Exhibit 99.2
Item 7. Management’s 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
We are a Delaware limited partnership formed on July 12, 2002 to indirectly acquire
substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy
Services, Ltd. Historically, we have operated 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 recast of our 2008 10-K filing reflects the change in our business
due to disposition of assets in 2009. In February 2009, we sold our Oklahoma assets; in August 2009
we sold our Alabama, Mississippi and south Texas Midstream properties and in October 2009 we sold
our Treating assets. Our primary focus for our continuing operations is on the gathering,
processing, transmission and marketing of natural gas and NGLs, as well as providing certain
producer services. Currently, our geographic focus is in the north Texas Barnett Shale area and in
Louisiana. We manage our operations by focusing on gross margin because our business is generally
to purchase and resell natural gas for a margin, or to gather, process, transport and market
natural gas or NGLs for a fee. We buy and sell most of our natural gas at a fixed relationship to
the relevant index price. In addition, we receive certain fees for processing based on a percentage
of the liquids produced and enter into hedge contracts for our expected share of the liquids
produced to protect our margins from changes in liquids prices.
During the past five years we have grown significantly as a result of our construction and
acquisition of gathering and transmission pipelines and treating and processing plants. From
January 1, 2004 through December 31, 2008, we have 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. Subsequent to
the filing of the annual report on Form 10-K for the period ended
December 31, 2008 (the “2008 10-K”), we
disposed of certain non-strategic assets as noted in the paragraph above. The financial information
presented in this revised filing aggregate the results of operations of the 2009 dispositions into
discontinued operations for the calculation of net income. Additionally, letter of credit fees
have been reclassified to interest expense for a better analysis of financing costs. Accordingly, the results of operations
for such acquisitions are included in our financial statements only from the applicable date of the
acquisition and the results of operations from assets disposed of are in discontinued operations.
As a consequence, the historical results of operations for the periods presented may not be
comparable.
Our margins are determined primarily by the volumes of natural gas gathered, transported,
purchased and sold through our pipeline systems, processed at our processing facilities, and the
volumes of NGLs handled at our fractionation facilities. We generate revenues from four primary
sources:
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purchasing and reselling or transporting natural gas on the pipeline systems we own; |
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processing natural gas at our processing plants and fractionating and marketing the
recovered NGLs; |
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providing compression services; and |
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providing off-system marketing services for producers. |
We generally gather or transport gas owned by others through our facilities for a fee, or we
buy 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 our purchase/sale
transactions, the resale price is generally based on the same index price at which the gas was
purchased, and, if we are to be profitable, at a smaller discount or larger premium to the index
than it was purchased. We attempt to execute all purchases and sales substantially concurrently, or
we enter into a future delivery obligation, thereby establishing the basis for the margin we will
receive for each natural gas transaction. Our gathering and transportation margins related to a
percentage of the index price can be adversely affected by declines in the price of natural gas.
We also realize margins from our 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 our margins are higher during periods of high liquid
prices relative to natural gas prices. Under fee based contracts our margins are driven by
throughput volume. See “—Commodity Price Risk.”
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.
Our general and administrative expenses are dictated by the terms of our partnership
agreement. Our general partner and its affiliates are reimbursed for expenses incurred on our
behalf. These expenses include the costs of employee, officer and director compensation and
benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct
of business and allocable to us. Our partnership agreement provides that our general partner
determines the expenses that are allocable to us in any reasonable manner determined by our general
partner in its sole discretion.
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 , including the Partnership, 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, our 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 our 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 our processing plants is settled under
POL agreements or 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, we are not responsible for the
fuel or shrink associated with processing. Under margin contracts we realize 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 we have seen some improvement in
NGL prices and the fractionation spread in the early months of 2009 over the levels experienced in
December 2008, we believe that our 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 42.4% of our gross margin was attributable to gas processing as compared to
54.9% of our 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 our
contractual processing arrangements.
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 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 our
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. We believe 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 our pipeline and gathering systems and processing through our
processing plants. We have seen a decline in drilling activity by gas producers in our areas of
operations 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 our customers, including one of our largest customers in the Barnett Shale, have recently
announced drilling plans for 2009 that are substantially below their drilling levels during 2008.
Our business was also negatively impacted by hurricanes Gustav and Ike, which came ashore in
the Gulf Coast in September 2008. Although the majority of our 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 our 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 we do
not anticipate that gas production to our south Louisiana plants will recover to pre-hurricane
levels until mid-2009, when all repairs are expected to be complete. Additionally, one of our 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. Our operations in north Texas were also impacted by these hurricanes because operations at
the 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 our gross margin of approximately $22.9
million.
Two of our 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, our 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 we were 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
We have 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 Holdings, LLC, or 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. The Hanover and Cardinal assets were included in the
disposition of Treating assets in 2009. As a result, the income from these assets is included in
discontinued operations. In addition, internal expansion projects in north Texas and Louisiana have
contributed to the increase in our business during 2006, 2007 and 2008.
On June 29, 2006, we expanded our operations in the north Texas area through our 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 our acquisition, as well as 60,000 net acres owned by other producers, were
dedicated to the systems. Immediately following the closing of the Chief acquisition, we began
expanding our north Texas pipeline gathering system. The continued expansion of our north Texas
gathering systems to handle the growing production in the Barnett Shale was one of our 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, we connected 444 new wells to our
gathering system and significantly increased the dedicated acreage owned by other producers. Our
processing capacity in the Barnett Shale is 280 MMcf/d including the Silver Creek plant, which is a
200 MMcf/d cryogenic processing plant, our Azle plant, which is a 50 MMcf/d cryogenic processing
plant, and our Goforth plant, which is a 30 MMcf/d processing plant. In 2007 and 2008, we
constructed a 29-mile expansion in north Johnson County to our 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 be increased to approximately 400 MMcf/d in
April 2009 by the addition of compression. We have 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 our north Texas gathering system was approximately 1,100 MMcf/d and
total throughput on our 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, we commenced construction of an $80.0 million natural gas processing facility
called Bear Creek in Hood County near our 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, we do not anticipate that the additional processing
capacity provided by the Bear Creek plant will be needed until late 2010 or in 2011. Therefore, we
have decided to put this construction project on hold until the demand for this processing capacity
returns, at which time we will seek to obtain financing for this project. As of December 31, 2008,
we have 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, we acquired 48 amine treating plants from a subsidiary of Hanover
Compression Company for $51.7 million. These assets were sold in October 2009 as part of the
Treating assets.
On October 3, 2006, we 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, we acquired the remaining 50% interest in the
amine-treating plants for approximately $1.5 million. These assets were sold in October 2009 as
part of the Treating assets.
Our 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, we 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 our customer’s access to premium midwest and east coast
markets.
In April 2007, we completed construction and commenced operations on our north Louisiana
expansion, which is an extension of our 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 our Red River
lateral. Our 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 we 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.
Commodity Price Risk
We are subject to significant risks due to fluctuations in commodity prices. Our exposure to
these risks is primarily in the gas processing component of our business. A large percentage of our
processing fees are realized under POL contracts that are directly impacted by the market price of
NGLs. We also realize 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 our 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 we are 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. We have a
number of fractionation margin contracts on our Plaquemine and Gibson processing plants that expose
us 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 our margins, and may negatively impact our gross margin further if
such declines continue.
We are also subject to price risk to a lesser extent for fluctuations in natural gas prices
with respect to a portion of our gathering and transportation services. Approximately 3.0% of the
natural gas we market 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, our 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.
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Years Ended December 31, |
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2008 |
|
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2007 |
|
|
2006 |
|
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|
(Dollars in millions) |
|
Midstream revenues |
|
$ |
3,072.6 |
|
|
$ |
2,380.2 |
|
|
$ |
1,534.8 |
|
Purchased gas |
|
|
(2,768.2 |
) |
|
|
(2,124.5 |
) |
|
|
(1,378.9 |
) |
Profits on energy trading activities |
|
|
3.4 |
|
|
|
4.1 |
|
|
|
2.5 |
|
|
|
|
|
|
|
|
|
|
|
Total gross margin |
|
$ |
307.8 |
|
|
$ |
259.8 |
|
|
$ |
158.4 |
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMBtu/d): |
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation |
|
|
1,991,000 |
|
|
|
1,555,000 |
|
|
|
845,000 |
|
Processing |
|
|
1,608,000 |
|
|
|
1,835,000 |
|
|
|
1,817,000 |
|
Producer services |
|
|
85,000 |
|
|
|
94,000 |
|
|
|
138,000 |
|
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $307.8
million for the year ended December 31, 2008 compared to $259.8 million for the year ended December
31, 2007, an increase of $48.0 million, or 18.5%. 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 due to 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 gathering systems in the region and NTP accounted for $41.3 million and $9.1 million of
this increase, respectively. The 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 due to the impact of hurricanes along the Gulf
Coast.
Our 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.
These storms are estimated to have cost approximately $22.9 million in gross margin 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 plant in August 2008 due to downtime from fire damage. The fire occurred during
an attempt to bring the plant back online following tropical storm Eduardo.
Operating Expenses. Operating expenses were $125.8 million for the year ended December 31,
2008 compared to $91.2 million for the year ended December 31, 2007, an increase of $34.6 million,
or 37.9%, resulting primarily from growth and expansion in the NTP, NTG, north Louisiana and east Texas
areas. The increase is primarily attributable to the following factors:
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Contractor services and labor costs increased $12.3 million;
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Chemicals and materials increased $6.2 million;
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Equipment rental increased $5.8 million; |
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Ad valorem taxes increased $2.2 million; and |
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$0.7 million in technical services operating expense. |
General and Administrative Expenses. General and administrative expenses were $68.9 million
for the year ended December 31, 2008 compared to $59.5 million for the year ended December 31,
2007, an increase of $9.4 million, or 15.8%. The increase is primarily attributable to the
following factors:
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$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; |
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$3.1 million increase in bad debt expense due to the SemStream, L.P. bankruptcy; |
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$1.8 million increase in professional fees and services; and |
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$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 $8.6 million for the year ended
December 31, 2008 compared to a gain of $4.1 million for the year ended December 31, 2007. The
derivative transaction types contributing to the net gain are as follows (in millions):
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Years Ended December 31, |
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2008 |
|
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2007 |
|
| (Gain)/Loss on Derivatives: |
|
Total |
|
|
Realized |
|
|
Total |
|
|
Realized |
|
Basis swaps |
|
$ |
(8.7 |
) |
|
$ |
(8.8 |
) |
|
$ |
(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 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(13.7 |
) |
|
$ |
(13.3 |
) |
|
$ |
(6.6 |
) |
|
$ |
(7.9 |
) |
Adjusted for derivative gains included in
income from discontinued operations |
|
|
5.1 |
|
|
|
5.4 |
|
|
|
2.5 |
|
|
|
2.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(8.6 |
) |
|
$ |
(7.9 |
) |
|
$ |
(4.1 |
) |
|
$ |
(5.1 |
) |
|
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|
Gain/Loss on Sale of Property. Assets sold during the year ended December 31, 2008 generated
a net gain of $0.9 million as compared to a gain of $1.0 million during the year ended December 31,
2007. The 2008 gain was primarily generated from the disposition of various small Midstream assets.
The 2007 gain was primarily generated from the disposition of unused catalyst material.
Impairments. During the year ended December 31, 2008, we had an impairment expense of $29.4
million compared to no impairment expense for the year ended December 31, 2007. The impairment
expense is comprised of:
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$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 our 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. As of January 2009, we had
not found an alternative source of new gas for the Blue Water plant so the plant
ceased operation from January 2009 until November 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. |
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$4.9 million related to goodwill — We determined that the carrying amount of
goodwill attributable to the Midstream segment was impaired because of the
significant decline in our 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 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 we 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. |
Depreciation and Amortization. Depreciation and amortization expenses were $107.5 million for
the year ended December 31, 2008 compared to $83.3 million for the year ended December 31, 2007, an
increase of $24.2 million, or 29.1%. Depreciation and amortization increased $22.5 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 $75.0 million for the year ended December 31, 2008
compared to $48.1 million for the year ended December 31, 2007, an increase of $26.9 million, or
56.0%. The increase relates primarily to the negative impact of declining interest rates on our
interest rate swaps. Net interest expense consists of the following (in millions):
| |
|
|
|
|
|
|
|
|
| |
|
Years Ended December 31, |
|
| |
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
Senior notes |
|
$ |
22.5 |
|
|
$ |
23.0 |
|
Credit facility |
|
|
20.8 |
|
|
|
24.8 |
|
Capitalized interest |
|
|
(2.7 |
) |
|
|
(4.8 |
) |
Mark to market interest rate swaps |
|
|
22.1 |
|
|
|
1.2 |
|
Realized interest rate swaps |
|
|
4.6 |
|
|
|
(0.7 |
) |
Interest income |
|
|
(0.3 |
) |
|
|
(0.7 |
) |
Other |
|
|
8.0 |
|
|
|
5.3 |
|
|
|
|
|
|
|
|
Total |
|
$ |
75.0 |
|
|
$ |
48.1 |
|
|
|
|
|
|
|
|
Income taxes. Income tax expense was $2.4 million for the year ended December 31, 2008
compared to $0.8 million for the year ended December 31, 2007, an increase of $1.6 million. The
increase relates primarily to the Texas margin tax.
Other Income. Other income was $27.8 million for the year ended December 31, 2008 compared to
$0.5 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.
Discontinued Operations. Income from discontinued operations was $74.8 million for the year
ended December 31, 2008 compared to $31.3 million for the year ended December 31, 2007.
Discontinued operations includes income related to the Seminole gas processing plant disposed of in
November 2008, income related to the Alabama, Mississippi and south Texas assets disposed of in
August 2009 and income related to the Treating assets disposed of in October 2009. The reported
income for the comparative periods has been recast to include 2009 dispositions in income from
discontinued operations.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $259.8
million for the year ended December 31, 2007 compared to $158.4 million for the year ended December
31, 2006, an increase of $101.5 million, or 64.1%. This increase was primarily due to system
expansions, increased system throughput and a favorable processing environment for natural gas and
NGLs.
Crosstex 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 twelve months 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. The Eastern region
plant group contributed margin growth of $9.9 million due to a favorable gas processing
environment.
The favorable processing margins we realized during 2007 at several of our processing
facilities may be higher than margins we may realize during 2008 and future periods if the NGL
markets do not remain as strong as they were during 2007. As discussed above under “— Commodity
Price Risk”, we receive a processing fee as a portion of liquids processed or a percentage of the
liquids recovered on a substantial portion of the gas processed through these plants. During
periods when processing margins are favorable, as existed during 2007, we experience higher
processing margins. We have the ability to bypass certain volumes when processing is uneconomic so
we can limit our exposure to adverse processing margins but our processing margins will be lower
during these periods.
In addition, we have the ability to buy gas from and to sell gas to various gas markets
through our pipeline systems. During 2007 we were able to benefit from price differentials between
the various gas markets by selling gas into markets with more favorable pricing thereby improving
our Midstream gross margin.
Operating Expenses. Operating expenses were $91.2 million for the year ended December 31,
2007 compared to $65.9 million for the year ended December 31, 2006, an increase of $25.3 million,
or 38.5%. The increase in operating expenses primarily reflects costs associated with growth and
expansion in the north Texas assets of $17.5 million, LIG and
the north Louisiana expansion of $3.4
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 $59.5 million
for the year ended December 31, 2007 compared to $43.7 million for the year ended December 31,
2006, an increase of $15.8 million, or 36.1%. 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 $4.1 million for the year ended
December 31, 2007 compared to a gain of $0.2 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 |
|
| (Gain) Loss on Derivatives: |
|
Total |
|
|
Realized |
|
|
Total |
|
|
Realized |
|
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 |
) |
Adjusted for derivative gains included in
income from discontinued operations |
|
|
2.5 |
|
|
|
2.8 |
|
|
|
1.4 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(4.1 |
) |
|
$ |
(5.1 |
) |
|
$ |
(0.2 |
) |
|
$ |
(1.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain/Loss on Sale of Property. Assets sold during the year ended December 31, 2007 generated
a net gain of $1.0 million as compared to a gain of $1.9 million during the year ended December 31,
2006. The 2007 gain was primarily generated from the disposition of unused catalyst material. The
gain in 2006 primarily related to the sale of inactive gas processing facilities acquired as a part
of the south Louisiana processing assets and as part of LIG acquisition.
Depreciation and Amortization. Depreciation and amortization expenses were $83.3 million for
the year ended December 31, 2007 compared to $56.3 million for the year ended December 31, 2006, an
increase of $27.0 million, or 47.9%. Depreciation and amortization increased $26.3 million due to
the NTP, NTG and north Louisiana expansion project assets.
Interest Expense. Interest expense was $48.1 million for the year ended December 31, 2007
compared to $19.9 million for the year ended December 31, 2006, an increase of $28.2 million, or
142.0%. 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 |
|
$ |
23.0 |
|
|
$ |
13.3 |
|
Credit facility |
|
|
24.8 |
|
|
|
7.9 |
|
Capitalized interest |
|
|
(4.8 |
) |
|
|
(5.4 |
) |
Mark to market interest rate swaps |
|
|
1.2 |
|
|
|
(0.1 |
) |
Realized interest rate swaps |
|
|
(0.7 |
) |
|
|
— |
|
Interest income |
|
|
(0.7 |
) |
|
|
(1.1 |
) |
Other |
|
|
5.3 |
|
|
|
5.3 |
|
|
|
|
|
|
|
|
Total |
|
$ |
48.1 |
|
|
$ |
19.9 |
|
|
|
|
|
|
|
|
Discontinued Operations. Income from discontinued operations was $31.3 million for the year
ended December 31, 2007 compared to $20.7 million for the year ended December 31, 2006.
Discontinued operations includes income related to the Seminole gas processing plant disposed of in
November 2008, income related to the Alabama, Mississippi and south Texas assets disposed of in
August 2009 and income related to the Treating assets disposed of in October 2009. The reported
income for the comparative periods has been recast to include 2009 dispositions in income from
discontinued operations.
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.
Revenue Recognition and Commodity Risk Management. We recognize revenue for sales or services
at the time the natural gas or NGLs are delivered or at the time the service is performed. We
generally accrue one to two months of sales and the related gas purchases and reverse these
accruals when the sales and purchases are actually invoiced and recorded in the subsequent months.
Actual results could differ from the accrual estimates.
We utilize extensive estimation procedures to determine the sales and cost of gas purchase
accruals for each accounting cycle. Accruals are based on estimates of volumes flowing each month
from a variety of sources. We use actual measurement data, if it is available, and will use such
data as producer/shipper nominations, prior month average daily flows, estimated flow for new
production and estimated end-user requirements (all adjusted for the estimated impact of weather
patterns) when actual measurement data is not available. Throughout the month or two following
production, actual measured sales and transportation volumes are received and invoiced and used in
a process referred to as “actualization”. Through the actualization process, any estimation
differences recorded through the accrual are reflected in the subsequent month’s 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. We believe that our
accrual process for the one to two months of sales and purchases provides a reasonable estimate of
such sales and purchases.
We engage in price risk management activities in order to minimize the risk from market
fluctuations in the price of natural gas and NGLs. We also manage our 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 our future commitments and
significantly reduce our risk to the movement in natural gas prices.
We use derivatives to hedge against changes in cash flows related to product prices and
interest rate risks, as opposed to their use for trading purposes. FASB ASC 815 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.
We conduct “off-system” gas marketing operations as a service to producers on systems that we
do not own. We refer to these activities as part of energy trading activities. In some cases, we
earn an agency fee from the producer for arranging the marketing of the producer’s natural gas. In
other cases, we purchase the natural gas from the producer and enter 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.
We manage our 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, we are subject to counter-party risk for both the
physical and financial contracts. Our energy trading contracts qualify as derivatives, and we use
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.
Impairment of Long-Lived Assets. In accordance with FASB ASC 360-10-05, we evaluate the
long-lived assets, including related intangibles, of identifiable business activities for
impairment when events or changes in circumstances indicate, in management’s judgment, that the
carrying value of such assets may not be recoverable. The determination of whether impairment has
occurred is based on management’s 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 our long-lived assets has occurred, we must
estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based
on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to
the asset, markets available to the asset, operating expenses, and future natural gas prices and
NGL product prices. The amount of availability of gas to an asset is sometimes based on assumptions
regarding future drilling activity, which may be dependent in part on natural gas prices.
Projections of gas volumes and future commodity prices are inherently subjective and contingent
upon a number of variable factors, including but not limited to:
| |
• |
|
changes in general economic conditions in regions in which our markets are
located; |
| |
| |
• |
|
the availability and prices of natural gas supply; |
| |
| |
• |
|
our ability to negotiate favorable sales agreements; |
| |
| |
• |
|
the risks that natural gas exploration and production activities will not occur
or be successful; |
| |
| |
• |
|
our dependence on certain significant customers, producers, and transporters of
natural gas; and |
| |
| |
• |
|
competition from other midstream companies, including major energy producers. |
Any significant variance in any of the above assumptions or factors could materially affect
our cash flows, which could require us to record an impairment of an asset.
Depreciation Expense and Cost Capitalization. Our assets consist primarily of natural gas
gathering pipelines, processing plants, and transmission pipelines. We capitalize all
construction-related direct labor and material costs, as well as indirect construction costs.
Indirect construction costs include general engineering and the costs of funds used in
construction. 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. We capitalize the costs of renewals and betterments that extend the useful
life, while we expense the costs of repairs, replacements and maintenance projects as incurred.
We generally compute 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, we
may review depreciation estimates 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 flow presented in liquidity discussions includes cash flow from discontinued operations.
Cash Flows from Operating Activities. Net cash provided by operating activities was $173.8
million, $114.8 million and $113.0 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 |
|
$ |
160.9 |
|
|
$ |
138.9 |
|
|
$ |
88.3 |
|
Changes in working capital |
|
|
12.9 |
|
|
|
(24.0 |
) |
|
|
24.7 |
|
The primary reason for the increased cash flow from income before non-cash income and expenses
of $22.0 million from 2007 to 2008 was increased operating income from our expansions 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 $50.6 million from 2006 to 2007 was increased
operating income from our 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, net of accrued amounts, as follows (in millions):
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Years Ended December 31, |
|
| |
|
2008 |
|
|
2007 |
|
|
2006 |
|
Growth capital expenditures |
|
$ |
257.3 |
|
|
$ |
403.7 |
|
|
$ |
308.8 |
|
Acquisitions and asset purchases |
|
|
— |
|
|
|
— |
|
|
|
576.1 |
|
Maintenance capital expenditures |
|
|
18.3 |
|
|
|
10.8 |
|
|
|
6.0 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
275.6 |
|
|
$ |
414.5 |
|
|
$ |
890.9 |
|
|
|
|
|
|
|
|
|
|
|
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 which were
sold in October 2009). 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 $14.6
million, $295.9 million and $772.2 million for the years ended December 31, 2008, 2007 and 2006,
respectively. Our financing activities primarily relate to funding of capital expenditures and
acquisitions. Our financings have primarily consisted of borrowings under our bank credit facility,
borrowings under capital lease obligations, equity offerings and senior note issuances 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 |
|
Net borrowings under capital lease obligations |
|
|
23.9 |
|
|
|
3.6 |
|
|
|
— |
|
Common unit offerings(1) |
|
|
101.9 |
|
|
|
58.8 |
|
|
|
— |
|
Senior subordinated unit offerings(1) |
|
|
— |
|
|
|
102.6 |
|
|
|
368.3 |
|
|
|
|
| (1) |
|
Includes our general partner’s proportionate contribution and net of
costs associated with the offering. |
Distributions to unitholders and our general partner represent our primary use of cash in
financing activities. Unless prohibited by our bank credit facility, we will distribute all
available cash, as defined in our partnership agreement, within 45 days after the end of each
quarter. Total cash distributions made during the last three years were as follows (in millions):
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Years Ended December 31, |
|
| |
|
2008 |
|
|
2007 |
|
|
2006 |
|
Common units |
|
$ |
94.4 |
|
|
$ |
49.8 |
|
|
$ |
39.7 |
|
Subordinated units |
|
|
2.8 |
|
|
|
11.9 |
|
|
|
16.1 |
|
General partner |
|
|
41.2 |
|
|
|
24.8 |
|
|
|
20.4 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
138.4 |
|
|
$ |
86.5 |
|
|
$ |
76.2 |
|
|
|
|
|
|
|
|
|
|
|
In order to reduce our interest costs, we do 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 $32.9 million as of December 31,
2008, primarily due to drafts payable of $21.5 million as of the same date. Our changes in working
capital may fluctuate significantly between periods even though our trade receivables and payables
are typically collected and paid in 30 to 60 day pay cycles. A large volume of our revenues are
collected and a large volume of our 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 my fluctuate
significantly depending on the timing of these receipts and payments. In addition, although we
strive to minimize our 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. Our working capital also includes our mark to market derivative assets
and liabilities associated with our commodity derivatives which may fluctuate significantly due to
the changes in natural gas and NGL prices and associated with our 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, we 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. Crosstex Energy GP, L.P. made a general partner contribution of $2.0 million in
connection with the issuance to maintain its 2% general partner interest.
December 2007 Sale of Common Units. On December 19, 2007, we 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, Crosstex Energy GP, L.P. made a general partner
contribution of $1.2 million in connection with the issuance to maintain its 2% general partner
interest.
March 2007 Sale of Senior Subordinated Series D Units. On March 23, 2007, we 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.
Crosstex Energy GP, L.P. made a general partner contribution of $2.7 million in connection with
this issuance to maintain its 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 units 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 us until March 23, 2009.
June 2006 Sale of Senior Subordinated Series C Units. On June 29, 2006, we 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. CEI purchased 6,414,830 of the senior subordinated series C units. In
addition, Crosstex Energy GP, L.P. made a general partner contribution of $9.0 million in
connection with this issuance to maintain its 2% general partner interest. The senior
subordinated series C units automatically converted to common units 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 we have been successful in accessing capital from both the equity market and
financial institutions to fund the growth of our operations. However, due to the lack of liquidity
in the financial and equity markets coupled with the decline in our Midstream operations, our
access to capital is expected to be severely limited in 2009. We have significantly reduced our
growth plans during 2009 and 2010 to operate within our existing capital structure.
One
of our first steps to continue to operate within our existing
capital structure was to amend the terms of our bank credit facility and senior secured note
agreement to allow us to operate with a higher leverage ratio and a lower interest coverage ratio
due to the anticipated decline in our operating income for 2009 and 2010 based on current economic
conditions. We amended our bank credit facility and our senior secured note agreement in November
2008 and again in February 2009 to provide for terms that we expect will allow us to continue to
operate our assets during the current difficult economic conditions. The terms of the amended
agreements allow us to maintain a higher level of leverage and to maintain a lower interest
coverage ratio but our interest costs will increase, our ability to incur additional indebtedness
will be restricted when we are operating at higher leverage ratios and our ability to pay
distributions will be prohibited until our leverage ratio is significantly lower and we repay the
PIK notes. The PIK notes are due six months after the earlier of the refinancing or maturity of our
bank credit facility. The terms of these agreements and our PIK notes are described more fully
under “Description of Indebtedness.”
We have lowered our 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 our bank credit facility and senior secured note agreement
restrict our ability to make distributions unless certain conditions are met. We do not expect that
we will meet these conditions in 2009.
We have reduced our 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. We will use cash flow from operations and existing capacity under our
bank credit facility to fund our 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 our bank credit facility. It is unlikely that we will be able to make any acquisitions based
on the terms of our credit facility and our senior secured note agreement and the condition of the
capital markets because we 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.
We have reduced our general and administrative expenses by reducing our work force by
approximately 8.0% through the elimination of open positions and certain corporate positions and
minimizing all non-essential costs. We have also reduced our 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 our 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 |
|
|
86.5 |
|
|
|
27.2 |
|
|
|
18.5 |
|
|
|
17.7 |
|
|
|
16.3 |
|
|
|
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 |
|
$ |
1,592.7 |
|
|
$ |
92.7 |
|
|
$ |
79.1 |
|
|
$ |
872.6 |
|
|
$ |
143.9 |
|
|
$ |
123.2 |
|
|
$ |
281.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The above table does not include any physical or financial contract purchase commitments for
natural gas.
The interest payable under our bank 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.
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, we 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 our
material pipeline, gas gathering and processing assets, all material working capital assets and a
pledge of all of our equity interests in substantially all of our subsidiaries, and rank pari passu
in right of payment with the senior secured notes. The bank credit facility is guaranteed by our
material subsidiaries. We 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, we entered into the Fifth Amendment and Consent (the “Fifth Amendment”)
to our 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 our
credit facility to, among other things, (i) increase the maximum permitted leverage ratio we must
maintain for the fiscal quarters ending December 31, 2008 through September 30, 2009, (ii) lower
the minimum interest coverage ratio we must maintain for the fiscal quarter ending December 31,
2008 and each fiscal quarter thereafter, (iii) permit us to sell certain assets, (iv) increase the
interest rate we pay on the obligations under the credit facility and (v) lower the maximum
permitted leverage ratio we must maintain if we or our subsidiaries incur unsecured note
indebtedness.
Due to the continued decline in commodity prices and the deterioration in the processing
margins, we determined that there was a significant risk that the amended terms negotiated in
November 2008 would not be sufficient to allow us to operate during 2009 without triggering a
covenant default under our bank credit facility and the senior secured note agreement. On February
27, 2009, we entered into the Sixth Amendment to Fourth Amended and Restated Credit Agreement and
Consent (the “Sixth Amendment”) to our credit facility with the Bank Lending Group. Under the Sixth
Amendment, borrowings will bear interest at our option at the administrative agent’s reference rate
plus an applicable margin or LIBOR plus an applicable margin. The applicable margins for the
Partnership’s interest rate and letter of credit fees vary quarterly based on the Partnership’s
leverage ratio as defined by the credit facility (the “Leverage Ratio” being generally 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 |
|
LIBOR Rate |
|
Letter of |
|
Commitment |
| Leverage Ratio |
|
Rate Advances(a) |
|
Advances(b) |
|
Credit 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 our current leverage ratio.
Based on our forecasted leverage ratios for 2009, we expect the applicable margins to be at the
high end of these ranges for our interest rate and letter of credit fees.
Pursuant to the Sixth Amendment, we must pay a leverage fee if we do 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, we must pay a leverage fee on such date, equal to the product of the
total amounts outstanding under our 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 we refinance our
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 any fiscal quarter ending March 31, 2011 through March 31, 2012; and |
| |
| |
• |
|
4.25 to 1.00 for any fiscal quarter ending June 30, 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 quarters 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 quarter ending September 30, 2010 and December 31, 2010; and |
| |
| |
• |
|
2.50 to 1.00 for any fiscal quarter ending March 31, 2011 and thereafter. |
Under the Sixth Amendment, no quarterly distributions may be paid to unitholders 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, we 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,
we may make quarterly distributions to unitholders from available cash as provided by our
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 our bank credit facility. In order to repay the PIK notes
prior to their scheduled maturity, we will need to amend or refinance our bank credit facility.
Based on our forecasted leverage ratios for 2009 and our near term ability to refinance our bank
credit facility, we do 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 our 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 amended 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 our bank credit facility, which
previously had permitted us 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. We 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* |
|
Repayment |
|
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. |
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 our 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 our business; |
| |
| |
• |
|
enter into certain commodity contracts; |
| |
• |
|
make certain amendments to our or the operating partnership’s 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 us or any of our subsidiaries, in excess of certain allowances; |
| |
| |
• |
|
certain ERISA events involving us or our 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 our 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.
We are subject to interest rate risk on our credit facility and have entered into interest
rate swaps to reduce this risk.
Senior Secured Notes. We 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 we 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 $49,000 from July 2012-July 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Issued |
|
|
505,000 |
|
|
|
|
|
|
|
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Principal repaid |
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(25,294 |
) |
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Balance as of December 31, 2008 |
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$ |
479,706 |
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| (1) |
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Interest rates have been adjusted to give effect to the 2% interest rate increase under the February 27,
2009 amendment described below. |
| |
| (2) |
|
Principal repayments were $19.4 million and $5.9 million on the June 2003 and July 2003 notes, respectively. |
On November 7, 2008, we amended our senior secured note agreement governing our senior secured
notes to, among other things, (i) modify the maximum permitted leverage ratio and lower the minimum
interest coverage ratio we must maintain consistent with the ratios under the Fifth Amendment to
the bank credit facility, (ii) permit us to sell certain assets and (iii) increase the interest
rate we pay on the senior secured notes. The interest rate we paid on the senior secured notes
increased by 1.25% for the fourth quarter of 2008 due to this amendment.
The covenant and terms of default for the senior secured notes are substantially the same as
the covenants and default terms under our bank credit facility, and therefore the agreement
governing the senior secured notes also required amendment in 2009. On February 27, 2009, we
amended our senior note agreement to (i) increase the maximum permitted leverage ratio and to lower
the minimum interest coverage ratio we 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
we pay 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 we pay
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 of the outstanding balance on
the senior secured notes is approximately 9.25% as of February 2009.
Under the amended senior secured notes agreement, the senior secured notes will accrue
additional interest of 1.25% per annum of the senior secured note (the “PIK notes”) in the form of
an increase in the principal amount unless our 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 our 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 notes agreement, commencing on the date we refinance our
bank credit facility, the interest rate payable in cash on our 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 our senior secured notes will increase by 0.50% per annum for any
quarter if our 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 we are paying the incremental 1.25%
per annum of interest described in the preceding sentence.
These notes represent our 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
our obligations under the credit facility, by first priority liens on all of our material pipeline,
gas gathering and processing assets, all material working capital assets and a pledge of all our
equity interests in substantially all of our subsidiaries. The senior secured notes are guaranteed
by our material subsidiaries.
The senior secured notes issued in 2003 are redeemable, at our 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 our bank credit facility.
We were in compliance with all debt covenants at December 31, 2008 and 2007 and expect 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 our 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 us and our 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 our bank credit facility and the purchasers of the senior
secured notes. This agreement specifies various rights and obligations of lenders under our bank
credit facility, holders of our senior secured notes and the other parties thereto in respect of
the collateral securing the Partnership’s obligations under our bank credit facility and the senior
secured note agreement. On February 27, 2009, the holders of the Partnership’s 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 our customers are a major concern in our business.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and
other counterparties, such as our lenders and hedging counterparties. Any increase in the
nonpayment and nonperformance by our customers could adversely affect our results of operations and
reduce our ability to make distributions to our unitholders. Many of our 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 our 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 our customers’ liquidity and ability to
make payments or perform on their obligations to us. Furthermore, some of our 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 us.
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
Our operations are subject to environmental laws and regulations adopted by various
governmental authorities in the jurisdictions in which these operations are conducted. We believe
we are 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 Processing’s 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 Denbury’s 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 Denbury’s allegations and asserting that they are improper parties as
Denbury’s 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, we do not believe this will have a material adverse
effect on our 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 us as part of our
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 ultimate outcomes of these matters, we do not believe that these claims will have a
material adverse impact on our 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. We believe the July sales of $2.2 million will
receive “administrative claim” status in the bankruptcy proceeding. The debtor’s schedules
acknowledge its obligation to us 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. We evaluated these receivables for collectability and provided a valuation allowance of $3.1
million during 2008.
Recent Accounting Pronouncements
As a result of the recent credit crisis, FASB ASC 820-10-35-15A was issued October 2008 and
clarifies the application of FASB ASC 820 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. FASB ASC
820-10-35-15A is effective upon issuance, for companies that have adopted FASB ASC 820. The
Partnership has evaluated FASB ASC 820-10-35-15A and determined that this standard has no impact on
its results of operations, cash flows or financial position for this reporting period.
FASB ASC 260-10-45-60 was issued June 2008 and requires unvested share-based payment awards
that contain nonforfeitable rights to dividends or dividend equivalents to be treated as
participating securities as defined in FASB ASC 260-10-20 and, therefore, included in the earnings
allocation in computing earnings per share under the two-class method described in FASB ASC 260.
FASB
ASC 260-10-45-60 is effective for financial statements issued for fiscal years beginning after
December 15, 2008 and interim periods within those years. Upon adoption, the Partnership 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.
FASB ASC 825-10-05-5 was issued February 2007 and 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. FASB
ASC 825-10-05-5 also establishes presentation and disclosure requirements designed to draw
comparisons between the different measurement attributes elected for similar types of assets and
liabilities. FASB ASC 825-10-05-5 was adopted effective January 1, 2008 and did not have a material
impact on our financial statements.
FASB ASC 805 and FASB ASC 810-10-65-1 were issued December 2007. FASB ASC 805 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 FASB ASC 805 all business combinations will be accounted for by applying the acquisition
method. FASB ASC 805 is effective for periods beginning on or after December 15, 2008. FASB ASC
810-10-65-1 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. FASB ASC 810-10-65-1 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 FASB ASC 810-10-65-1.
In addition, FASB ASC 260-10-55-102 addresses the consensus reached by the Task Force that
incentive distribution rights (IDRs) in a typical master limited partnership are participating
securities under FASB ASC 260, but earnings in excess of the partnership’s “available cash” should
not be allocated to the IDR holders for purposes of calculating earnings-per-share using the
two-class method when “available cash” represents a specified threshold that limits participation.
The consensus only applies when payments to IDR holders are accounted for as equity distributions.
The consensus is effective for fiscal years beginning after December 15, 2008 and applied
retrospectively to all periods presented. Under our partnership agreement, “available cash” is a
specified threshold that limits participation for IDR holders. Therefore earnings in excess of our
“available cash” during periods presented were not allocated to IDR holders.
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 Partnership is currently evaluating the
potential impact, if any, of the adoption of SFAS No. 162 on our consolidated financial statements.
FASB ASC 815-10-65-1 was issued March 2008 and 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 FASB ASC 815 and how the instruments and related
hedged items affect the financial position, results of operations and cash flows of the entity.
FASB ASC 815-10-65-1 is effective for fiscal years beginning after November 15, 2008. The principal
impact to the Partnership 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
management’s 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.