Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

ý Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the quarterly period ended September 30, 2013

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the transition period from to

Commission file number: 000-50536

CROSSTEX ENERGY, INC.

(Exact name of registrant as specified in its charter)



Delaware		52-2235832
(State of organization)		(I.R.S. Employer Identification No.)

2501 CEDAR SPRINGS
DALLAS, TEXAS		75201
(Address of principal executive offices)		(Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer o		Accelerated filer x

Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ý

As of October 25, 2013, the Registrant had 47,758,109 shares of common stock outstanding.

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Item	Description	Page

	PART I—FINANCIAL INFORMATION

1.	Financial Statements	3

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

3.	Quantitative and Qualitative Disclosures About Market Risk	45

4.	Controls and Procedures	49


	PART II—OTHER INFORMATION

1.	Legal Proceedings	49

1A.	Risk Factors	49

6.	Exhibits	52

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CROSSTEX ENERGY, INC.

Condensed Consolidated Balance Sheets



	September 30, 2013		December 31, 2012
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	13,757	$	2,976
Accounts receivable:
Trade, net of allowance for bad debt of $520 and $535, respectively	82,558		63,690
Accrued revenue and other	121,527		155,828
Fair value of derivative assets	1,110		3,234
Natural gas and natural gas liquids inventory, prepaid expenses and other	20,736		11,866
Assets held for disposition	—		22,599
Total current assets	239,688		260,193
Property and equipment, net of accumulated depreciation of $574,414 and $504,442, respectively	1,849,902		1,472,161
Intangible assets, net of accumulated amortization of $219,056 and $263,305, respectively	325,154		425,005
Goodwill	153,802		152,627
Investment in limited liability company	99,561		90,500
Other assets, net	24,458		25,989
Total assets	$	2,692,565	$	2,426,475

LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Accounts payable, drafts payable and other	$	35,962	$	32,265
Accrued gas and crude oil purchases	127,533		140,344
Fair value of derivative liabilities	600		1,310
Other current liabilities	82,750		71,916
Accrued interest	16,062		26,712
Liabilities held for disposition	—		3,572
Total current liabilities	262,907		276,119
Long-term debt	1,102,357		1,036,305
Other long-term liabilities	27,888		30,256
Deferred tax liability	123,543		133,555
Fair Value of derivatives liabilities	19		—
Commitments and contingencies	—		—
Stockholders’ equity	1,175,851		950,240
Total liabilities and stockholders’ equity	$	2,692,565	$	2,426,475

See accompanying notes to condensed consolidated financial statements.

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CROSSTEX ENERGY, INC.

Condensed Consolidated Statements of Operations



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
				(As adjusted)						(As adjusted)
	(Unaudited) (In thousands, except per share amounts)
Revenues	$	468,643		$	444,947		$	1,369,069		$	1,265,308
Operating costs and expenses:
Purchased gas, NGLs and crude oil	368,349			345,202			1,068,465			975,507
Operating expenses	39,412			35,551			113,608			93,928
General and administrative	16,364			17,349			53,930			46,729
(Gain) loss on sale of property	(270		)	109			(175		)	(395		)
(Gain) loss on derivatives	1,634			759			1,662			(1,977		)
Depreciation and amortization	33,411			45,078			101,828			110,163
Impairment	72,576			—			72,576			—
Total operating costs and expenses	531,476			444,048			1,411,894			1,223,955
Operating income (loss)	(62,833		)	899			(42,825		)	41,353
Other income (expense):
Interest expense, net of interest income	(16,157		)	(23,228		)	(55,149		)	(63,926		)
Equity in income (loss) of limited liability company	(65		)	1,511			(106		)	1,511
Other income	37			4,440			367			4,464
Total other expense	(16,185		)	(17,277		)	(54,888		)	(57,951		)
Loss before non-controlling interest and income taxes	(79,018		)	(16,378		)	(97,713		)	(16,598		)
Income tax benefit	6,152			1,824			8,333			2,612
Net loss	(72,866		)	(14,554		)	(89,380		)	(13,986		)
Less: Net loss attributable to the non-controlling interest	(61,617		)	(10,240		)	(70,529		)	(7,176		)
Net loss attributable to Crosstex Energy, Inc.	$	(11,249	)	$	(4,314	)	$	(18,851	)	$	(6,810	)
Net loss per common share:
Basic and diluted per common share	$	(0.23	)	$	(0.09	)	$	(0.38	)	$	(0.14	)
Weighted average shares outstanding:
Basic and diluted	47,724			47,396			47,634			47,372

See accompanying notes to condensed consolidated financial statements.

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CROSSTEX ENERGY, INC.

Consolidated Statements of Comprehensive Income (Loss)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(Unaudited) (In thousands)
Net loss	$	(72,866	)	$	(14,554	)	$	(89,380	)	$	(13,986	)
Hedging gains reclassified to earnings, net of taxes of ($47), ($48), ($103) and ($6), respectively	(421		)	(546		)	(879		)	(162		)
Adjustment in fair value of derivatives, net of taxes of ($79), ($14), $31 and ($154), respectively	(698		)	(165		)	245			1,417
Comprehensive loss	(73,985		)	(15,265		)	(90,014		)	(12,731		)
Less: Comprehensive income (loss) attributable to the non-controlling interest	(62,610		)	(3,669		)	(71,091		)	991
Comprehensive loss attributable to Crosstex Energy, Inc.	$	(11,375	)	$	(11,596	)	$	(18,923	)	$	(13,722	)

See accompanying notes to condensed consolidated financial statements.

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CROSSTEX ENERGY, INC.

Consolidated Statements of Changes in Stockholders’ Equity

Nine Months Ended September 30, 2013



				Additional			Retained			Accumulated Other			Non-
	Common Stock			Paid in			Earnings			Comprehensive			Controlling			Total
	Shares	Amount		Capital			(Deficit)			Income (loss)			Interest			Total
	(Unaudited) (In thousands)
Balance, December 31, 2012	47,414	$	473	$	274,635		$	(117,583	)	$	141		$	792,574		$	950,240
Issuance of units by the Partnership to non-controlling interest	—	—		—			—			—			389,186			389,186
Stock-based compensation	—	—		5,604			—			—			5,620			11,224
Common dividends	—	—		—			(17,647		)	—			—			(17,647		)
Net loss	—	—		—			(18,851		)	—			(70,529		)	(89,380		)
Conversion of restricted stock for common, net of shares withheld for taxes	321	3		(2,090		)	—			—			—			(2,087		)
Hedging gains or losses reclassified to earnings	—	—		—			—			(103		)	(776		)	(879		)
Adjustment in fair value of derivatives	—	—		—			—			31			214			245
Non-controlling partner’s impact of conversion of restricted units and options exercise	—	—		—			—			—			(1,191		)	(1,191		)
Distribution to non-controlling interest	—	—		—			—			—			(66,055		)	(66,055		)
Changes in equity due to issuance of units by the Partnership	—	—		25,823			—			(62		)	(31,722		)	(5,961		)
Contribution from non-controlling interest in Subsidiary	—	—		—			—			—			8,156			8,156
Balance, September 30, 2013	47,735	$	476	$	303,972		$	(154,081	)	$	7		$	1,025,477		$	1,175,851

See accompanying notes to condensed consolidated financial statements.

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CROSSTEX ENERGY, INC.

Consolidated Statements of Cash Flows



	Nine Months Ended September 30,
	2013			2012
	(Unaudited) (In thousands)
Cash flows from operating activities:
Net loss	$	(89,380	)	$	(13,986	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	101,828			110,163
Impairment	72,576			—
Gain on sale of property and other assets	(175		)	(3,381		)
Deferred tax benefit	(16,460		)	(4,492		)
Non-cash stock-based compensation	11,224			7,695
(Gain) loss on derivatives recognized in net loss	(1,662		)	1,977
Cash received (paid) on derivatives not recognized as revenue	2,418			(7,500		)
Distribution of earnings from limited liability company	3,144			—
Equity in (income) loss from limited liability company	106			(1,511		)
Amortization of debt issue costs	4,567			3,940
Amortization of discount on notes	1,423			1,423
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other	14,254			(18,276		)
Natural gas and natural gas liquids, prepaid expenses and other	(7,057		)	(7,145		)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	(3,666		)	(26,029		)
Net cash provided by operating activities	93,140			42,878
Cash flows from investing activities:
Additions to property and equipment	(454,862		)	(141,319		)
Acquisition of business	—			(212,521		)
Proceeds from sale of property	18,459			11,677
Investment in limited liability company	(22,261		)	(52,250		)
Distribution from limited liability company in excess of earnings	9,951			—
Net cash used in investing activities	(448,713		)	(394,413		)
Cash flows from financing activities:
Proceeds from borrowings	374,153			696,500
Payments on borrowings	(309,525		)	(526,000		)
Payments on capital lease obligations	(2,433		)	(2,337		)
Increase in drafts payable	1,306			4,319
Debt refinancing costs	(3,261		)	(6,896		)
Conversion of restricted stock, net of shares withheld for taxes	(2,087		)	(794		)
Distributions to non-controlling partners in the Partnership	(66,055		)	(52,536		)
Contributions from non-controlling partners	3,908			—
Common dividend paid	(17,647		)	(17,078		)
Issuance of common units by the Partnership	389,186			232,791
Conversion of restricted units, net of units withheld for taxes	(1,928		)	(1,030		)
Proceeds from exercise of Partnership unit options	737			348
Net cash provided by financing activities	366,354			327,287
Net increase (decrease) in cash and cash equivalents	10,781			(24,248		)
Cash and cash equivalents, beginning of period	2,976			30,343
Cash and cash equivalents, end of period	$	13,757		$	6,095
Cash paid for interest	$	78,334		$	70,460
Cash paid for income taxes	$	6,565		$	953

See accompanying notes to condensed consolidated financial statements.

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CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements

September 30, 2013

(Unaudited)

(1) General

Unless the context requires otherwise, references to “we,” “us,” “our,” “CEI” or the “Company” mean Crosstex Energy, Inc. and its consolidated subsidiaries.

Crosstex Energy, Inc ., a Delaware corporation formed on April 28, 2000 , is engaged, through its subsidiaries, in the gathering, transmission, processing and marketing of natural gas, natural gas liquids ("NGLs") and crude oil. The Company also provides crude oil, condensate and brine services to producers. The Company connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. The Company purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. The Company operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee arrangements. In addition, the Company purchases natural gas from producers not connected to its gathering systems for resale and sells natural gas on behalf of producers for a fee. The Company provides a variety of crude services throughout the Ohio River Valley ("ORV") which include crude oil gathering via pipelines and trucks and oilfield brine disposal. The Company also has crude oil terminal facilities in south Louisiana that provide access for crude oil producers to the premium markets in this area.

The accompanying condensed consolidated financial statements include the assets, liabilities and results of operations of the Company, its majority owned subsidiaries and Crosstex Energy, L.P. (herein referred to as the “Partnership” or “CELP”), a publicly traded Delaware limited partnership. The Partnership is included because CEI controls the general partner of the Partnership (the “General Partner”).

(a) Basis of Presentation

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America ("US GAAP") for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to the consolidated financial statements for the prior year to conform to the current presentation. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2012 .

The preparation of financial statements in accordance with US GAAP requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

(b) Investment in E2

In March 2013, the Company entered into an agreement to form a new company (“E2”) that provides compression and stabilization services for producers in the liquids-rich window of the Utica Shale play. The Company owns a majority interest in E2 and consolidates its investment in E2 pursuant to Financial Accounting Standards Board ("FASB") ASC 810-10-05-08. The Company has committed to invest of approximately $75.0 million in E2 to fund the construction of three new natural gas compression and condensate stabilization facilities which E2 will own and operate located in Noble and Monroe counties in the southern portion of the Utica Shale play in Ohio. As of September 30, 2013 , the Company had invested $49.1 million in E2. E2 will build, own and operate the three gas gathering compressor stations and condensate stabilization assets. Commercial operations of the two initial facilities is expected to occur during the fourth quarter of 2013 and the third plant is expected to be

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operational during the first quarter of 2014. The Company owns approximately 93.0% of E2 and has pre-determined rights to purchase the management ownership interests of E2 in the future.

Accumulated Other Comprehensive Income Reclassifications. In February 2013, the FASB issued Accounting Standards Update ("ASU") 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 requires disclosure of amounts reclassified out of accumulated other comprehensive income ("AOCI") by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income but only if the amount reclassified is required to be reclassified to net income in its entirety in the same reporting period. For amounts not reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. For the three months ended September 30, 2013 and 2012 , the Partnership reclassified cash flow hedge gains in the amounts of $0.4 million and $0.5 million , respectively, and $0.9 million and $0.2 million for the nine months ended September 30, 2013 and 2012 , respectively, included in other comprehensive income to revenues on the condensed consolidated statement of operations.

(d) Intangible Asset Impairment

In August 2013, the Partnership shut-down the Eunice processing plant (the “Plant”), which is located in south Louisiana and is part of our PNGL segment, due to adverse economics driven by low NGL prices and low processing volumes which the Partnership does not see improving in the near future based on forecasted price curves. The Partnership recorded an impairment expense of $72.6 million during the third quarter of 2013 related to the intangible assets for the terminated customer relationships attributable to the Plant shut-down.

(e) Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Partnership evaluates goodwill for impairment annually as of July 1 , and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. There were no impairment charges resulting from the Partnership's July 1, 2013 impairment testing, and no event indicating impairment has occurred subsequent to that date. The Company had no goodwill outside of the Partnership as of September 30, 2013.

(2) 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 its wholly owned subsidiaries (collectively, “Clearfield”). Clearfield’s business included 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 included in the Partnership’s ORV segment.

Purchase Price Allocation

The Partnership paid approximately $215.4 million in cash in the acquisition. The following table is a summary of the consideration paid in the Clearfield acquisition and the purchase price allocation for the fair value of the assets acquired and liabilities assumed at the acquisition date:

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CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements-(Continued)



Purchase Price Allocation (in thousands):
Purchase Price to Clearfield Energy, Inc.	$	215,397
Total Purchase Price	$	215,397

Assets acquired:
Current assets	$	17,622
Assets held for disposition	19,358
Property, plant and equipment	91,422
Goodwill	153,802
Intangibles	37,600
Liabilities assumed:
Current liabilities	(28,274		)
Liabilities held for disposition	(1,400		)
Deferred taxes	(65,228		)
Long term liabilities	(9,505		)
Total purchase price	$	215,397

From the period July 2, 2012 to September 30, 2012, the Partnership recognized $52.9 million of crude oil buy/sell, crude oil transportation and brine service sales related to properties acquired in the Clearfield acquisition. For the period July 2, 2012 to September 30, 2012, the Partnership recognized $46.1 million of net operating expense related to properties acquired in the Clearfield acquisition.

Pro Forma Information

The following unaudited pro forma condensed financial data for the nine months ended September 30, 2012 gives effect to the Clearfield acquisition as if it had occurred on January 1, 2012. 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.



	Nine Months Ended September 30, 2012

Pro forma total revenues	$	1,371,219
Pro forma net loss	$	(16,267	)
Pro forma net loss attributable to Crosstex Energy, Inc.	$	(9,091	)
Pro forma net loss per common share:
Basic and Diluted	$	(0.19	)

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CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements-(Continued)

(3) Long-Term Debt

As of September 30, 2013 and December 31, 2012 , long-term debt consisted of the following (in thousands):



	September 30, 2013		December 31, 2012
Partnership's bank credit facility (due 2016), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2013 and December 31, 2012 was 3.6% and 4.3%, respectively	$	76,000	$	71,000
Subsidiary Borrower’s credit facility (due 2016), interest based on LIBOR plus 5.0%, interest rate at September 30, 2013 was 5.3%	47,275		—
Partnership's senior unsecured notes (due 2018), net of discount of $8.3 million and $9.7 million, respectively, which bear interest at the rate of 8.875%	716,728		715,305
Partnership's senior unsecured notes (due 2022), which bear interest at the rate of 7.125%	250,000		250,000
Other debt	12,354		—
Debt classified as long-term	$	1,102,357	$	1,036,305

Subsidiary Borrower’s Credit Facility. On March 5, 2013 , XTXI Capital, LLC, a wholly-owned subsidiary of the Company (“Subsidiary Borrower”), entered into a Credit Agreement (the “Subsidiary Credit Agreement”) with Citibank, N.A., as Administrative Agent, Collateral Agent and a Lender, and the other lenders party thereto. The Subsidiary Credit Agreement initially permitted Subsidiary Borrower to borrow up to $75.0 million on a revolving credit basis. The maturity date of the Subsidiary Credit Agreement is March 5, 2016 .

In May 2013, Subsidiary Borrower exercised the accordion feature of the Subsidiary Credit Agreement, thereby increasing the amount Subsidiary Borrower is permitted to borrow on a revolving credit basis from $75.0 million to up to $90.0 million . Subsidiary Borrower intends to distribute these additional funds for the Company's investment commitment in E2. As of September 30, 2013 , there was $47.3 million borrowed under the Subsidiary Credit Agreement, leaving approximately $42.7 million available for future borrowing based on the borrowing capacity of $90.0 million .

Subsidiary Borrower’s obligations under the Subsidiary Credit Agreement are guaranteed by the Company (the “Guaranty”) and are secured by a first priority lien on 10,700,000 common units representing limited partner interests (“Common Units”) in the Partnership, which Common Units have been contributed by the Company to Subsidiary Borrower (together with any additional Common Units subsequently pledged as collateral under the Subsidiary Credit Agreement, the “Pledged Units”).

Borrowings under the Subsidiary Credit Agreement bear interest at a per annum rate equal to the reserve-adjusted British Banks Association LIBOR Rate plus 5.00% . Subsidiary Borrower pays a commitment fee of 0.75% per annum on the unused availability under the Subsidiary Credit Agreement. Subject to the $90.0 million cap on outstanding borrowings and the percentage obtained by dividing (A) the total net outstanding borrowings under the Subsidiary Credit Agreement by (B) the product of (x) the number of Common Units included in the Pledged Units on such date and (y) the closing sale price per Common Unit on such date (the “Loan to Equity Value Percentage”) not equaling or exceeding 47% , Subsidiary Borrower may elect to pay interest, fees and expenses in connection with the Subsidiary Credit Agreement in kind by adding such amounts to the principal amount of the borrowings under the Subsidiary Credit Agreement.

The Subsidiary Credit Agreement requires mandatory prepayments of all amounts outstanding thereunder if the Company ceases to own all of the equity interests of Subsidiary Borrower. In addition, if the Loan to Equity Value Percentage exceeds 47% , Subsidiary Borrower must prepay the loan, pledge additional Common Units as collateral and/or direct the collateral agent to sell Pledged Units to achieve a Loan to Equity Value Percentage that is less than 42.5% .

The Subsidiary Credit Agreement prohibits Subsidiary Borrower from making any distributions or other payments to the Company (including any distributions resulting from Subsidiary Borrower’s receipt of distributions from the Partnership) if the Loan to Equity Value Percentage exceeds 47% or any event of default exists under the Subsidiary Credit Agreement. The Subsidiary Credit Agreement also limits the Company’s ability and the ability of its subsidiaries (other than the Partnership) to sell Common Units in certain circumstances.

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CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements-(Continued)

The Subsidiary Credit Agreement contains various other covenants that, among other restrictions, limit Subsidiary Borrower’s ability to incur indebtedness, enter into acquisition or disposition transactions and engage in any business activities. The Subsidiary Credit Agreement does not include any financial covenants.

Events of default under the Subsidiary Credit Agreement include, among others, (i) Subsidiary Borrower’s failure to pay principal or interest when due, (ii) Subsidiary Borrower’s or the Company’s failure to comply with agreements, obligations or covenants in the Subsidiary Credit Agreement, the Guaranty or any other loan document, (iii) material inaccuracy of any representation or warranty, (iv) certain change of control events, bankruptcy and other insolvency events and (v) the occurrence of certain events relating to the Common Units.

If an event of default relating to bankruptcy or other insolvency events occur, all indebtedness under the Subsidiary Credit Agreement will immediately become due and payable. If any other event of default exists under the Subsidiary Credit Agreement, the lenders may accelerate the maturity of the obligations outstanding under the Subsidiary Credit Agreement, Subsidiary Borrower will be unable to borrow funds and the lenders may exercise other rights and remedies. In addition, if any event of default exists under the Subsidiary Credit Agreement, the lenders may commence foreclosure or other actions against the Pledged Units. If the Company defaults on its obligations under the Guaranty, then the lenders could declare all amounts outstanding under the Subsidiary Credit Agreement immediately due and payable (with accrued interest). If Subsidiary Borrower and the Company are unable to pay such amounts, the lenders may foreclose on the Pledged Units. Citibank, N.A., as the agent under the Subsidiary Credit Agreement, has the right to demand additional collateral or amend the Subsidiary Credit Agreement if certain events occur that adversely impact the composition and quality of the Pledged Units or Citibank, N.A’s position as a secured creditor.

Other Borrowings. On September 4, 2013 , E2 Energy Services LLC ("E2 Services"), a subsidiary of the Company's E2 investment, entered into a credit agreement with JPMorgan Chase Bank, ("JPMorgan"). The maturity date of the credit agreement is September 4, 2016 . As of September 30, 2013 , there was $11.8 million borrowed under the agreement, leaving approximately $8.2 million available for future borrowing based on borrowing capacity of $20.0 million . The interest rate under the credit agreement is based on Prime plus an applicable margin. The effective interest rate as of September 30, 2013 was approximately 4.0% . Additionally, as of September 30, 2013 , E2 Services had notes outstanding in the amount of $0.6 million due in increments through July 2017 . The notes bear interest at fixed rates ranging 4.2% to 7.0% .

The Partnership’s Credit Facility. As of September 30, 2013 , there was $62.3 million in outstanding letters of credit and $76.0 million in outstanding borrowings under the Partnership’s bank credit facility, leaving approximately $496.7 million available for future borrowing based on the borrowing capacity of $635.0 million . As of September 30, 2013 , based on the Partnership’s maximum permitted consolidated leverage ratio (as defined in the amended credit facility), the Partnership could borrow approximately $271.4 million of additional funds.

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 facility, 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 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) 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.

In August 2013, the Partnership amended the credit facility to, among other things, (i) allow the Partnership to make additional investments in joint ventures and subsidiaries that are not guarantors of the Partnership's obligations under the amended credit facility, (ii) decrease the minimum consolidated interest coverage ratio (as defined in the amended credit facility, 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 March 31, 2014, June 30, 2014, September 30, 2014 and December 31, 2014, with a minimum ratio of 2.50 to 1.0 for each fiscal quarter ending thereafter, and (iii) increase 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

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CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements-(Continued)

and certain other non-cash charges) to 5.50 to 1.0 for the fiscal quarters ending March 31, 2014, June 30, 2014 and September 30, 2014, with a maximum ratio of 5.25 to 1.0 for each fiscal quarter ending thereafter.

The Partnership’s credit facility is guaranteed by substantially all of the Partnership’s subsidiaries and is secured by first priority liens on substantially all of its 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 the Partnership’s equity interests in substantially all of its subsidiaries. The Partnership may prepay all loans under the Partnership’s credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The Partnership’s 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 Partnership’s credit facility.

All other material terms of the Partnership’s credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 . The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

(4) Other Long-term Liabilities

The Partnership has the following assets under capital leases as of September 30, 2013 (in thousands):



Compressor equipment	$	37,199
Less: Accumulated amortization	(16,401		)
Net assets under capital leases	$	20,798

The following are the minimum lease payments to be made in each of the following years indicated for the capital leases in effect as of September 30, 2013 (in thousands):



Fiscal Year
2013	$	1,146
2014	4,582
2015	4,582
2016	4,582
2017	6,910
Thereafter	5,189
Less: Interest	(4,169		)
Net minimum lease payments under capital lease	22,822
Less: Current portion of net minimum lease payments	(4,449		)
Long-term portion of net minimum lease payments	$	18,373

(5) Certain Provisions of the Partnership Agreement

(a) Partnership Distributions

Unless restricted by the terms of the Partnership’s credit facility and/or the indentures governing the Partnership’s 8.875% senior notes due 2018 (the “2018 Notes”) or the Partnership’s 7.125% senior notes due 2022 (the “2022 Notes” and, together with the 2018 Notes, “all senior unsecured notes”), the Partnership must make distributions of 100.0% of available cash, as defined in the Partnership's partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made to the common unitholders and to the General Partner relative to their proportional share of ownership of the

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Partnership, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved.

Under the quarterly incentive distribution provisions, generally the Partnership’s General Partner is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23.0% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit. Incentive distributions totaling $1.3 million and $4.2 million were earned by the Company for the three and nine months ended September 30, 2013 , respectively.

A summary of the Partnership's distribution activity relating to its common units and preferred units (which it pays in kind "PIK") for the nine months ended September 30, 2013 is provided below:



Declaration period	Distribution/unit		PIK Units Distributed (1)	Date paid/payable
Q4 2012	$	0.33	375,382	February 14, 2013
Q1 2013	$	0.33	384,731	May 13, 2013
Q2 2013	$	0.33	394,313	August 12, 2013
Q3 2013	$	0.34	—	November 12, 2013

(1) Represents distributions on preferred units paid-in-kind through the issuance of additional preferred units.

(b) Issuance of Common Units

In June 2013 , the Partnership issued 8,280,000 common units representing limited partner interests in the Partnership (including 1,080,000 common units issued pursuant to the exercise of the underwriters' option to purchase additional common units) at a public offering price of $20.33 per common unit for net proceeds of $162.0 million . The net proceeds from the common unit offering were used for capital expenditures for currently identified projects, including the Cajun-Sibon NGL pipeline expansion, and for general partnership purposes. Pending such use, the Partnership repaid outstanding borrowings under its credit facility. The General Partner did not exercise its option to make a general partner contribution to maintain its then-current general partner percentage in connection with this offering.

In January 2013 , the Partnership issued 8,625,000 common units representing limited partner interests in the Partnership at a public offering price of $15.15 per common unit for net proceeds of $125.4 million . Concurrent with the public offering, the Partnership issued 2,700,000 common units representing limited partner interests in the Partnership at an offering price of $14.55 per unit for net proceeds of $39.2 million . The net proceeds from both common unit offerings were used for capital expenditures, to repay bank borrowings and for general partnership purposes. The General Partner did not exercise its option to make a general partner contribution to maintain its then-current general partner percentage in connection with this offering.

In May 2013, the Partnership entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (“BMOCM”). This EDA replaced the previous equity distribution agreement entered into in March 2013 between BMOCM and the Partnership. Pursuant to the terms of the EDA, the Partnership may from time to time, through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million . Sales of such common units will be made by means of ordinary brokers’ transactions through the facilities of the Nasdaq Global Select Market LLC at market prices, in block transactions or as otherwise agreed by BMOCM and the Partnership. Under the terms of the EDA, the Partnership may sell common units from time to time to BMOCM as principal for its own account at a price to be agreed upon at the time of sale. For any such sales, the Partnership will enter into a separate terms agreement with BMOCM.

Through September 30, 2013 , the Partnership sold an aggregate of 3,370,486 common units under the EDA and prior equity distribution agreement with BMOCM, generating proceeds of approximately $62.9 million (net of approximately $0.9 million of commissions to BMOCM). The Partnership used the net proceeds for general partnership purposes, including working capital, capital expenditures and repayments of indebtedness.

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The Company reflects changes in its ownership interest in the Partnership as equity transactions. The carrying amount of the non-controlling interest is adjusted to reflect the change in the Company’s ownership interest in the Partnership. Any difference between the fair value of the consideration received and the amount by which the non-controlling interest is adjusted is recognized in additional paid-in-capital ("APIC'). The Company’s book carrying amount per Partnership unit was below the price per unit received by the Partnership for its January 2013, June 2013 and EDA sales of common units, resulting in changes in equity of $31.7 million . The changes were recorded as an increase in APIC and a reduction in non-controlling interest during the period ended September 30, 2013 . The Company also increased its deferred tax liability in the amount of $6.0 million relating to the difference between its book and tax investment in the Partnership with the offset to APIC.

(6) Earnings per Share and Dilution Computations

Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding for the three and nine months ended September 30, 2013 and 2012 . The computation of diluted earnings per share further assumes the dilutive effect of common share options and restricted shares. All common share equivalents were antidilutive in the three and nine months ended September 30, 2013 and 2012 because the Company had a net loss for the periods.

The following table reflects the computation of basic earnings per share for the periods presented (in thousands except per share amounts):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net loss attributable to Crosstex Energy, Inc.	$	(11,249	)	$	(4,314	)	$	(18,851	)	$	(6,810	)
Distributed earnings allocated to:
Common shares	$	5,727		$	5,687		$	17,146		$	16,578
Unvested restricted shares	172			170			501			500
Total distributed earnings	$	5,899		$	5,857		$	17,647		$	17,078
Undistributed loss allocated to:
Common shares	$	(16,629	)	$	(9,885	)	$	(35,376	)	$	(23,207	)
Unvested restricted shares	(518		)	(286		)	(1,122		)	(681		)
Total undistributed loss	$	(17,147	)	$	(10,171	)	$	(36,498	)	$	(23,888	)
Net loss allocated to:
Common shares	$	(10,902	)	$	(4,198	)	$	(18,230	)	$	(6,629	)
Unvested restricted shares	(347		)	(116		)	(621		)	(181		)
Total net loss	$	(11,249	)	$	(4,314	)	$	(18,851	)	$	(6,810	)
Basic and diluted net loss per share:
Basic common share	$	(0.23	)	$	(0.09	)	$	(0.38	)	$	(0.14	)
Diluted common share	$	(0.23	)	$	(0.09	)	$	(0.38	)	$	(0.14	)

The following are the share amounts used to compute the basic and diluted earnings per common share unit for the three and nine months ended September 30, 2013 and 2012 (in thousands):

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	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
Basic and diluted weighted average shares outstanding:
Weighted average common shares outstanding	47,724	47,396	47,634	47,372

(7) Employee Incentive Plans

(a) Long-Term Incentive Plans

The Company accounts for share-based compensation in accordance with FASB ASC 718, which requires that compensation related to all stock-based awards, including stock options, be recognized in the consolidated financial statements. On May 9, 2013, the Partnership’s unitholders approved the amended and restated Crosstex Energy GP, LLC Long-Term Incentive Plan (the “Plan”). Amendments to the Plan include an increase in the number of common units representing limited partner interests in the Partnership authorized for issuance under the Plan by 3,470,000 common units to an aggregate of 9,070,000 common units. In addition, the Plan includes technical amendments to certain other provisions of the Plan (i) to describe awards of restricted units as restricted incentive units, (ii) to revise the change in control definition to (among other things) eliminate and clarify certain change in control events, (iii) to make minor changes to better conform certain provisions to applicable law and (iv) to include minor updates to clarify the meaning of, and consistently describe, certain terms thereunder.

The Company and the Partnership each have similar unit or share-based payment plans for employees, which are described below. Share-based compensation associated with the CEI share-based compensation plan awarded to officers and employees of the Partnership are recorded by the Partnership since CEI has no substantial or managed operating activities other than its interest in the Partnership. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Cost of share-based compensation charged to general and administrative expense	$	2,664	$	2,272	$	9,821	$	6,746
Cost of share-based compensation charged to operating expense	423		310		1,403		949
Total amount charged to income	$	3,087	$	2,582	$	11,224	$	7,695
Interest of non-controlling partners in share-based compensation	$	1,235	$	1,338	$	4,387	$	4,054
Amount of related income tax benefit recognized in income	$	686	$	459	$	2,534	$	1,347

(b) Partnership Restricted Incentive Units

The restricted incentive units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2013 is provided below:



	Nine Months Ended September 30, 2013
Crosstex Energy, L.P. Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,003,159			$	13.31
Granted	625,339			16.19
Vested*	(396,927		)	9.50
Forfeited	(52,648		)	13.52
Non-vested, end of period	1,178,923			$	16.11
Aggregate intrinsic value, end of period (in thousands)	$	23,461

_____________________________________________

* Vested units include 113,804 units withheld for payroll taxes paid on behalf of employees.

The Partnership issued restricted incentive units in 2013 to officers and other employees. These restricted incentive units typically vest at the end of three years and are included in the restricted incentive units outstanding and the current share-based compensation cost calculations at September 30, 2013 . In March 2013 , the Partnership issued 57,897 restricted incentive units with a fair value of $1.0 million to officers and certain employees as bonus payments for 2012 , which vested immediately and are included in the restricted incentive units granted and vested line items above.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and nine months ended September 30, 2013 and 2012 are provided below (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
Crosstex Energy, L.P. Restricted Incentive Units:	2013		2012		2013		2012
Aggregate intrinsic value of units vested	$	2,457	$	448	$	6,750	$	4,031
Fair value of units vested	$	1,275	$	452	$	3,771	$	2,060

As of September 30, 2013 , there was $9.0 million of unrecognized compensation cost related to non-vested restricted incentive units. That cost is expected to be recognized over a weighted-average period of 1.5 years.

A summary of the unit option activity for the nine months ended September 30, 2013 is provided below:



	Nine Months Ended September 30, 2013
Crosstex Energy, L.P. Unit Options:	Number of Units			Weighted Average Exercise Price
Outstanding, beginning of period	349,018			$	7.25
Exercised	(132,986		)	5.56
Forfeited	(3,109		)	23.60
Outstanding, end of period	212,923			$	8.07
Options exercisable at end of period	212,923
Weighted average contractual term (years) end of period:
Options outstanding	5.5
Options exercisable	5.5
Aggregate intrinsic value end of period (in thousands):
Options outstanding	$	2,803
Options exercisable	$	2,803

A summary of the unit options intrinsic value exercised (market value in excess of exercise price at date of exercise) and fair value of units exercised (value per Black-Scholes-Merton option pricing model at date of grant) during the three and nine months ended September 30, 2013 and 2012 are provided below (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
Crosstex Energy, L.P. Unit Options:	2013		2012		2013		2012
Intrinsic value of unit options exercised	$	356	$	327	$	1,716	$	805
Fair value of unit options vested	$	—	$	—	$	254	$	277

As of September 30, 2013 , all options were vested and fully expensed.

(d) Crosstex Energy, Inc.’s Restricted Stock

On May 9, 2013, CEI's stockholders approved the amended and restated Crosstex Energy, Inc. 2009 Long-Term Incentive Plan (the “CEI Plan”). Amendments to the CEI Plan included an increase in the number of shares of CEI's common stock authorized for issuance under the CEI Plan by 1,785,000 shares to an aggregate of 4,385,000 shares of common stock. In addition, the CEI Plan amendment included technical amendments to certain other provisions of the CEI Plan (i) to clarify that awards of restricted stock units may be granted as stock awards, (ii) to revise the change of control definition to (among other things) eliminate and clarify certain change of control events, (iii) to make minor changes to better conform certain provisions to applicable law and (iv) to include minor updates to clarify the meaning of, and consistently describe, certain terms thereunder.

The Company’s restricted shares are valued at their fair value at the date of grant which is equal to the market value of the common stock on such date. A summary of the restricted share activities for the nine months ended September 30, 2013 is provided below:



	Nine Months Ended September 30, 2013
Crosstex Energy, Inc. Restricted Shares:	Number of Shares			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,329,162			$	9.75
Granted	632,912			15.08
Vested*	(445,177		)	7.43
Forfeited	(63,864		)	11.69
Non-vested, end of period	1,453,033			$	12.69
Aggregate intrinsic value, end of period (in thousands)	$	30,354

__________________________________________________

* Vested shares include 124,493 shares withheld for payroll taxes paid on behalf of employees.

CEI issued restricted shares in 2013 to officers and other employees. These restricted shares typically vest at the end of three years and are included in restricted shares outstanding and the current share-based compensation cost calculations at September 30, 2013 . In March 2013 , CEI issued 60,018 restricted shares with a fair value of $1.0 million to officers and certain employees as bonus payments for 2012 , which vested immediately and are included in restricted shares granted and vested in the above line items.

A summary of the restricted shares’ aggregate intrinsic value (market value at vesting date) and fair value of shares vested during the three and nine months ended September 30, 2013 and 2012 are provided below (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
Crosstex Energy, Inc. Restricted Shares:	2013		2012		2013		2012
Aggregate intrinsic value of shares vested	$	3,290	$	537	$	7,593	$	3,963
Fair value of shares vested	$	1,123	$	448	$	3,307	$	1,714

As of September 30, 2013 , there was $9.0 million of unrecognized compensation costs related to non-vested CEI restricted shares. The cost is expected to be recognized over a weighted average period of 1.4 years.

(e) Crosstex Energy, Inc.’s Stock Options

CEI stock options have not been granted to officers or employees of the Partnership since 2005 . All options outstanding at September 30, 2013 were vested and exercisable with all associated costs recognized. The following is a summary of the CEI stock options outstanding as of September 30, 2013 :



	Nine Months Ended September 30, 2013
		Weighted
	Number of	Average
Crosstex Energy, Inc. Stock Options:	Shares	Exercise Price
Outstanding, beginning of period	37,500	$	6.50
Forfeited	—	—
Outstanding, end of period	37,500	$	6.50
Options exercisable at end of period	37,500
Weighted average contractual term (years) end of period	1.4

(8) Derivatives

Commodity Swaps

The Partnership manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risks related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs.

The Partnership commonly enters into various derivative financial transactions which it does not designate as accounting hedges. These transactions include “swing swaps,” “storage swaps,” “basis swaps,” “processing margin swaps,” “liquids swaps” and “put options.” Swing swaps are generally short-term in nature (one month) and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. Storage swap transactions protect against changes in the value of products that the Partnership has stored to serve various operational requirements (gas) or has in inventory due to short term constraints in moving the product to market (liquids or condensate). Basis swaps are used to hedge basis location price risk due to buying gas into one of the Partnership’s systems on one index and selling gas off that same system on a different index. Processing margin financial swaps are used to hedge fractionation spread risk at the Partnership’s processing plants relating to the option to process versus bypassing the Partnership’s equity gas. Liquids financial swaps are used to hedge price risk on percent of liquids contracts. Put options are purchased to hedge against declines in pricing and as such, represent options, not obligations, to sell the related underlying volumes at a fixed price.

Changes in the fair value of the Partnership’s mark to market derivatives are recognized in earnings in the period of change. The effective portion of changes in the fair value of cash flow hedges is recorded in AOCI until the related anticipated future cash flow is recognized in earnings. The ineffective portion is recorded in earnings immediately.

The components of (gain) loss on derivatives in the condensed consolidated statements of operations relating to commodity swaps are provided below (in thousands):

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CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements-(Continued)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013			2012
Change in fair value of derivatives that are not designated as hedging instruments	$	1,012	$	433	$	768		$	(5,481	)
Realized losses on derivatives	591		308		906			3,547
Ineffective portion of derivatives designated as hedging instruments	31		18		(12		)	(43		)
(Gain) loss on derivatives	$	1,634	$	759	$	1,662		$	(1,977	)

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CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements-(Continued)

The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in thousands):



	September 30, 2013			December 31, 2012
Fair value of derivative assets — current, designated	$	287		$	724
Fair value of derivative assets — current, non-designated	823			2,510
Fair value of derivative liabilities — current, designated	(313		)	(105		)
Fair value of derivative liabilities — current, non-designated	(287		)	(1,205		)
Fair value of derivative liabilities — long term, designated	(19		)	—
Net fair value of derivatives	$	491		$	1,924

Set forth below are the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets as of September 30, 2013 (all gas volumes are expressed in million British thermal units, liquids volumes are expressed in gallons and condensate volumes are expressed in barrels). The remaining terms of the contracts extend no later than December 2014 .



	September 30, 2013
Transaction Type	Volume		Fair Value
	(In thousands)
Cash Flow Hedges:
Liquids swaps (short contracts)	(9,322	)	$	(45	)
Total swaps designated as cash flow hedges			$	(45	)

Mark to Market Derivatives:*
Swing swaps (long contracts)	1,659		$	4
Physical offsets to swing swap transactions (short contracts)	(1,659	)	(1		)

Processing margin hedges — liquids (short contracts)	(3,926	)	256
Processing margin hedges — gas (long contracts)	422		(125		)

Liquids swaps - non-designated (short contracts)	(1,369	)	308

Storage swap transactions — (short contracts)	(100	)	21
Storage swap transactions — liquids inventory (long contracts)	420		3
Storage swap transactions — liquids inventory (short contracts)	(1,680	)	70
Total mark to market derivatives			$	536

__________________________________________________

* All are gas contracts except as otherwise noted.

On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements ("ISDAs") with its counterparties. If the Partnership’s counterparties failed to perform under existing swap contracts entered into under these ISDAs, the Partnership’s maximum loss as of September 30, 2013 of $0.9 million would be reduced to $0.7 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

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CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements-(Continued)

Impact of Cash Flow Hedges

The impact of realized gains or losses from derivatives designated as cash flow hedge contracts in the condensed consolidated statements of operations is summarized below (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
Increase in Midstream Revenue	2013		2012		2013		2012
Liquids realized gain included in Midstream revenue	$	159	$	456	$	819	$	851

Natural Gas

As of September 30, 2013 , the Partnership had no balances in AOCI related to natural gas.

Liquids

As of September 30, 2013 , an unrealized derivative fair value net loss of less than $0.1 million related to cash flow hedges of liquids price risk was recorded in AOCI. Of that amount, a net loss of less than $0.1 million is expected to be reclassified into earnings through September 2014. The actual reclassification to earnings will be based on mark to market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected in the above table.

Derivatives Other Than Cash Flow Hedges

Assets and liabilities related to third party derivative contracts, swing swaps, basis swaps, storage swaps, processing margin swaps and liquids swaps are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as (gain) loss on derivatives in the condensed consolidated statement of operations. The Partnership estimates the fair value of all of its energy trading contracts using Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):



	Maturity Periods
	Less than one year		One to two years		More than two years		Total fair value
September 30, 2013	$	536	$	—	$	—	$	536

(9) Fair Value Measurements

FASB ASC 820 sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under FASB ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

FASB ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Partnership’s derivative contracts primarily consist of commodity swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be

derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.

Net assets measured at fair value on a recurring basis are summarized below (in thousands):



	September 30, 2013 Level 2		December 31, 2012 Level 2
Commodity Swaps*	$	491	$	1,924
Total	$	491	$	1,924

__________________________________________________

* Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in AOCI at each measurement date. The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.

Fair Value of Financial Instruments

The estimated fair value of the Company’s financial instruments has been determined by the Company using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Company could realize upon the sale or refinancing of such financial instruments (in thousands):



	September 30, 2013				December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	1,102,357	$	1,162,192	$	1,036,305	$	1,118,875
Obligations under capital lease	$	22,822	$	24,381	$	25,257	$	27,667

The carrying amounts of the Company’s cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

The Partnership had $76.0 million in borrowings under its revolving credit facility included in long-term debt as of September 30, 2013 and $71.0 million at December 31, 2012 . The Subsidiary Borrower had $47.3 million in borrowings under the Subsidiary Credit Agreement included in long-term debt as of September 30, 2013 . As borrowings under the Partnership’s credit facility, the Subsidiary Credit Agreement and other borrowings of $12.4 million accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under their respective credit facilities. As of September 30, 2013 and December 31, 2012 , the Partnership also had borrowings totaling $716.7 million and $715.3 million , net of discount, respectively, under the 2018 Notes with a fixed rate of 8.875% and borrowings of $250.0 million under the 2022 Notes with a fixed rate of 7.125% . The fair value of all senior unsecured notes as of September 30, 2013 and December 31, 2012 was based on Level 1 inputs from third-party market quotations. The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks.

(10) Income Tax

The income tax provision for the nine months ended September 30, 2013 reflects a tax benefit of $8.3 million for the current period loss. Unrecognized tax benefits increased $0.4 million during the nine months ended September 30, 2013 , and the increase, if recognized, would affect the effective tax rate.

The Company records deferred tax liabilities relating to property, plant, equipment and intangible assets primarily related to the Company’s share of the book basis in excess of tax basis for the assets inside of the Partnership. The Company also records deferred taxes relating to the difference between the Company’s book and tax basis of its investment in the Partnership. As of December 31, 2012, the difference between the Company’s book and tax basis in its investment in the Partnership was a deferred tax asset of $6.0 million which was offset by a valuation allowance of $6.0 million . As of September 30, 2013 , the

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difference between the Company’s book and tax basis in its investment in the Partnership was a deferred tax liability; therefore, the valuation allowance of $6.0 million related to the deferred tax asset has been reversed.

(11) Commitments and Contingencies

(a) Employment and Severance Agreements

Certain members of management of the Company are parties to employment and/or severance agreements with the General Partner of the Partnership. The employment and severance agreements provide those managers with severance payments in certain circumstances and, in the case of employment agreements, prohibit each such person from competing with the General Partner of the Partnership or its affiliates for a certain period of time following the termination of such person’s employment.

(b) Environmental Issues

The Partnership acquired LIG Pipeline Company and its subsidiaries on April 1, 2004 . Contamination from historical operations was identified during due diligence at a number of sites owned by the acquired companies. The seller, AEP, has indemnified the Partnership for these identified sites. Moreover, AEP has entered into an agreement with a third party company pursuant to which the remediation costs associated with these sites have been assumed by this third party company that specializes in remediation work. To date, 23 of the 25 sites requiring remediation have been completed and have received a “No Further Action” status from the Louisiana Department of Environmental Quality. The remaining two sites continuing with remediation efforts are expected to reach closure in 2013 . The Partnership does not expect to incur any material liability with these sites; however, there can be no assurance that the third parties who have assumed responsibility for remediation of site conditions will fulfill their obligations.

The Company is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.

At times, the Partnership’s subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.

The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. 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. In January 2012 , a plaintiff in one of these lawsuits was awarded a judgment of $2.0 million . The Partnership has appealed the matter and has posted a bond to secure the judgment pending its resolution. The Partnership has accrued a $2.0 million liability related to this matter. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to federal court. The amount of damages is unspecified. The Partnership's subsidiary, Crosstex LIG, LLC, is one of the named defendants as the owner of pipelines in the area. The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case.

(12) Segment Information

Identification of operating segments is based principally upon regions served. The Partnership’s reportable segments consist of the natural gas gathering, processing and transmission operations located in north Texas and in the Permian Basin in west Texas ("NTX"), the pipelines and processing plants located in Louisiana ("LIG"), the south Louisiana processing and NGL assets ("PNGL") and rail, truck, pipeline, and barge facilities in the ORV, which includes the Company's investment in E2. Operating activity for intersegment eliminations is shown in the corporate segment. Sales are derived from external domestic customers.

The Partnership evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist primarily of property and equipment, including software, for general corporate support, working capital, debt financing costs and its investment in Howard Energy Partners ("HEP").

Summarized financial information concerning reportable segments is shown in the following table.



	LIG			NTX			PNGL			ORV			Corporate			Totals
	(In thousands)
Three Months Ended September 30, 2013
Sales to external customers	$	119,716		$	72,129		$	181,327		$	95,471		$	—		$	468,643
Sales to affiliates	22,949			21,839			3,140			—			(47,928		)	—
Purchased gas, NGLs and crude oil	(121,910		)	(54,460		)	(159,991		)	(79,916		)	47,928			(368,349		)
Operating expenses	(8,487		)	(13,853		)	(6,847		)	(10,225		)	—			(39,412		)
Segment profit	$	12,268		$	25,655		$	17,629		$	5,330		$	—		$	60,882
Loss on derivatives	$	(584	)	$	(510	)	$	(271	)	$	(269	)	$	—		$	(1,634	)
Depreciation, amortization and impairments	$	(3,168	)	$	(19,887	)	$	(78,652	)	$	(3,451	)	$	(829	)	$	(105,987	)
Capital expenditures	$	10,842		$	4,821		$	101,406		$	39,085		$	1,464		$	157,618
Identifiable assets	$	282,945		$	989,583		$	869,156		$	402,510		$	148,371		$	2,692,565
Three Months Ended September 30, 2012
Sales to external customers	$	141,977		$	65,606		$	184,427		$	52,937		$	—		$	444,947
Sales to affiliates	50,304			22,278			35,209			—			(107,791		)	—
Purchased gas, NGLs and crude oil	(166,374		)	(41,807		)	(204,267		)	(40,545		)	107,791			(345,202		)
Operating expenses	(8,468		)	(14,255		)	(7,306		)	(5,522		)	—			(35,551		)
Segment profit	$	17,439		$	31,822		$	8,063		$	6,870		$	—		$	64,194
Gain (loss) on derivatives	$	(498	)	$	(293	)	$	32		$	—		$	—		$	(759	)
Depreciation, amortization and impairments	$	(4,379	)	$	(21,508	)	$	(16,503	)	$	(2,164	)	$	(524	)	$	(45,078	)
Capital expenditures	$	1,596		$	7,596		$	34,064		$	556		$	5,573		$	49,385
Identifiable assets	$	281,891		$	1,067,591		$	538,427		$	318,258		$	147,707		$	2,353,874
Nine Months Ended September 30, 2013
Sales to external customers	$	372,499		$	230,939		$	550,811		$	214,820		$	—		$	1,369,069
Sales to affiliates	68,854			55,309			19,659			—			(143,822		)	—
Purchased gas, NGLs and crude oil	(377,937		)	(160,255		)	(502,680		)	(171,415		)	143,822			(1,068,465		)
Operating expenses	(23,960		)	(40,499		)	(22,067		)	(27,082		)	—			(113,608		)
Segment profit	$	39,456		$	85,494		$	45,723		$	16,323		$	—		$	186,996
Gain (loss) on derivatives	$	370		$	(1,557	)	$	(26	)	$	(449	)	$	—		$	(1,662	)
Depreciation, amortization and impairments	$	(9,477	)	$	(59,528	)	$	(94,842	)	$	(8,561	)	$	(1,996	)	$	(174,404	)



Capital expenditures	$	27,010		$	12,073		$	329,071		$	71,771		$	7,406		$	447,331
Identifiable assets	$	282,945		$	989,583		$	869,156		$	402,510		$	148,371		$	2,692,565
Nine Months Ended September 30, 2012
Sales to external customers	$	410,154		$	191,523		$	610,694		$	52,937		$	—		$	1,265,308
Sales to affiliates	183,529			70,988			120,997			—			(375,514		)	—
Purchased gas, NGLs and crude oil	(509,196		)	(123,284		)	(677,996		)	(40,545		)	375,514			(975,507		)
Operating expenses	(25,164		)	(41,549		)	(21,693		)	(5,522		)	—			(93,928		)
Segment profit	$	59,323		$	97,678		$	32,002		$	6,870		$	—		$	195,873
Gain (loss) on derivatives	$	4,145		$	(2,709	)	$	541		$	—		$	—		$	1,977
Depreciation, amortization and impairments	$	(10,747	)	$	(62,950	)	$	(32,531	)	$	(2,164	)	$	(1,771	)	$	(110,163	)
Capital expenditures	$	3,484		$	41,050		$	79,981		$	556		$	7,109		$	132,180
Identifiable assets	$	281,891		$	1,067,591		$	538,427		$	318,258		$	147,707		$	2,353,874

The following table reconciles the segment profits reported above to the operating income as reported in the condensed consolidated statements of operations (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Segment profits	$	60,882		$	64,194		$	186,996		$	195,873
General and administrative expenses	(16,364		)	(17,349		)	(53,930		)	(46,729		)
Gain (loss) on derivatives	(1,634		)	$	(759	)	(1,662		)	1,977
Gain (loss) on sale of property	270			(109		)	175			395
Depreciation, amortization and impairments	(105,987		)	$	(45,078	)	(174,404		)	(110,163		)
Operating income (loss)	$	(62,833	)	$	899		$	(42,825	)	$	41,353

(13) Immaterial Correction of Prior Period Financial Statements

During the period ended June 30, 2013, the Company determined certain immaterial corrections were required for previously-issued financial statements as discussed below. The corrections did not impact the Company’s operating income and were not considered material to the Company’s revenues and costs for the applicable periods.

The Company determined that revenues and purchased gas costs related to a new processing arrangement were improperly reduced from revenue and purchased gas costs which resulted in equal understatements of revenues and purchased gas costs in its previously-issued financial statements for the three and nine months ended September 30, 2012 . As a result both revenues and purchased gas were understated by $38.0 million and $135.4 million for the three and nine months ended September 30, 2012 , respectively. The following table reflects the revenues, purchased gas costs and total operating costs and expenses as previously reported and as adjusted for the three and nine months ended September 30, 2012 (in thousands):

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	Three Months Ended September 30, 2012		Nine Months Ended September 30, 2012
As previously reported:
Total revenues	$	406,968	$	1,129,871
Purchased gas, NGLs and crude oil	$	307,223	$	840,070
Total operating costs and expenses	$	406,069	$	1,088,518
Operating income	$	899	$	41,353

As adjusted:
Total revenues	$	444,947	$	1,265,308
Purchased gas, NGLs and crude oil	$	345,202	$	975,507
Total operating costs and expenses	$	444,048	$	1,223,955
Operating income	$	899	$	41,353

(14) Subsequent Events

On October 21, 2013 , the Company and the Partnership entered into agreements with Devon Energy Corporation (“Devon”) to combine substantially all of Devon’s U.S. midstream assets with our assets to form a new midstream business. The new business will consist of two publicly traded entities: the Master Limited Partnership and a General Partner entity (collectively “the New Company”). The transaction is expected to be completed during the first quarter of 2014 pending stockholder approval.

On October 28, 2013, the Partnership announced it will expand its natural gas gathering and processing system in the Permian Basin by constructing a new natural gas processing complex and rich gas gathering pipeline system. The initial investment of approximately $140.0 million will include treating, processing and gas takeaway solutions for regional producers. The project, which will be fully owned by the Partnership, is supported by long-term, fee-based contracts. The entire project is scheduled to be completed and operational in the summer of 2014.

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Item 2. 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.

Overview

We are a Delaware corporation formed on April 28, 2000. Our assets consist primarily of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership and the majority interest in E2, a series company focused on the Utica Shale play in the Ohio River Valley. As of September 30, 2013 , we owned, directly or indirectly, 16,414,830 common units representing limited partner interests in Crosstex Energy, L.P. (the "Partnership"), and a 100% ownership interest in Crosstex Energy GP, LLC, the general partner of the Partnership (the "General Partner"), which owns the general partner interest and the incentive distribution rights in the Partnership. The Partnership is engaged in providing midstream energy services, including gathering, processing, transmission and marketing, to producers of natural gas, natural gas liquids ("NGLs") and crude oil. The Partnership also provides crude oil, condensate and brine disposal services to producers. The Partnership’s midstream energy asset network includes approximately 3,500 miles of pipelines, ten natural gas processing plants, four fractionators, 3.1 million barrels of NGL cavern storage, rail terminals, barge terminals, truck terminals and a fleet of approximately 100 trucks. The Partnership manages and reports its activities primarily according to geography. The Partnership has five reportable segments: (1) South Louisiana processing, crude and NGL, or PNGL, which includes its processing and NGL assets in South Louisiana; (2) Louisiana, or LIG, which includes its pipelines and processing plants located in Louisiana; (3) North Texas, or NTX, which includes its activities in the Barnett Shale and the Permian Basin; (4) Ohio River Valley, or ORV, which includes its activities in the Utica and Marcellus Shales; and (5) Corporate Segment, or Corporate, which includes its equity investment in Howard Energy Partners, or HEP, in the Eagle Ford Shale and its general partnership property and expenses.

Our cash flows consist primarily of distributions from the Partnership on the partnership interests we own. Unless restricted by the terms of the Partnership’s credit facility and/or senior unsecured note indentures, the Partnership is required by its partnership agreement to distribute all of its cash on hand at the end of each quarter, less reserves established by its General Partner in its sole discretion to provide for the proper conduct of the Partnership’s business or to provide for future distributions.

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries. Our condensed consolidated results of operations are derived from the results of operations of the Partnership and also include our deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’s results of operations. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership.

The Partnership manages its operations by focusing on gross operating margin because its business is generally to purchase and resell natural gas, NGLs and crude oil for a margin, or to gather, process, transport or market natural gas, NGLs and crude oil for a fee. The Partnership earns a volume based fee for providing crude oil transportation and brine disposal services. We define gross operating margin as operating revenue minus cost of purchased gas, NGLs and crude oil. Gross operating margin is a non-generally accepted accounting principles, or non-GAAP, financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below.

The Partnership’s gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities, the volumes of NGLs handled at its fractionation facilities, the volumes of crude oil handled at its crude terminals, the volumes of crude oil gathered, transported, purchased and sold and the volume of brine disposed. The Partnership generates revenues from seven primary sources:

• purchasing and reselling or transporting natural gas on the pipeline systems it owns;

• processing natural gas at its processing plants;

• fractionating and marketing the recovered NGLs;

• providing compression services;

• purchasing and reselling crude oil and condensate;

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• providing crude oil transportation and terminal services; and

• providing brine disposal services.

The Partnership generally gathers or transports gas owned by others through its facilities for a fee, or it buys natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transports and resells the natural gas at the market index. The Partnership attempts to execute all purchases and sales substantially concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the margin it will receive for each natural gas transaction. The Partnership’s gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. The Partnership is also party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that it has under contract may decline due to reduced drilling or other causes and the Partnership may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In the Partnership’s purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. However, on occasion the Partnership has entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and it captures the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as margin. Changes in the basis spread can increase or decrease margins.

One contract (the “Delivery Contract”) has a term to 2019 that obligates the Partnership to supply approximately 150,000 million British thermal units per day ("MMBtu/d") of gas. At the time that the Partnership entered into the Delivery Contract in 2008, it had dedicated supply sources in the Barnett Shale that exceeded the delivery obligations under the Delivery Contract. The Partnership’s agreements with these suppliers generally provided that the purchase price for the gas was equal to a portion of its sales price for such gas less certain fees and costs. Accordingly, the Partnership was initially able to generate a positive margin under the Delivery Contract. However, since entering into the Delivery Contract, there has been both (1) a reduction in the gas available under the supply contracts and (2) the discovery of other shale reserves, most notably the Haynesville and the Marcellus Shales, which has increased the supplies available to east coast markets and reduced the basis spread between north Texas-area production and the market indices used in the Delivery Contract. Due to these factors, the Partnership has had to purchase a portion of the gas necessary to fulfill its obligations under the Delivery Contract at market prices, resulting in negative margins under the Delivery Contract.

The Partnership has recorded a loss of approximately $ 13.5 million during the nine months ended September 30, 2013 on the Delivery Contract. The Partnership currently expects that it will record an additional loss of approximately $ 4.0 million to $ 6.0 million on the Delivery Contract for the remainder of the year ending December 31, 2013 and a loss of $20.0 million to $23.0 million during the year ended December 31, 2014. These estimates are based on forward prices, basis spreads and other market assumptions as of September 30, 2013 . These assumptions are subject to change if market conditions change during the remainder of 2013 , and actual results under the Delivery Contract in 2013 could be substantially different from the Partnership’s current estimates, which may result in a greater loss than currently estimated.

The Partnership generally gathers or transports crude oil owned by others by rail, truck, pipeline and barge facilities for a fee, or it buys crude oil from a producer at a fixed discount to a market index, then transports and resells the crude oil at the market index. The Partnership executes all purchases and sales substantially concurrently, thereby establishing the basis for the margin it will receive for each crude oil transaction. Additionally, it provides crude oil, condensate and brine services on a volume basis.

The Partnership also realizes gross operating margins from its processing services primarily through three different contract arrangements: processing margins ("margin"), percentage of liquids ("POL") or fixed-fee based. Under margin contract arrangements the Partnership’s gross operating margins are higher during periods of high liquid prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Under fixed-fee based contracts the Partnership’s gross operating margins are driven by throughput volume. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk — 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, property insurance, property taxes, repair and maintenance expenses, contract services and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not

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normally decrease or increase significantly in the short term with decreases or increases in the volume of gas, liquids or crude oil moved through or by the asset.

Recent Developments

Devon Energy Transaction. On October 21, 2013, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Devon Energy Corporation (“Devon”), Devon Gas Services, L.P., a wholly-owned subsidiary of Devon, Acacia Natural Gas Corp I, Inc., a wholly-owned subsidiary of Devon (“New Acacia”), New Public Rangers, L.L.C., a holding company newly formed by Devon (“New Public Rangers”), Rangers Merger Sub, Inc., a wholly-owned subsidiary of New Public Rangers (“Rangers Merger Sub”), and Boomer Merger Sub, Inc., a wholly-owned subsidiary of New Public Rangers (“Boomer Merger Sub”), pursuant to which Rangers Merger Sub will merge with and into the Company, and Boomer Merger Sub will merge with and into New Acacia (collectively, the “Mergers”), with the Company and New Acacia surviving as wholly-owned subsidiaries of New Public Rangers. At the effective time of the Mergers, New Acacia will own a 50% limited partner interest in Devon Midstream Holdings, L.P., a wholly-owned subsidiary of Devon (“Midstream Holdings”), which, together with its subsidiaries, will own Devon’s midstream assets in the Barnett Shale in North Texas, the Cana and Arkoma Woodford Shales in Oklahoma and Devon’s interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. Devon will own the managing member of New Public Rangers, and New Public Rangers will indirectly own 100% of the Partnership’s General Partner.

In connection with the Merger Agreement, the Partnership and its wholly-owned subsidiary, Crosstex Energy Services, L.P. (“Crosstex Energy Services”) entered into a Contribution Agreement (the “Contribution Agreement”) with Devon and certain of its wholly-owned subsidiaries pursuant to which two of Devon’s subsidiaries would contribute to Crosstex Energy Services the remaining 50% of the outstanding equity interests in Midstream Holdings and all of the outstanding equity interests in Devon Midstream Holdings GP, L.L.C., the general partner of Midstream Holdings (“Midstream Holdings GP” and, together with Midstream Holdings and their subsidiaries, the “Midstream Group Entities”) in exchange for the issuance by the Partnership of 120,542,441 units representing a new class of limited partnership interests in the Partnership (collectively, the “Contribution”).

The consummation of the transactions contemplated by the Merger Agreement, including the Mergers, is subject to the satisfaction of a number of conditions, including, but not limited to, (i) the adoption and approval of the Merger Agreement at a special meeting of our stockholders by at least 67% of the shares of our common stock issued and outstanding and entitled to vote on the adoption of the Merger Agreement, voting together as a single class; (ii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”) and (iii) the concurrent closing of the Contribution.

The Merger Agreement provides certain termination rights for both us and Devon, including our right to terminate the Merger Agreement to enter into an agreement with respect to a superior proposal (as defined in the Merger Agreement). The Merger Agreement will automatically terminate upon any termination of the Contribution Agreement.

Bearkat Natural Gas Gathering and Processing System. On October 28, 2013, the Partnership announced it will expand its natural gas gathering and processing system in the Permian Basin by constructing a new natural gas processing complex and rich gas gathering pipeline system. The initial investment of approximately $140.0 million will include treating, processing and gas takeaway solutions for regional producers. The project, which will be fully owned by the Partnership, is supported by long-term, fee-based contracts.

The new-build processing complex, called Bearkat, will be strategically located near the Partnership’s existing Deadwood joint venture assets in Glasscock County, Texas. The processing plant will have an initial capacity of 60 million cubic feet per day (MMcf/d), increasing the Partnership’s total operated processing capacity in the Permian to approximately 115 MMcf/d. The Partnership will also construct a 30-mile high-pressure gathering system upstream of the Bearkat complex to provide additional gathering capacity for producers in Glasscock and Reagan counties. The entire project is scheduled to be completed and operational in the summer of 2014. The Partnership continues to develop additional expansion opportunities for constrained producer customers in Howard, Martin, Glasscock, and Reagan counties.

Black Run Rail Terminal. In June 2013, the Partnership re-activated its Black Run rail loading terminal located in Frazeysburg, Ohio on the Ohio Central Railroad ("OHCR"), allowing for the transport of various grades of crude oil and condensate. The Black Run facility is a 20-car rail rack with tracking gangways designed to top load multiple products, including condensate and various grades of crude oil, at a rate of 24,000 barrels per day ("Bbls/d"). The Black Run rail terminal moves condensate out of the ORV region to refinery and petrochemical markets.

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The OHCR is a 70-mile short line freight railroad that interchanges with the Columbus and Ohio River Railroad, CSX Transportation, Norfolk Southern, Ohio Southern Railroad and Wheeling and Lake Erie Railway. The Black Run terminal, which is adjacent to the Partnership's oil gathering pipeline, leverages the Partnership's existing tankage and piping, as well as the capabilities of its extensive truck fleet in the ORV.

Riverside Crude Facility Expansion. In June 2013, the Partnership completed the Phase II expansion of its Riverside facility located on the Mississippi River in southern Louisiana. The Riverside facility’s capacity to transload crude oil from railcars to the Partnership’s barge facility increased to approximately 15,000 Bbls/d of crude oil. Phase II additions to the Riverside facility include a 100,000 barrel above-ground crude oil storage tank, a rail spur with a 26-car rail unloading rack and a crude offloading facility with pumps and metering as well as a truck unloading bay. As part of the Phase II expansion, the Riverside facility was modified so that sour crude can be unloaded in addition to sweet crude.

E2 Investment. On March 5, 2013, we entered into an agreement to form a new company (“E2”) that will provide services for producers in the liquids-rich window of the Utica Shale play. Our investment commitment of approximately $75.0 million is funding the construction of three new natural gas compression and condensate stabilization facilities. As of September 30, 2013 , we had invested approximately $49.1 million in E2.

E2 will build, own and operate the three gas gathering compressor stations and condensate stabilization assets in Noble and

Monroe counties in the southern portion of the Utica Shale play in Ohio. Commercial operations of the two initial facilities is

expected to occur during the fourth quarter of 2013 and the third plant is expected to be operational during the first quarter of 2014. We own approximately 93 percent of E2 with the remainder owned by E2 management. We have pre-determined rights to purchase the management ownership interests of E2 in the future.

In March 2013, XTXI Capital, LLC, our wholly-owned subsidiary (“Subsidiary Borrower”), entered into a $75.0 million senior secured credit facility in order to provide the financing for our investment in E2. We have guaranteed Subsidiary Borrower’s obligations under such credit facility. In May 2013, we, as parent and guarantor, and Subsidiary Borrower, as borrower, entered into an amendment to such credit facility to increase the amount that Subsidiary Borrower is permitted to borrow thereunder from $75.0 million to up to $90.0 million.

Cajun-Sibon Phases I and II. In Louisiana, the Partnership is transforming its business that has been historically focused on processing offshore natural gas to a business that is focused on NGLs with additional opportunities for growth from new onshore supplies of NGLs. The Louisiana petrochemical market has historically relied on liquids from offshore production; however, the decrease in offshore production and increase in onshore rich gas production have changed the market structure. Cajun-Sibon Phases I and II will work to bridge the gap between supply, which aggregates in the Mont Belvieu area, and demand, located in the Mississippi River corridor of Louisiana, thereby building a strategic NGL position in this region. The Partnership currently estimates that the total capital investment for Cajun-Sibon Phases I and II will be approximately $750.0 million.

The Partnership began this transformation by restarting its Eunice fractionator during 2011 at a rate of 15,000 Bbls/d of NGLs. This is a pivotal asset for Cajun-Sibon Phase I as the Partnership is expanding this facility to a rate of 55,000 Bbls/d. Phase I of its pipeline extension project was completed in October 2013 and connects Mont Belvieu supply lines in east Texas to Eunice, providing a direct link to its fractionators in south Louisiana markets. The Phase I Eunice fractionator expansion, which was completed in early November 2013, has increased the Partnership’s interconnected fractionation capacity in Louisiana to approximately 97,000 Bbls/d of raw-make NGLs. The Partnership expects the Phase I facilities to ramp-up to full volumes during the fourth quarter of 2013.

Cajun-Sibon Phase II will further enhance the Partnership’s Louisiana NGL business with significant additions to the Cajun-Sibon Phase I NGL pipeline extension and Eunice expansion. Under Phase II the Partnership will add pumping stations on the Phase I pipeline extension to increase its NGL supply capacity from approximately 70,000 Bbls/d to approximately 120,000 Bbls/d, construct a new 100,000 Bbl/d fractionator at the Plaquemine gas processing plant site and extend the Phase I NGL pipeline from Eunice to the new Plaquemine fractionator. The Partnership expects Phase II will be in service during the second half of 2014.

Issuance of Common Units. In June 2013, the Partnership issued 8,280,000 common units representing limited partner interests in the Partnership (including 1,080,000 common units issued pursuant to the exercise of the underwriters' option to purchase additional common units) at a public offering price of $20.33 per common unit for net proceeds of $162.0 million. The net proceeds from the common unit offering were used for capital expenditures for currently identified projects, including the Cajun-Sibon natural gas liquids pipeline expansion, and for general partnership purposes. Pending such use, the Partnership repaid outstanding borrowings under its credit facility.

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In January 2013, the Partnership issued 8,625,000 common units representing limited partner interests in the Partnership at a public offering price of $15.15 per common unit for net proceeds of $125.4 million. Concurrently with the public offering, the Partnership issued 2,700,000 common units representing limited partner interest in the Partnership at a price of $14.55 per unit for net proceeds of $39.2 million. The net proceeds from both common unit offerings were used for capital expenditures for currently identified projects, to repay bank borrowings and for general partnership purposes.

In May 2013, the Partnership entered into an Equity Distribution Agreement (the "EDA”) with BMO Capital Markets Corp. (“BMOCM”). This EDA replaced the previous equity distribution agreement entered into in March 2013 between BMOCM and the Partnership. Pursuant to the terms of the EDA, the Partnership may from time to time through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million. Through September 30, 2013, the Partnership sold an aggregate of 3,370,486 common units under the EDA and prior equity distribution agreement generating proceeds of approximately $62.9 million (net of approximately $0.9 million of commissions to BMOCM). The Partnership used the net proceeds for general partnership purposes, including working capital, capital expenditures and repayments of indebtedness.

Other Developments. HEP is continuing to expand its midstream assets in the Eagle Ford Shale in south Texas. The Partnership contributed an additional $22.3 million to HEP during the nine months ended September 30, 2013 to fund its 30.6% share of HEP’s expansion costs. The Partnership also received cash distributions totaling $13.1 million from HEP during the nine months ended September 30, 2013 . The Partnership is obligated to contribute additional funds to HEP upon one or more requests made by HEP. The Partnership expects that as HEP makes additional distributions to the Partnership and its other investors from its existing operations, HEP will request that the Partnership make additional capital contributions to fund its ongoing expansion efforts.

Non-GAAP Financial Measures

We include the following non-GAAP financial measures: The Partnership’s adjusted earnings before interest, taxes, depreciation and amortization, or adjusted EBITDA, and gross operating margin.

The Partnership’s adjusted EBITDA is defined as net income plus interest expense, provision for income taxes, depreciation and amortization expense, impairments, stock-based compensation, (gain) loss on noncash derivatives, distribution from limited liability company and noncontrolling interest; less gain on sale of property and equity in (income) loss of limited liability company. The Partnership’s adjusted EBITDA is used as a supplemental performance measure by its management and by external users of its financial statements, such as investors, commercial banks, research analysts and others, to assess:


•	financial performance of the Partnership’s assets without regard to financing methods, capital structure or historical

cost basis;


•	the ability of the Partnership’s assets to generate cash sufficient to pay interest costs, support its indebtedness and

make cash distributions to its unitholders and the General Partner;

• the Partnership’s operating performance and return on capital as compared to those of other companies in the

midstream energy sector, without regard to financing methods or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment

opportunities.

The Partnership’s adjusted EBITDA is one of the critical inputs into the financial covenants within the Partnership’s credit facility. The rates the Partnership pays for borrowings under its credit facility are determined by the ratio of its debt to the Partnership’s adjusted EBITDA. The calculation of these ratios allows for further adjustments to the Partnership’s adjusted EBITDA for recent material projects and acquisitions and dispositions.

The Partnership’s adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to similarly titled measures of other companies because other entities may not calculate adjusted EBITDA in the same manner.

The Partnership’s adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because the Partnership has borrowed money to finance its operations, interest expense is a necessary element of its

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costs and its ability to generate cash available for distribution. Because the Partnership uses capital assets, depreciation and amortization are also necessary elements of its costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as the Partnership’s adjusted EBITDA, to evaluate the Partnership’s overall performance.

The following table provides a reconciliation of the Company’s net loss to the Partnership’s adjusted EBITDA:



	Three months ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In millions)
Net loss attributable to Crosstex Energy, Inc.	$	(11.2	)	$	(4.3	)	$	(18.9	)	$	(6.8	)
Interest expense	16.2			23.2			55.1			63.9
Depreciation and amortization	33.4			45.1			101.8			110.2
Impairments	72.6			—			72.6			—
Equity in (income) loss of limited liability company	0.1			(1.5		)	0.1			(1.5		)
Distribution from limited liability company	4.3			—			13.1			—
(Gain) loss on sale of property	(0.3		)	0.1			(0.2		)	(0.4		)
Stock-based compensation	3.1			2.6			11.2			7.7
Non-controlling interest	(61.6		)	(10.2		)	(70.5		)	(7.2		)
Taxes	(6.2		)	1.8			(8.3		)	2.6
Other (a)	1.4			(2.2		)	1.3			(8.3		)
Company's adjusted EBITDA	$	51.8		$	54.6		$	157.3		$	160.2
Direct operating activity related to the Company	0.7			0.6			3.7			2.1
Partnership's adjusted EBITDA	$	52.5		$	55.2		$	161.0		$	162.3

__________________________________________________

(a) Includes the Partnership’s financial derivatives marked-to-market, acquisition costs and other income that are not included

in the Partnership’s adjusted EBITDA.

Gross operating margin is defined, generally, as revenues less cost of purchased gas, NGLs and crude oil. We present gross operating margin by segment in “Results of Operations”. We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because the Partnership’s business is generally to purchase and resell natural gas and crude oil for a margin or to gather, process, transport or market natural gas, NGLs and crude oil for a fee. Operating expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of the Partnership’s operating expenses. The Partnership does not deduct operating expenses from total revenue in calculating gross operating margin because these expenses are largely independent of the volumes the Partnership transports or processes and fluctuate depending on the activities performed during a specific period. As an indicator of the Partnership’s operating performance, gross operating margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. The Partnership’s gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

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The following table provides a reconciliation of the Company’s gross operating margin to operating income (loss):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In millions)
Total gross operating margin	$	100.3		$	99.8		$	300.6		$	289.8

Add (deduct):
Operating expenses	(39.4		)	(35.6		)	(113.6		)	(93.9		)
General and administrative expenses	(16.4		)	(17.3		)	(53.9		)	(46.7		)
Gain (loss) on sale of property	0.3			(0.1		)	0.2			0.4
Gain (loss) on derivatives	(1.6		)	(0.8		)	(1.7		)	2.0
Depreciation, amortization and other	(33.4		)	(45.1		)	(101.8		)	(110.2		)
Impairments	(72.6		)	—			(72.6		)	—
Operating income (loss)	$	(62.8	)	$	0.9		$	(42.8	)	$	41.4

Results of Operations

Set forth in the table below is certain financial and operating data for the periods indicated, which includes the Partnership's July 2012 acquisition of the ORV assets from the date of acquisition. The Partnership manages its operations by focusing on gross operating margin which the Partnership defines as operating revenue less cost of purchased gas, NGLs and crude oil as

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reflected in the table below.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
				(As Adjusted)						(As Adjusted)
	(Dollars in millions)
LIG Segment
Revenues	$	142.7		$	192.3		$	441.4		$	593.7
Purchased gas and NGLs	(121.9		)	(166.4		)	(377.9		)	(509.2		)
Total gross operating margin	$	20.8		$	25.9		$	63.5		$	84.5
NTX Segment
Revenues	$	93.9		$	87.9		$	286.2		$	262.5
Purchased gas and NGLs	(54.4		)	(41.8		)	(160.3		)	(123.3		)
Total gross operating margin	$	39.5		$	46.1		$	125.9		$	139.2
PNGL Segment
Revenues	$	184.5		$	219.7		$	570.5		$	731.7
Purchased gas, NGLs and crude oil	(160.0		)	(204.3		)	(502.7		)	(678.0		)
Total gross operating margin	$	24.5		$	15.4		$	67.8		$	53.7
ORV Segment
Revenues	$	95.4		$	52.9		$	214.8		$	52.9
Purchased crude oil	(79.9		)	(40.5		)	(171.4		)	(40.5		)
Total gross operating margin	$	15.5		$	12.4		$	43.4		$	12.4
Corporate
Revenues	$	(47.9	)	$	(107.8	)	$	(143.8	)	$	(375.5	)
Purchased gas and NGLs	47.9			107.8			143.8			375.5
Total gross operating margin	$	—		$	—		$	—		$	—
Total
Revenues	$	468.6		$	445.0		$	1,369.1		$	1,265.3
Purchased gas, NGLs and crude oil	(368.3		)	(345.2		)	(1,068.5		)	(975.5		)
Total gross operating margin	$	100.3		$	99.8		$	300.6		$	289.8

Midstream Volumes:
LIG
Gathering and Transportation (MMBtu/d)	457,000			741,000			494,000			814,000
Processing (MMBtu/d)	256,000			215,000			254,000			241,000
NTX
Gathering and Transportation (MMBtu/d)	1,032,000			1,163,000			1,060,000			1,177,000
Processing (MMBtu/d)	374,000			386,000			388,000			353,000
PNGL
Processing (MMBtu/d)	392,000			602,000			416,000			769,000
NGL Fractionation (Gals/d)	1,187,000			1,350,000			1,171,000			1,284,000
ORV*
Crude Oil Handling (Bbls/d)	14,000			12,000			11,000			12,000
Brine Disposal (Bbls/d)	8,000			8,000			8,000			8,000

__________________________________________________

* Crude oil handling from PNGL is included in ORV reported volumes.

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Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

Gross Operating Margin. Gross operating margin was $100.3 million for the three months ended September 30, 2013 compared to $99.8 million for the three months ended September 30, 2012 , an increase of $0.5 million , or 0.5% . The overall increase was due to increased south Louisiana NGL fractionation and marketing activity and an increase from the Partnership's ORV assets. The following provides additional details regarding this change in gross operating margin:

•

The ORV segment contributed an increase of $3.1 million to the Partnership's gross operating margin for the three months ended September 30, 2013 . The crude oil and condensate handling activity margin increased $2.4 million to $10.9 million for the third quarter of 2013 as compared to the third quarter 2012 due to an increase in condensate volumes. Additionally, gross operating margins increased by $0.3 million related to the E2 operations. Gross operating margins from brine disposal and handling increased by $0.5 million to $4.4 million for the third quarter of 2013 as compared to the third quarter of 2012.

•

The PNGL segment had a gross operating margin increase of $9.1 million for the three months ended September 30, 2013 compared to the three months ended September 30, 2012 . The Partnership's NGL fractionation and marketing activities contributed $6.8 million of the gross operating margin increase due to increased NGL volumes from truck and rail activity. The PNGL crude oil terminal activity in south Louisiana contributed $1.0 million due to an increase in crude activity. The south Louisiana processing plants gross operating margin increased $1.3 million from third party opportunity processing during July and August 2013 due to third-party system repairs which diverted liquids-rich gas by the Partnership's plant.

•

The NTX segment had a decrease in gross operating margin of $6.6 million for the three months ended September 30, 2013 compared to the three months ended September 30, 2012 . Gross operating margin decreased by $6.6 million from the Partnership's transmission and gathering assets due to a decline in the Partnership's throughput volumes combined with a reduction in gathering rates under certain contracts, including a contract with a major producer in north Texas.

•

The LIG segment had a decrease in gross operating margin of $5.1 million for the three months ended September 30, 2013 compared to the three months ended September 30, 2012 . Gross operating margins decreased by $0.7 million from the Partnership's Gibson and Plaquemine plants and gas processed for its account by a third-party processor due to a weaker processing environment during 2013 as compared to 2012. Gross operating margins decreased by $4.4 million on the gathering and transmission assets due to sales volumes lost related to the Bayou Corne sinkhole, lost opportunity sales volumes due to lower processing margins and a reduction in treating and blending volumes.

Operating Expenses . Operating expenses were $39.4 million for the three months ended September 30, 2013 compared to $35.6 million for the three months ended September 30, 2012 , an increase of $3.9 million , or 10.9% . The primary contributors to the increase are as follows:


•	the Partnership's labor and benefits expenses increased by $1.8 million related to an increase in employee headcount due to increased activity in its ORV and PNGL segments;


•	the Partnership's rents, lease and vehicle expenses increased by $0.6 million primarily related to an increase in vehicles in the Partnership's ORV segment;


•	the Partnership's regulatory and tax expenses increased $1.2 million as a result of increased ad valorem tax expenses on its ORV assets; and


•	the Company incurred maintenance and labor expenses of $0.2 million related to the E2 assets.

General and Administrative Expenses . General and administrative expenses were $16.4 million for the three months ended September 30, 2013 compared to $17.3 million for the three months ended September 30, 2012 , a decrease of $1.0 million , or 5.7% . The primary contributors to the total decrease are as follows:


•	the Partnership's labor and benefits expenses decreased by $0.6 million due to a decrease in the Partnership's estimated bonus accrual during the third quarter of 2013 that more than offset its increase in labor costs arising from an increase in employee headcount;


•	the Company's fees and services expenses decreased by $1.1 million due to a decrease in legal and other professional fees including a decrease in fees related to the Company's investment in E2; and

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•	the Partnership's stock based compensation expense increased by $0.4 million due to an increase in headcount.

(Gain)/Loss on Derivatives . The Partnership had a loss on derivatives of $1.6 million for the three months ended September 30, 2013 compared to a loss of $0.8 million for the three months ended September 30, 2012 . The derivative transaction types contributing to the net loss are as follows (in millions):



	Three Months Ended September 30,
	2013					2012
	Total		Realized			Total		Realized
Basis swaps	$	0.1	$	0.3		$	0.1	$	1.3
Processing margin hedges	0.5		(0.4		)	0.3		(0.8		)
Liquids Swaps - non-designated	0.5		—			0.3		—
Storage/Inventory Swaps	0.4		0.7			0.1		(0.3		)
Other	0.1		—			—		0.1
Net loss on derivatives	$	1.6	$	0.6		$	0.8	$	0.3

Depreciation and Amortization . Depreciation and amortization expenses were $33.4 million for the three months ended September 30, 2013 compared to $45.1 million for the three months ended September 30, 2012 , a decrease of $11.7 million , or 25.9% . This decrease includes $8.6 million related to accelerated depreciation and amortization of the Sabine Plant included in the quarter ended September 30, 2012, $2.5 million of decreased intangible amortization due to the Eunice processing plant impairment discussed below, and $1.7 million of decreased intangible amortization related to the revision in future estimated throughput volumes attributable to the dedicated acreage purchased with the Partnership's gathering system in North Texas. These decreases were partially offset by additional depreciation due to net asset additions.

Impairment. Impairment expense was $72.6 million for the three months ended September 30, 2013. The impairment relates to the termination of customer contracts associated with the Eunice processing plant which was shut-down in August 2013.

Interest Expense . Interest expense was $16.2 million for the three months ended September 30, 2013 compared to $23.2 million for the three months ended September 30, 2012 , a decrease of $7.1 million , or 30.4% . Net interest expense consists of the following (in millions):



	Three Months Ended September 30,
	2013			2012
Senior notes	$	20.5		$	20.5
Bank credit facility	2.0			1.4
Capitalized interest (1)	(9.3		)	(1.0		)
Amortization of debt issue costs and discount	1.9			1.9
Other	1.1			0.4
Total	$	16.2		$	23.2

(1) The increase in capitalized interest is primarily related to project expansions in the Partnership's PNGL segment.

Equity in income (loss) of limited liability company. Equity in losses of limited liability company was $0.1 million for the three months ended September 30, 2013 compared to earnings of $1.5 million for the three months ended September 30, 2012. The decrease of $1.6 million of equity in earnings relates to the Partnership's HEP equity investment.

Other Income. Other income was less than $0.1 million for the three months ended September 30, 2013 compared to $4.4 million for the three months ended September 30, 2012. The Partnership's 2012 other income included a $3.0 million net gain related to the assignment to a third party of its rights, title and interest in a contract for the construction of a processing plant. In addition, the Partnership settled certain liabilities associated with sold assets for less than the accrued liabilities resulting in a $1.3 million gain in 2012.

Income Taxes. Income tax benefit was $6.2 million for the three months ended September 30, 2013 compared to a $1.8 million benefit for the three months ended September 30, 2012 , an increase of $4.3 million . The increased tax benefit is due to an increase in the loss from operations.

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Interest of Non-Controlling Partners in the Partnership’s Net Loss. The interest of non-controlling partners in the Partnership’s net income was a net loss of $61.6 million for the three months ended September 30, 2013 compared to a net loss of $10.2 million for the three months ended September 30, 2012 due to the changes shown in the following summary (in millions):



	Three Months Ended September 30,
	2013			2012
Net loss for the Partnership	$	(78.8	)	$	(16.1	)
Income allocation to CEI for the general partner incentive distribution	(1.4		)	(1.2		)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors	1.5			1.2
Loss allocation to CEI for its general partner share of Partnership income	1.3			0.3
Net loss allocable to limited partners	$	(77.4	)	$	(15.8	)
Less: CEI’s share of net income (loss) allocable to limited partners	(15.9		)	(5.7		)
Plus: Non-controlling partners' share of net income in Denton County Joint Venture	—			(0.1		)
Non-controlling partners’ share of Partnership net loss (1)	$	(61.5	)	$	(10.2	)

(1) Non-controlling partners' share of net loss in E2 of $0.1 million is not included for the three months ended September 30,

2013, as it relates to CEI operating activity.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Gross Operating Margin. Gross operating margin was $300.6 million for the nine months ended September 30, 2013 compared to $289.8 million for the nine months ended September 30, 2012 , resulting in an increase of $10.8 million , or 3.7% . The overall increase was due to the July 2012 acquisition of the ORV assets and increased south Louisiana NGL fractionation and marketing activity. The following provides additional details regarding this change in gross operating margin:

•

The ORV gross margin was $43.4 million for the nine months ended September 30, 2013 which includes a full nine months of ORV operations compared to $12.4 million for the nine months ended September 30, 2012 which only includes operations for the three months in 2012 from the date of acquisition, an increase of $31.0 million between periods. Gross operating margins for the nine months ended September 30, 2013 from crude oil and condensate handling and brine disposal and handling totaled $29.0 million and $14.0 million, respectively. Additionally, gross operating margins increased by $0.4 million related to the E2 operations.

•

The PNGL segment had a gross operating margin increase of $14.1 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 . The Partnership's NGL fractionation and marketing activities contributed $20.6 million of the gross operating margin increase due to improved margins from seasonal pricing spreads and increased NGL volumes from truck and rail activity. The PNGL segment also includes the Partnership's crude oil terminal activity in south Louisiana, which contributed $2.0 million of gross operating margin increase. These increases were offset by a combined gross operating margin decrease of $8.5 million from the Partnership's south Louisiana processing plants due to the less favorable processing environment which caused a significant decline in volumes processed through the plants as well as declines in margins earned on those volumes.

•

The NTX segment had a decrease in gross operating margin of $13.3 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 . Gross operating margin increased by $4.6 million from the Partnership's gas processing facilities primarily due to increased throughput on its Permian Basin system. This increase was offset by a decline in the Partnership's gross operating margin of $17.8 million from the gathering and transmission assets due to a decline in its throughput volumes together with reduced gathering and treating rates under certain contracts, including a contract with a major producer in north Texas.

•

The LIG segment had a decrease in gross operating margin of $21.0 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 . Gross operating margins decreased by $6.1 million from the Partnership's Gibson and Plaquemine plants and decreased by $3.5 million from gas processed on its account by a third-party processor due to a weaker processing environment during 2013 as compared to 2012. Gross operating margins decreased by $11.4 million on the gathering and transmission assets due to sales volumes lost related to the Bayou Corne sinkhole, loss of opportunity sales volumes due to lower processing margins and lower blending and treating volumes for the first nine months of 2013 as compared to same period in 2012. Although the Partnership's north LIG system in the

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Haynesville Shale had volume declines, most of these volume declines were associated with gas transported under firm transportation agreements so the Partnership only realized a slight decrease in its transportation fee on its north LIG system.

Operating Expenses . Operating expenses were $113.6 million for the nine months ended September 30, 2013 compared to $ 93.9 million for the nine months ended September 30, 2012 , an increase of $19.7 million , or 21.0% . This increase in operating expenses includes a total increase of $17.9 million related to the direct operating costs of ORV assets which are included for nine months during 2013 and only three months during 2012 (as set forth in more detail in the bullets below). The primary contributors to the total increase are as follows:


•	the Partnership's labor and benefits expenses increased by $11.1 million related to an increase in employee headcount following the acquisition of its ORV assets and project expansion in its PNGL segment;


•	the Partnership's rents, lease and vehicle expenses increased by $4.0 million primarily related to the acquisition of its ORV assets;


•	the Partnership's regulatory and tax expenses increased $2.5 million as a result of increased ad valorem tax expenses on its ORV assets; and


•	the Company incurred maintenance and labor expenses of $0.2 million related to the E2 assets.

General and Administrative Expenses . General and administrative expenses were $53.9 million for the nine months ended September 30, 2013 compared to $46.7 million for the nine months ended September 30, 2012 , an increase of $7.2 million , or 15.4% . The primary contributors to the total increase are as follows:


•	the Partnership's labor and benefits expenses increased by $2.5 million driven by an increase in headcount primarily related to the acquisition of the Partnership's ORV assets and activity related to project expansion in its PNGL segment;


•	the Partnership's stock based compensation expense increased by $3.1 million due to an increase in headcount, including $2.0 million attributable to certain bonuses paid in March 2013 in the form of stock and unit awards that immediately vested;


•	the Partnership's communication related costs increased by $0.5 million due to network upgrades;


•	the Company's rent and office supply fees increased by $0.8 million, including $0.3 million related to costs incurred by E2 due to increases in rent and office related costs; and


•	the Company's fees and services expenses decreased by $0.6 million due to a decrease in legal and other professional fees which includes such fees related to the Company's investment in E2.

(Gain)/Loss on Derivatives . The Partnership had a loss on derivatives of $1.7 million for the nine months ended September 30, 2013 compared to a gain of $2.0 million for the nine months ended September 30, 2012 . The derivative transaction types contributing to the net (gain)/loss are as follows (in millions):



	Nine Months Ended September 30,
	2013						2012
	Total			Realized			Total			Realized
Basis swaps	$	1.1		$	1.9		$	3.5		$	3.5
Processing margin hedges	(0.5		)	(1.5		)	(3.9		)	0.8
Liquids Swaps - non-designated	0.7			—			(1.1		)	—
Storage/Inventory Swaps	0.3			0.5			(0.4		)	(0.8		)
Other	0.1			—			(0.1		)	—
Net (gain) loss on derivatives	$	1.7		$	0.9		$	(2.0	)	$	3.5

Depreciation and Amortization . Depreciation and amortization expenses were $101.8 million for the nine months ended September 30, 2013 compared to $110.2 million for the nine months ended September 30, 2012 , a decrease of $8.3 million , or 7.6% . This decrease includes accelerated depreciation and amortization of $9.8 million related to the Sabine Pass Plant included in 2012, $2.5 million decrease of intangible amortization related to the Eunice processing plant impairment discussed below

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and $4.5 million of decreased intangible amortization related to the revision in future estimated throughput volumes attributable to the dedicated acreage purchased with the Partnership's gathering system in North Texas. These decreases were partially offset by $8.3 million of additional depreciation due to net asset additions, including $6.2 million related to the July 2012 acquisition of the ORV assets for the nine months in 2013 as compared to three months in 2012.

Impairment. Impairment expense was $72.6 million for the nine months ended September 30, 2013. The impairment relates to the termination of customer contracts associated with Eunice processing plant which was shut-down in August 2013.

Interest Expense . Interest expense was $55.1 million for the nine months ended September 30, 2013 compared to $63.9 million for the nine months ended September 30, 2012 , a decrease of $8.8 million , or 13.7% . Net interest expense consists of the following (in millions):



	Nine Months Ended September 30,
	2013			2012
Senior notes	$	61.6		$	54.6
Bank credit facility	5.1			5.2
Capitalized interest (1)	(19.4		)	(2.2		)
Amortization of debt issue costs and discount	6.0			5.3
Other	1.8			1.0
Total	$	55.1		$	63.9

(1) The increase in capitalized interest is primarily related to project expansions in the Partnership's PNGL segment.

Equity in income (loss) of limited liability company. Equity in losses of limited liability company was $0.1 million for the nine months ended September 30, 2013 compared to earnings of $1.5 million for the nine months ended September 30, 2012. The decrease of $1.6 million of equity in earnings relates to the Partnership's HEP equity investment.

Other Income. Other income was $0.4 million for the nine months ended September 30, 2013 compared to $4.5 million for the nine months ended September 30, 2012. The Partnership's 2012 other income included a $3.0 million net gain related to the assignment to a third party of its rights, title and interest in a contract for the construction of a processing plant. In addition, the Partnership settled certain liabilities associated with sold assets for less than the accrued liabilities resulting in a $1.3 million gain in 2012.

Income Taxes. Income tax benefit was $8.3 million for the nine months ended September 30, 2013 compared to $2.6 million benefit for the nine months ended September 30, 2012 , an increase of $5.7 million . The increased tax benefit is due to an increase in the loss from operations.

Interest of Non-Controlling Partners in the Partnership’s Net Income (loss). The interest of non-controlling partners in the Partnership’s net income was a net loss of $70.5 million for the nine months ended September 30, 2013 compared to a net loss of $7.2 million for the nine months ended September 30, 2012 due to the changes shown in the following summary (in millions):



	Nine Months Ended September 30,
	2013			2012
Net loss for the Partnership	$	(95.4	)	$	(15.7	)
Income allocation to CEI for the general partner incentive distribution	(4.2		)	(3.3		)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors	5.5			3.5
Loss allocation to CEI for its general partner share of Partnership income	1.7			0.4
Net loss allocable to limited partners	$	(92.4	)	$	(15.1	)
Less: CEI’s share of net loss allocable to limited partners	(22.1		)	(8.1		)
Plus: Non-controlling partners' share of net income in Denton County Joint Venture	—			(0.2		)
Non-controlling partners’ share of Partnership net loss (1)	$	(70.3	)	$	(7.2	)

(1) Non-controlling partners' share of net loss in E2 of $0.2 million is not included for the nine months ended September 30, 2013 , as it relates to CEI operating activity.

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Critical Accounting Policies

Impairment of Goodwill. Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Partnership evaluates goodwill for impairment annually as of July 1, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. The Partnership evaluated its goodwill for impairment on July 1, 2013. The Partnership's goodwill impairment analysis performed on that date did not result in an impairment as the fair value of the ORV reporting unit substantially exceeded its carrying value, and subsequent to that date, no event has occurred indicating that the implied fair value of the reporting unit is less than the carrying value of the Partnership's net assets.

Information regarding the Partnership’s other Critical Accounting Policies is included in Item 7 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012.

Liquidity and Capital Resources

Cash Flows from Operating Activities . Net cash provided by operating activities was $ 93.1 million for the nine months ended September 30, 2013 compared to net cash provided by operating activities of $ 42.9 million for the nine months ended September 30, 2012 . Income before non-cash income and expenses and changes in working capital for comparative periods were as follows (in millions):



	Nine Months Ended September 30,
	2013		2012
Income before non-cash income and expenses	$	89.6	$	94.3
Changes in working capital	$	3.5	$	(51.5	)

The change in working capital for 2013 and 2012 primarily relates to fluctuations in trade receivable and payable balances due to timing of collections and payments.

Cash Flows from Investing Activities . Net cash used in investing activities was $448.7 million for the nine months ended September 30, 2013 and $394.4 million for the nine months ended September 30, 2012 . The Company’s primary investing outflows were capital expenditures, net of accrued amounts, as follows (in millions):



	Nine Months Ended September 30,
	2013		2012
Growth capital expenditures (including $29.2 million related to E2 during 2013)	$	444.8	$	130.5
Maintenance capital expenditures	10.1		10.8
Acquisition	—		212.5
Investment in limited liability company	22.3		52.3
Total	$	477.2	$	406.1

Net cash provided by investing activities for the nine months ended September 30, 2013 includes proceeds of $18.5 million from the Partnership's sale of the local distribution companies acquired in connection with the Partnership's July 2012 acquisition of its ORV assets, which were classified as held for disposition on the balance sheet as of December 31, 2012 and $10.0 million of distributions from limited liability company in excess of earnings.

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Cash Flows from Financing Activities . Net cash provided by financing activities was $366.4 million for the nine months ended September 30, 2013 and $327.3 million for nine months ended September 30, 2012 . The Company's primary financing activities consist of the following (in millions):



	Nine Months Ended September 30,
	2013			2012
Net borrowings (repayments) on the Partnership's bank credit facility	$	5.0		$	(79.5	)
Net borrowings on the Subsidiary Borrower's credit facility	47.3			—
Other debt borrowings	12.4			—
2022 Notes borrowings	—			250.0
Net repayments under capital lease obligations	(2.4		)	(2.3		)
Debt refinancing costs	(3.3		)	(6.9		)
Contributions from non-controlling partners	3.9			—
Common unit offerings	389.2			232.8

Successful completion of the Mergers and the Contribution would trigger an event of default under the Partnership's credit facility and a mandatory repurchase offer under the terms of the indenture governing the Partnership's 8.875% senior unsecured notes due 2018 (the “2018 Notes”) at a purchase price equal to 101% of the aggregate principal amount of the 2018 Notes repurchased, plus accrued and unpaid interest, if any. In certain circumstances, completion of the Mergers and Contribution also could trigger a mandatory repurchase offer under the terms of the indenture governing the Partnership's 7.125% senior unsecured notes due 2022 (the “2022 Notes”) if, within 90 days of consummation of the transactions, the Partnership experiences a rating downgrade of the 2022 Notes by either Moody’s or S&P. The Partnership expects that, in connection with the closing of the Mergers and the Contribution, the Partnership will seek an amendment to or waiver of the event of default provisions of its credit facility.

Dividends to shareholders and distributions to non-controlling partners in the Partnership are also primary uses of cash in financing activities. Total cash dividends and distributions made during the nine months ended September 30, 2013 and 2012 were as follows (in millions):



	Nine Months Ended September 30,
	2013		2012
Dividend to shareholders	$	17.6	$	17.1
Non-controlling partner distributions	66.1		52.5
Total	$	83.7	$	69.6

__________________________________________________

(1) Excludes distributions paid through the issuance of paid-in-kind preferred units for the nine months ended September 30, 2013 .

In order to reduce interest costs, the Partnership and Subsidiary Borrower 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 the Partnership’s and Subsidiary Borrower's credit facilities. The Partnership and Subsidiary Borrower borrow money under their respective credit facilities to fund checks as they are presented. As of September 30, 2013 , the Partnership and Subsidiary Borrower had approximately $ 496.7 million and $42.7 million , respectively, of available borrowing capacity under their respective credit facilities. Changes in drafts payable for the nine months ended September 30, 2013 and 2012 were as follows (in millions):



	Nine Months Ended September 30,
	2013		2012
Decrease in drafts payable	$	1.3	$	4.3

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Working Capital. We had a working capital deficit of $ 23.2 million as of September 30, 2013 . Changes in working capital may fluctuate significantly between periods even though the Partnership’s trade receivables and payables are typically collected and paid in 30 to 60 day pay cycles. A large volume of the Partnership’s revenues is collected and a large volume of its gas purchases is paid near each month end or the first few days of the following month. As such, receivable and payable balances at any month end may fluctuate significantly depending on the timing of these receipts and payments. During times of significant construction, accounts payable balances also include construction related invoices, which negatively impact working capital until paid from long-term funds. In addition, although the Partnership strives to minimize the amount of time and volumes that its natural gas, NGLs and crude oil are kept in inventory, these working inventory balances may fluctuate significantly from period to period due to operational reasons and due to changes in natural gas, NGL and crude oil prices. Working capital also includes mark to market derivative assets and liabilities associated with commodity derivatives which may fluctuate significantly due to the changes in natural gas, NGL and crude oil prices.

Changes in Operations During 2012 and 2013. The Partnership has a gas gathering contract with a major producer in its North Texas assets with a primary term that expired August 31, 2012 that was modified to be on a month-to-month basis beginning September 1, 2012. Subsequently, the modified contract was extended for six months at a reduced gathering fee rate which reduced its gross operating margin by approximately $1.2 million per quarter. The contract is currently rolling month to month in evergreen status (under the terms of the previously mentioned six month extension), and the Partnership is in the process of finalizing negotiations of a longer term agreement.

The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of these pipelines and underground storage reservoirs. This sinkhole is situated west of the Partnership’s underground natural gas and NGL storage facility. The cause of the sinkhole is currently under investigation by Louisiana state and local officials. The Partnership took a section of its 36-inch-diameter natural gas pipeline located near the sinkhole out of service. Service to certain markets, primarily in the Mississippi River area, has been curtailed or interrupted, and the Partnership has worked with its customers to secure alternative natural gas supplies so that disruptions are minimized. The Partnership is currently in the initial phase of constructing the replacement pipeline in its rerouted location and anticipates services will resume during the first half of 2014 due to permit delays.

The Partnership is assessing the potential for recovering its losses from responsible parties, and it is seeking recovery from its insurers. The Partnership’s insurers, however, have denied its insurance claim for coverage and filed a declaratory judgment asking a court to determine that the Partnership’s insurance policy does not cover this damage. The Partnership has sued its insurers for breach of contract due to their refusal to pay its insurance claim for this damage. The Partnership has also sued Texas Brine, LLC, the operator of a failed cavern in the area, and its insurers seeking recovery for this damage. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

Capital Requirements . During the nine months ended September 30, 2013 , capital investments were $466.9 million , which were funded by internally generated cash flow, borrowings under the Partnership’s credit facility, borrowings under the Subsidiary Borrower’s credit facility and proceeds from equity offerings by the Partnership. The Company’s remaining current growth capital spending projection for 2013 is approximately $177.0 million to $186.0 million (including E2 projected capital growth spending) related to identified growth projects, and the Company's 2014 capital budget includes approximately $450.0 million to $500.0 million of identified growth projects and capital interest and approximately $21 million to $27 million related to the Company's E2 investment. The Partnership and the Company expect to fund the growth capital expenditures from the proceeds of borrowings under the Partnership's and the Subsidiary Borrower's respective credit facilities and from other debt and equity sources.

Off-Balance Sheet Arrangements . No off-balance sheet arrangements existed as of September 30, 2013 .

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Total Contractual Cash Obligations. A summary of contractual cash obligations as of September 30, 2013 is as follows (in millions):



	Payments Due by Period
	Total		2013		2014		2015		2016		2017		Thereafter
Long-term debt obligations	$	975.0	$	—	$	—	$	—	$	—	$	—	$	975.0
Partnership's bank credit facility	76.0		—		—		—		76.0		—		—
Subsidiary Borrower's credit facility	47.3		—		—		—		47.3				—
Other long-term debt obligations	12.4		—		—		—		12.4		—		—
Interest payable on fixed long-term debt obligations	448.9		8.9		82.1		82.1		82.2		82.2		111.4
Capital lease obligations	27.0		1.1		4.6		4.6		4.6		6.9		5.2
Operating lease obligations	56.9		1.8		10.1		10.2		8.2		5.1		21.5
Purchase obligations	13.7		13.7		—		—		—		—		—
Consulting agreement	3.8		0.3		3.5		—		—		—		—
Inactive easement commitment*	10.0		—		—		—		—		—		10.0
Uncertain tax position obligations	4.5		4.5		—		—		—		—		—
Total contractual obligations	$	1,675.5	$	30.3	$	100.3	$	96.9	$	230.7	$	94.2	$	1,123.1

__________________________________________________

* Amounts related to inactive easements paid as utilized by the Partnership with balance due at end of 10 years if not utilized.

The above table does not include any physical or financial contract purchase commitments for natural gas due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis.

The interest payable under the Partnership's bank credit facility, Subsidiary Borrower’s credit facility and other debt are not reflected in the above table because such amounts depend on the outstanding balances and interest rates, which vary from time to time. However, given the same borrowing amount and rates in effect at September 30, 2013 , the cash obligation for interest expense on the the Partnership's bank credit facility, Subsidiary Borrower’s credit facility, and other debt would be approximately $2.7 million, $2.5 million and $0.5 million per year, or approximately $0.7 million, $0.6 million and $0.1 million for the remainder of 2013, respectively.

Indebtedness

As of September 30, 2013 and December 31, 2012 , long-term debt consisted of the following (in millions):



	September 30, 2013		December 31, 2012
Partnership's bank credit facility (due 2016), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2013 and December 31, 2012 was 3.6% and 4.3%, respectively	$	76.0	$	71.0
Subsidiary Borrower’s credit facility (due 2016), interest based on LIBOR plus 5.0%, interest rate at September 30, 2013 was 5.3%	47.3		—
Partnership's senior unsecured notes (due 2018), net of discount of $8.3 million and $9.7 million, respectively, which bear interest at the rate of 8.875%	716.7		715.3
Partnership's senior unsecured notes (due 2022), which bear interest at the rate of 7.125%	250.0		250.0
Other debt	12.4		—
Debt classified as long-term	$	1,102.4	$	1,036.3

Subsidiary Borrower’s Credit Facility. On March 5, 2013, Subsidiary Borrower entered into a Credit Agreement (the “Subsidiary Credit Agreement”) with Citibank, N.A., as Administrative Agent, Collateral Agent and a Lender, and the other lenders party thereto. Subsidiary Borrower intends to distribute the proceeds from the Subsidiary Credit Agreement to us to

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finance our investment in E2. The Subsidiary Credit Agreement initially permitted Subsidiary Borrower to borrow up to $75.0 million on a revolving credit basis. On May 8, 2013, we, as parent and guarantor, and Subsidiary Borrower, as borrower, entered into an amendment to the Subsidiary Credit Agreement to increase the amount that Subsidiary Borrower is permitted to borrow thereunder from $75.0 million to up to $90.0 million. The maturity date of the Subsidiary Credit Agreement is March 5, 2016. As of September 30, 2013 , there was $47.3 million borrowed under the Subsidiary Borrower’s credit facility, leaving approximately $42.7 million available for future borrowing based on the borrowing capacity of $90.0 million . See Note 3 to condensed consolidated financial statements titled “Long-Term Debt” for further details.

Other Borrowings. On September 4, 2013 , E2 Energy Services LLC ("E2 Services"), a subsidiary of the Company's E2 investment, entered into a credit agreement with JPMorgan Chase Bank, ("JPMorgan"). The maturity date of the credit agreement is September 4, 2016 . As of September 30, 2013 , there was $11.8 million borrowed under the agreement, leaving approximately $8.2 million available for future borrowing based on the borrowing capacity of $20.0 million . The interest rate under the credit agreement is based on Prime plus an applicable margin. The effective interest rate as of September 30, 2013 was approximately 4.0%. Additionally, as of September 30, 2013, E2 Services had notes outstanding in the amount of $0.6 million due in increments through July 2017. The notes bear interest at fixed rates ranging 4.2% to 7.0%.

The Partnership’s Credit Facility . As of September 30, 2013 , there were $62.3 million in outstanding letters of credit and $76.0 million outstanding borrowings under the Partnership’s bank credit facility, leaving approximately $496.7 million available for future borrowing based on the borrowing capacity of $635.0 million . As of September 30, 2013 , based on the Partnership's maximum permitted consolidated leverage ratio (as defined in the amended credit facility), the Partnership could borrow approximately $271.4 million of additional funds. The Partnership's credit facility matures in May 2016. In January and August 2013, the Partnership amended the credit facility. See Note 3 to the condensed consolidated financial statements titled “Long-Term Debt” for further details.

Recent Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board issued Accounting Standards Update 2013-02-Comprehensive Income (ASC 220), “ Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income .” This update requires that we report reclassifications out of accumulated other comprehensive income and their effect on net income by component or financial statement line. We have included the required disclosures in the notes to our financial statements for the nine months ended September 30, 2013 .

We have reviewed all other recently issued accounting pronouncements that became effective during the nine months ended September 30, 2013 and have determined that none would have a material impact to our Unaudited Condensed Consolidated Financial Statements.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. 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 specific uncertainties discussed elsewhere in this Form 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012 , and those set forth in Part II, “Item 1A. Risk Factors” of this report, if any, may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The Partnership’s primary market risk is the risk related to changes in the prices of natural gas, NGLs and crude oil. In addition, it is exposed to the risk of changes in interest rates on its floating rate debt.

Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the Commodities Futures Trading Commission ("CFTC") to regulate certain markets for derivative products, including over-

the-counter (“OTC”) derivatives. The CFTC has issued several new relevant regulations and other rulemakings are pending at the CFTC, the product of which would be rules that implement the mandates in the new legislation to cause significant portions of derivatives markets to clear through clearinghouses. The legislation and new regulations may also require counterparties to the Partnership’s derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Partnership encounters, reduce the Partnership’s ability to monetize or restructure its existing derivative contracts, and increase the Partnership’s exposure to less creditworthy counterparties. If the Partnership reduces its use of derivatives as a result of the legislation and regulations, the Partnership’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Partnership’s ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. The Partnership’s revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on the Partnership, its financial condition and its results of operations.

Commodity Price Risk

The Partnership is subject to significant risks due to fluctuations in commodity prices. Its exposure to these risks is primarily in the gas processing component of its business. The Partnership currently processes gas under three main types of contractual arrangements:

1. Processing margin contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and the Partnership makes a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. The Partnership’s margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, the Partnership mitigates its risk of processing natural gas when margins are negative primarily through its ability to bypass processing when it is not profitable for the Partnership or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.

2. Percent of liquids (“POL”) contracts: Under these contracts, the Partnership receives a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, the Partnership’s margins from these contracts are greater during periods of high liquids prices. The Partnership’s margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.

3. Fee based contracts: Under these contracts the Partnership has no commodity price exposure and is paid a fixed fee per unit of volume that is processed.

Gas processing margins by contract types and gathering, transportation and crude handling margins as a percent of total gross operating margin for the comparative year-to-date periods are as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Gathering, transportation and crude handling margin	62.2	%	70.0	%	61.6	%	63.6	%

Gas processing margins:
Processing margin	4.7	%	4.9	%	4.5	%	11.2	%
Percent of liquids	8.6	%	6.4	%	8.9	%	8.1	%
Fee based	24.5	%	18.7	%	25.0	%	17.1	%
Total gas processing	37.8	%	30.0	%	38.4	%	36.4	%

Total	100	%	100.0	%	100.0	%	100.0	%

The Partnership’s primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a risk management committee, including members of senior management, which oversees all hedging activity. The

Partnership enters into hedges for natural gas and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by its risk management committee.

The Partnership has hedged its exposure to declines in prices for NGL volumes produced for its account. The Partnership hedges exposure based on volumes it considers hedgeable (volumes committed under contracts that are long term in nature) versus total volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month to month processing options.

The Partnership has hedges in place at September 30, 2013 covering a portion of the liquids volumes it expects to receive under POL contracts. The hedges were done via swaps and are set forth in the following tables. The relevant payment index price is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service ("OPIS").

Period

Underlying

Notional Volume

We Pay

We Receive *

Fair Value Asset/(Liability)

(In thousands)

October 2013 - December 2013

Ethane

(MBbls)

Index

$0.3422/gal

199

October 2013 - December 2013

Propane

(MBbls)

Index

$1.0720/gal

October 2013 - December 2013

Iso Butane

(MBbls)

Index

$1.7135/gal

October 2013 - December 2013

Normal Butane

(MBbls)

Index

$1.6055/gal

110

October 2013 - December 2013

Natural Gasoline

(MBbls)

Index

$2.1446/gal

443

__________________________________________________

*weighted average

Period

Underlying

Notional Volume

We Pay

We Receive *

Fair Value Asset/(Liability)

(In thousands)

January 2014 - December 2014

Ethane

(MBbls)

Index

$0.2540/gal

(11

)

January 2014 - December 2014

Propane

(MBbls)

Index

$0.9654/gal

(98

)

January 2014 - December 2014

Normal Butane

(MBbls)

Index

$1.2415gal

(43

)

January 2014 - December 2014

Natural Gasoline

(MBbls)

Index

$1.9560/gal

(28

)

(180

)

__________________________________________________

*weighted average

The Partnership has hedged 80.1% of its total volumes at risk through December 2013 and hedged 20.7% of its total volumes at risk for 2014 relating to the Partnership's POL contracts.

The Partnership has hedges in place at September 30, 2013 covering the fractionation spread risk related to its processing margin contracts as set forth in the following tables:

Period

Underlying

Notional Volume

We Pay

We Receive *

Fair Value Asset/(Liability)

(In thousands)

October 2013 - December 2013

Ethane

(MBbls)

Index

$0.2825/gal

October 2013 - December 2013

Propane

(MBbls)

Index

$1.2222/gal

117

October 2013 - December 2013

Normal Butane

(MBbls)

Index

$1.6653/gal

164

October 2013 - December 2013

Natural Gasoline

(MBbls)

Index

$2.2168/gal

October 2013 - December 2013

Natural Gas

2,348

(MMBtu/d)

$3.82806/MMBtu*

Index

(46

)

295

__________________________________________________

*weighted average

Period

Underlying

Notional Volume

We Pay

We Receive *

Fair Value Asset/(Liability)

(In thousands)

January 2014 - December 2014

Ethane

(MBbls)

Index

$0.2800/gal

January 2014 - December 2014

Propane

(MBbls)

Index

$0.9545/gal

(49

)

January 2014 - December 2014

Normal Butane

(MBbls)

Index

$1.2587/gal

(24

)

January 2014 - December 2014

Natural Gasoline

(MBbls)

Index

$1.9642/gal

(16

)

January 2014 - December 2014

Natural Gas

755

(MMBtu/d)

$4.19828/MMBtu*

Index

(79

)

(164

)

__________________________________________________

*weighted average

The Partnership has hedged 17.9% of its total liquids volumes relating to its fractionation spread risk and 21.5% of the related total PTR volumes through December 2013. The Partnership has also hedged 4.3% of its total liquids volumes at risk and 5.3% of the related total PTR volumes through December 2014.

The Partnership is subject to price risk to a lesser extent for fluctuations in natural gas prices with respect to a portion of its gathering and transport services. Approximately 3.4% of the natural gas the Partnership markets is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price.

Another price risk the Partnership faces is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. The Partnership enters each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves it with short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

The use of financial instruments may expose the Partnership to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that the Partnership engages in hedging activities, it may be prevented from realizing the benefits of favorable price changes in the physical market. However, the Partnership is similarly insulated against unfavorable changes in such prices.

As of September 30, 2013 , outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value asset of $0.5 million . The aggregate effect of a hypothetical 10% increase in gas and NGL prices would result in a decrease of approximately $1.5 million in the net fair value of these contracts as of September 30, 2013 to a net fair value liability of approximately $1.0 million .

Interest Rate Risk

The Company is exposed to interest rate risk on the variable rate bank credit facilities of the Partnership, Subsidiary Borrower, and other debt. At September 30, 2013 , Subsidiary Borrower and other debt had $47.3 million and $12.4 million , respectively in borrowings under its facility. A 1% increase or decrease in interest rates would change its annual interest expense by approximately $0.6 million for the year.

The Partnership is exposed to interest rate risk on its variable rate bank credit facility. At September 30, 2013, the Partnership had $76.0 million in outstanding borrowings under this facility. A 1% increase or decrease in interest rates would change the Partnership's annual interest expense by approximately $0.8 million for the year.

At September 30, 2013 , the Partnership had fixed rate debt obligations of $716.7 million and $250.0 million , consisting of its senior unsecured notes with an interest rate of 8.875% and 7.125% , respectively. The fair value of the fixed rate obligations for the 2018 Notes and 2022 Notes was approximately $770.3 million and $256.3 million , respectively, as of September 30, 2013 . The Partnership estimates that a 1% decrease or increase in interest rates would increase or decrease the fair value of the 2018 Notes and the 2022 Notes by $8.7 million and $13.2 million , respectively.

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Crosstex Energy, Inc. of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report ( September 30, 2013 ), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting that occurred in the three months ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position or results of operations.

For a discussion of certain litigation and similar proceedings, please refer to Note 11, “Commitments and Contingencies,” of the Notes to Condensed Consolidated Financial Statements, which is incorporated by reference herein.

Item 1A. Risk Factors

Information about risk factors does not differ materially from that set forth in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2013 other than as supplemented by our Form 10-Q for the quarterly period ended March 31, 2013 in response to Part II, Item 1A. of such Form 10-Q and as listed below.

We cannot assure you that we will complete the Mergers, or if completed, that such transaction will be beneficial to us.

We cannot assure you that we will complete the Mergers, or if completed, that such transaction would achieve the desired benefits. The success of the mergers will depend, in part, on the ability of the combined company to realize the anticipated benefits from combining our business with that of the Midstream Group Entities. Realizing the benefits of the mergers will depend in part on the integration of assets, operations and personnel while maintaining adequate focus on the core businesses of the combined company. We cannot assure you that any cost savings, greater economies of scale and other operational efficiencies, as well as

revenue enhancement opportunities anticipated from the combination of the two businesses will occur. If management of the combined company is unable to minimize the potential disruption of the combined company’s ongoing business and distraction of the management during the integration process, the anticipated benefits of the mergers may not be realized. These integration matters could have an adverse effect on us.

If we consummate the Mergers and if any of these risks or unanticipated liabilities or costs were to materialize, any desired benefits of the Mergers may not be fully realized, if at all, and our future financial performance and results of operations could be negatively impacted. Further, the failure to complete the Mergers could negatively impact the market price of our shares of common stock and our future business and financial results, and we may experience negative reactions from the financial markets and from our customers and employees.

If we complete the Mergers, we will expand our operations into new geographic areas.

The Mergers would, if ultimately consummated, significantly increase the size of our business and diversify the geographic areas in which we operate. Midstream Holdings operates its business in geographic regions in which we do not currently operate, including the Cana and Arkoma Woodford Shales in Oklahoma. The inability to manage successfully the geographically more diverse and substantially larger combined organization could have a material adverse effect on the combined company after the Mergers and cause us not to fully realize the expected benefits of the Mergers.

Pending the completion of the Mergers, our business and operations could be materially adversely affected.

Under the terms of the Merger Agreement, we are subject to certain restrictions on the conduct of our business prior to completing the transactions which may adversely affect our ability to execute certain of our business strategies, including our ability in certain cases to enter into contracts or incur capital expenditures to grow our business. Such limitations could negatively affect our business and operations prior to the completion of the Mergers. Additionally, uncertainty about the effect of the mergers on employees, customers and suppliers may have an adverse effect on our business. These uncertainties may impair our ability to attract, retain and motivate key personnel until the mergers are consummated and for a period of time thereafter, and could cause our customers, suppliers and others who deal with us to seek to change their existing business relationships, which could negatively impact revenues, earnings and cash flows of our business, as well as the market prices of our common stock, regardless of whether the mergers are completed. Furthermore, matters relating to the Mergers may require substantial commitments of time and resources by management, which could otherwise have been devoted to other opportunities that may have been beneficial to us.

We will incur substantial transaction-related costs in connection with the Mergers.

We expect to incur a number of non-recurring transaction-related costs associated with completing the Mergers, combining the operations of the Midstream Group Entities with our business and achieving desired synergies. These fees and costs will be substantial. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time. Thus, any net benefit may not be achieved in the near term, or at all.

Our stockholders will have a reduced ownership in New Public Rangers after the Mergers and will exercise less influence over management.

Our stockholders currently have the right to vote in the election of our board of directors and on other matters affecting us. Upon the completion of the mergers, each of our stockholders will become a stockholder of New Public Rangers with a percentage ownership of New Public Rangers that is much smaller than such stockholder’s percentage ownership of us. Additionally, only one existing member of the our board of directors, our president and chief executive officer, will be automatically appointed to the New Public Rangers board of directors, with Devon having the right to appoint five directors and the other three to be mutually agreed upon by Devon and Crosstex. Our stockholders, as a group, will receive shares in the mergers constituting approximately 30% of the equity interests of New Public Rangers assumed to be outstanding immediately after the mergers. Further, New Public Rangers unitholders will not be entitled to elect the directors of New Public Rangers’ general partner and have only limited voting rights on matters affecting New Public Rangers’ business. Because of this, our current stockholders, as a group, will have less influence on the board of directors, management and policies of New Public Rangers than they now have on the management and policies of us.

The closing of the Mergers and Contribution would trigger an event of default under the Partnership's credit facility and a mandatory repurchase offer under the indenture governing the Partnership's 2018 Notes and, in certain circumstances, the Partnership's 2022 Notes.

The closing of the Mergers and Contribution will trigger an event of default under the Partnership's credit facility and a mandatory repurchase offer under the indenture governing its 2018 Notes. Completion of the Contribution and the Mergers also could trigger a mandatory repurchase offer under the indenture governing the Partnership's 2022 Notes if, within 90 days of the consummation of the transactions, the Partnership experiences a rating downgrade of the 2022 Notes by either Moody’s or S&P. If the Partnership is unable to negotiate an amendment or waiver of the applicable provisions in the Partnership's credit facility or if the Partnership is unable to fund a repurchase of its 2018 Notes or, if necessary, its 2022 Notes, the counterparties may exercise their rights and remedies under the agreements. Even if the Partnership is able to negotiate an amendment or waiver, the lenders under the Partnership's credit facility may require a fee for such waiver or seek to renegotiate the credit agreement on less favorable terms. Further, during the pendency of the proposed transactions, a decrease in Devon’s perceived creditworthiness may have an adverse effect on the Partnership's perceived creditworthiness, possibly resulting in a downgrade of credit ratings, tightening of credit under the Partnership's existing credit facility or increasing its borrowing costs.

Table of Contents

Item 6. Exhibits

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):



Number		Description
2.1**	—	Stock Purchase and Sale Agreement, dated as of May 7, 2012, by and among Energy Equity Partners, L.P., the Individual Owners (as defined therein), Clearfield Energy, Inc., Clearfield Holdings, Inc., West Virginia Oil Gathering Corporation, Appalachian Oil Purchasers, Inc., Kentucky Oil Gathering Corporation, Ohio Oil Gathering Corporation II, Ohio Oil Gathering Corporation III, OOGC Disposal Company I, M&B Gas Services, Inc., Clearfield Ohio Holdings, Inc., Pike Natural Gas Company, Eastern Natural Gas Company, Southeastern Natural Gas Company and Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 2.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated May 7, 2012, filed with the Commission on May 8, 2012).
2.2**	—	Agreement and Plan of Merger, dated as of October 21, 2013, by and among Devon Energy Corporation, Devon Gas Services, L.P., Acacia Natural Gas Corp I, Inc., Crosstex Energy, Inc., New Public Rangers, L.L.C., Boomer Merger Sub, Inc. and Rangers Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated October 21, 2013, filed with the Commission on October 22, 2013).
2.3**	—	Contribution Agreement, dated as of October 21, 2013, by and among Devon Energy Corporation, Devon Gas Corporation, Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc., Crosstex Energy, L.P. and Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated October 21, 2013, filed with the Commission on October 22, 2013).
3.1	—	Amended and Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.'s Current Report on Form 8-K dated October 26, 2006, filed with the Commission on October 31, 2006).
3.2	—	Fourth Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.'s Current Report on Form 8-K dated August 1, 2013, filed with the Commission on August 2, 2013).
3.3	—	Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-97779).
3.4	—	Certificate of Amendment to the Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.2 to Crosstex Energy, L.P.'s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012).
3.5	—	Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).
3.6	—	Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007).
3.7	—	Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008).
3.8	—	Amendment No. 3 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of January 19, 2010 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010).
3.9	—	Amendment No. 4 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of September 13, 2012 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated September 13, 2012, filed with the Commission on September 14, 2012).
3.10	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to Crosstex Energy, L.P.'s Registration Statement on Form S-1).
3.11	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to Crosstex Energy, L.P.'s Registration Statement on Form S-1, file No. 333-97779).
3.12	—	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of January 19, 2010 (incorporated by reference to Exhibit 3.2 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010).

Table of Contents



4.1	—	Registration Rights Agreement, dated August 6, 2013, by and among Crosstex Energy, Inc. and Blackstone / GSO Capital Solutions Overseas Master Fund L.P. and Blackstone / GSO Capital Solutions Fund LP (incorporated by reference to Exhibit 4.1 to Crosstex Energy, Inc.'s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013).
10.1	—	Stockholders Agreement, dated August 6, 2013, by and among Crosstex Energy, Inc. and Blackstone / GSO Capital Solutions Overseas Master Fund L.P. and Blackstone / GSO Capital Solutions Fund LP (incorporated by reference to Exhibit 10.2 to Crosstex Energy, Inc.'s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013).
10.2	—	Eighth Amendment to Amended and Restated Credit Agreement, dated as of August 28, 2013, by and among Crosstex Energy, L.P., Bank of America, N.A., as Administrative Agent and L/C Issuer, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.'s Current Report on Form 8-K dated August 28, 2013, filed with the Commission on August 30, 2013).
31.1*	—	Certification of the Principal Executive Officer.
31.2*	—	Certification of the Principal Financial Officer.
32.1*	—	Certification of the Principal Executive Officer and Principal Financial Officer, pursuant to 18 U.S.C. Section 1350.
101*	—	The following financial information from Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012, (ii) Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012, (iii) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2013 and 2012, (iv) Consolidated Statements of Changes in Stockholder's Equity for the nine months ended September 30, 2013, (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012, and (vi) the Notes to Condensed Consolidated Financial Statements.

__________________________________________________

* Filed herewith.

** Pursuant to Item 601(b)(2) of Regulation S-K, the Registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.




	By:	CROSSTEX ENERGY, INC.

	By:	/s/ MICHAEL J. GARBERDING
		Michael J. Garberding
		Executive Vice President and Chief Financial Officer

November 8, 2013

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