider restricted shares with
nonforfeitable dividend rights in the calculation of earnings
per share and will adjust all prior reporting periods
retrospectively to conform to the requirements, although the
impact should not be material.
In February 2007, the FASB issued SFAS No. 159,
Fair Value Option for Financial Assets and Financial
Liabilities-Including an amendment to FASB Statement
No. 115
(SFAS 159).
SFAS 159 permits entities to choose to measure many
financial assets and financial liabilities at fair value.
Changes in the fair value on items for which the fair value
option has been elected are recognized in earnings each
reporting period. SFAS 159 also establishes presentation
and disclosure requirements designed to draw comparisons between
the different measurement attributes elected for similar types
of assets and liabilities. SFAS 159 was adopted effective
January 1, 2008 and did not have a material impact on our
financial statements.
In December 2007, the FASBs Emerging Issues Task Force
(EITF) reached a consensus on
EITF 06-11
Accounting for Income Tax Benefits of Dividends on
Share Based Payment Awards.
The tax benefit received
on dividends associated with share-based awards that are charged
to retained earnings should be recorded in additional
paid-in-capital
(APIC) and included in the pool of excess tax
benefits available to absorb potential future tax deficiencies
on share-based payment awards. The consensus is effective for
the tax benefits of dividends declared in fiscal years beginning
after December 15, 2007. The Company has evaluated the
impact of the EITF and determined we will not recognize any tax
benefit or a related credit to additional paid in capital for
dividends on restricted stock charged to retained earnings. The
tax benefit and credit to the APIC pool will be recognized when
the tax deduction reduces income taxes payable after utilization
of our net operating loss carry forward.
In December 2007, the FASB issued SFAS No. 141R,
Business Combinations
(SFAS 141R) and SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements
(SFAS 160). SFAS 141R
requires most identifiable assets, liabilities, noncontrolling
interests and goodwill acquired in a business combination to be
recorded at full fair value. The Statement applies
to all business combinations, including
66
combinations among mutual entities and combinations by contract
alone. Under SFAS 141R, all business combinations will be
accounted for by applying the acquisition method. SFAS 141R
is effective for periods beginning on or after December 15,
2008. SFAS 160 will require noncontrolling interests
(previously referred to as minority interests) to be treated as
a separate component of equity, not as a liability or other item
outside of permanent equity. The statement applies to the
accounting for noncontrolling interests and transactions with
noncontrolling interest holders in consolidated financial
statements. SFAS 160 is effective for periods beginning on
or after December 15, 2008 and will be applied
prospectively to all noncontrolling interests, including any
that arose before the effective date, except that comparative
period information must be recast to classify noncontrolling
interests in equity, attribute net income and other
comprehensive income to noncontrolling interests and provide
other disclosures required by SFAS 160.
In May 2008, the FASB issued SFAS No. 162,
The
Hierarchy of Generally Accepted Accounting Principles
(SFAS No. 162). SFAS No. 162 is
intended to improve financial reporting by identifying a
consistent framework, or hierarchy, for selecting accounting
principles to be used in preparing financial statements of
nongovernmental entities that are presented in conformity with
generally accepted accounting principles in the United States of
America. SFAS 162 is effective for fiscal years beginning
after November 15, 2008. The Company is currently
evaluating the potential impact, if any, of the adoption of
SFAS No. 162 on our consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities, an amendment of FASB Statement No. 133
(SFAS 161). SFAS 161 requires entities
to provide greater transparency about how and why the entity
uses derivative instruments, how the instruments and related
hedged items are accounted for under SFAS 133 and how the
instruments and related hedged items affect the financial
position, results of operations and cash flows of the entity.
SFAS 161 is effective for fiscal years beginning after
November 15, 2008. The principal impact to the Company will
be to require expanded disclosure regarding derivative
instruments.
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 NGLs. In addition, it is exposed to the risk of changes in
interest rates on its floating rate debt.
Interest
Rate Risk
The Partnership is exposed to interest rate risk on its variable
rate bank credit facility. At December 31, 2008 and 2007,
the bank credit facility had outstanding borrowings of
$784.0 million and $734.0 million, respectively, which
approximated fair value. The Partnership manages a portion of
its interest rate exposure on variable rate debt by utilizing
interest rate swaps, which allows conversion of a portion of
variable rate debt into fixed rate debt. In January 2008, the
Partnership amended its existing interest rate swaps covering
$450.0 million of the variable rate
67
debt to extend the period by one year (coverage periods end from
November 2010 through October 2011) and reduce the interest
rates to a range of 4.38% to 4.68%. In September 2008, the
Partnership entered into additional interest rate swaps covering
the $450.0 million that converted the floating rate portion
of the original swaps from three month LIBOR to one month LIBOR.
In addition the Partnership entered into one new interest rate
swap in January 2008 covering $100.0 million of the
variable rate debt for a period of one year at an interest rate
of 2.83%. As of December 31, 2008, the fair value of these
interest rate swaps was reflected as a liability of
$35.5 million ($17.1 million in net current
liabilities and $18.4 million in long-term liabilities) on
the financial statements. The Partnership estimates that a 1%
increase or decrease in the interest rate would increase or
decrease the fair value of these interest rate swaps by
approximately $22.4 million. Considering the interest rate
swaps and the amount outstanding on its bank credit facility as
of December 31, 2008, the Partnership estimates that a 1%
increase or decrease in the interest rate would change its
annual interest expense by approximately $2.3 million for
periods when the entire portion of the $550.0 million of
interest rate swaps are outstanding and $7.8 million for
annual periods after 2011 when all the interest rate swaps lapse.
At December 31, 2008 and 2007, the Partnership had total
fixed rate debt obligations of $479.7 million and
$489.1 million, respectively, consisting of its senior
secured notes with a weighted average interest rate of 8.0%. The
fair value of these fixed rate obligations was approximately
$374.4 million and $500.5 million as of
December 31, 2008 and 2007, respectively. The Partnership
estimates that a 1% increase or decrease in interest rates would
increase or decrease the fair value of the fixed rated debt (its
senior secured notes) by $15.2 million based on the debt
obligations as of December 31, 2008.
Commodity
Price Risk
The Partnership is subject to significant risks due to
fluctuations in commodity prices. Its exposure to these risks is
primarily in the gas processing component of its business. The
Partnership currently processes gas under three main types of
contractual arrangements:
1.
Processing margin 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. However, the Partnership mitigates
its risk of processing natural gas when its margins are negative
under its current processing margin contracts primarily through
its ability to bypass processing when it is not profitable for
the Partnership, or by contracts that revert to a minimum fee
for processing if the natural gas must be processed to meet
pipeline quality specifications.
2.
Percent of liquids 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 processing cannot
become negative under percent of liquids contracts, but do
decline during periods of low NGL prices.
3.
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.
68
Gas processing margins by contract types, gathering and
transportation margins and treating margins as a percent of
total gross margin for the comparative year-to-date periods are
as follows:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Gathering and transportation margin
|
|
|
49.3
|
%
|
|
|
41.5
|
%
|
Gas processing margins:
|
|
|
|
|
|
|
|
|
Processing margin
|
|
|
17.0
|
%
|
|
|
18.4
|
%
|
Percent of liquids
|
|
|
14.2
|
%
|
|
|
19.6
|
%
|
Fee based
|
|
|
7.5
|
%
|
|
|
8.1
|
%
|
|
|
|
|
|
|
|
|
|
Total gas processing
|
|
|
38.7
|
%
|
|
|
46.1
|
%
|
Treating margin
|
|
|
12.0
|
%
|
|
|
12.4
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
The Partnership has hedges in place at December 31, 2008
covering liquids volumes it expects to receive under percent of
liquids (POL) contracts as set forth in the following table. The
relevant payment index price is the monthly average of the daily
closing price for deliveries of commodities into Mont Belvieu,
Texas as reported by the Oil Price Information Service (OPIS).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
|
|
|
Fair Value
|
|
Period
|
|
Underlying
|
|
Volume
|
|
We Pay
|
|
We Receive
|
|
Asset/(Liability)
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
January
2009-December
2009
|
|
Ethane
|
|
114 (MBbls)
|
|
Index
|
|
$0.760 - $0.8275/gal
|
|
$
|
1,751
|
|
January
2009-December
2009
|
|
Propane
|
|
113 (MBbls)
|
|
Index
|
|
$1.39 - $1.46/gal
|
|
|
3,577
|
|
January
2009-December
2009
|
|
Iso Butane
|
|
31 (MBbls)
|
|
Index
|
|
$1.7375 -$1.78/gal
|
|
|
1,222
|
|
January
2009-December
2009
|
|
Normal Butane
|
|
37 (MBbls)
|
|
Index
|
|
$1.705-$1.765/gal
|
|
|
1,475
|
|
January
2009-December
2009
|
|
Natural Gasoline
|
|
86 (MBbls)
|
|
Index
|
|
$2.1275-$2.1575/gal
|
|
|
4,553
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
12,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Partnership has hedged its exposure to declines in prices
for NGL volumes produced for its account. The NGL volumes
hedged, as set forth above, focus on POL contracts. The
Partnership hedges POL exposure based on volumes considered
hedgeable (volumes committed under contracts that are long term
in nature) versus total POL volumes that include volumes that
may fluctuate due to contractual terms, such as contracts with
month to month processing options. The Partnership hedged 44% of
its hedgeable volumes at risk through the end of 2009 (20% of
total volumes at risk through the end of 2009). The Partnership
currently has not hedged any of its processing margin volumes
for 2009.
The Partnership is also subject to price risk to a lesser extent
for fluctuations in natural gas prices with respect to a portion
of its gathering and transport services. Approximately 4.0% 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, resale margins
are higher during periods of high natural gas prices and lower
during periods of lower natural gas prices. The Partnership has
hedged 34% of its natural gas volumes at risk through the end of
2009.
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 commercial services business for the year
ended December 31, 2008.
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, 2008
|
|
|
|
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(2)
|
|
|
248,715
|
|
|
|
3,955
|
|
|
|
252,670
|
|
|
|
|
|
South Texas system(1)
|
|
|
124,888
|
|
|
|
11,892
|
|
|
|
126,969
|
|
|
|
|
|
North Texas system
|
|
|
84,311
|
|
|
|
4,577
|
|
|
|
88,339
|
|
|
|
|
|
Other assets and activities(1)
|
|
|
78,373
|
|
|
|
2,160
|
|
|
|
15,456
|
|
|
|
|
|
|
|
|
(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.
|
|
(2)
|
|
LIG plants purchase the gathering system plant thermal reduction
(PTR).
|
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 natural gas bought and
sold on the same basis. However, it is normal to experience
fluctuations in the volumes of natural 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 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 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.
As of December 31, 2008, 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 $16.0 million. The aggregate effect of a
hypothetical 10% increase in gas and NGLs prices would result in
a decrease of approximately $1.4 million in the net fair
value asset of these contracts as of December 31, 2008.
|
|
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-49 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 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, 2008 in
alerting them in a timely manner to material information
required to be disclosed in our reports filed with the
Securities and Exchange Commission.
70
|
|
(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, 2008 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
|
On February 27, 2009, the Partnership entered into the
Sixth Amendment to its Fourth Amended and Restated Credit
Agreement and Consent with Bank of America, N.A. and the other
lenders party thereto (the Credit Agreement
Amendment) and Letter Amendment No. 4 to its Amended
and Restated Note Purchase Agreement with the holders of our
senior secured promissory notes and other parties thereto (the
Note Purchase Agreement Amendment). We have filed
the Credit Agreement Amendment and the Note Purchase Agreement
Amendment as Exhibits 10.13 and 10.18, respectively, to
this
Form 10-K.
See Item 1. Business Amendments to Credit
Documents and Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
Operations Description of Indebtedness for
more information.
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)
|
|
|
47
|
|
|
President, Chief Executive Officer and Director
|
Robert S. Purgason
|
|
|
52
|
|
|
Executive Vice President -- Chief Operating Officer
|
William W. Davis(1)
|
|
|
55
|
|
|
Executive Vice President and Chief Financial Officer
|
Joe A. Davis(1)
|
|
|
48
|
|
|
Executive Vice President, General Counsel and Secretary
|
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 has
served as director since our initial public offering in December
2002. 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.
Mr. Davis also serves as the Chairman of the Board for
Crosstex Energy, Inc.
Robert S. Purgason
,
Executive Vice
President Chief Operating Officer, joined Crosstex
in October 2004 as Senior Vice President-Treating Division 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.
71
William W. Davis
, Executive Vice President and Chief
Financial Officer, joined our predecessor in September 2001, and
has over 25 years of finance and accounting experience.
Mr. Davis has served as our Chief Financial Officer since
joining our predecessor. 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.
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.
Code of
Ethics
We adopted a Code of Business Conduct and Ethics applicable to
all of our employees, officers, and directors, 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 the Code 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 Proposal One: Election of
Directors, Additional Information Regarding the
Board of Directors, Section 16(a) Beneficial
Ownership Reporting Compliance, and Stockholder
Proposals and Other Matters that will appear in our proxy
statement for the 2009 annual meeting of stockholders, which we
expect to file with the Securities and Exchange Commission
within 120 days after December 31, 2008 (the 2009
Proxy Statement), will 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
will appear in the 2009 Proxy Statement will set forth certain
information with respect to the compensation of our management,
and is incorporated herein by reference.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
The sections entitled Equity Compensation Plans and
Security Ownership of Certain Beneficial Owners and
Management that appears in the 2009 Proxy Statement will
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.
72
|
|
Item 13.
|
Certain
Relationships and Related Transactions and Director
Independence
|
The sections entitled Certain Relationships and Related
Party Transactions and Additional Information
Regarding the Board of Directors that will appear in the
2009 Proxy Statement will set forth certain information with
respect to certain relationships and related party transactions,
and are incorporated herein by reference.
|
|
Item 14.
|
Principal
Accounting Fees and Services
|
The section entitled Fees Paid to Independent Public
Accounting Firm that will appear in the 2009 Proxy
Statement will set 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-39
and Schedule II Valuation and Qualifying
Accounts on
Page F-45.
(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
|
|
|
|
Sixth Amended and Restated Agreement of Limited Partnership of
Crosstex Energy, L.P., dated as of March 23, 2007
(incorporated by reference to Exhibit 3.1 to Crosstex
Energy, L.P.s Current Report on
Form 8-K
dated March 23, 2007, filed with the Commission on
March 27, 2007).
|
|
3
|
.5
|
|
|
|
Amendment No. 1 to Sixth Amended and Restated Agreement of
Limited Partnership of Crosstex Energy, L.P., dated
December 20, 2007 (incorporated by reference to
Exhibit 3.1 to Crosstex Energy, L.P.s Current Report
on
Form 8-K
dated December 20, 2007, filed with the Commission on
December 21, 2007).
|
|
3
|
.6
|
|
|
|
Amendment No. 2 to Sixth Amended and Restated Agreement of
Limited Partnership of Crosstex Energy, L.P. (incorporated by
reference to Exhibit 3.1 to Crosstex Energy, L.P.s
Current Report on
Form 8-K
dated March 27, 2008, filed with the Commission on
March 28, 2008).
|
|
3
|
.7
|
|
|
|
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
|
.8
|
|
|
|
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
|
.9
|
|
|
|
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).
|
73
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
3
|
.10
|
|
|
|
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
|
.11
|
|
|
|
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
|
.12
|
|
|
|
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. 333-97779).
|
|
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, file
No. 000-50536).
|
|
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
for the year ended December 31, 2002, 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 Statement and Waiver 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, file
No. 000-50536).
|
|
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, file
No. 000-50536).
|
|
10
|
.8
|
|
|
|
Fourth Amended and Restated Credit Agreement, dated
November 1, 2005, 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 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
|
|
|
|
Third Amendment to Fourth Amended and Restated Credit Agreement,
effective as of March 28, 2007, 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
Form 8-K
dated April 3, 2007, filed with the Commission on
April 5, 2007).
|
74
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
10
|
.12
|
|
|
|
Fifth Amendment and Consent to Fourth Amended and Restated
Credit Agreement, effective as of November 7, 2008, 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 Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2008).
|
|
10
|
.13
|
|
|
|
Sixth Amendment to Fourth Amended and Restated Credit Agreement,
effective as of February 27, 2009, among Crosstex Energy,
L.P., Bank of America, N.A. and certain other parties
(incorporated by reference to Exhibit 10.6 to Crosstex
Energy, L.P.s Annual Report on
Form 10-K
for the year ended December 31, 2008).
|
|
10
|
.14
|
|
|
|
Commitment Increase Agreement, dated as of September 19,
2007, among Crosstex Energy, L.P., Bank of America, N.A., and
certain lenders party thereto (incorporated by reference to
Exhibit 10.1 to Crosstex Energy, L.P.s Current Report on
Form 8-K
dated September 19, 2007, filed with the Commission on
September 24, 2007).
|
|
10
|
.15
|
|
|
|
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
|
.16
|
|
|
|
Letter Amendment No. 1 to Amended and Restated Note
Purchase Agreement, effective as of March 30, 2007, among
Crosstex Energy, L.P., Prudential Investment Management, Inc.
and certain other parties (incorporated by reference to
Exhibit 10.2 to Crosstex Energy, L.P.s
Form 8-K
dated April 3, 2007, filed with the Commission on
April 5, 2007).
|
|
10
|
.17
|
|
|
|
Waiver and Letter Amendment No. 3 to Amended and Restated
Note Purchase Agreement, effective as of November 7, 2008,
among Crosstex Energy, L.P., Prudential Investment Management,
Inc. and certain other parties (incorporated by reference to
Exhibit 10.2 to Crosstex Energy, L.P.s Quarterly
Report on
Form 10-Q
for the quarterly period ended September 30, 2008).
|
|
10
|
.18
|
|
|
|
Letter Amendment No. 4 to Amended and Restated Note
Purchase Agreement, effective as of February 27, 2009,
among Crosstex Energy, L.P., Prudential Investment Management,
Inc. and certain other parties (incorporated by reference to
Exhibit 10.11 to Crosstex Energy, L.P.s Annual Report
on
Form 10-K
for the year ended December 31, 2008).
|
|
10
|
.19
|
|
|
|
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
|
.20
|
|
|
|
Stock Purchase Agreement, dated as of May 16, 2006, by and
among Crosstex Energy, Inc. 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
|
.21
|
|
|
|
Senior Subordinated Series D Unit Purchase Agreement, dated
as of March 23, 2007, by and among Crosstex Energy, L.P. an
deach of the Purchasers set forth on Schedule A thereto
(incorporated by reference to Exhibit 10.1 to Crosstex
Energy, L.P.s
Form 8-K
dated March 23, 2007, filed with the Commission on
March 27, 2007).
|
|
10
|
.22
|
|
|
|
Registration Rights Agreement, dated as of March 23, 2007,
by and among Crosstex Energy, L.P. and each of the Purchasers
set forth on Schedule A thereto (incorporated by reference
to Exhibit 4.1 to Crosstex Energy, L.P.s
Form 8-K
dated March 23, 2007, filed with the Commission on
March 27, 2007).
|
|
10
|
.23
|
|
|
|
Form of Performance Share Agreement (incorporated by reference
to Exhibit 10.1 to Crosstex Energy, Inc.s Current
Report on
Form 8-K
dated June 27, 2007, filed with the Commission on
July 3, 2007).
|
|
10
|
.24
|
|
|
|
Form of Performance Unit Agreement (incorporated by reference to
Crosstex Energy, L.P.s Current Report on
Form 8-K
dated June 27, 2007, filed with the Commission on
July 3, 2007).
|
75
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
10
|
.25
|
|
|
|
Form of Employment Agreement (incorporated by reference to
Exhibit 10.6 to Crosstex Energy, L.P.s Annual Report
on
Form 10-K
for the year ended December 31, 2002, file
No. 000-50067).
|
|
10
|
.26
|
|
|
|
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).
|
|
10
|
.27
|
|
|
|
Common Unit Purchase Agreement, dated as of April 8, 2008,
by and among Crosstex Energy, L.P. and each of the Purchasers
set forth Schedule A thereto (incorporated by reference to
Exhibit 10.1 to Crosstex Energy, L.P.s
Form 8-K
dated April 9, 2008).
|
|
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
|
76
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 2nd day of March 2009.
CROSSTEX ENERGY, INC.
B
arry
E.
D
avis
,
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 Chairman of the Board
(Principal Executive Officer)
|
|
March 2, 2009
|
|
|
|
|
|
/s/
Leldon
E. Echols
Leldon
E. Echols
|
|
Director
|
|
March 2, 2009
|
|
|
|
|
|
/s/
James
C. Crain
James
C. Crain
|
|
Director
|
|
March 2, 2009
|
|
|
|
|
|
/s/
Bryan
H. Lawrence
Bryan
H. Lawrence
|
|
Lead Director
|
|
March 2, 2009
|
|
|
|
|
|
/s/
Sheldon
B. Lubar
Sheldon
B. Lubar
|
|
Director
|
|
March 2, 2009
|
|
|
|
|
|
/s/
Cecil
E. Martin
Cecil
E. Martin
|
|
Director
|
|
March 2, 2009
|
|
|
|
|
|
/s/
Robert
F. Murchison
Robert
F. Murchison
|
|
Director
|
|
March 2, 2009
|
|
|
|
|
|
/s/
William
W. Davis
William
W. Davis
|
|
Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
|
|
March 2, 2009
|
77
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 IParent Company Statements:
|
|
|
|
|
|
|
|
F-47
|
|
|
|
|
F-48
|
|
|
|
|
F-49
|
|
Schedule IIValuation and Qualifying Accounts:
|
|
|
|
|
|
|
|
F-50
|
|
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
consolidated financial statements, management has undertaken an
assessment of the effectiveness of the Companys internal
control over financial reporting as of December 31, 2008,
based on criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the 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, 2008, 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 the
Companys 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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2008, 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.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
Companys internal control over financial reporting as of
December 31, 2008, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO), and our reported dated March 2, 2009, expressed an
unqualified opinion on the effectiveness of the Companys
internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 2, 2009
F-3
Report of
Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Crosstex Energy, Inc.:
We have audited Crosstex Energy, Inc.s internal control
over financial reporting as of December 31, 2008, based on
criteria established in
Internal Control
Integrated Framework
issued by the Committee of Sponsoring
Organizations of the Treadway Commission (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, included in the accompanying
Managements Report on Internal Control over Financial
Reporting. Our responsibility is to express an opinion on the
Companys internal control over financial reporting based
on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk. Our audit also included 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, the Company maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2008, based on criteria established in
Internal Control Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway
Commission.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of the Company as of
December 31, 2008 and 2007, and the related consolidated
statements of operations, stockholders equity,
comprehensive income, and cash flows for each of the years in
the three-year period ended December 31, 2008, and our
report dated March 2, 2009
,
expressed an unqualified
opinion on those consolidated financial statements.
KPMG LLP
Dallas, Texas
March 2, 2009
F-4
CROSSTEX
ENERGY, INC.
Consolidated
Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands, except share data)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
13,959
|
|
|
$
|
7,853
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade, net of allowance for bad debts of $3,655 and $985,
respectively
|
|
|
49,185
|
|
|
|
46,441
|
|
Accrued revenues
|
|
|
292,668
|
|
|
|
443,448
|
|
Imbalances
|
|
|
3,893
|
|
|
|
3,865
|
|
Note receivable
|
|
|
375
|
|
|
|
1,026
|
|
Other
|
|
|
7,243
|
|
|
|
2,531
|
|
Fair value of derivative assets
|
|
|
27,166
|
|
|
|
8,589
|
|
Natural gas and natural gas liquids, prepaid expenses and other
|
|
|
9,658
|
|
|
|
16,098
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
404,147
|
|
|
|
529,851
|
|
|
|
|
|
|
|
|
|
|
Property and equipment:
|
|
|
|
|
|
|
|
|
Transmission assets
|
|
|
474,771
|
|
|
|
468,692
|
|
Gathering systems
|
|
|
614,572
|
|
|
|
460,420
|
|
Gas plants
|
|
|
577,250
|
|
|
|
565,464
|
|
Other property and equipment
|
|
|
72,106
|
|
|
|
65,561
|
|
Construction in process
|
|
|
86,462
|
|
|
|
79,889
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment
|
|
|
1,825,161
|
|
|
|
1,640,026
|
|
Accumulated depreciation
|
|
|
(296,671
|
)
|
|
|
(213,480
|
)
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
1,528,490
|
|
|
|
1,426,546
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative assets
|
|
|
4,628
|
|
|
|
1,337
|
|
Intangible assets, net of accumulated amortization of $89,231
and $60,118, respectively
|
|
|
578,096
|
|
|
|
610,076
|
|
Goodwill
|
|
|
19,673
|
|
|
|
25,402
|
|
Other assets, net
|
|
|
11,709
|
|
|
|
9,617
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,546,743
|
|
|
$
|
2,602,829
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Drafts payable
|
|
$
|
21,514
|
|
|
$
|
28,931
|
|
Accounts payable
|
|
|
23,879
|
|
|
|
13,727
|
|
Accrued gas purchases
|
|
|
270,229
|
|
|
|
427,293
|
|
Accrued imbalances payable
|
|
|
7,100
|
|
|
|
9,447
|
|
Fair value of derivative liabilities
|
|
|
28,506
|
|
|
|
21,066
|
|
Current portion of long-term debt
|
|
|
9,412
|
|
|
|
9,412
|
|
Other current liabilities
|
|
|
63,938
|
|
|
|
59,305
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
424,578
|
|
|
|
569,181
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
1,254,294
|
|
|
|
1,213,706
|
|
Other long-term liabilities
|
|
|
24,708
|
|
|
|
3,553
|
|
Deferred tax liability
|
|
|
81,998
|
|
|
|
71,563
|
|
Fair value of derivative liabilities
|
|
|
22,775
|
|
|
|
9,426
|
|
Interest of non-controlling partners in the Partnership
|
|
|
522,961
|
|
|
|
489,034
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock (150,000,000 shares authorized, $.01 par
value, 46,341,621 and 46,019,235 issued and outstanding in 2008
and 2007, respectively)
|
|
|
464
|
|
|
|
463
|
|
Additional paid-in capital
|
|
|
268,988
|
|
|
|
267,859
|
|
Accumulated deficit
|
|
|
(54,693
|
)
|
|
|
(16,878
|
)
|
Accumulated other comprehensive income (loss)
|
|
|
670
|
|
|
|
(5,078
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
215,429
|
|
|
|
246,366
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
2,546,743
|
|
|
$
|
2,602,829
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
F-5
CROSSTEX
ENERGY, INC.
Consolidated
Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except per share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream
|
|
$
|
4,838,747
|
|
|
$
|
3,791,316
|
|
|
$
|
3,075,481
|
|
Treating
|
|
|
64,953
|
|
|
|
53,682
|
|
|
|
52,095
|
|
Profit on energy trading activities
|
|
|
3,349
|
|
|
|
4,090
|
|
|
|
2,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
4,907,049
|
|
|
|
3,849,088
|
|
|
|
3,130,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream purchased gas
|
|
|
4,471,308
|
|
|
|
3,468,924
|
|
|
|
2,859,815
|
|
Treating purchased gas
|
|
|
14,579
|
|
|
|
7,892
|
|
|
|
9,463
|
|
Operating expenses
|
|
|
169,056
|
|
|
|
125,184
|
|
|
|
98,839
|
|
General and administrative
|
|
|
74,518
|
|
|
|
64,304
|
|
|
|
47,707
|
|
Gain on derivatives
|
|
|
(12,203
|
)
|
|
|
(6,628
|
)
|
|
|
(1,591
|
)
|
Gain on sale of property
|
|
|
(1,519
|
)
|
|
|
(1,667
|
)
|
|
|
(2,108
|
)
|
Impairments
|
|
|
31,240
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
131,318
|
|
|
|
106,685
|
|
|
|
80,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,878,297
|
|
|
|
3,764,694
|
|
|
|
3,092,704
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
28,752
|
|
|
|
84,394
|
|
|
|
37,382
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net of interest income
|
|
|
(102,565
|
)
|
|
|
(78,993
|
)
|
|
|
(51,051
|
)
|
Other income
|
|
|
27,885
|
|
|
|
683
|
|
|
|
1,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(74,680
|
)
|
|
|
(78,310
|
)
|
|
|
(49,277
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes,
gain on issuance of Partnership units and interest of
non-controlling partners in the Partnerships net income
(loss)
|
|
|
(45,928
|
)
|
|
|
6,084
|
|
|
|
(11,895
|
)
|
Income tax provision from continuing operations
|
|
|
(2,410
|
)
|
|
|
(10,147
|
)
|
|
|
(9,958
|
)
|
Gain on issuance of units of the Partnership
|
|
|
14,748
|
|
|
|
7,461
|
|
|
|
18,955
|
|
Interest of non-controlling partners in the Partnerships
net income (loss) from continuing operations
|
|
|
45,593
|
|
|
|
7,246
|
|
|
|
17,213
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before discontinued operations
and cumulative effect of change in accounting principle
|
|
|
12,003
|
|
|
|
10,644
|
|
|
|
14,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued
operations-net
of tax and net of minority interest
|
|
|
1,266
|
|
|
|
1,532
|
|
|
|
1,970
|
|
Gain on sale of discontinued
operations-net
of tax and net of minority interest
|
|
|
10,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations-net
of tax and net of minority interest
|
|
|
12,230
|
|
|
|
1,532
|
|
|
|
1,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect of change in accounting
principle
|
|
|
24,233
|
|
|
|
12,176
|
|
|
|
16,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
24,233
|
|
|
$
|
12,176
|
|
|
$
|
16,455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued
operations and cumulative effect of change in accounting
principle per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.26
|
|
|
$
|
0.23
|
|
|
$
|
0.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.26
|
|
|
$
|
0.23
|
|
|
$
|
0.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from discontinued operations per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.26
|
|
|
$
|
0.03
|
|
|
$
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.26
|
|
|
$
|
0.03
|
|
|
$
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle per common
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.52
|
|
|
$
|
0.26
|
|
|
$
|
0.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.52
|
|
|
$
|
0.26
|
|
|
$
|
0.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
46,298
|
|
|
|
45,988
|
|
|
|
42,168
|
|
Diluted
|
|
|
46,589
|
|
|
|
46,607
|
|
|
|
42,666
|
|
Dividends per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
$
|
1.32
|
|
|
$
|
0.91
|
|
|
$
|
0.807
|
|
See accompanying notes to consolidated financial statements.
F-6
CROSSTEX
ENERGY, INC.
Consolidated
Statements of Changes in Stockholders Equity
Years
Ended December 31, 2008, 2007 and 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Retained
|
|
|
Other
|
|
|
Total
|
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Earnings
|
|
|
Comprehensive
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
(Deficit)
|
|
|
Income
|
|
|
Equity
|
|
|
|
(In thousands)
|
|
|
Balance, December 31, 2005
|
|
|
12,760
|
|
|
$
|
127
|
|
|
$
|
80,187
|
|
|
$
|
31,747
|
|
|
$
|
(814
|
)
|
|
$
|
111,247
|
|
Three-for-one common stock split
|
|
|
30,628
|
|
|
|
309
|
|
|
|
(309
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock, net of offering costs
|
|
|
2,550
|
|
|
|
26
|
|
|
|
179,694
|
|
|
|
|
|
|
|
|
|
|
|
179,720
|
|
Proceeds from exercise of stock options
|
|
|
3
|
|
|
|
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
|
|
|
|
463
|
|
|
|
263,264
|
|
|
|
13,535
|
|
|
|
2,151
|
|
|
|
279,413
|
|
Conversion of restricted stock to common, net of shares withheld
for taxes
|
|
|
63
|
|
|
|
|
|
|
|
(919
|
)
|
|
|
|
|
|
|
|
|
|
|
(919
|
)
|
Proceeds from exercise of stock options
|
|
|
15
|
|
|
|
|
|
|
|
98
|
|
|
|
|
|
|
|
|
|
|
|
98
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
5,416
|
|
|
|
|
|
|
|
|
|
|
|
5,416
|
|
Common dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(42,589
|
)
|
|
|
|
|
|
|
(42,589
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,176
|
|
|
|
|
|
|
|
12,176
|
|
Non-controlling partners share of other comprehensive
income in Partnership
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
281
|
|
|
|
281
|
|
Hedging gains or losses reclassified to earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(963
|
)
|
|
|
(963
|
)
|
Adjustment in fair value of derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,547
|
)
|
|
|
(6,547
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
46,019
|
|
|
|
463
|
|
|
|
267,859
|
|
|
|
(16,878
|
)
|
|
|
(5,078
|
)
|
|
|
246,366
|
|
Conversion of restricted stock to common, net of shares withheld
for taxes
|
|
|
285
|
|
|
|
|
|
|
|
(3,815
|
)
|
|
|
|
|
|
|
|
|
|
|
(3,815
|
)
|
Proceeds from exercise of stock options
|
|
|
38
|
|
|
|
1
|
|
|
|
243
|
|
|
|
|
|
|
|
|
|
|
|
244
|
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
4,701
|
|
|
|
|
|
|
|
|
|
|
|
4,701
|
|
Common dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(62,048
|
)
|
|
|
|
|
|
|
(62,048
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,233
|
|
|
|
|
|
|
|
24,233
|
|
Non-controlling partners share of other comprehensive
income in Partnership
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
431
|
|
|
|
431
|
|
Hedging gains or losses reclassified to earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,689
|
|
|
|
4,689
|
|
Adjustment in fair value of derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
628
|
|
|
|
628
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
46,342
|
|
|
$
|
464
|
|
|
$
|
268,988
|
|
|
$
|
(54,693
|
)
|
|
$
|
670
|
|
|
$
|
215,429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-7
CROSSTEX
ENERGY, INC.
Consolidated
Statements of Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Net income
|
|
$
|
24,233
|
|
|
$
|
12,176
|
|
|
$
|
16,455
|
|
Non-controlling partners share of other comprehensive
income in the Partnership, net of taxes of $254, $103 and $0,
respectively
|
|
|
431
|
|
|
|
281
|
|
|
|
|
|
Hedging gains or losses reclassified to earnings, net of taxes
of $2,765, $(564) and $(779), respectively
|
|
|
4,689
|
|
|
|
(963
|
)
|
|
|
(1,361
|
)
|
Adjustment in fair value of derivatives, net of taxes of $372,
$(3,783) and $2,460, respectively
|
|
|
628
|
|
|
|
(6,547
|
)
|
|
|
4,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
29,981
|
|
|
$
|
4,947
|
|
|
$
|
19,420
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-8
CROSSTEX
ENERGY, INC.
Consolidated
Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
24,233
|
|
|
$
|
12,176
|
|
|
$
|
16,455
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
133,030
|
|
|
|
108,926
|
|
|
|
82,792
|
|
Non-cash stock-based compensation
|
|
|
11,279
|
|
|
|
12,259
|
|
|
|
8,579
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(170
|
)
|
Gain on sale of property
|
|
|
(51,325
|
)
|
|
|
(1,667
|
)
|
|
|
(2,108
|
)
|
Impairment
|
|
|
31,240
|
|
|
|
|
|
|
|
|
|
Deferred tax expense
|
|
|
7,022
|
|
|
|
10,338
|
|
|
|
11,386
|
|
Interest of non-controlling partners in the Partnership net
income
|
|
|
(9,470
|
)
|
|
|
(3,198
|
)
|
|
|
(13,027
|
)
|
Gain on issuance of units of the Partnership
|
|
|
(14,748
|
)
|
|
|
(7,461
|
)
|
|
|
(18,955
|
)
|
Non-cash derivatives loss
|
|
|
23,510
|
|
|
|
2,418
|
|
|
|
550
|
|
Amortization of debt issue costs
|
|
|
2,854
|
|
|
|
2,639
|
|
|
|
2,694
|
|
Changes in assets and liabilities net of acquisition effects:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, accrued revenue, and other
|
|
|
156,280
|
|
|
|
(121,285
|
)
|
|
|
78,338
|
|
Natural gas and natural gas liquids, prepaid expenses and other
|
|
|
5,199
|
|
|
|
(5,498
|
)
|
|
|
12,999
|
|
Accounts payable, accrued gas purchases, and other accrued
liabilities
|
|
|
(148,950
|
)
|
|
|
102,096
|
|
|
|
(65,694
|
)
|
Fair value of derivatives
|
|
|
|
|
|
|
835
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
170,154
|
|
|
|
112,578
|
|
|
|
113,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property and equipment
|
|
|
(275,548
|
)
|
|
|
(414,452
|
)
|
|
|
(314,766
|
)
|
Acquisitions and asset purchases
|
|
|
|
|
|
|
|
|
|
|
(576,110
|
)
|
Proceeds from sale of property
|
|
|
88,780
|
|
|
|
3,070
|
|
|
|
5,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(186,768
|
)
|
|
|
(411,382
|
)
|
|
|
(885,825
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from borrowings
|
|
|
1,743,580
|
|
|
|
1,189,500
|
|
|
|
1,708,500
|
|
Payments on borrowings
|
|
|
(1,702,992
|
)
|
|
|
(953,512
|
)
|
|
|
(1,244,021
|
)
|
Proceeds from capital lease obligations
|
|
|
28,010
|
|
|
|
3,553
|
|
|
|
|
|
Payments on capital lease obligations
|
|
|
(4,101
|
)
|
|
|
|
|
|
|
|
|
Increase (decrease) in drafts payable
|
|
|
(7,417
|
)
|
|
|
(19,017
|
)
|
|
|
18,094
|
|
Debt refinancing costs
|
|
|
(4,903
|
)
|
|
|
(892
|
)
|
|
|
(5,646
|
)
|
Distributions to non-controlling partners in the Partnership
|
|
|
(63,149
|
)
|
|
|
(38,960
|
)
|
|
|
(34,902
|
)
|
Common dividends paid
|
|
|
(62,048
|
)
|
|
|
(42,589
|
)
|
|
|
(34,667
|
)
|
Proceeds from exercise of common stock option
|
|
|
244
|
|
|
|
98
|
|
|
|
126
|
|
Conversion of restricted units, net of units withheld for taxes
|
|
|
(1,536
|
)
|
|
|
(329
|
)
|
|
|
|
|
Conversion of restricted stock, net of shares withheld for taxes
|
|
|
(3,815
|
)
|
|
|
(919
|
)
|
|
|
|
|
Net proceeds from issuance of units of the Partnership
|
|
|
99,888
|
|
|
|
157,491
|
|
|
|
179,185
|
|
Proceeds from exercise of Partnership unit options
|
|
|
850
|
|
|
|
1,598
|
|
|
|
3,328
|
|
Contributions from non-controlling partners in the Partnership
|
|
|
109
|
|
|
|
|
|
|
|
|
|
Net proceeds from issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
179,720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
22,720
|
|
|
|
296,022
|
|
|
|
769,717
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
6,106
|
|
|
|
(2,782
|
)
|
|
|
(2,269
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
7,853
|
|
|
|
10,635
|
|
|
|
12,904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
13,959
|
|
|
$
|
7,853
|
|
|
$
|
10,635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
76,291
|
|
|
$
|
79,648
|
|
|
$
|
46,794
|
|
Cash paid (refunded) for income taxes
|
|
$
|
1,821
|
|
|
$
|
(45
|
)
|
|
$
|
(847
|
)
|
See accompanying notes to consolidated financial statements.
F-9
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial Statements
December 31, 2008 and 2007
|
|
(1)
|
Organization
and Summary of Significant Agreements:
|
|
|
(a)
|
Description
of Business
|
CEI, 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 natural gas liquids (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 NGLs, transports natural gas and NGLs and ultimately
provides natural gas and NGLs to a variety of markets. In
addition, the Company purchases natural gas and NGLs from
producers not connected to its gathering systems for resale and
markets natural gas and NGLs on behalf of producers for a fee.
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 owns 16,414,830 common units in the
Partnership through its wholly-owned subsidiaries on
December 31, 2008 which represented 34.0% of the limited
partner interests in the Partnership.
|
|
(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 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 6. 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.
|
|
(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.
F-10
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
(d)
|
Property,
Plant, and Equipment
|
Property, plant and equipment consists of intrastate gas
transmission systems, gas gathering systems, industrial supply
pipelines, NGL pipelines, natural gas processing plants, NGL
fractionation plants, dew point control and gas treating plants.
Other property and equipment is primarily comprised of computer
software and equipment, furniture, fixtures, leasehold
improvements and office equipment. Property, plant and equipment
are recorded at cost. Gas required to maintain pipeline minimum
pressures is capitalized and classified as property, plant and
equipment. 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 $2.7 million, $4.8 million
and $5.4 million were capitalized for the years ended
December 31, 2008, 2007 and 2006, respectively.
Depreciation is provided using the straight-line method based on
the estimated useful life of each asset, as follows:
|
|
|
|
|
|
|
Useful Lives
|
|
|
Transmission assets
|
|
|
15-30 years
|
|
Gathering systems
|
|
|
7-15 years
|
|
Gas treating and gas processing plants
|
|
|
15 years
|
|
Other property and equipment
|
|
|
3-10 years
|
|
Depreciation expense of $98.2 million, $78.3 million
and $66.8 million was recorded for the years ended
December 31, 2008, 2007 and 2006, 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.
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.
The Partnership recorded impairments to long-lived assets of
$25.6 million during the year ending December 31,
2008. See Note 4(c) for further details on the
long-lived assets impaired. No impairments were incurred during
the years ended December 31, 2007 and 2006.
Statement of Financial Accounting Standards (SFAS) No. 144,
Accounting for the Impairment or Disposal of Long-Lived
Assets
, also requires long-lived assets being held for sale
or disposed of to be presented in the financial statements
separately. During the third quarter of 2008 the Partnership
held for sale its undivided 12.4% interest in the Seminole gas
processing plant. The sale was finalized on November 17,
2008. All operating results for the Seminole plant are recorded
in discontinued operating income and the gain on the disposition
of the plant is recorded in gain on sale of discontinued
operations. See Note 4(c) for further information on
discontinued operations.
F-11
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
(e)
|
Goodwill
and Intangibles
|
The Company has approximately $19.7 million and
$25.4 million of goodwill at December 31, 2008 and
2007, respectively. Goodwill created in the formation of the
Partnership of $5.7 million net book value associated with
the Midstream assets was impaired during the year ending
December 31, 2008. The goodwill remaining in the
Partnership is attributable to Treating assets acquired during
2005 and 2006. See Note 5 for further details on the
impairment of goodwill on the Midstream assets. Goodwill will
continue to be assessed at least annually for impairment.
Intangible assets consist of customer relationships and the
value of the dedicated and non-dedicated acreage attributable to
pipeline, gathering and processing systems. The Chief
acquisition, as discussed in Note 4(a), included
$395.6 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
$33.2 million, $28.4 million and $13.8 million
for the years ended December 31, 2008, 2007 and 2006,
respectively.
The following table summarizes the Companys estimated
aggregate amortization expense for the next five years (in
thousands):
|
|
|
|
|
2009
|
|
$
|
39,810
|
|
2010
|
|
|
40,193
|
|
2011
|
|
|
44,735
|
|
2012
|
|
|
47,511
|
|
2013
|
|
|
47,620
|
|
Thereafter
|
|
|
358,227
|
|
|
|
|
|
|
Total
|
|
$
|
578,096
|
|
|
|
|
|
|
Unamortized debt issuance costs totaling $11.7 million and
$9.6 million as of December 31, 2008 and 2007,
respectively, are included in other assets, net. 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.
|
|
(g)
|
Gas
Imbalance Accounting
|
Quantities of natural gas and NGLs 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 or NGLS. The Company had
imbalance payables of $7.1 million and $9.4 million at
December 31, 2008 and 2007, respectively, which
approximates the fair value for these imbalances. The Company
had imbalance receivables of $3.9 million at
December 31, 2008 and 2007, which are carried at the lower
of cost or market value.
F-12
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
(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, 2008 or 2007
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. Purchase and sale arrangements are generally
reported in revenues and costs on a gross basis in the
statements of operations in accordance with EITF Issue
No. 99-19,
Reporting Revenue Gross as a Principal versus Net as an
Agent
Except for fee based arrangements and energy
trading activities related to off-system gas
marketing operations discussed in Note 2(k), the
Partnership acts as the principal in these purchase and sale
transactions, has the risk and reward of ownership as evidenced
by title transfer, and schedules the transportation and assumes
credit risk.
The Company accounts for taxes collected from customers
attributable to revenue transactions and remitted to government
authorities on a net basis (excluded from revenues).
The Partnership uses derivatives to hedge against changes in
cash flows related to product price and interest rate risks, as
opposed to their use for trading purposes.
SFAS No. 133,
Accounting for Derivative
Instruments and Hedging Activities,
requires that all
derivatives be recorded on the balance sheet at fair value. It
generally determines the fair value of futures contracts and
swap contracts based on the difference between the
derivatives fixed contract price and the underlying market
price at the determination date. The asset or liability related
to the derivative instruments is recorded on the balance sheet
in fair value of derivative assets or liabilities.
Realized and unrealized gains and losses on derivatives that are
not designated as hedges, as well as the ineffective portion of
hedge derivatives, are recorded as gain or loss on derivatives
in the consolidated statement of operations. Unrealized gains
and losses on effective cash flow hedge derivatives are recorded
as a component of accumulated other comprehensive income. When
the hedged transaction occurs, the realized gain or loss on the
hedge derivative is transferred from accumulated other
comprehensive income to earnings. Realized gains and losses on
commodity hedge derivatives are recognized in revenues, and
realized gains and losses on interest hedge derivatives are
recorded as adjustments to interest expense. Settlements of
derivatives are included in cash flows from operating activities.
|
|
(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,
F-13
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
the Company earns an agency fee from the producer for arranging
the marketing of the producers natural gas or NGLs. In
other cases, the Company purchases the natural gas or NGLs from
the producer and enters into a sales contract with another party
to sell the natural gas or NGLs. The revenue and cost of sales
for energy trading activities are shown net in the consolidated
statements of operations.
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 and NGL 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.
Net margins earned on settled contracts from the
Partnerships energy trading activities included in profit
on energy trading activities in the consolidated statement of
operations were $3.3 million, $4.1 million, and
$2.5 million for the years ended December 31, 2008,
2007 and 2006, respectively.
Energy trading contract volumes that were physically settled
were as follows (in MMBtus):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Volumes purchased and sold
|
|
|
31,003,000
|
|
|
|
34,432,000
|
|
|
|
50,563,000
|
|
|
|
(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 since 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. 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, 2008, 2007 and
2006 of $3.7 million, $1.0 million and
$0.6 million, respectively. The increase in reserve in 2008
primarily relates to SemStream, L. P. See
Note 16(e) for a discussion of the bankruptcy of
SemStream, L. P. and related subsidiaries.
During 2008, 2007 and 2006, Dow Hydrocarbons accounted for
11.0%, 11.8% and 13.4%, respectively, 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 this customer
F-14
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
represents a significant percentage of revenues, the loss of
this customer 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, 2008, 2007 and 2006, such
expenditures were not significant.
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 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. 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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Cost of share-based compensation charged to general and
administrative expense
|
|
$
|
9,364
|
|
|
$
|
10,417
|
|
|
$
|
7,448
|
|
Cost of share-based compensation charged to operating expense
|
|
|
1,879
|
|
|
|
1,842
|
|
|
|
1,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total amount charged to income before cumulative effect of
accounting change
|
|
$
|
11,243
|
|
|
$
|
12,259
|
|
|
$
|
8,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest of non-controlling partners in share-based compensation
|
|
$
|
4,014
|
|
|
$
|
4,214
|
|
|
$
|
2,857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of related income tax benefit recognized in income
|
|
$
|
2,685
|
|
|
$
|
2,982
|
|
|
$
|
2,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of each option is estimated on the date of grant
using the Black Scholes option-pricing model as disclosed in
Note 11 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).
F-15
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
(r)
|
Recent
Accounting Pronouncements
|
In October 2008, as a result of the recent credit crisis, the
FASB issued FSP
No. FAS 157-3,
Determining the Fair Value of a Financial Asset in a
Market That is Not Active
(FSP
FAS 157-3).
FSP
FAS 157-3
clarifies the application of SFAS No. 157 in a market
that is not active and provides guidance on how observable
market information in a market that is not active should be
considered when measuring fair value, as well as how the use of
market quotes should be considered when assessing the relevance
of observable and unobservable data available to measure fair
value. FSP
FAS 157-3
is effective upon issuance, for companies that have adopted
SFAS No. 157. The Partnership has evaluated the FSP
and determined that this standard has no impact on its results
of operations, cash flows or financial position for this
reporting period.
In June 2008, the Financial Accounting Standards Board
(FASB) issued Staff Position FSP
EITF 03-6-1
(the FSP) which requires unvested share-based payment awards
that contain nonforfeitable rights to dividends or dividend
equivalents to be treated as
participating securities
as
defined in EITF Issue
No. 03-6,
Participating Securities and the Two-Class Method
under FASB Statement No. 128, and, therefore,
included in the earnings allocation in computing earnings per
share under the two-class method described in FASB Statement
No. 128,
Earnings per Share
. The FSP is effective
for financial statements issued for fiscal years beginning after
December 15, 2008 and interim periods within those years.
Upon adoption, the Company will consider restricted shares with
nonforfeitable dividend rights in the calculation of earnings
per share and will adjust all prior reporting periods
retrospectively to conform to the requirements, although the
impact should not be material.
In February 2007, the FASB issued SFAS No. 159,
Fair Value Option for Financial Assets and Financial
Liabilities-Including an amendment to FASB Statement
No. 115
(SFAS 159).
SFAS 159 permits entities to choose to measure many
financial assets and financial liabilities at fair value.
Changes in the fair value on items for which the fair value
option has been elected are recognized in earnings each
reporting period. SFAS 159 also establishes presentation
and disclosure requirements designed to draw comparisons between
the different measurement attributes elected for similar types
of assets and liabilities. SFAS 159 was adopted effective
January 1, 2008 and did not have a material impact on our
financial statements.
In December 2007, the FASBs Emerging Issues Task Force
(EITF) reached a consensus on
EITF 06-11
Accounting for Income Tax Benefits of Dividends on
Share Based Payment Awards.
The tax benefit received
on dividends associated with share-based awards that are charged
to retained earnings should be recorded in additional
paid-in-capital
(APIC) and included in the pool of excess tax
benefits available to absorb potential future tax deficiencies
on share-based payment awards. The consensus is effective for
the tax benefits of dividends declared in fiscal years beginning
after December 15, 2007. The Company has evaluated the
impact of the EITF and determined we will not recognize any tax
benefit or a related credit to additional paid in capital for
dividends on restricted stock charged to retained earnings. The
tax benefit and credit to the APIC pool will be recognized when
the tax deduction reduces income taxes payable after utilization
of our net operating loss carry forward.
In December 2007, the FASB issued SFAS No. 141R,
Business Combinations
(SFAS 141R) and SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements
(SFAS 160). SFAS 141R
requires most identifiable assets, liabilities, noncontrolling
interests and goodwill acquired in a business combination to be
recorded at full fair value. The Statement applies
to all business combinations, including combinations among
mutual entities and combinations by contract alone. Under
SFAS 141R, all business combinations will be accounted for
by applying the acquisition method. SFAS 141R is effective
for periods beginning on or after December 15, 2008.
SFAS 160 will require noncontrolling interests (previously
referred to as minority interests) to be treated as a separate
component of equity, not as a liability or other item outside of
permanent equity. The statement applies to the accounting for
noncontrolling interests and transactions with noncontrolling
interest holders in consolidated financial statements.
SFAS 160 is effective for periods beginning on or after
December 15, 2008 and will be applied prospectively to all
noncontrolling interests, including any that arose before the
effective date, except that comparative period information must
be recast to classify noncontrolling interests in equity,
F-16
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
attribute net income and other comprehensive income to
noncontrolling interests and provide other disclosures required
by SFAS 160.
In May 2008, the FASB issued SFAS No. 162,
The
Hierarchy of Generally Accepted Accounting Principles
(SFAS No. 162). SFAS No. 162
is intended to improve financial reporting by identifying a
consistent framework, or hierarchy, for selecting accounting
principles to be used in preparing financial statements of
nongovernmental entities that are presented in conformity with
generally accepted accounting principles in the United States of
America. SFAS No. 162 is effective for fiscal years
beginning after November 15, 2008. The Company is currently
evaluating the potential impact, if any, of the adoption of
SFAS No. 162 on our consolidated financial statements.
In March of 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities, an amendment of FASB Statement No. 133
(SFAS 161). SFAS 161 requires entities
to provide greater transparency about how and why the entity
uses derivative instruments, how the instruments and related
hedged items are accounted for under SFAS 133 and how the
instruments and related hedged items affect the financial
position, results of operations and cash flows of the entity.
SFAS 161 is effective for fiscal years beginning after
November 15, 2008. The principal impact to the Company will
be to require expanded disclosure regarding derivative
instruments.
|
|
(3)
|
Public
Offerings of Units by CELP and Certain Provisions of the
Partnership Agreement
|
|
|
(a)
|
Issuance
of Common Units
|
On April 9, 2008, the Partnership issued 3,333,334 common
units in private offering at $30.00 per unit, which represented
an approximate 7% discount from the market price. Net proceeds
from the issuance, including our general partner contribution
less expenses associated with the issuance, were approximately
$102.0 million.
On December 19, 2007, the Partnership issued 1,800,000
common units representing limited partner interests in the
Partnership at a price of $33.28 per unit for net proceeds of
$57.6 million. In addition, CEI made a general partner
contribution of $1.2 million in connection with the
issuance to maintain its 2% general partner interest.
|
|
(b)
|
Conversion
of Subordinated and Senior Subordinated Series C
Units
|
The subordination period for the Partnerships subordinated
units ended and the remaining 4,668,000 subordinated units
converted into common units representing limited partner
interests of the Partnership effective February 16, 2008.
We own all 4,668,000 of the units that converted.
The 12,829,650 senior subordinated series C units of the
Partnership issued June 29, 2006, also converted into
common units representing limited partner interests of the
Partnership effective February 16, 2008. The Company owns
6,414,830 of the senior subordinated series C units that
converted to common units.
|
|
(c)
|
Senior
Subordinated Series D Units
|
On March 23, 2007, the Partnership issued an aggregate of
3,875,340 senior subordinated series D units representing
limited partner interests of the Partnership in a private
offering. These senior subordinated series D units will
convert into common units representing limited partner interests
of the Partnership on March 23, 2009. The Partnership did
not make distributions of available cash from operating surplus,
as defined in the partnership agreement, of at least $0.62 per
unit on each outstanding common units for the quarter ending
December 31, 2008, therefore each senior subordinated
series D unit will convert into 1.05 common units.
Unless restricted by the terms of our credit facility, 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
F-17
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
common and subordinated unitholders and 2% to the general
partner, subject to the payment of incentive distributions.
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
$30.8 million, $24.8 million and $20.4 million
were earned by the Company for the years ended December 31,
2008, 2007 and 2006, respectively. The Partnership paid annual
per common unit distributions of $2.36, $2.28, and $2.13 for the
years ended December 31, 2008, 2007 and 2006, respectively.
See Note 7 for a description of the Partnerships
credit facilities which restrict the Partnerships ability
to make future distributions.
|
|
(e)
|
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 3(d) above.
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Income allocation for incentive distributions
|
|
$
|
30,772
|
|
|
$
|
24,802
|
|
|
$
|
20,422
|
|
Stock-based compensation attributable to CEIs stock
options and restricted shares
|
|
|
(4,665
|
)
|
|
|
(5,441
|
)
|
|
|
(3,545
|
)
|
2% general partner interest in net income (loss)
|
|
|
308
|
|
|
|
(109
|
)
|
|
|
(421
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner share of net income
|
|
$
|
26,415
|
|
|
$
|
19,252
|
|
|
$
|
16,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 income of $5.9 million for the year ended
December 31, 2008 respectively and a net loss of
$2.0 million and $7.4 million for the year ended
December 31, 2007 and 2006, respectively.
|
|
(4)
|
Significant
Asset Acquisitions, Impairments, and Dispositions, Including
Discontinued Operations
|
On June 29, 2006, the Partnership expanded its operations
in the north Texas area through the acquisition of the natural
gas gathering pipeline systems and related facilities of Chief
Holdings, LLC, or Chief in the Barnett Shale for
$475.3 million. The acquired systems, which we refer to in
conjunction with the NTP and other facilities in the area as the
north Texas assets, included gathering pipeline, a
125 MMcf/d
carbon dioxide treating plant and compression facilities with
26,000 horsepower.
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.
F-18
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
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 fixed gathering fees over the term. In addition
to the Devon agreement, approximately 60,000 additional net
acres were dedicated to the NTG Assets under agreements with
other producers.
In November 2008, the Partnership sold a contract right for firm
transportation capacity on a third party pipeline to an
unaffiliated third party for $20.0 million. The entire
amount of such proceeds is reflected in other income in the
consolidated statement of operations.
|
|
(b)
|
Long-Lived
Asset Impairments
|
Impairments of $25.6 million were recorded in the year
ended December 31, 2008 related to long-lived assets. The
impairments are comprised of:
|
|
|
|
|
$17.8 million related to the Blue Water gas processing
plant located in south Louisiana The impairment on
our 59.27% interest in the Blue Water gas processing plant was
recognized because the pipeline company which owns the offshore
Blue Water system and supplies gas to the Partnerships
Blue Water plant reversed the flow of the gas on its pipeline in
early January 2009 thereby removing access to all the gas
processed at the Blue Water plant from the Blue Water offshore
system. At this time, the Partnership has not found an
alternative source of new gas for the Blue Water plant so the
plant ceased operations in January 2009. An impairment of
$17.8 million was recognized for the carrying amount of the
plant in excess of the estimated fair value of the plant as of
December 31, 2008. The fair value of the Blue Water plant
was determined by using the market and cost approach for valuing
the plant. The income approach was not considered because the
plant is not in operation.
|
|
|
|
$4.1 million related to leasehold improvements
The Partnership had planned to relocate its corporate office
during 2008 to a larger office facility. The Partnership had
leased office space and was close to completing the renovation
of this office space when the global economic decline began
impacting our operations in October 2008. On December 31,
2008, the decision was made to cancel the new office lease and
not relocate the corporate offices from its existing office
location. The impairment relates to the leasehold improvements
on the office space for the cancelled lease.
|
|
|
|
$2.6 million related to the Arkoma gathering
system The impairment on the Arkoma gathering system
was recognized because the Partnership sold this asset in
February 2009 for approximately $11.0 million and the
carrying amount of the asset exceeded the sale price by
approximately $2.6 million.
|
|
|
|
$1.0 million related to unused treating
equipment The impairment relates to certain older
equipment in the Treating division that will not be used in the
Partnerships operations.
|
|
|
(c)
|
Discontinued
Operations
|
As part of the Partnerships strategy to increase liquidity
in response to the tightening financial markets, the Partnership
began marketing a non-strategic asset for sale in late September
2008. In early October 2008, the Partnership entered into an
agreement to sell its undivided 12.4% interest in the Seminole
gas processing plant to a third party for $85.0 million.
The transaction was completed on November 17, 2008 and the
Partnership recorded a $49.8 million pre-tax gain. The
pre-tax gain was adjusted for minority interest of
$32.4 million and taxes of approximately $6.4 million.
This asset was previously presented in the Partnerships
Treating segment.
F-19
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
The consolidated balance sheets at December 31, 2008 and
December 31, 2007 do not reflect the asset held for sale
due to the fact that the decision to dispose of the asset
occurred after December 31, 2007, and the sale was
completed prior to December 31, 2008.
The revenues and expenses related to the operations of the asset
held for sale have been segregated from continuing operations
and reported as discontinued operations for all periods.
Following are revenues, income from discontinued operations net
of minority interest and taxes and gain on discontinued
operations net of minority interest and taxes (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Treating Revenues
|
|
$
|
8,539
|
|
|
$
|
11,343
|
|
|
$
|
11,718
|
|
Income from discontinued operations net of minority interest and
taxes
|
|
$
|
1,266
|
|
|
$
|
1,532
|
|
|
$
|
1,970
|
|
Gain from discontinued operations net of minority interest and
taxes
|
|
$
|
10,964
|
|
|
$
|
|
|
|
$
|
|
|
As of December 31, 2006 and 2007, the carrying amount of
goodwill was considered recoverable. In the fourth quarter of
2008, the Partnership determined that the carrying amount of
goodwill attributable to the Midstream segment was impaired
because of the significant decline in its Midstream operations
due to the significant declines in natural gas and NGL prices
during the last half of 2008 coupled with the global economic
decline. The Partnership determined the estimated fair value of
the Midstream reporting unit by calculating the present value of
its estimated future cash flows. The Partnership determined the
implied fair value of goodwill associated with the Midstream
reporting unit by subtracting the estimated fair value of the
tangible assets and intangible assets associated with the
Midstream reporting unit from the estimated fair value of the
unit. The Partnership recognized an impairment loss of
$4.9 million in the Midstream segment for the year ended
December 31, 2008.
The Company recorded $0.8 million of goodwill at the date
of Partnership formation and this $0.8 million additional
goodwill was impaired at the corporate level bringing the total
impaired goodwill for CEI to $5.7 million for the period
ended December 31, 2008.
|
|
(6)
|
Investment
in Limited Partnerships and Note Receivable
|
The Partnership owns a majority interest in Crosstex Denton
County Joint Venture (CDC) and consolidates its investment
in CDC pursuant to FIN No. 46R. The Partnership
manages the business affairs of CDC. The other joint venture
partner (the CDC partner) is an unrelated third party who owns
and operates a natural gas field located in Denton County, Texas.
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 majority share of
distributable cash flow to repay the loan. The balance remaining
on the note of $0.4 million is included in current notes
receivable as of December 31, 2008.
F-20
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
As of December 31, 2008 and 2007, long-term debt consisted
of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Bank credit facility, interest based on Prime or LIBOR plus an
applicable margin, interest rates at December 31, 2008 and
2007 were 6.33% and 6.71%, respectively
|
|
$
|
784,000
|
|
|
$
|
734,000
|
|
Senior secured notes, weighted average interest rates at
December 31, 2008 and 2007 of 8.0% and 6.75%, respectively
|
|
|
479,706
|
|
|
|
489,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,263,706
|
|
|
|
1,223,118
|
|
Less current portion
|
|
|
(9,412
|
)
|
|
|
(9,412
|
)
|
|
|
|
|
|
|
|
|
|
Debt classified as long-term
|
|
$
|
1,254,294
|
|
|
$
|
1,213,706
|
|
|
|
|
|
|
|
|
|
|
Credit Facility.
In September 2007, the
Partnership increased borrowing capacity under the bank credit
facility to $1.185 billion. The bank credit facility
matures in June 2011. As of December 31, 2008,
$850.4 million was outstanding under the bank credit
facility, including $66.4 million of letters of credit,
leaving approximately $334.6 million available for future
borrowing.
Obligations under the bank 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 substantially all of its
subsidiaries, and rank
pari passu
in right of payment
with the senior secured notes. The credit agreement is
guaranteed by its material 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.
On November 7, 2008, the Partnership entered into the Fifth
Amendment and Consent (the Fifth Amendment) to its
credit facility with Bank of America, N.A., as administrative
agent, and the banks and other parties thereto (the Bank
Lending Group). The Fifth Amendment amended the agreement
governing the credit facility to, among other things,
(i) increase the maximum permitted leverage ratio the
Partnership must maintain for the fiscal quarters ending
December 31, 2008 through September 30, 2009,
(ii) lower the minimum interest coverage ratio the
Partnership must maintain for the fiscal quarter ending
December 31, 2008 and each fiscal quarter thereafter,
(iii) permit the Partnership to sell certain assets,
(iv) increase the interest rate the Partnership pays on the
obligations under the credit facility and (v) lowers the
maximum permitted leverage ratio the Partnership must maintain
if it or its subsidiaries incur unsecured note indebtedness.
Due to the continued decline in commodity prices and the
deterioration in the processing margins the Partnership
determined that there was a significant risk that the amended
terms negotiated in November 2008 would not be sufficient to
allow it to operate during 2009 without triggering a covenant
default under its bank facility and the senior secured note
agreement. On February 27, 2009, the Partnership entered
into the Sixth Amendment to the Fourth Amended and Restated
Credit Agreement and Consent (the Sixth Amendment)
to its credit facility with Bank Lending Group. Under the Sixth
Amendment, borrowings will bear interest at the
Partnerships option at the administrative agents
reference rate plus an applicable margin or London Interbank
Offering Rate (LIBOR) plus an applicable margin. The applicable
margins for the Partnerships interest rate and letter of
credit fees vary quarterly based on the Partnerships
leverage ratio as defined by the credit facility (the
Leverage Ratio being generally
F-21
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
computed as total funded debt to consolidated earnings before
interest, taxes, depreciation, amortization and certain other
non-cash charges) and are as follows beginning February 27,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank
|
|
|
|
|
|
Letter of
|
|
|
|
|
|
|
Reference Rate
|
|
|
LIBOR Rate
|
|
|
Credit
|
|
|
Commitment
|
|
Leverage Ratio
|
|
Advances(a)
|
|
|
Advances(b)
|
|
|
Fees(c)
|
|
|
Fees(d)
|
|
|
Greater than or equal to 5.00 to 1.00
|
|
|
3.00
|
%
|
|
|
4.00
|
%
|
|
|
4.00
|
%
|
|
|
0.50
|
%
|
Greater than or equal to 4.25 to 1.00 and less than 5.00 to 1.00
|
|
|
2.50
|
%
|
|
|
3.50
|
%
|
|
|
3.50
|
%
|
|
|
0.50
|
%
|
Greater than or equal to 3.75 to 1.00 and less than 4.25 to 1.00
|
|
|
2.25
|
%
|
|
|
3.25
|
%
|
|
|
3.25
|
%
|
|
|
0.50
|
%
|
Less than 3.75 to 1.00
|
|
|
1.75
|
%
|
|
|
2.75
|
%
|
|
|
2.75
|
%
|
|
|
0.50
|
%
|
|
|
|
(a)
|
|
The applicable margins for the bank reference rate advances
ranged from 0% to 0.25% under the bank credit facility prior to
the Fifth and Sixth Amendments. The applicable margin for the
bank reference rate advances was paid at the maximum rate of
2.00% under the Fifth Amendment from the November 7, 2008
until February 27, 2009.
|
|
(b)
|
|
The applicable margins for the LIBOR rate advances ranged from
1.00% to 1.75% under the bank credit facility prior to the Fifth
and Sixth Amendments. The applicable margin for the bank
reference rate advances was paid at the maximum rate of 3.00%
under the Fifth Amendment from the November 7, 2008 until
February 27, 2009.
|
|
(c)
|
|
The letter of credit fees ranged from 1.00% to 1.75% per annum
plus a fronting fee of 0.125% per annum under the bank credit
facility prior to the Fifth and Sixth Amendments. The letter of
credit fees were paid at the maximum rate of 3.00% per annum in
addition to the fronting fee under the Fifth Amendment from the
November 7, 2008 until February 27, 2009.
|
|
(d)
|
|
The commitment fees ranged from 0.20% to 0.375% per annum on the
unused amount of the credit facility under the bank credit
facility prior to the Fifth and Sixth Amendments. The commitment
fees were paid at the maximum rate of 0.50% per annum under the
Fifth Amendment from the November 7, 2008 until
February 27, 2009.
|
The Sixth Amendment also sets a floor for the LIBOR interest
rate of 2.75% per annum, which means, effective as of
February 27, 2009, borrowings under the bank credit
facility accrue interest at the rate of 6.75% based on the LIBOR
rate in effect on such date and the Partnerships current
leverage ratio. Based on the Partnerships forecasted
leverage ratios for 2009, it expects the applicable margins to
be at the high end of these ranges for interest rate and letter
of credit fees.
Pursuant to the Sixth Amendment, the Partnership must pay a
leverage fee if it does not prepay debt and permanently reduce
the banks commitments by the cumulative amounts of
$100.0 million on September 30, 2009,
$200.0 million on December 31, 2009, and
$300.0 million on March 31, 2010. If we fail to meet
any de-leveraging target, the Partnership must pay a leverage
fee on such date, equal to the product of the aggregate
commitments outstanding under its bank credit facility and
outstanding amount of the senior secured note agreement on such
date, and 1.0% on September 30, 2009, 1.0% on
December 31, 2009, and 2.0% on March 31, 2010. This
leverage fee will accrue on the applicable date, but not be
payable until the Partnership refinances its bank credit
facility.
Under the Sixth Amendment, the maximum Leverage Ratio (measured
quarterly on a rolling four-quarter basis) is as follows:
|
|
|
|
|
7.25 to 1.00 for the fiscal quarter ending March 31, 2009;
|
|
|
8.25 to 1.00 for the fiscal quarters ending June 30, 2009
and September 30, 2009;
|
|
|
8.50 to 1.00 for the fiscal quarter ending December 31,
2009;
|
|
|
8.00 to 1.00 for the fiscal quarter ending March 31, 2010;
|
|
|
6.65 to 1.00 for the fiscal quarter ending June 30, 2010;
|
|
|
5.25 to 1.00 for the fiscal quarter ending September 30,
2010;
|
F-22
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
|
|
5.00 to 1.00 for the fiscal quarter ending December 31, 2010
|
|
|
4.50 to 1.00 for the fiscal quarters ending March 31, 2011
thru March 31, 2012; and
|
|
|
4.25 to 1.00 for the fiscal quarters ending June 20, 2012
and thereafter.
|
The minimum cash interest coverage ratio (as defined in the
agreement, measured quarterly on a rolling four-quarter basis)
is as follows under the Sixth Amendment:
|
|
|
|
|
1.75 to 1.00 for the fiscal quarter ending March 31, 2009;
|
|
|
1.50 to 1.00 for the fiscal quarter ending June 30, 2009;
|
|
|
1.30 to 1.00 for the fiscal quarter ending September 30,
2009;
|
|
|
1.15 to 1.00 for the fiscal quarter ending December 31,
2009;
|
|
|
1.25 to 1.00 for the fiscal quarter ending March 31, 2010;
|
|
|
1.50 to 1.00 for the fiscal quarter ending June 30, 2010;
|
|
|
1.75 to 1.00 for any fiscal quarters ending September 30,
2010 and December 31, 2010;
|
|
|
2.50 to 1.00 for any fiscal quarters ending March 31, 2011,
and thereafter.
|
Under the Sixth Amendment, no quarterly distributions may be
paid to unitholders of the Partnership unless the PIK notes have
been repaid and if the Leverage Ratio is less than 4.25 to 1.00.
If the Leverage Ratio is between 4.00 to 1.00 and 4.25 to 1.00,
the Partnership may make the minimum quarterly distribution of
up to $0.25 per unit if the PIK notes have been repaid. If the
Leverage Ratio is less than 4.00 to 1.00, the Partnership may
make quarterly distributions to unitholders from available cash
as provided by the partnership agreement if the PIK notes have
been repaid. The PIK notes are due six months after the earlier
of the refinancing or maturity of its bank credit facility.
Based on the Partnerships forecasted leverage ratios for
2009 and the Partnerships near term ability to refinance
its bank credit facility, it does not anticipate making
quarterly distributions in 2009 other than the distribution paid
in February 2009 related to fourth quarter 2008 operating
results. The Partnership will not be able to make distributions
to its unitholders in future periods if its leverage ratio does
not improve.
The Sixth Amendment also limits the Partnerships annual
capital expenditures (excluding maintenance capital
expenditures) to $120.0 million in 2009 and
$75.0 million in 2010 and each year thereafter (with unused
amounts in any year being carried forward to the next year). It
is unlikely that we will be able to make any acquisitions based
on the terms of our credit facility and the current condition of
the capital markets because we may only use a portion of the
proceeds from the incurrence of unsecured debt and the issuance
of equity to make such acquisitions.
The Sixth Amendment also eliminated the accordion in the
Partnerships bank credit facility, which previously had
permitted it to increase commitments thereunder by certain
amounts if any bank was willing to undertake such commitment
increase.
The Sixth Amendment also revised the terms for mandatory
repayment of outstanding indebtedness from asset sales and
proceeds from incurrence of unsecured debt and equity issuances.
Proceeds from debt issuances and from equity issuances not
required to prepay indebtedness are considered to be
Excess Proceeds under the amended bank credit
agreement. The Partnership may retain all Excess Proceeds. The
following table sets forth the amended prepayment terms:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of Net Proceeds
|
|
|
% of Net Proceeds
|
|
|
% of Net Proceeds
|
|
|
|
from Asset Sales
|
|
|
from Debt Issuances
|
|
|
from Equity Issuance
|
|
|
|
Required for
|
|
|
Required for
|
|
|
Required for
|
|
Leverage Ratio*
|
|
Prepayment
|
|
|
Prepayment
|
|
|
Prepayment
|
|
|
Greater than or equal to 4.50
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
50
|
%
|
Greater or equal to 3.50 and Less Than 4.50
|
|
|
100
|
%
|
|
|
50
|
%
|
|
|
25
|
%
|
Less than 3.50
|
|
|
100
|
%
|
|
|
0
|
%
|
|
|
0
|
%
|
|
|
|
*
|
|
The Leverage Ratio is to be adjusted to give effect to proceeds
from debt or equity issuance and the use of such proceeds for
each proportional level of Leverage Ratio.
|
F-23
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
The prepayments are to be applied pro rata based on total debt
(including letter of credit obligations) outstanding under the
bank credit agreement and the total debt outstanding under the
note agreement described below. Any prepayments of advances on
the bank credit facility from proceeds from asset sales, debt or
equity issuances will permanently reduce the borrowing capacity
or commitment under the facility in an amount equal to 100% of
the amount of the prepayment. Any such commitment reduction will
not reduce the banks $300.0 million commitment to
issue letters of credit.
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;
|
|
|
|
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;
|
|
|
|
bankruptcy or other insolvency events;
|
|
|
|
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.
|
If an event of default relating to bankruptcy or other
insolvency events occurs, all indebtedness under the
Partnerships bank credit facility will immediately become
due and payable. If any other event of default exists under the
bank credit facility, the lenders may accelerate the maturity of
the obligations under the bank credit facility and exercise
other rights and remedies.
The Partnership is subject to interest rate risk on its credit
facility and has entered into interest rate swaps to reduce this
risk. See Note 13 to the financial statements for a
discussion of interest rate swaps.
F-24
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
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, pursuant to which it issued
the following senior secured notes (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
|
|
|
|
Month Issued
|
|
Amount
|
|
|
Rate(1)
|
|
|
Maturity
|
|
|
Principal Payment Terms
|
|
June 2003(2)
|
|
$
|
30,000
|
|
|
|
9.45
|
%
|
|
|
7 years
|
|
|
Quarterly payments of $1,765
from June 2006-June 2010
|
July 2003(2)
|
|
|
10,000
|
|
|
|
9.38
|
%
|
|
|
7 years
|
|
|
Quarterly payments of $588
from July 2006-July 2010
|
June 2004
|
|
|
75,000
|
|
|
|
9.46
|
%
|
|
|
10 years
|
|
|
Annual payments of $15,000
from July 2010-July 2014
|
November 2005
|
|
|
85,000
|
|
|
|
8.73
|
%
|
|
|
10 years
|
|
|
Annual payments of $17,000
from November 2010-December 2014
|
March 2006
|
|
|
60,000
|
|
|
|
8.82
|
%
|
|
|
10 years
|
|
|
Annual payments of $12,000
from March 2012-March 2016
|
July 2006
|
|
|
245,000
|
|
|
|
8.46
|
%
|
|
|
10 years
|
|
|
Annual payments of $49,000
from July 2012-July 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Issued
|
|
|
505,000
|
|
|
|
|
|
|
|
|
|
|
|
Principal repaid
|
|
|
(25,294
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
$
|
479,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Interest rates have been adjusted to give effect to the 2%
interest rate increase under the February 27, 2009
amendment described below.
|
|
(2)
|
|
Principle repayments were $19.4 million and
$5.9 million on the June 2003 and July 2003 notes,
respectively.
|
On November 7, 2008, the Partnership amended its senior
secured note agreement governing its senior secured notes to,
among other things, (i) modify the maximum permitted
leverage ratio and lower the minimum interest coverage ratio it
must maintain consistent with the ratios under the Fifth
Amendment to the bank credit facility, (ii) permit it to
sell certain assets and (iii) increase the interest rate it
pays on the senior secured notes. The interest rate the
Partnership paid on the senior secured notes increased by 1.25%
for the fourth quarter of 2008 due to this amendment.
The covenants and terms of default for the senior secured notes
are substantially the same as the covenants and default terms
under the bank credit facility, and therefore the agreement
governing the senior secured notes also required amendment in
2009. On February 27, 2009, the partnership amended its
senior note agreement to (i) increase the maximum permitted
leverage ratio and to lower the minimum interest coverage ratio
it must maintain consistent with the ratios under the Sixth
Amendment to the bank credit facility, (ii) revise the
mandatory prepayment terms consistent with the terms under the
Sixth Amendment to the bank credit facility, (iii) increase
the interest rate it pays on the senior secured notes and
(iv) provide for the payment of a leverage fee consistent
with the terms of the bank credit facility. Commencing
February 27, 2009 the interest rate the Partnership pays in
cash on all of the senior secured notes will increase by 2.25%
per annum over the comparative interest rates under the senior
note agreements prior to the November and February amendments.
As a result of this rate increase, the weighted average interest
rate on the outstanding balance on the senior secured notes is
approximately 9.25% as of February 2009.
Under the amended senior secured note agreement, the senior
secured notes will accrue additional interest of 1.25% per annum
of the senior secured notes (the PIK notes) in the
form of an increase in the principal amount unless the
Partnerships leverage ratio is less than 4.25 to 1.00 as
of the end of any fiscal quarter. All PIK notes will
F-25
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
be payable six months after the maturity of its bank credit
facility, which is currently scheduled to mature in June 2011,
or six months after refinancing of such indebtedness if prior to
the maturity date.
Per the terms of the amended senior note agreement, commencing
on the date the Partnership refinances its bank credit facility,
the interest rate payable in cash on its senior secured notes
will increase by 1.25% per annum for any quarter if its leverage
ratio as of the most recently ended fiscal quarter was greater
than or equal to 4.25 to 1.00. In addition, commencing on
June 30, 2012, the interest rate payable in cash on the
Partnerships senior secured notes will increase by 0.50%
per annum for any quarter if its leverage as of the most
recently ended fiscal quarter was greater than or equal to 4.00
to 1.00, but this incremental interest will not accrue if the
Partnership is paying the incremental 1.25% per annum of
interest described in the preceding sentence.
These notes represent the Partnerships senior secured
obligations and will rank
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 equity
interests in substantially all of the Partnerships
subsidiaries. The senior secured notes are guaranteed by the
Partnerships material subsidiaries.
The 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 senior secured note agreement.
The senior secured notes issued 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.
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 senior secured note agreement relating to the notes contains
substantially the same covenants and events of default as the
Partnerships bank credit facility.
The Partnership was in compliance with all debt covenants at
December 31, 2008 and 2007 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 senior secured note agreement, the lenders under the
Partnerships 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 Partnerships
bank credit facility and the Partnerships purchasers of
the senior secured notes. This agreement specifies various
rights and obligations of lenders under the bank credit
facility, holders of its senior secured notes and the other
parties thereto in respect of the collateral securing the
Partnerships obligations under the Partnerships bank
credit facility and the senior secured note agreement. On
February 27, 2009, the holders of the Partnerships
senior secured notes and a majority of the banks under its bank
credit facility entered into an amendment to the Intercreditor
and Collateral Agency Agreement, which provides that the PIK
notes and certain treasury management obligations will be
secured by the collateral for its bank credit facility and the
senior secured notes, but only paid with proceeds of collateral
after obligations under its bank credit facility and the senior
secured notes are paid in full.
F-26
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
Maturities:
Maturities for the long-term debt
as of December 31, 2008 are as follows (in thousands):
|
|
|
|
|
2009
|
|
$
|
9,412
|
|
2010
|
|
|
20,294
|
|
2011
|
|
|
816,000
|
|
2012
|
|
|
93,000
|
|
2013
|
|
|
93,000
|
|
Thereafter
|
|
|
232,000
|
|
|
|
(8)
|
Other
Long-Term Liabilities
|
The Partnership entered into 9 and
10-year
capital leases for certain compressor equipment. Assets under
capital leases are summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Compressor equipment
|
|
$
|
28,890
|
|
|
$
|
4,011
|
|
Less: Accumulated amortization
|
|
|
(1,523
|
)
|
|
|
(29
|
)
|
|
|
|
|
|
|
|
|
|
Net assets under capital lease
|
|
$
|
27,367
|
|
|
$
|
3,982
|
|
|
|
|
|
|
|
|
|
|
The following are the minimum lease payments to be made in each
of the following years indicated for the capital lease in effect
as of December 31, 2008 (in thousands):
|
|
|
|
|
Fiscal Year
|
|
|
|
|
2009 through 2013
|
|
$
|
16,150
|
|
Thereafter
|
|
|
16,691
|
|
Less: Interest
|
|
|
(5,184
|
)
|
|
|
|
|
|
Net minimum lease payments under capital lease
|
|
|
27,657
|
|
Less: Current portion of net minimum lease payments
|
|
|
(3,189
|
)
|
|
|
|
|
|
Long-term portion of net minimum lease payments
|
|
$
|
24,468
|
|
|
|
|
|
|
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).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Current tax provision
|
|
$
|
2,593
|
|
|
$
|
711
|
|
|
$
|
(268
|
)
|
Deferred tax provision
|
|
|
7,022
|
|
|
|
10,338
|
|
|
|
11,386
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
9,615
|
|
|
$
|
11,049
|
|
|
$
|
11,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-27
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
A reconciliation of the provision for income taxes is as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Federal income tax at statutory rate (35)%
|
|
$
|
11,847
|
|
|
$
|
8,129
|
|
|
$
|
9,591
|
|
State income taxes, net
|
|
|
1,329
|
|
|
|
682
|
|
|
|
567
|
|
Tax basis adjustment in Partnership related to issuance of
common units
|
|
|
(5,209
|
)
|
|
|
2,118
|
|
|
|
1,151
|
|
Non-deductible expenses
|
|
|
510
|
|
|
|
144
|
|
|
|
88
|
|
Other
|
|
|
1,138
|
|
|
|
(24
|
)
|
|
|
(279
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax provision
|
|
$
|
9,615
|
|
|
$
|
11,049
|
|
|
$
|
11,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the components of the income tax
provision (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
From continuing operations
|
|
$
|
2,410
|
|
|
$
|
10,147
|
|
|
$
|
9.958
|
|
From discontinued operations
|
|
|
7,205
|
|
|
|
902
|
|
|
|
1,160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tax provision
|
|
$
|
9,615
|
|
|
$
|
11,049
|
|
|
$
|
11,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The principal components of the Companys net deferred tax
liability are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carryforward current
|
|
$
|
41
|
|
|
$
|
4
|
|
Net operating loss carryforward non-current
|
|
|
40,310
|
|
|
|
35,229
|
|
Investment in the Partnership
|
|
|
3,892
|
|
|
|
9,101
|
|
Other comprehensive income
|
|
|
|
|
|
|
3,009
|
|
Other
|
|
|
41
|
|
|
|
140
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,284
|
|
|
|
47,483
|
|
Less: valuation allowance
|
|
|
(3,892
|
)
|
|
|
(9,101
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
40,392
|
|
|
|
38,382
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax liabilities:
|
|
|
|
|
|
|
|
|
Property, plant, equipment, and intangible assets
current
|
|
|
(501
|
)
|
|
|
(501
|
)
|
Property, plant, equipment, and intangible assets
non-current
|
|
|
(121,457
|
)
|
|
|
(109,820
|
)
|
Other comprehensive income
|
|
|
(367
|
)
|
|
|
|
|
Other
|
|
|
(524
|
)
|
|
|
(121
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(122,849
|
)
|
|
|
(110,442
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(82,457
|
)
|
|
$
|
(72,060
|
)
|
|
|
|
|
|
|
|
|
|
At December 31, 2008, the Company had a net operating loss
carryforward of approximately $108.6 million that expires
from 2021 through 2028. The Company also has various state net
operating loss carryforwards of approximately $46.4 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, the
F-28
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
Company expects to have future taxable income from its
investment in the Partnership, generated by the remedial
allocations of income among the unitholders and the income
generated by operations.
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 $3.9 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
deferred tax asset and the related valuation allowance decreased
$6.1 million during the first quarter of 2008 due to the
conversion of the Partnerships senior subordinated
series C units to common units and increased
$0.9 million during the second quarter for the issuance of
Partnership common units for a net decrease of $5.2 million
from 2007 to 2008.
Effective as of January 1, 2007, the Company is now subject
to the franchise margin tax enacted by the state of Texas on
May 1, 2006. The new tax law had a $0.6 million impact
on the Companys net deferred tax liability.
The Company adopted the provisions of FASB Interpretation
No. 48,
Accounting for Uncertainty in Income Taxes,
on January 1, 2007. A reconciliation of the beginning
and ending amount of the unrecognized tax benefits is as follows
(In thousands):
|
|
|
|
|
Balance as of December 31, 2007
|
|
$
|
|
|
Increases related to prior year tax positions
|
|
|
569
|
|
Increases related to current year tax positions
|
|
|
451
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
$
|
1,020
|
|
|
|
|
|
|
Unrecognized tax benefits of $1.0 million, if recognized,
would affect the effective tax rate. We do not expect any
material change in the balance of our unrecognized tax benefits
over the next twelve months. In the event interest or penalties
are incurred with respect to income tax matters, our policy will
be to include such items in income tax expense. At
December 31, 2008, tax years 2001 through 2008 remain
subject to examination by the Internal Revenue Service and
applicable states.
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, 2008, 2007 and 2006
were $3.4 million, $1.6 million and $1.1 million,
respectively.
|
|
(11)
|
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 4,800,000 common unit
options and restricted units. The plan is administered by the
compensation committee of the Partnerships board of
directors. The units issued upon exercise or vesting are newly
issued units.
|
|
(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.
F-29
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
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 in 2006, 2007 and 2008 generally cliff vest after
three years of service.
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, 2008 is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Grant-Date
|
|
Crosstex Energy, L.P. Restricted Units:
|
|
Units
|
|
|
Fair Value
|
|
|
Non-vested, beginning of period
|
|
|
504,518
|
|
|
$
|
34.29
|
|
Granted
|
|
|
432,354
|
|
|
|
29.60
|
|
Vested*
|
|
|
(204,033
|
)
|
|
|
33.40
|
|
Forfeited
|
|
|
(34,273
|
)
|
|
|
29.69
|
|
Reduced estimated performance units
|
|
|
(154,499
|
)
|
|
|
31.66
|
|
|
|
|
|
|
|
|
|
|
Non-vested, end of period
|
|
|
544,067
|
|
|
$
|
31.90
|
|
|
|
|
|
|
|
|
|
|
Aggregate intrinsic value, end of period (in thousands)
|
|
$
|
2,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Vested units include 51,214 units withheld for payroll
taxes paid on behalf of employees.
|
The Partnerships executive officers were granted
restricted units during 2008 and 2007, the number of which may
increase or decrease based on the accomplishment of certain
performance targets based on the Partnerships average
growth rate (defined as the percentage increase or decrease in
distributable cash flow per common unit over a three-year
period). The minimum number of restricted units for all
executives of 52,795 and 14,319 for 2008 and 2007, respectively,
are included in the non-vested, end of period units line in the
table above. Target performance grants were previously included
in the restricted units granted and were included in share-based
compensation as it appeared probable that target thresholds
would be achieved. However, during the last half of 2008, the
Partnerships assets were negatively impacted by hurricanes
Gustav and Ike. During this same period, the Partnership has
also been negatively impacted by the declines in natural gas and
NGL prices coupled with the global economic decline and
tightening of capital markets. The impact of these events was
significant enough to make the achievement of target performance
goals less than probable. Therefore, an expense of
$0.7 million previously recorded for target
performance-based restricted units has been reversed and is
shown as a reduction to stock-based compensation expense and a
reduction in the number of estimated performance units
outstanding of 154,499 units in the year ended
December 31, 2008. All performance-based awards greater
than the minimum performance grant levels will be subject to
reevaluation and adjustment until the restricted units vest. The
performance-based restricted units are included in the current
share-based compensation calculations as required by
SFAS No. 123(R) when it is deemed probable of
achieving the performance criteria.
F-30
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
A summary of the restricted units aggregate intrinsic value
(market value at vesting date) and fair value (market value at
date of grant) of units vested during the years ended
December 31, 2008 and 2007 are provided below (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
Crosstex Energy, L.P. Restricted Units:
|
|
2008
|
|
|
2007
|
|
|
Aggregate intrinsic value of units vested
|
|
$
|
5,907
|
|
|
$
|
1,342
|
|
Fair value of units vested
|
|
$
|
6,815
|
|
|
$
|
888
|
|
As of December 31, 2008, there was $7.8 million of
unrecognized compensation cost related to non-vested restricted
units. That cost is expected to be recognized over a
weighted-average period of 2.5 years.
|
|
(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 to estimate expected forfeiture rates. 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 expected term of
the unit option is based on the U.S. Treasury yield curve
in effect at the time of the grant. The Partnership used the
simplified method to calculate the expected term.
Unit options are generally awarded with an exercise price equal
to the market price of the Partnerships common units at
the date of grant. The unit options granted in 2008, 2007 and
2006 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 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
Crosstex Energy, L.P. Unit Options Granted:
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Weighted average distribution yield
|
|
|
7.15
|
%
|
|
|
5.75
|
%
|
|
|
5.5
|
%
|
Weighted average expected volatility
|
|
|
30.0
|
%
|
|
|
32.0
|
%
|
|
|
33.0
|
%
|
Weighted average risk free interest rate
|
|
|
1.81
|
%
|
|
|
4.39
|
%
|
|
|
4.80
|
%
|
Weighted average expected life
|
|
|
6 years
|
|
|
|
6 years
|
|
|
|
6 years
|
|
Weighted average contractual life
|
|
|
10 years
|
|
|
|
10 years
|
|
|
|
10 years
|
|
Weighted average of fair value of unit options granted
|
|
$
|
3.48
|
|
|
$
|
6.73
|
|
|
$
|
7.45
|
|
F-31
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
A summary of the unit option activity for the years ended
December 31, 2008, 2007 and 2006 is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
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
|
|
|
1,107,309
|
|
|
$
|
29.65
|
|
|
|
926,156
|
|
|
$
|
25.70
|
|
|
|
1,039,832
|
|
|
$
|
18.88
|
|
Granted (b)
|
|
|
402,185
|
|
|
|
31.58
|
|
|
|
347,599
|
|
|
|
37.29
|
|
|
|
286,403
|
|
|
|
34.62
|
|
Exercised
|
|
|
(56,678
|
)
|
|
|
14.16
|
|
|
|
(90,032
|
)
|
|
|
18.20
|
|
|
|
(304,936
|
)
|
|
|
11.19
|
|
Forfeited
|
|
|
(90,208
|
)
|
|
|
31.29
|
|
|
|
(67,688
|
)
|
|
|
29.84
|
|
|
|
(95,143
|
)
|
|
|
24.56
|
|
Expired
|
|
|
(58,414
|
)
|
|
|
32.93
|
|
|
|
(8,726
|
)
|
|
|
31.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
1,304,194
|
|
|
$
|
30.64
|
|
|
|
1,107,309
|
|
|
$
|
29.65
|
|
|
|
926,156
|
|
|
$
|
25.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at end of period
|
|
|
540,782
|
|
|
$
|
29.12
|
|
|
|
281,973
|
|
|
$
|
28.05
|
|
|
|
121,131
|
|
|
$
|
23.58
|
|
Weighted average contractual term (years) end of period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding
|
|
|
7.4
|
|
|
|
|
|
|
|
7.6
|
|
|
|
|
|
|
|
7.8
|
|
|
|
|
|
Options exercisable
|
|
|
6.5
|
|
|
|
|
|
|
|
7.1
|
|
|
|
|
|
|
|
7.5
|
|
|
|
|
|
Aggregate intrinsic value end of period (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding
|
|
$
|
(a
|
)
|
|
|
|
|
|
$
|
4,681
|
|
|
|
|
|
|
$
|
13,107
|
|
|
|
|
|
Options exercisable
|
|
$
|
(a
|
)
|
|
|
|
|
|
$
|
1,322
|
|
|
|
|
|
|
$
|
1,970
|
|
|
|
|
|
|
|
|
(a)
|
|
Exercise price on all outstanding options exceeds current market
price.
|
|
(b)
|
|
No options were granted with an exercise price less than or
equal to market value at grant during 2008, 2007 and 2006.
|
A summary of the unit options intrinsic value exercised (market
value in excess of exercise price at date of exercise) and fair
value (value per Black-Scholes option pricing model at date of
grant) of units vested during the years ended December 31,
2008 and 2007 are provided below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
Crosstex Energy, L.P. Unit Options:
|
|
2008
|
|
|
2007
|
|
|
Intrinsic value of units options exercised
|
|
$
|
746
|
|
|
$
|
1,675
|
|
Fair value of units vested
|
|
$
|
279
|
|
|
$
|
197
|
|
As of December 31, 2008, there was $1.6 million of
unrecognized compensation cost related to non-vested unit
options. That cost is expected to be recognized over a
weighted-average period of 1.5 years.
|
|
(d)
|
Crosstex
Energy, Inc.s Restricted Stock and Option
Plan
|
The Crosstex Energy, Inc. long-term incentive plan provides for
the award of stock options and restricted stock (collectively,
Awards) for up to 4,590,000 shares of Crosstex
Energy, Inc.s common stock. As of January 1, 2009,
approximately 626,000 shares remained available under the
long-term incentive plan for future issuance to participants. A
participant may not receive in any calendar year options
relating to more than 100,000 shares of common stock. The
maximum number of shares set forth above are subject to
appropriate adjustment in the event of a recapitalization of the
capital structure of Crosstex Energy, Inc. or reorganization of
Crosstex Energy, Inc. Shares of common stock underlying Awards
that are forfeited, terminated or expire unexercised become
immediately available for additional Awards under the long-term
incentive plan.
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. CEIs restricted stock
granted in 2006, 2007 and 2008 generally cliff vest
F-32
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
after three years of service. A summary of the restricted stock,
which activity for the year ended December 31, 2008, is
provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Grant-Date Fair
|
|
Crosstex Energy, Inc. Restricted Shares:
|
|
Shares
|
|
|
Value
|
|
|
Non-vested, beginning of period
|
|
|
860,275
|
|
|
$
|
21.16
|
|
Granted
|
|
|
361,796
|
|
|
|
32.62
|
|
Vested*
|
|
|
(401,004
|
)
|
|
|
18.41
|
|
Forfeited
|
|
|
(63,716
|
)
|
|
|
21.86
|
|
Reduced estimated performance shares
|
|
|
(153,038
|
)
|
|
|
32.10
|
|
|
|
|
|
|
|
|
|
|
Non-vested, end of period
|
|
|
604,313
|
|
|
$
|
27.62
|
|
|
|
|
|
|
|
|
|
|
Aggregate intrinsic value, end of period (in thousands)
|
|
$
|
2,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Vested shares include 116,118 shares withheld for payroll
taxes paid on behalf of employees.
|
The Partnerships executive officers were granted
restricted shares during 2008 and 2007, the number of which may
increase or decrease based on the accomplishment of certain
performance targets based on the Partnerships average
growth rate (defined as the percentage increase or decrease in
distributable cash flow per common unit over a three-year
period). The minimum number of restricted shares for all
executives of 50,090 and 16,536 for 2008 and 2007, respectively,
are included in the non-vested, end of period shares line in the
table above. Target performance grants were previously included
in the restricted units granted and were included in share-based
compensation as it appeared probable that target thresholds
would be achieved. However, during the last half of 2008, the
Partnerships assets were negatively impacted by hurricanes
Gustav and Ike. During this same period, the Partnership has
also been negatively impacted by the declines in natural gas and
NGL prices coupled with the global economic decline and
tightening of capital markets. The impact of these events was
significant enough to make the achievement of target performance
goals less than probable. Therefore, an expense of
$0.7 million previously recorded for target
performance-based restricted shares has been reversed and is
shown as a reduction to stock-based compensation expense and a
reduction in the number of estimated performance shares
outstanding of 153,038 shares in the year ended
December 31, 2008. All performance-based awards greater
than the minimum performance grant levels will be subject to
reevaluation and adjustment until the restricted shares vest.
The performance-based restricted shares are included in the
current share-based compensation calculations as required by
SFAS No. 123(R) when it is deemed probable of
achieving the performance criteria.
A summary of the restricted shares aggregate intrinsic
value (market value at vesting date) and fair value (market
value at date of grant) of shares vested during the years ended
December 31, 2008 and 2007 are provided below (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
Crosstex Energy, Inc. Restricted Shares:
|
|
2008
|
|
|
2007
|
|
|
Aggregate intrinsic value of shares vested
|
|
$
|
13,493
|
|
|
$
|
3,067
|
|
Fair value of shares vested
|
|
$
|
7,382
|
|
|
$
|
1,275
|
|
Restricted shares in CEI totaling 244,578 and 186,840 were
issued to officers and employees of the Partnership with a
weighted-average grant-date fair value of $29.58 and $25.05 per
share in 2007 and 2006, respectively. As of December 31,
2008 and 2007 there was $7.2 million and $7.0 million,
respectively, of unrecognized compensation costs related to
non-vested CEI restricted stock. The cost is expected to be
recognized over a weighted average period of 2.4 years.
F-33
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
CEI
Stock Options
No CEI stock options were granted to any officers or employees
of the Partnership during 2008, 2007 and 2006.
A summary of the stock option activity for the years ended
December 31, 2008, 2007 and 2006, is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
Number
|
|
|
Weighted Average
|
|
|
Number
|
|
|
Weighted Average
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
of Shares
|
|
|
Exercise Price
|
|
|
of Shares
|
|
|
Exercise Price
|
|
|
Number of Shares(a)
|
|
|
Exercise Price(a)
|
|
|
|
|
|
Outstanding, beginning of period
|
|
|
105,000
|
|
|
$
|
8.45
|
|
|
|
120,000
|
|
|
$
|
8.21
|
|
|
|
159,933
|
|
|
$
|
9.53
|
|
|
|
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cancelled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(37,500
|
)
|
|
|
6.50
|
|
|
|
(15,000
|
)
|
|
|
6.50
|
|
|
|
(9,933
|
)
|
|
|
12.58
|
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(30,000
|
)
|
|
|
13.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period
|
|
|
67,500
|
|
|
$
|
9.54
|
|
|
|
105,000
|
|
|
$
|
8.45
|
|
|
|
120,000
|
|
|
$
|
8.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at end of period
|
|
|
22,500
|
|
|
$
|
11.05
|
|
|
|
37,500
|
|
|
$
|
7.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Adjusted to reflect three-for-one stock split.
|
A summary of the stock options intrinsic value exercised (market
value in excess of exercise price at date of exercise) and fair
value (value per Black-Scholes option pricing model at date of
grant) of units vested during the years ended December 31,
2008 and 2007 is provided below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
Crosstex Energy, Inc. Stock Options:
|
|
2008
|
|
|
2007
|
|
|
Intrinsic value of stock options exercised
|
|
$
|
1,089
|
|
|
$
|
366
|
|
Fair value of shares vested
|
|
$
|
38
|
|
|
$
|
66
|
|
No stock options were granted, cancelled, exercised or forfeited
by officers and employees of the Partnership during the years
ended December 31, 2008, 2007 and 2006.
As of December 31, 2008, there was $15,931 of unrecognized
compensation costs related to non-vested CEI stock options. The
cost is expected to be recognized over a weighted average period
of 0.7 years.
|
|
(12)
|
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).
F-34
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Value
|
|
|
Value
|
|
|
Value
|
|
|
Value
|
|
|
Cash and cash equivalents
|
|
$
|
13,959
|
|
|
$
|
13,959
|
|
|
$
|
7,853
|
|
|
$
|
7,853
|
|
Trade accounts receivable and accrued revenues
|
|
|
341,853
|
|
|
|
341,853
|
|
|
|
489,889
|
|
|
|
489,889
|
|
Fair value of derivative assets
|
|
|
31,794
|
|
|
|
31,794
|
|
|
|
9,926
|
|
|
|
9,926
|
|
Note receivable
|
|
|
375
|
|
|
|
375
|
|
|
|
1,026
|
|
|
|
1,026
|
|
Accounts payable, drafts payable and accrued gas purchases
|
|
|
315,622
|
|
|
|
315,622
|
|
|
|
469,951
|
|
|
|
469,951
|
|
Current portion, long-term debt
|
|
|
9,412
|
|
|
|
9,412
|
|
|
|
9,412
|
|
|
|
9,412
|
|
Long-term debt
|
|
|
1,254,294
|
|
|
|
1,148,939
|
|
|
|
1,213,706
|
|
|
|
1,225,087
|
|
Fair value of derivative liabilities
|
|
|
51,281
|
|
|
|
51,281
|
|
|
|
30,492
|
|
|
|
30,492
|
|
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 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
$784.0 million and $734.0 million as of
December 31, 2008 and 2007, 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, 2008, the Partnership also had borrowings
totaling $479.7 million under senior secured notes with a
weighted average interest rate of 8.0%. The fair value of these
borrowings as of December 31, 2008 and 2007 were adjusted
reflect to current market interest rate for such borrowings as
of December 31, 2008 and 2007, respectively.
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.
Interest
Rate Swaps
The Partnership is subject to interest rate risk on its credit
facility and has entered into interest rate swaps to reduce this
risk.
The Partnership entered into eight interest rate swaps prior to
September 2008 as shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade Date
|
|
Term
|
|
|
From
|
|
|
To
|
|
|
Rate
|
|
|
Notional Amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
November 14, 2006
|
|
|
4 years
|
|
|
|
November 28, 2006
|
|
|
|
November 30, 2010
|
|
|
|
4.3800
|
%
|
|
$
|
50,000
|
|
March 13, 2007
|
|
|
4 years
|
|
|
|
March 30, 2007
|
|
|
|
March 31, 2011
|
|
|
|
4.3950
|
%
|
|
|
50,000
|
|
July 30, 2007
|
|
|
4 years
|
|
|
|
August 30, 2007
|
|
|
|
August 30, 2011
|
|
|
|
4.6850
|
%
|
|
|
100,000
|
|
August 6, 2007
|
|
|
4 years
|
|
|
|
August 30, 2007
|
|
|
|
August 31, 2011
|
|
|
|
4.6150
|
%
|
|
|
50,000
|
|
August 9, 2007
|
|
|
3 years
|
|
|
|
November 30, 2007
|
|
|
|
November 30, 2010
|
|
|
|
4.4350
|
%
|
|
|
50,000
|
|
August 16, 2007*
|
|
|
4 years
|
|
|
|
October 31, 2007
|
|
|
|
October 31, 2011
|
|
|
|
4.4875
|
%
|
|
|
100,000
|
|
September 5, 2007
|
|
|
4 years
|
|
|
|
September 28, 2007
|
|
|
|
September 28, 2011
|
|
|
|
4.4900
|
%
|
|
|
50,000
|
|
January 22, 2008
|
|
|
1 year
|
|
|
|
January 31, 2008
|
|
|
|
January 31, 2009
|
|
|
|
2.8300
|
%
|
|
|
100,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
550,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-35
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
*
|
|
Amended swap is a combination of two swaps that each had a
notional amount of $50.0 million with the same original term.
|
Each swap fixes the three month LIBOR rate, prior to credit
margin, at the indicated rates for the specified amounts of
related debt outstanding over the term of each swap agreement.
In January 2008, the Partnership amended existing swaps with the
counterparties in order to reduce the fixed rates and extend the
terms of the existing swaps by one year. The Partnership also
entered into one new swap in January 2008.
The Partnership had previously elected to designate all interest
rate swaps (except the November 2006 swap) as cash flow hedges
for FAS 133 accounting treatment. Accordingly, unrealized
gains and losses relating to the designated interest rate swaps
were recorded in accumulated other comprehensive income.
Immediately prior to the January 2008 amendments, these swaps
were de-designated as cash flow hedges. The unrealized loss in
accumulated other comprehensive income of $17.0 million at
the de-designation dates is being reclassified to earnings over
the remaining original terms of the swaps using the effective
interest method. The related loss reclassified to earnings and
included in (gain) loss on derivatives during the year ended
December 31, 2008 is $6.4 million.
The Partnership elected not to designate any of the amended
swaps or the new swap entered into in January 2008 as cash flow
hedges for FAS 133 treatment. Accordingly, unrealized gains
and losses are recorded through the consolidated statement of
operations in (gain) loss on derivatives over the period hedged.
In September 2008, the Partnership entered into four additional
interest rate swaps. The effect of the new interest rate swaps
was to convert the floating rate portion of the original swaps
on $450.0 million (all swaps except the January 22,
2008 swap that expires January 31, 2009) from three
month LIBOR to one month LIBOR. The Partnership received a cash
settlement in September of $1.4 million which represented
the present value of the basis point differential between one
month LIBOR and three month LIBOR. The $1.4 million was
recorded in the consolidated statement of operations in (gain)
loss on derivatives.
The table below aligns the new swap which receives one month
LIBOR and pays three month LIBOR with the original interest rate
swaps.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Original Swap Trade Date
|
|
New Trade Date
|
|
|
From
|
|
|
To
|
|
|
Notional Amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
March 13, 2007
|
|
|
September 12, 2008
|
|
|
|
September 30, 2008
|
|
|
|
March 31, 2011
|
|
|
$
|
50,000
|
|
September 5, 2007
|
|
|
September 12, 2008
|
|
|
|
September 30, 2008
|
|
|
|
September 28, 2011
|
|
|
|
50,000
|
|
August 16, 2007
|
|
|
September 12, 2008
|
|
|
|
October 30, 2008
|
|
|
|
October 31, 2011
|
|
|
|
100,000
|
|
November 14, 2006
|
|
|
September 12, 2008
|
|
|
|
November 28, 2008
|
|
|
|
November 30, 2010
|
|
|
|
50,000
|
|
August 9, 2007
|
|
|
September 12, 2008
|
|
|
|
November 28, 2008
|
|
|
|
November 30, 2010
|
|
|
|
50,000
|
|
July 30, 2007
|
|
|
September 12, 2008
|
|
|
|
November 28, 2008
|
|
|
|
August 30, 2011
|
|
|
|
100,000
|
|
August 6, 2007
|
|
|
September 23, 2008
|
|
|
|
November 28, 2008
|
|
|
|
August 30, 2011
|
|
|
|
50,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
450,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The impact of the interest rate swaps on net income is included
in other income (expense) in the consolidated statements of
operations as a part of interest expense, net, as follows (in
thousands):
F-36
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Change in fair value of derivatives that do not
|
|
|
|
|
|
|
|
|
qualify for hedge accounting
|
|
$
|
(22,105
|
)
|
|
$
|
(1,185
|
)
|
Realized gains on derivatives
|
|
|
(4,608
|
)
|
|
|
707
|
|
Ineffective portion of derivatives qualifying for hedge
accounting
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(26,713
|
)
|
|
$
|
(478
|
)
|
|
|
|
|
|
|
|
|
|
No comparison is listed for 2006 because the first interest rate
swaps were entered into in November 2006 and therefore had no
material operational impact prior to 2007.
The fair value of derivative assets and liabilities relating to
interest rate swaps are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Fair value of derivative assets current
|
|
$
|
149
|
|
|
$
|
68
|
|
Fair value of derivative assets long-term
|
|
|
|
|
|
|
|
|
Fair value of derivative liabilities current
|
|
|
(17,217
|
)
|
|
|
(3,266
|
)
|
Fair value of derivative liabilities long-term
|
|
|
(18,391
|
)
|
|
|
(8,057
|
)
|
|
|
|
|
|
|
|
|
|
Net fair value of interest rate swaps
|
|
$
|
(35,459
|
)
|
|
$
|
(11,255
|
)
|
|
|
|
|
|
|
|
|
|
Commodity
Swaps
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, basis swaps
and processing margin 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 our systems on one index and selling gas off that
same system on a different index. Processing margin financial
swaps are used to hedge fractionation spread risk at our
processing plants relating to the option to process versus
bypassing our equity gas.
F-37
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
The components of (gain) loss on derivatives in the consolidated
statements of operations relating to commodity swaps are (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Change in fair value of derivatives that do not qualify for
hedge accounting
|
|
$
|
(246
|
)
|
|
$
|
1,197
|
|
|
$
|
713
|
|
Realized (gains) losses on derivatives
|
|
|
(11,889
|
)
|
|
|
(7,918
|
)
|
|
|
(2,238
|
)
|
Ineffective portion of derivatives qualifying for hedge
accounting
|
|
|
(68
|
)
|
|
|
93
|
|
|
|
(66
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(12,203
|
)
|
|
$
|
(6,628
|
)
|
|
$
|
(1,591
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of derivative assets and liabilities relating to
commodity swaps are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Fair value of derivative assets current
|
|
$
|
27,017
|
|
|
$
|
8,521
|
|
Fair value of derivative assets long term
|
|
|
4,628
|
|
|
|
1,337
|
|
Fair value of derivative liabilities current
|
|
|
(11,289
|
)
|
|
|
(17,800
|
)
|
Fair value of derivative liabilities long term
|
|
|
(4,384
|
)
|
|
|
(1,369
|
)
|
|
|
|
|
|
|
|
|
|
Net fair value of commodity swaps
|
|
$
|
15,972
|
|
|
$
|
(9,311
|
)
|
|
|
|
|
|
|
|
|
|
Set forth below is the summarized notional volumes and fair
values of all instruments held for price risk management
purposes and related physical offsets at December 31, 2008
(all gas volumes are expressed in MMBtus and liquids are
expressed in gallons). The remaining terms of the contracts
extend no later than June 2010 for derivatives, except for
certain basis swaps that extend to March 2012. The
Partnerships counterparties to derivative contracts
include BP Corporation, Total Gas & Power, Fortis,
Morgan Stanley, J. Aron & Co., a subsidiary of Goldman
Sachs and Sempra Energy. Changes in the fair value of the
Partnerships mark to market derivatives are recorded in
earnings in the period the transaction is entered into. The
effective portion of changes in
F-38
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
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. The ineffective portion is
recorded in earnings immediately.
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
Transaction Type
|
|
Volume
|
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
|
Cash Flow Hedges:
|
|
|
|
|
|
|
|
|
Natural gas swaps (short contracts) (MMBtus)
|
|
|
(600
|
)
|
|
$
|
1,136
|
|
Liquids swaps (short contracts) (gallons)
|
|
|
(16,026
|
)
|
|
|
12,578
|
|
|
|
|
|
|
|
|
|
|
Total swaps designated as cash flow hedges
|
|
|
|
|
|
$
|
13,714
|
|
|
|
|
|
|
|
|
|
|
Mark to Market Derivatives:*
|
|
|
|
|
|
|
|
|
Swing swaps (long contracts)
|
|
|
2,155
|
|
|
$
|
10
|
|
Physical offsets to swing swap transactions (short contracts)
|
|
|
(2,155
|
)
|
|
|
|
|
Swing swaps (short contracts)
|
|
|
(397
|
)
|
|
|
(3
|
)
|
Physical offsets to swing swap transactions (long contracts)
|
|
|
397
|
|
|
|
|
|
Basis swaps (long contracts)
|
|
|
82,681
|
|
|
|
7,464
|
|
Physical offsets to basis swap transactions (short contracts)
|
|
|
(1,550
|
)
|
|
|
9,072
|
|
Basis swaps (short contracts)
|
|
|
(78,025
|
)
|
|
|
(6,175
|
)
|
Physical offsets to basis swap transactions (long contracts)
|
|
|
1,771
|
|
|
|
(9,067
|
)
|
Third-party on-system financial swaps (long contracts)
|
|
|
2,300
|
|
|
|
(8,065
|
)
|
Physical offsets to third-party on-system transactions (short
contracts)
|
|
|
(2,283
|
)
|
|
|
8,157
|
|
Third-party on-system financial swaps (short contracts)
|
|
|
(172
|
)
|
|
|
2
|
|
Physical offsets to third-party on-system transactions (long
contracts)
|
|
|
155
|
|
|
|
89
|
|
Storage swap transactions (long contracts)
|
|
|
158
|
|
|
|
(23
|
)
|
Storage swap transactions (short contracts)
|
|
|
(353
|
)
|
|
|
797
|
|
|
|
|
|
|
|
|
|
|
Total mark to market derivatives
|
|
|
|
|
|
$
|
2,258
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
All are gas contracts, volume in MMBtus
|
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
The impact of realized gains or losses from derivatives
designated as cash flow hedge contracts in the consolidated
statements of operations is summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
|
Increase (decrease) in Midstream revenue
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
Natural gas
|
|
$
|
63
|
|
|
$
|
5,533
|
|
|
$
|
5,886
|
|
|
|
|
|
Liquids
|
|
|
(10,402
|
)
|
|
|
(4,066
|
)
|
|
|
1,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(10,339
|
)
|
|
$
|
1,467
|
|
|
$
|
7,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-39
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
Natural
Gas
As of December 31, 2008, an unrealized derivative fair
value net gain of $1.1 million, related to cash flow hedges
of gas price risk was recorded in accumulated other
comprehensive income (loss). Of this net amount, $1.1 million is
expected to be reclassified into earnings through December 2009.
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 cash flow hedge contracts related to January
2009 gas production increased gas revenue by approximately
$0.1 million.
Liquids
As of December 31, 2008 an unrealized derivative fair value
net gain of $12.6 million related to cash flow hedges of
liquids price risk was recorded in accumulated other
comprehensive income (loss). Of this amount, $12.6 million
is expected to be reclassified into earnings through December
2009. 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.
Derivatives
Other Than Cash Flow Hedges
Assets and liabilities related to third party derivative
contracts, swing swaps, basis swaps, storage swaps and
processing margin swaps 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 net 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, 2008
|
|
$
|
2,014
|
|
|
$
|
181
|
|
|
$
|
63
|
|
|
$
|
2,258
|
|
|
|
(14)
|
Fair
Value Measurements
|
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements
(SFAS 157).
SFAS 157 introduces a framework for measuring fair value
and expands required disclosure about fair value measurements of
assets and liabilities. SFAS 157 for financial assets and
liabilities is effective for fiscal years beginning after
November 15, 2007. The Partnership has adopted the standard
for those assets and liabilities as of January 1, 2008 and
the impact of adoption was not significant.
Fair value is defined as the price at which an asset could be
exchanged in a current transaction between knowledgeable,
willing parties. A liabilitys fair value is defined as the
amount that would be paid to transfer the liability to a new
obligor, not the amount that would be paid to settle the
liability with the creditor. Where available, fair value is
based on observable market prices or parameters or derived from
such prices or parameters. Where observable prices or inputs are
not available, use of unobservable prices or inputs are used to
estimate the current fair value, often using an internal
valuation model. These valuation techniques involve some level
of management estimation and judgment, the degree of which is
dependent on the item being valued.
SFAS 157 establishes a three-tier fair value hierarchy,
which prioritizes the inputs used in measuring fair value. These
tiers include: Level 1, defined as observable inputs such
as quoted prices in active markets; Level 2, defined as
inputs other than quoted prices in active markets that are
either directly or indirectly observable; and Level 3,
defined as unobservable inputs in which little or no market data
exists, therefore requiring an entity to develop its own
assumptions.
F-40
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
The Partnerships derivative contracts primarily consist of
commodity swaps and interest rate swap contracts which are not
traded on a public exchange. The fair values of commodity swap
contracts are determined based on inputs that are readily
available in public markets or can be derived from information
available in publicly quoted markets. The Partnership determines
the value of interest rate swap contracts by utilizing inputs
and quotes from the counterparties to these contracts. The
reasonableness of these inputs and quotes is verified by
comparing similar inputs and quotes from other counterparties as
of each date for which financial statements are prepared.
Net assets (liabilities) measured at fair value on a recurring
basis are summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Interest rate swaps*
|
|
$
|
(35,459
|
)
|
|
|
|
|
|
$
|
(35,459
|
)
|
|
|
|
|
Commodity swaps*
|
|
|
15,972
|
|
|
|
|
|
|
|
15,972
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(19,487
|
)
|
|
|
|
|
|
$
|
(19,487
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Unrealized gains or losses on commodity derivatives qualifying
for hedge accounting are recorded in accumulated other
comprehensive income (loss) at each measurement date.
Accumulated other comprehensive income also includes the
unrealized losses on interest rate swaps of $17.0 million
recorded prior to de-designation in January 2008, of which
$6.4 million has been amortized to earnings through
December 2008.
|
|
|
(15)
|
Transactions
with Related Parties -Distribution of Assets for Cash
|
During 2008 we transferred two inactive processing plants to the
Partnership at net book value for a cash price of
$0.4 million which represented the fair value of the plants.
|
|
(16)
|
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 with the south Louisiana processing
assets provides for annual lease payments of $12.2 million
with a lease term extending to November 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 with initial or remaining
non-cancelable lease terms in excess of one year (in millions):
|
|
|
|
|
2009
|
|
$
|
28.4
|
|
2010
|
|
|
19.0
|
|
2011
|
|
|
17.9
|
|
2012
|
|
|
16.4
|
|
2013
|
|
|
3.1
|
|
Thereafter
|
|
|
3.7
|
|
|
|
|
|
|
|
|
$
|
88.5
|
|
|
|
|
|
|
Operating lease rental expense for the years ended
December 31, 2008, 2007 and 2006 was approximately
$43.8 million, $31.7 million and $23.8 million,
respectively.
F-41
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
During 2008 the Partnership leased approximately 162 of its
treating plants, most of which the Partnership operates, and 33
of its dew point control plants to customers under operating
leases. The initial terms on these leases are generally
12 months at which time the leases revert to
30-day
cancelable leases. As of December 31, 2008, the Company
only had 31 treating plants under 36 operating leases with
remaining non-cancelable lease terms in excess of one year. The
future minimum lease rentals are $16.3 million and
$5.4 million for the years ended December 31, 2009 and
2010, respectively. These leased treating plants have a cost of
$25.4 million and accumulated depreciation of
$4.9 million as of December 31, 2008.
|
|
(c)
|
Employment
Agreements
|
Certain members of management of the Company are parties to
employment contacts with the general partner of the Partnership.
The employment agreements provide those senior managers with
severance payments in certain circumstances and prohibit each
such person from competing with the general partner of the
Partnership 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. As
of December 31, 2008, we had incurred approximately
$0.5 million in such remediation costs. Since this
remediation project is a result of previous owners
operation and the actual contamination occurred prior to our
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 was identified during due diligence at a
number of sites owned by the acquired companies. 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. In addition, the
Partnership has disclosed possible Clean Air Act monitoring
deficiencies it has discovered to the Louisiana Department of
Environmental Quality and is working with the department to
correct these deficiencies and to 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 Duke Energy Field Services,
or 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 estimated
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. The
Company does not expect to incur any material environmental
liability associated with the Conroe site.
F-42
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 November 15, 2007, Crosstex CCNG Processing Ltd.
(Crosstex Processing), the Partnerships
wholly-owned subsidiary, received a demand letter from Denbury
Onshore, LLC (Denbury), asserting a claim for breach
of contract and seeking payment of approximately
$11.4 million in damages. On April 15, 2008, the
parties mediated the matter unsuccessfully. On December 4,
2008, Denbury initiated formal arbitration proceedings against
Crosstex Processing, Crosstex Energy Services, L.P., Crosstex
North Texas Gathering, L.P., and Crosstex Gulf Coast Marketing,
Ltd., seeking $11.4 million and additional unspecified
damages. On December 23, 2008, Crosstex Processing filed an
answer denying Denburys allegations and a counterclaim
seeking a declaratory judgment that its processing plant is
uneconomic under the Processing Contract. Crosstex Energy,
Crosstex Marketing, and Crosstex Gathering also filed an answer
denying Denburys allegations and asserting that they are
improper parties as Denburys claim is for breach of the
Processing Contract and none of these entities is a party to
that agreement. Crosstex Gathering also filed a counterclaim
seeking approximately $40.0 million in damages for the
value of the NGLs it is entitled to under its Gas Gathering
Agreement with Denbury. Once the three-person arbitration panel
has been named and cleared conflicts, the arbitration panel will
hold a preliminary conference with the parties to set a date for
the final hearing and other case deadlines and to establish
discovery limits. Although it is not possible to predict with
certainty the ultimate outcome of this matter, the Partnership
does not believe this will have a material adverse effect on its
consolidated results of operations or financial position.
The Partnership (or its subsidiaries) is defending eleven
lawsuits filed by owners of property located near processing
facilities or compression facilities constructed by the
Partnership as part of its systems in north Texas. The suits
generally allege that the facilities create a private nuisance
and have damaged the value of surrounding property. Claims of
this nature have arisen as a result of the industrial
development of natural gas gathering, processing and treating
facilities in urban and occupied rural areas. At this time, five
cases are set for trial in 2009. The remaining cases have not
yet been set for trial. Discovery is underway. Although it is
not possible to predict the ultimate outcomes of these matters,
the Partnership does not believe that these claims will have a
material adverse impact on its consolidated results of
operations or financial condition.
On July 22, 2008, SemStream, L.P. and certain of its
subsidiaries filed voluntary petitions for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. As of
July 22, 2008, SemStream, L.P. owed the Partnership
approximately $6.2 million, including approximately
$3.9 million for June 2008 sales and approximately
$2.2 million for July 2008 sales. The Partnership believes
the July sales of $2.2 million will receive
administrative claim status in the bankruptcy
proceeding. The debtors schedules acknowledge its
obligation to Crosstex for an administrative claim in the amount
of $2.2 but the allowance of the administrative claim status is
still subject to approval of the bankruptcy court in accordance
with the administrative claim allowance procedures order in the
case. The Partnership evaluated these receivables for
collectibility and provided a valuation allowance of
$3.1 million during the year ended December 31, 2008.
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.
F-43
CROSSTEX
ENERGY, INC.
Notes to Consolidated Financial
Statements (Continued)
|
|
(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.
|
|
(c)
|
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 effected a three-for-one stock
split. In conjunction with the Companys initial public
offering in January 2004, the Company effected a two-for-one
split. All share amounts for prior periods presented herein have
been restated to reflect these stock splits.
The following are the share amounts used to compute the basic
and diluted earnings per share for the years ended
December 31, 2008, 2007 and 2006 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Basic shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
|
|
|
46,298
|
|
|
|
45,988
|
|
|
|
42,168
|
|
Dilutive shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
|
|
|
46,298
|
|
|
|
45,988
|
|
|
|
42,168
|
|
Dilutive effect of restricted shares
|
|
|
248
|
|
|
|
537
|
|
|
|
410
|
|
Dilutive effect of exercise of options
|
|
|
43
|
|
|
|
82
|
|
|
|
88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dilutive shares
|
|
|
46,589
|
|
|
|
46,607
|
|
|
|
42,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 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 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-44
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008:
|
|
Midstream
|
|
|
Treating
|
|
|
Corporate
|
|
|
Totals
|
|
|
|
(In thousands)
|
|
|
Sales to external customers
|
|
$
|
4,838,747
|
|
|
$
|
64,953
|
|
|
$
|
|
|
|
$
|
4,903,700
|
|
Sales to affiliates
|
|
|
16,155
|
|
|
|
7,367
|
|
|
|
(23,522
|
)
|
|
|
|
|
Profit on energy trading activities
|
|
|
3,349
|
|
|
$
|
|
|
|
$
|
|
|
|
|
3,349
|
|
Purchased gas
|
|
|
(4,487,463
|
)
|
|
|
(14,579
|
)
|
|
|
16,155
|
|
|
|
(4,485,887
|
)
|
Operating expenses
|
|
|
(148,906
|
)
|
|
|
(27,517
|
)
|
|
|
7,367
|
|
|
|
(169,056
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
221,882
|
|
|
$
|
30,224
|
|
|
$
|
|
|
|
$
|
252,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives
|
|
$
|
12,203
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
12,203
|
|
Impairments
|
|
$
|
20,365
|
|
|
$
|
1,063
|
|
|
$
|
9,812
|
|
|
$
|
31,240
|
|
Depreciation and amortization
|
|
$
|
(112,898
|
)
|
|
$
|
(12,484
|
)
|
|
$
|
(5,936
|
)
|
|
$
|
(131,318
|
)
|
Capital expenditures (excluding acquisitions)
|
|
$
|
224,032
|
|
|
$
|
32,299
|
|
|
$
|
11,431
|
|
|
$
|
267,762
|
|
Identifiable assets
|
|
$
|
2,304,889
|
|
|
$
|
200,114
|
|
|
$
|
41,740
|
|
|
$
|
2,546,743
|
|
Year ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to external customers
|
|
$
|
3,791,316
|
|
|
$
|
53,682
|
|
|
$
|
|
|
|
$
|
3,844,998
|
|
Sales to affiliates
|
|
|
9,441
|
|
|
|
4,944
|
|
|
|
(14,385
|
)
|
|
|
|
|
Profit on energy trading activities
|
|
|
4,090
|
|
|
|
|
|
|
|
|
|
|
|
4,090
|
|
Purchased gas
|
|
|
(3,478,365
|
)
|
|
|
(7,892
|
)
|
|
|
9,441
|
|
|
|
(3,476,816
|
)
|
Operating expenses
|
|
|
(109,910
|
)
|
|
|
(20,218
|
)
|
|
|
4,944
|
|
|
|
(125,184
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
216,572
|
|
|
$
|
30,516
|
|
|
$
|
|
|
|
$
|
247,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives
|
|
$
|
6,628
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6,628
|
|
Impairments
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Depreciation and amortization
|
|
$
|
(89,621
|
)
|
|
$
|
(12,327
|
)
|
|
$
|
(4,737
|
)
|
|
$
|
(106,685
|
)
|
Capital expenditures (excluding acquisitions)
|
|
$
|
371,120
|
|
|
$
|
25,085
|
|
|
$
|
5,192
|
|
|
$
|
401,397
|
|
Identifiable assets
|
|
$
|
2,339,326
|
|
|
$
|
214,481
|
|
|
$
|
49,022
|
|
|
$
|
2,602,829
|
|
Year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to external customers
|
|
$
|
3,075,481
|
|
|
$
|
52,095
|
|
|
$
|
|
|
|
$
|
3,127,576
|
|
Sales to affiliates
|
|
|
10,520
|
|
|
|
2,412
|
|
|
|
(12,932
|
)
|
|
|
|
|
Profit on energy trading activities
|
|
|
2,510
|
|
|
|
|
|
|
|
|
|
|
|
2,510
|
|
Purchased gas
|
|
|
(2,870,335
|
)
|
|
|
(9,463
|
)
|
|
|
10,520
|
|
|
|
(2,869,278
|
)
|
Operating expenses
|
|
|
(83,400
|
)
|
|
|
(17,851
|
)
|
|
|
2,412
|
|
|
|
(98,839
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
134,776
|
|
|
$
|
27,193
|
|
|
$
|
|
|
|
$
|
161,969
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives
|
|
$
|
1,591
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,591
|
|
Impairments
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Depreciation and amortization
|
|
$
|
(63,409
|
)
|
|
$
|
(13,587
|
)
|
|
$
|
(3,583
|
)
|
|
$
|
(80,579
|
)
|
Capital expenditures (excluding acquisitions)
|
|
$
|
294,597
|
|
|
$
|
31,463
|
|
|
$
|
8,184
|
|
|
$
|
334,244
|
|
Identifiable assets
|
|
$
|
1,962,543
|
|
|
$
|
203,528
|
|
|
$
|
40,627
|
|
|
$
|
2,206,698
|
|
F-45
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Segment profits
|
|
$
|
252,106
|
|
|
$
|
247,088
|
|
|
$
|
161,969
|
|
General and administrative expenses
|
|
|
(74,518
|
)
|
|
|
(64,304
|
)
|
|
|
(47,707
|
)
|
Gain on derivatives
|
|
|
12,203
|
|
|
|
6,628
|
|
|
|
1,591
|
|
Gain on sale of property
|
|
|
1,519
|
|
|
|
1,667
|
|
|
|
2,108
|
|
Depreciation and amortization
|
|
|
(131,318
|
)
|
|
|
(106,685
|
)
|
|
|
(80,579
|
)
|
Impairments
|
|
|
(31,240
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
28,752
|
|
|
$
|
84,394
|
|
|
$
|
37,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19)
|
Quarterly
Financial Data (Unaudited)
|
Summarized unaudited quarterly financial data is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
Total
|
|
|
|
(In thousands, except per share amount)
|
|
|
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
1,266,720
|
|
|
$
|
1,540,608
|
|
|
$
|
1,330,610
|
|
|
$
|
769,111
|
|
|
$
|
4,907,049
|
|
Operating income (loss)
|
|
|
23,124
|
|
|
|
24,394
|
|
|
|
15,812
|
|
|
|
(34,578
|
)
|
|
|
28,752
|
|
Income from discontinued operations net of tax and net of
minority interest
|
|
|
333
|
|
|
|
324
|
|
|
|
294
|
|
|
|
11,279
|
|
|
|
12,230
|
|
Net income (loss)
|
|
|
10,706
|
|
|
|
17,452
|
|
|
|
540
|
|
|
|
(4,465
|
)
|
|
|
24,233
|
|
Basic earnings (loss) per common share
|
|
$
|
0.23
|
|
|
$
|
0.38
|
|
|
$
|
0.01
|
|
|
$
|
(0.10
|
)
|
|
$
|
0.52
|
|
Diluted earnings (loss) per common share
|
|
$
|
0.23
|
|
|
$
|
0.37
|
|
|
$
|
0.01
|
|
|
$
|
(0.10
|
)
|
|
$
|
0.52
|
|
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
824,028
|
|
|
$
|
999,113
|
|
|
$
|
940,392
|
|
|
$
|
1,085,555
|
|
|
$
|
3,849,088
|
|
Operating income
|
|
|
10,271
|
|
|
|
18,635
|
|
|
|
21,164
|
|
|
|
34,324
|
|
|
|
84,394
|
|
Income from discontinued operations net of tax and net of
minority interest
|
|
|
341
|
|
|
|
378
|
|
|
|
378
|
|
|
|
435
|
|
|
|
1,532
|
|
Net income
|
|
|
74
|
|
|
|
2,193
|
|
|
|
2,181
|
|
|
|
7,728
|
|
|
|
12,176
|
|
Basic earnings per common share
|
|
$
|
0.00
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.17
|
|
|
$
|
0.26
|
|
Diluted earnings per common share
|
|
$
|
0.00
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.17
|
|
|
$
|
0.26
|
|
F-46
SCHEDULE I
CROSSTEX
ENERGY, INC. (PARENT COMPANY)
CONDENSED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
12,323
|
|
|
$
|
7,712
|
|
Prepaid expenses and other
|
|
|
463
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
12,786
|
|
|
|
7,748
|
|
|
|
|
|
|
|
|
|
|
Investment in the Partnership
|
|
|
276,221
|
|
|
|
301,852
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
289,007
|
|
|
$
|
309,600
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Payable to the Partnership
|
|
$
|
110
|
|
|
$
|
37
|
|
Other accrued liabilities
|
|
|
197
|
|
|
|
152
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
307
|
|
|
|
189
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liability
|
|
|
73,271
|
|
|
|
63,045
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Common stock
|
|
|
464
|
|
|
|
463
|
|
Additional paid-in capital
|
|
|
268,988
|
|
|
|
267,859
|
|
Retained earnings
|
|
|
(54,693
|
)
|
|
|
(16,878
|
)
|
Accumulated other comprehensive income
|
|
|
670
|
|
|
|
(5,078
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
215,429
|
|
|
|
246,366
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
289,007
|
|
|
$
|
309,600
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements of
Crosstex Energy, Inc. included in this report.
F-47
CROSSTEX
ENERGY, INC. (PARENT COMPANY)
CONDENSED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands except share data)
|
|
|
Operating income and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from investment in the Partnership
|
|
$
|
8,238
|
|
|
$
|
15,670
|
|
|
$
|
6,354
|
|
Income (loss) from investment in subsidiary
|
|
|
(139
|
)
|
|
|
(35
|
)
|
|
|
1,538
|
|
General and administrative expense
|
|
|
(3,429
|
)
|
|
|
(2,776
|
)
|
|
|
(2,014
|
)
|
Impairment of goodwill
|
|
|
(804
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
3,866
|
|
|
|
12,859
|
|
|
|
5,878
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income
|
|
|
238
|
|
|
|
410
|
|
|
|
378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before gain on issuance of
units by the Partnership and income taxes
|
|
|
4,104
|
|
|
|
13,269
|
|
|
|
6,256
|
|
Gain on issuance of units in the Partnership
|
|
|
14,748
|
|
|
|
7,461
|
|
|
|
18,955
|
|
Income tax provision expense
|
|
|
(6,849
|
)
|
|
|
(10,086
|
)
|
|
|
(10,896
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations before discontinued
operations and cumulative effect of change in accounting
principle
|
|
|
12,003
|
|
|
|
10,644
|
|
|
|
14,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations from investment in the
Partnership-net
of tax and net of minority interest
|
|
|
1,266
|
|
|
|
1,532
|
|
|
|
1,970
|
|
Gain on sale of discontinued operations from investment in the
Partnership-net
of tax and net of minority interest
|
|
|
10,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations-net
of tax and net of minority interest
|
|
|
12,230
|
|
|
|
1,532
|
|
|
|
1,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect of change in accounting
principle
|
|
|
24,233
|
|
|
|
12,176
|
|
|
|
16,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle from
investment in the Partnership
|
|
|
|
|
|
|
|
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
24,233
|
|
|
$
|
12,176
|
|
|
$
|
16,455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect of change in accounting
principle per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
0.52
|
|
|
$
|
0.26
|
|
|
$
|
0.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle per common
share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
0.52
|
|
|
$
|
0.26
|
|
|
$
|
0.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
46,298
|
|
|
|
45,988
|
|
|
|
42,168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
46,589
|
|
|
|
46,607
|
|
|
|
42,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements of
Crosstex Energy, Inc. included in this report.
F-48
CROSSTEX
ENERGY, INC. (PARENT COMPANY)
CONDENSED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
24,233
|
|
|
$
|
12,176
|
|
|
$
|
16,455
|
|
Adjustments to reconcile net income (loss) to net cash flow
provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from investment in the Partnership, including
discontinued operations
|
|
|
(20,428
|
)
|
|
|
(17,202
|
)
|
|
|
(8,324
|
)
|
(Income) loss from investment in subsidiary
|
|
|
139
|
|
|
|
35
|
|
|
|
(1,538
|
)
|
Impairment
|
|
|
804
|
|
|
|
|
|
|
|
|
|
Deferred taxes
|
|
|
6,849
|
|
|
|
10,086
|
|
|
|
10,896
|
|
Stock-based compensation
|
|
|
36
|
|
|
|
(25
|
)
|
|
|
22
|
|
Gain on issuance of units in the Partnership
|
|
|
(14,748
|
)
|
|
|
(7,461
|
)
|
|
|
(18,955
|
)
|
Cumulative effect of change in accounting principle from
investment in the Partnership
|
|
|
|
|
|
|
|
|
|
|
(170
|
)
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, prepaid expenses and other
|
|
|
(467
|
)
|
|
|
68
|
|
|
|
(13
|
)
|
Accounts payable and other accrued liabilities
|
|
|
118
|
|
|
|
116
|
|
|
|
(153
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
(3,464
|
)
|
|
|
(2,207
|
)
|
|
|
(1,780
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in the Partnership
|
|
|
(2,193
|
)
|
|
|
(4,014
|
)
|
|
|
(189,407
|
)
|
Distributions from the Partnership
|
|
|
76,026
|
|
|
|
47,565
|
|
|
|
41,711
|
|
Dividends from subsidiary
|
|
|
|
|
|
|
|
|
|
|
2,610
|
|
Contributions to subsidiary
|
|
|
(139
|
)
|
|
|
(35
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities
|
|
|
73,694
|
|
|
|
43,516
|
|
|
|
(145,086
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of common and preferred stock
|
|
|
|
|
|
|
|
|
|
|
179,720
|
|
Proceeds from exercise of common stock options
|
|
|
244
|
|
|
|
98
|
|
|
|
126
|
|
Conversion of restricted stock, net of shares withheld for taxes
|
|
|
(3,815
|
)
|
|
|
(919
|
)
|
|
|
|
|
Common dividends paid
|
|
|
(62,048
|
)
|
|
|
(42,588
|
)
|
|
|
(34,667
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(65,619
|
)
|
|
|
(43,409
|
)
|
|
|
145,179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
|
4,611
|
|
|
|
(2,100
|
)
|
|
|
(1,687
|
)
|
Cash, beginning of year
|
|
|
7,712
|
|
|
|
9,812
|
|
|
|
11,499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, end of year
|
|
$
|
12,323
|
|
|
$
|
7,712
|
|
|
$
|
9,812
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Notes to Consolidated Financial Statements of
Crosstex Energy, Inc. included in this report.
F-49
SCHEDULE II
CROSSTEX
ENERGY, INC.
VALUATION AND QUALIFYING ACCOUNTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
|
|
|
Balance at
|
|
|
|
Beginning
|
|
|
Costs and
|
|
|
|
|
|
End of
|
|
|
|
of Period
|
|
|
Expenses
|
|
|
Deductions
|
|
|
Period
|
|
|
|
(In thousands)
|
|
|
Year Ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
985
|
|
|
$
|
2,670
|
|
|
|
|
|
|
$
|
3,655
|
|
Year Ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
618
|
|
|
$
|
367
|
|
|
|
|
|
|
$
|
985
|
|
Year Ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
259
|
|
|
$
|
359
|
|
|
|
|
|
|
$
|
618
|
|
F-50
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
|
|
|
|
Sixth Amended and Restated Agreement of Limited Partnership of
Crosstex Energy, L.P., dated as of March 23, 2007
(incorporated by reference to Exhibit 3.1 to Crosstex
Energy, L.P.s Current Report on
Form 8-K
dated March 23, 2007, filed with the Commission on
March 27, 2007).
|
|
3
|
.5
|
|
|
|
Amendment No. 1 to Sixth Amended and Restated Agreement of
Limited Partnership of Crosstex Energy, L.P., dated
December 20, 2007 (incorporated by reference to
Exhibit 3.1 to Crosstex Energy, L.P.s Current Report
on
Form 8-K
dated December 20, 2007, filed with the Commission on
December 21, 2007).
|
|
3
|
.6
|
|
|
|
Amendment No. 2 to Sixth Amended and Restated Agreement of
Limited Partnership of Crosstex Energy, L.P. (incorporated by
reference to Exhibit 3.1 to Crosstex Energy, L.P.s
Current Report on
Form 8-K
dated March 27, 2008, filed with the Commission on
March 28, 2008).
|
|
3
|
.7
|
|
|
|
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
|
.8
|
|
|
|
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
|
.9
|
|
|
|
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
|
.10
|
|
|
|
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
|
.11
|
|
|
|
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
|
.12
|
|
|
|
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. 333-97779).
|
|
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, file No. 000-50536).
|
|
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
for the year ended December 31, 2002, file
No. 000-50067).
|
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
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 Statement and Waiver 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, file No. 000-50536).
|
|
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, file No. 000-50536).
|
|
10
|
.8
|
|
|
|
Fourth Amended and Restated Credit Agreement, dated
November 1, 2005, 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 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
|
|
|
|
Third Amendment to Fourth Amended and Restated Credit Agreement,
effective as of March 28, 2007, 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
Form 8-K
dated April 3, 2007, filed with the Commission on
April 5, 2007).
|
|
10
|
.12
|
|
|
|
Fifth Amendment and Consent to Fourth Amended and Restated
Credit Agreement, effective as of November 7, 2008, 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 Quarterly Report on
Form 10-Q
for the quarterly period ended September 30, 2008).
|
|
10
|
.13
|
|
|
|
Sixth Amendment to Fourth Amended and Restated Credit Agreement,
effective as of February 27, 2009, among Crosstex Energy,
L.P., Bank of America, N.A. and certain other parties
(incorporated by reference to Exhibit 10.6 to Crosstex
Energy, L.P.s Annual Report on Form 10-K for the year
ended December 31, 2008).
|
|
10
|
.14
|
|
|
|
Commitment Increase Agreement, dated as of September 19,
2007, among Crosstex Energy, L.P., Bank of America, N.A., and
certain lenders party thereto (incorporated by reference to
Exhibit 10.1 to Crosstex Energy, L.P.s Current Report on
Form 8-K
dated September 19, 2007, filed with the Commission on
September 24, 2007).
|
|
10
|
.15
|
|
|
|
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
|
.16
|
|
|
|
Letter Amendment No. 1 to Amended and Restated Note
Purchase Agreement, effective as of March 30, 2007, among
Crosstex Energy, L.P., Prudential Investment Management, Inc.
and certain other parties (incorporated by reference to
Exhibit 10.2 to Crosstex Energy, L.P.s
Form 8-K
dated April 3, 2007, filed with the Commission on
April 5, 2007).
|
|
10
|
.17
|
|
|
|
Waiver and Letter Amendment No. 3 to Amended and Restated
Note Purchase Agreement, effective as of November 7, 2008,
among Crosstex Energy, L.P., Prudential Investment Management,
Inc. and certain other parties (incorporated by reference to
Exhibit 10.2 to Crosstex Energy, L.P.s Quarterly
Report on
Form 10-Q
for the quarterly period ended September 30, 2008).
|
|
|
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
10
|
.18
|
|
|
|
Letter Amendment No. 4 to Amended and Restated Note
Purchase Agreement, effective as of February 27, 2009,
among Crosstex Energy, L.P., Prudential Investment Management,
Inc. and certain other parties (incorporated by reference to
Exhibit 10.11 to Crosstex Energy, L.P.s Annual Report
on Form 10-K for the year ended December 31, 2008).
|
|
10
|
.19
|
|
|
|
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
|
.20
|
|
|
|
Stock Purchase Agreement, dated as of May 16, 2006, by and
among Crosstex Energy, Inc. 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
|
.21
|
|
|
|
Senior Subordinated Series D Unit Purchase Agreement, dated
as of March 23, 2007, by and among Crosstex Energy, L.P. an
deach of the Purchasers set forth on Schedule A thereto
(incorporated by reference to Exhibit 10.1 to Crosstex
Energy, L.P.s
Form 8-K
dated March 23, 2007, filed with the Commission on
March 27, 2007).
|
|
10
|
.22
|
|
|
|
Registration Rights Agreement, dated as of March 23, 2007,
by and among Crosstex Energy, L.P. and each of the Purchasers
set forth on Schedule A thereto (incorporated by reference
to Exhibit 4.1 to Crosstex Energy, L.P.s
Form 8-K
dated March 23, 2007, filed with the Commission on
March 27, 2007).
|
|
10
|
.23
|
|
|
|
Form of Performance Share Agreement (incorporated by reference
to Exhibit 10.1 to Crosstex Energy, Inc.s Current
Report on
Form 8-K
dated June 27, 2007, filed with the Commission on
July 3, 2007).
|
|
10
|
.24
|
|
|
|
Form of Performance Unit Agreement (incorporated by reference to
Crosstex Energy, L.P.s Current Report on
Form 8-K
dated June 27, 2007, filed with the Commission on
July 3, 2007).
|
|
10
|
.25
|
|
|
|
Form of Employment Agreement (incorporated by reference to
Exhibit 10.6 to Crosstex Energy, L.P.s Annual Report
on
Form 10-K
for the year ended December 31, 2002, file
No. 000-50067).
|
|
10
|
.26
|
|
|
|
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).
|
|
10
|
.27
|
|
|
|
Common Unit Purchase Agreement, dated as of April 8, 2008,
by and among Crosstex Energy, L.P. and each of the Purchasers
set forth Schedule A thereto (incorporated by reference to
Exhibit 10.1 to Crosstex Energy, L.P.s
Form 8-K
dated April 9, 2008).
|
|
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.
|
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