(1) Organization and Summary of Significant Agreements

(a)       Description of Business

Crosstex Energy, L.P., a Delaware limited partnership formed on July 12, 2002, is engaged in the gathering, processing, transmission and marketing to producers of natural gas, NGLs, and crude oil. We also provide crude oil, condensate and brine services to producers. We connect the wells of natural gas producers in our market areas to our gathering systems, process natural gas for the removal of NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee arrangements. In addition, we purchase natural gas from producers not connected to our gathering systems for resale and sell natural gas on behalf of producers for a fee. We provide a variety of crude services throughout the Ohio River Valley (ORV) which include crude oil gathering via pipelines and trucks and oilfield brine disposal. We also have crude oil terminal facilities in south Louisiana that provide access for crude oil producers to the premium markets in this area.

Crosstex Energy GP, LLC

(b) Partnership Ownership

Crosstex Energy GP, LLC, the general partner of the Partnership, is a direct wholly-owned subsidiary of Crosstex Energy, Inc. (CEI). As of December 31, 2012, CEI owns 16,414,830 common units in the Partnership through its wholly-owned subsidiaries. As of December 31, 2012, CEI owned 19.7% (17.3% effective following the Partnership's January 2013 offerings) of the limited partner interests in the Partnership and a 1.9% (1.6% effective following the Partnership's January 2013 offering) general partner interest. On September 13, 2012, the board of directors of the general partner amended the partnership agreement to convert the general partner's obligation to make capital contributions to the Partnership to maintain its 2% interest in connection with the issuance of additional limited interests by the Partnership to an option of the general partner to make future capital contributions to maintain its then current general partner percentage interest.

(c) Basis of Presentation

The accompanying consolidated financial statements include the assets, liabilities and results of operations of the Partnership and its wholly-owned subsidiaries. The Partnership proportionately consolidates its undivided 50.0% interest in a gas processing plant located in the Permian Basin and its undivided 64.29% interest in a gas plant located in south Louisiana. The Partnership also consolidates its majority interest in Crosstex DC Gathering, J.V. (CDC). until October 2012 when it acquired the remaining interest for $0.4 million. The consolidated operations are hereafter referred to collectively as the “Partnership.” All material intercompany balances and transactions have been eliminated.

(2) Significant Accounting Policies

(a) Management's Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management of the Partnership to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

(b) Cash and Cash Equivalents

The Partnership considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(c) Natural Gas and Natural Gas Liquids Inventory

The Partnership's inventories of products consist of natural gas and NGLs. The Partnership reports these assets at the lower of cost or market.

(d) Property, Plant, and Equipment

Property, plant and equipment consist of intrastate gas transmission systems, gas gathering systems, NGL and crude oil pipelines, natural gas processing plants, NGL fractionation plants and brine disposal wells. Gas required to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Other property and equipment is primarily comprised of the ORV trucking fleet, computer software and equipment, furniture, fixtures, leasehold improvements and office equipment. Property, plant and equipment are recorded at cost. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Interest costs are capitalized to property, plant and equipment during the period the assets are undergoing preparation for intended use. Interest costs totaling $ 4.0 million, $0.9 million and $0.1 million were capitalized for the years ended December 31, 2012, 2011 and 2010, respectively.

Depreciation is provided using the straight-line method based on the estimated useful life of each asset, as follows:

Depreciation expense of $98.1 million, $77.8 million and $75.7 million was recorded for the years ended December 31, 2012, 2011 and 2010, respectively. Depreciation expense also includes the amortization of assets classified as capital lease assets.

FASB ASC 360-10-05-4 requires long-lived assets to be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. In order to determine whether an impairment has occurred, the Partnership compares the net book value of the asset to the undiscounted expected future net cash flows. If an impairment has occurred, the amount of such impairment is determined based on the expected future net cash flows discounted using a rate commensurate with the risk associated with the asset.

When determining whether impairment of one of our long-lived assets has occurred, the Partnership must estimate the undiscounted cash flows attributable to the asset. The Partnership's estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas and crude oil 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 and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas and crude oil prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

(e) Goodwill and Intangible Assets

The Partnership has approximately $152.6 million of goodwill at December 31, 2012 related to the acquisition of Clearfield Energy, Inc. and its wholly-owned subsidiaries (collectively, “Clearfield”) in July 2012. The goodwill recognized from the Clearfield acquisition results primarily from the value of opportunity created from the strategic asset positioning in the Utica and Marcellus shale plays which provides the Partnership with a substantial growth platform in a new geographic area. The goodwill is allocated to the ORV segment. Goodwill will be assessed at least annually for impairment beginning on July1, 2013.

Intangible assets consist of customer relationships and the value of the dedicated and non-dedicated acreage attributable to pipeline, gathering and processing systems. Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from three to twenty years. The intangible assets associated with dedicated and non-dedicated acreage attributable to pipeline, gathering and processing systems are being amortized using the units of throughput method of amortization.

The following table represents the Partnership's total purchased intangible assets at years ended December 31, 2012 and 2011 (in thousands):

The weighted average amortization period for intangible assets is 18.1 years. Amortization expense for intangibles was approximately $64.1 million, $47.5 million and $35.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

The following table summarizes the Partnership's estimated aggregate amortization expense for the next five years (in thousands):

(f) Investment in Limited Liability Company

On June 22, 2011, the Partnership entered into a limited liability agreement with Howard Energy Partners (“HEP”) for an initial capital contribution of $35.0 million in exchange for an individual ownership interest in HEP. In 2012, the Partnership made an additional capital contribution of $52.3 million to HEP related to HEP's acquisition of substantially all of Meritage Midstream Services' natural gas gathering assets in south Texas. HEP owns midstream assets and provides midstream services to Eagle Ford Shale producers. The Partnership owns 30.6 percent of HEP and accounts for this investment under the equity method of accounting. This investment is reflected on the balance sheet as “Investment in limited liability company.” The Partnership's proportional share of earnings is recorded as an increase to this investment account and recorded as equity in earnings of limited liability company.

(g) Other Assets

Unamortized debt issuance costs totaling $26.0 million and $24.2 million as of December 31, 2012 and 2011, respectively, are included in other assets, net. Debt issuance costs are amortized into interest expense using the straight-line method over the terms of the debt.

(h) Gas Imbalance Accounting

Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. The Partnership had imbalance payables of $2.3 million and $2.3 million at December 31, 2012 and 2011, respectively, which approximate the fair value of these imbalances. The Partnership had imbalance receivables of $1.5 million and $1.7 million at December 31, 2012 and 2011, respectively, which are carried at the lower of cost or market value.

(i) Asset Retirement Obligations

FASB ASC 410-20-25-16 was issued in March 2005, which became effective at December 31, 2005. FASB ASC 410-20-25-16 clarifies that the term “conditional asset retirement obligation” as used in FASB ASC 410-20, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FASB ASC 410-20-25-16 provides that a liability for the fair value of a conditional asset retirement activity should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FASB ASC 410-20-25-16 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation under FASB ASC 410-20. The Partnership provided an asset retirement obligation of $0.5 million as of December 31, 2012 related to the discontinued use of the Sabine Pass plant. The Partnership did not provide any asset retirement obligations as of 2011 because it did not have sufficient information as set forth in FASB ASC 410-20-25-16 to reasonably estimate such obligations, and the Partnership had no intention of discontinuing use of any significant assets. See Note 2 “Acquisition, Disposition, and Impairments” for further discussion of the Sabine Pass plant.

(j) Revenue Recognition

The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs or crude oil are delivered or at the time the service is performed. The Partnership generally accrues one month of sales and the related gas purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates. The Partnership's purchase and sale arrangements are generally reported in revenues and costs on a gross basis in the consolidated statement of operations in accordance with FASB ASC 605-45-45-1. Except for fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, has the risk and reward of ownership as evidenced by title transfer, schedules the transportation and assumes credit risk. 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 included in revenue on a net basis in the consolidated statement of operations.

The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

(k) Derivatives

The Partnership uses derivatives to hedge against changes in cash flows related to product price, as opposed to their use for trading purposes. FASB ASC 815 requires that all derivatives be recorded on the balance sheet at fair value. We generally determine the fair value of futures contracts and swap contracts based on the difference between the derivative's fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet in fair value of derivative assets or liabilities.

Realized and unrealized gains and losses on commodity related derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, are recorded as gain or loss on derivatives in the consolidated statement of operations. Realized and unrealized gains and losses on interest rate derivatives that are not designated as hedges are included in interest expense in the consolidated statement of operations. Unrealized gains and losses on effective cash flow hedge derivatives are recorded as a component of accumulated other comprehensive income. When the hedged transaction occurs, the realized gain or loss on the hedge derivative is transferred from accumulated other comprehensive income to earnings. Realized gains and losses on commodity hedge derivatives are recognized in revenues, and realized gains and losses on interest hedge derivatives are recorded as adjustments to interest expense. Settlements of derivatives are included in cash flows from operating activities.

(l) Comprehensive Income (Loss)

Comprehensive income includes net income (loss) and other comprehensive income, which includes unrealized gains and losses on derivative financial instruments. Pursuant to FASB ASC 815, the Partnership records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.

(m) Legal Costs Expected to be Incurred in Connection with a Loss Contingency

Legal costs incurred in connection with a loss contingency are expensed as incurred.

(n) Concentrations of Credit Risk

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist primarily of trade accounts receivable and derivative financial instruments. Management believes the risk is limited since the Partnership's customers represent a broad and diverse group of energy marketers and end users. In addition, the Partnership continually monitors and reviews credit exposure to its marketing counter-parties and letters of credit or other appropriate security are obtained as considered necessary to limit the risk of loss. The Partnership records reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers. The Partnership had a reserve for uncollectible receivables as of December 31, 2012, 2011 and 2010 of $0.5 million, $0.4 million and $0.2 million, respectively.

During the years ended December 31, 2012 and 2011, the Partnership had only one customer that represented greater than 10.0% individually of its revenue. The customer is located in the LIG segment and represented 10.5% and 12.3% of the consolidated revenue for each of the years ended December 31, 2012 and 2011, respectively. During the year ended December 31, 2010, three customers accounted for 14.5%, 10.6%, and 10.2% of consolidated revenue. As the Partnership continues to grow and expand, the relationship between individual customer sales and consolidated total sales is expected to continue to change. While these customers represent a significant percentage of revenues, the loss of these customers would not have a material adverse impact on the Partnership's results of operations because the gross operating margin received from transactions with these customers are not material to the Partnership's gross operating margin.

(o) Environmental Costs

Environmental expenditures are expensed or capitalized as appropriate, depending on the nature of the expenditures and their future economic benefit. Expenditures that related to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. For the years ended December 31, 2012, 2011 and 2010, such expenditures were not significant.

(p) Share-Based Awards

The Partnership recognizes compensation cost related to all stock-based awards, including stock options, in its consolidated financial statements in accordance with FASB ASC 718. The Partnership and CEI each have similar unit or share-based payment plans for employees, which are described below. Share-based compensation associated with CEI's share-based compensation plans awarded to officers and employees of the general partner of the Partnership are recorded by the Partnership since CEI has no operating activities other than its interest in the Partnership. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in thousands):

(q) Recent Accounting Pronouncements

We have reviewed recently issued accounting pronouncements that became effective during the year ended December 31, 2012, and have determined that none would have a material impact on our Consolidated Financial Statements.

(3) Acquisition, Disposition and Impairments

(a) Acquisition

On July 2, 2012, the Partnership, through a wholly-owned subsidiary, acquired all of the issued and outstanding common stock of Clearfield Energy, Inc. and Clearfield Energy's wholly owned subsidiaries (collectively, “Clearfield”). Clearfield is a well-established crude oil, condensate and water services company with operations in Ohio, Kentucky and West Virginia. Clearfield's business includes crude oil pipelines, a barge loading terminal on the Ohio River, a rail loading terminal on the Ohio Central Railroad network, a trucking fleet and brine disposal wells. All of these assets are now included in the Partnership's ORV segment.

The Partnership paid approximately $215.0 million in cash (before working capital and certain purchase price adjustments) for the acquisition and the purchase was funded with proceeds from the senior notes offering in May 2012.

Included in the Clearfield acquisition were three local distribution companies, or LDCs, which the Partnership marketed for sale and were classified as held for disposition on the balance sheet as of December 31, 2012. The Partnership chose not to apply discontinued operations presentation on the income statement as the related amounts are immaterial during the period of the Partnership's ownership. On October 15, 2012, the Partnership entered into an agreement to sell the LDCs for an amount of $19.5 million, and the sale was completed on January 18, 2013. The assets held for disposition net of liabilities assumed are recorded at the sales price of $19.5 million.

The goodwill recognized from the Clearfield acquisition results primarily from the value of opportunity created from the strategic asset positioning in the Utica and Marcellus shale plays which provides the Partnership with a substantial growth platform in a new geographic area.

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 20 years.

The Partnership assumed a long-term liability related to additional benefit obligations. Also, the Partnership assumed a long-term liability related to inactive easement commitments for a period of 10 years.

Purchase Price Allocation in Clearfield Acquisition

Based on currently available information, the following table is a summary of the consideration paid for the Clearfield acquisition and the preliminary purchase price allocation for the fair value of the assets acquired and liabilities assumed at the acquisition date, subject to revision pending finalization of closing adjustments and the sale of the LDC assets:

For the period from July 2, 2012 to December 31, 2012, the Partnership recognized $108.0 million of midstream revenue related to properties acquired in the Clearfield acquisition. For the period from July 2, 2012 to December 31, 2012, the Partnership recognized $94.2 million of operating costs and expenses related to properties acquired in the Clearfield acquisition.

Pro Forma Information

The following unaudited pro forma condensed financial data for the year ended December 31, 2012 and 2011 gives effect to the Clearfield acquisition as if it had occurred on January 1, 2011. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.

(b) Other Disposition

The Partnership disposed of assets that were not considered discontinued operations in the year ended December 31, 2010. The 2010 disposition was related to assets in east Texas for a gain of $14.0 million.

(c) Long-Lived Assets Impairments

Impairments of $1.3 million were recorded in the year ended December 31, 2010 related to long-lived assets. The impairment in 2010 primarily relates to the write down of certain excess pipe inventory prior to its sale.

Changes in Operations During 2012 and 2013.

Our Sabine Pass plant held a contract with a third-party to fractionate the raw-make NGLs produced by the Sabine Pass plant. The primary term of the contract expired in March 2012 and was renewed on a month-to-month basis. Due to the anticipated termination of this third-party fractionation agreement in early 2013, we began accelerating depreciation of this facility during the third quarter of 2012. The plant also had some equipment failures during the fourth quarter of 2012. In January 2013, we ceased plant operations because the cost to repair the equipment could not be supported by an existing month-to-month fractionation agreement. Depreciation and amortization expense during the fourth quarter 2012 was changed to accelerate the remaining non-recoverable costs associated with the plant. Total depreciation and amortization of $28.9 million was recognized for the Sabine Pass plant during 2012. The Sabine Pass plant contributed gross operating margin of $2.0 million and $2.7 million for the years ended December 31, 2012 and 2011, respectively. The net book value for the plant is $20.0 million as of December 31, 2012 and represents the plant's fair market value. Although we do not have specific plans at this time to relocate the Sabine Pass plant, we may utilize it elsewhere in our operations.

(4) Long-Term Debt

As of December 31, 2012 and 2011, long-term debt consisted of the following (in thousands):

Maturities. Maturities for the long-term debt as of December 31, 2012 are as follows (in thousands):

Credit Facility. In January 2012, the Partnership amended its credit facility to increase the Partnership's borrowing capacity from $485.0 million to $635.0 million and amend certain terms under the facility to provide additional financial flexibility during the remaining four-year term of the facility.

The Partnership amended the credit facility again in May 2012. This amendment, among other things, increased the maximum permitted consolidated leverage ratio (as defined in the amended credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) during the Clearfield acquisition period (as defined in the amended credit facility, being generally the four quarterly measurement periods after closing the Clearfield acquisition) from 5.0 to 1.0 to 5.5 to 1.0.

In August 2012, the Partnership amended the credit facility to include projected EBITDA from material projects (as defined in the amendment, but generally being the construction or expansion of any capital project by the Partnership or any of its subsidiaries that is expected to cost more than $20.0 million and the Partnership's “Riverside Phase II” project) in its EBITDA for purposes of calculating compliance with the amended credit agreement's minimum interest coverage ratio, maximum leverage ratio and maximum senior leverage ratio. The amount of projected EBITDA from material projects that is included in such financial covenant calculations is subject to the approval of Bank of America, N.A. (the “Administrative Agent”), and it will be based on contracts related to the material project, expected expenses, the completion percentage of the material project, the expected commercial operation date of the material project, and other factors deemed appropriate by the Administrative Agent. The aggregate amount of all material project EBITDA adjustments during any period shall be limited to 15% of the total actual consolidated EBITDA for such period (which total actual consolidated EBITDA shall be determined without including any material project EBITDA adjustments).

In January 2013, the Partnership amended the credit facility to, among other things, (i) decrease the minimum consolidated interest coverage ratio (as defined in the amended credit agreement, being generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) to 2.25 to 1.0 for the fiscal quarters ending September 30, 2013 and December 31, 2013, with a minimum ratio of 2.50 to 1.0 for each fiscal quarter ending thereafter, (ii) increase the maximum permitted consolidated leverage ratio (as defined in the amended credit agreement, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) to 5.50 to 1.0 for each fiscal quarter ending on or prior to December 31, 2013, with a maximum ratio of 5.25 to 1.0 for each fiscal quarter ending thereafter, and (iii) eliminate the existing and any future step-up in the maximum permitted consolidated leverage ratio for acquisitions.

As of December 31, 2012, there was $71.0 million of borrowing and $62.2 million in outstanding letters of credit, under the bank credit facility leaving approximately $501.8 million available for future borrowing based on a borrowing capacity of $635.0 million. However, the financial covenants in the amended credit facility limit the amount of funds that we can borrow. As of December 31, 2012, based on the financial covenants in the amended credit facility, we could borrow approximately $334.6 million of additional funds.

The credit facility is guaranteed by substantially all of our subsidiaries and is secured by first priority liens on substantially all of our assets and those of the guarantors, including all 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.

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. The credit facility requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, extraordinary receipts, equity issuances and debt incurrences, but these mandatory prepayments do not require any reduction of the lenders' commitments under the credit facility.

Under the amended credit facility, borrowings bear interest at our option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent's prime rate) plus an applicable margin. We pay a per annum fee (as described below) on all letters of credit issued under the amended credit facility and a commitment fee of between 0.375% and 0.50% per annum on the unused availability under the amended credit facility. The commitment fee, letter of credit fee and the applicable margins for the interest rate vary quarterly based on our leverage ratio (as defined in the credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows:

The amended credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The maximum permitted leverage ratio (as defined in the credit facility, but generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 5.50 to 1.00 for the fiscal quarters ending on or before December 31, 2013 with a maximum ratio of 5.25 to 1.00 for each fiscal quarter thereafter. The maximum permitted senior leverage ratio (as defined in the credit facility, but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non cash charges) is 2.75 to 1.00. The minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.25 to 1.00 for the fiscal quarters ending on or before December 31, 2013, with a minimum ratio of 2.50 to 1.0 for each fiscal quarter ending thereafter.

In addition, the credit facility contains various covenants that, among other restrictions, limit the Partnerhship's ability to:

• grant or assume liens;

   

• make investments;

   

• incur or assume indebtedness;

   

• engage in mergers or acquisitions;

   

• sell, transfer, assign or convey assets;

   

• repurchase the Partnership's equity, make distributions and certain other restricted payments;

   

• change the nature of the Partnership's business;

   

• engage in transactions with affiliates;

   

• enter into certain burdensome agreements;

   

• make certain amendments to the omnibus agreement or the Partnership's subsidiaries' organizational documents;

   

• prepay the senior unsecured notes and certain other indebtedness; and

   

• enter into certain hedging contracts.

The credit facility permits the Partnership to make quarterly distributions to unitholders so long as no default exists under the credit facility.

Each of the following is an event of default under the credit facility:

• failure to pay any principal, interest, fees, expenses or other amounts when due;

   

• failure to meet the quarterly financial covenants;

   

• failure to observe any other agreement, obligation, or covenant in the credit facility or any related loan document, subject to cure periods for certain failures;

   

• the failure of any representation or warranty to be materially true and correct when made;

   

• The Partnership's or any of its subsidiaries default under other indebtedness that exceeds a threshold amount;

   

• judgments against the Partnership or any of its material subsidiaries, in excess of a threshold amount;

   

• certain ERISA events involving the Partnership or any of its material subsidiaries, in excess of a threshold amount;

   

• bankruptcy or other insolvency events involving the Partnership or any of its material subsidiaries; and

   

• a change in control (as defined in the credit facility).

If an event of default relating to bankruptcy or other insolvency events occurs, all indebtedness under the credit facility will immediately become due and payable. If any other event of default exists under the credit facility, the lenders may accelerate the maturity of the obligations outstanding under the credit facility and exercise other rights and remedies. In addition, if any event of default exists under the credit facility, the lenders may commence foreclosure or other actions against the collateral.

If any default occurs under the credit facility, or if the Partnership is unable to make any of the representations and warranties in the credit facility, the Partnership will be unable to borrow funds or have letters of credit issued under the credit facility.

The Partnership expects to be in compliance with the covenants in the credit facility for at least the next twelve months.

Senior Unsecured Notes. On February 10, 2010, the Partnership and Crosstex Energy Finance Corporation issued $725.0 million in aggregate principal amount of 8.875% senior unsecured notes (the “2018 Notes”) due on February 15, 2018 at an issue price of 97.907% to yield 9.25% to maturity including the original issue discount (OID). Net proceeds from the sale of the notes of $689.7 million (net of transaction costs and OID), together with borrowings under the credit facility discussed above, were used to repay in full amounts outstanding under the prior bank credit facility and senior secured notes and to pay related fees, costs and expenses, including the settlement of interest rate swaps associated with the prior credit facility. Interest payments on the notes are due semi-annually in arrears in February and August.

On May 24, 2012, the Partnership and Crosstex Energy Finance Corporation issued $250.0 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes” and together with the 2018 Notes, the “Senior Notes”) due on June 1, 2022 at an issue price of 100% of the principal amount to yield 7.125% to maturity. The interest payments are due semi-annually in arrears in June and December. Net proceeds from the sale of the notes of $245.1 million (net of transaction costs) were used to fund the Clearfield acquisition and for general partnership purposes, including capital expenditures for the Cajun-Sibon NGLs pipeline expansion.

The indentures governing the Senior Notes contain covenants that, among other things, limit the Partnership's ability and the ability of certain of its subsidiaries to:

• sell assets including equity interests in its subsidiaries;

   

• pay distributions on, redeem or repurchase units or redeem or repurchase its subordinated debt (as discussed in more detail below);

   

• make investments;

   

• incur or guarantee additional indebtedness or issue preferred units;

   

• create or incur certain liens;

   

• enter into agreements that restrict distributions or other payments from its restricted subsidiaries to the Partnership;

   

• consolidate, merge or transfer all or substantially all of its assets;

   

• engage in transactions with affiliates;

   

• create unrestricted subsidiaries;

   

• enter into sale and leaseback transactions; or

   

• engage in certain business activities.

The indentures provide that if the Partnership's fixed charge coverage ratio (the ratio of consolidated cash flow to fixed charges, which generally represents the ratio of adjusted EBITDA to interest charges with further adjustments as defined per the indenture) for the most recently ended four full fiscal quarters is not less than 2.00 to 1.0, the Partnership will be permitted to pay distributions to its unitholders in an amount equal to available cash from operating surplus (each as defined in our partnership agreement) with respect to its preceding fiscal quarter plus a number of items, including the net cash proceeds received by the Partnership as a capital contribution or from the issuance of equity interests since the date of the indenture, to the extent not previously expended. If the Partnership's fixed charge coverage ratio is less than 2.00 to 1.0, the Partnership will be able to pay distributions to its unitholders in an amount equal to a specified basket (less amounts previously expended pursuant to such basket), plus the same number of items discussed in the preceding sentence to the extent not previously expended. The Partnership was in compliance with this covenant as of December 31, 2012.

If the Senior Notes achieve an investment grade rating from each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services, many of the covenants discussed above will terminate. Our current ratings on our bonds from Moody's Investors Service, Inc. and Standard & Poor's Rating Services are B2 and B+, respectively.

Prior to February 15, 2014, the Partnership may redeem the 2018 Notes, in whole or in part, at a “make-whole” redemption price. On or after February 15, 2014, the Partnership may redeem all or a part of the notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on February 15, 2014, 102.219% for the twelve-month period beginning February 15, 2015 and 100.00% for the twelve-month period beginning on February 15, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the notes.

The Partnership may redeem up to 35% of the 2022 Notes at any time prior to June 1, 2015 in an amount not greater than the cash proceeds from equity offerings at a redemption price of 107.125% of the principal amount of the 2022 Notes (plus accrued and unpaid interest to the redemption date) provided that:

• at least 65% of the aggregate principal amount of the 2022 Notes remains outstanding immediately after the occurrence of such redemption; and

   

• the redemption occurs within 180 days of the date of the closing of the equity offering.

Prior to June 1, 2017, the Partnership may redeem all or a part of the 2022 Notes at the redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest to the redemption date.

On or after June 1, 2017, the Partnership may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.563% for the twelve-month period beginning on June 1, 2017, 102.375% for the twelve-month period beginning on June 1, 2018, 101.188% for the twelve-month period beginning on June 1, 2019 and 100.000% for the twelve-month period beginning on June 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

Each of the following is an event of default under the indenture:

• failure to pay any principal or interest when due;

   

• failure to observe any other agreement, obligation, or other covenant in the indenture, subject to the cure periods for certain failures;

   

• the Partnership's or any of its subsidiaries' default under other indebtedness that exceeds a certain threshold amount;

   

• failures by the Partnership or any of its subsidiaries to pay final judgments that exceed a certain threshold amount; and

   

• bankruptcy or other insolvency events involving the Partnership or any of its material subsidiaries.

If an event of default relating to bankruptcy or other insolvency events occurs, the Senior Notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the Senior Notes may accelerate the maturity of the Senior Notes and exercise other rights and remedies.

Non Guarantors. The Senior Notes are jointly and severally guaranteed by each of the Partnership's current material subsidiaries (the “Guarantors”), with the exception of our regulated Louisiana subsidiaries (which may only guarantee up to $500.0 million of the Partnership's debt) and Crosstex Energy Finance Corporation (a wholly owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Partnership's indebtedness, including the Senior Notes). Guarantors may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into another company if such a sale would cause a default under the terms of the Senior Notes. The Partnership has no assets or operations independent of its subsidiaries. There are no significant restrictions on the ability of the Partnership or any Subsidiary Guarantor to obtain funds from its subsidiaries by dividend or loan. Since certain wholly owned subsidiaries do not guarantee the Senior Notes, the condensed consolidating financial statements of the guarantors and non-guarantors as of and for the years ended December 31, 2012 and 2011 are disclosed below in accordance with Rule 3-10 of Regulation S-X. Comprehensive income (loss) is not included in the condensed consolidating statements of operations of the guarantors and non-guarantors for the years ended December 31, 2012, 2011 and 2010 as these amounts are not considered material.