Targa Pipeline Partners LP - FORM 10-Q

Targa Pipeline Partners LP - FORM 10-Q - November 6, 2014

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

¨	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: 1-14998

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


DELAWARE		23-3011077
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One
1000 Commerce Drive, 4^th Floor
Pittsburgh, Pennsylvania		15275-1011
(Address of principal executive office)		(Zip code)

Registrant’s telephone number, including area code : (877) 950-7473

Indicate by check mark whether the 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 x No ¨

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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.

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

The number of common units of the registrant outstanding on November 4, 2014 was 84,499,824.

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT

ON FORM 10-Q


		Page

GLOSSARY OF TERMS			3

PART I.	FINANCIAL INFORMATION		4

Item 1.	Financial Statements		4

	Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013 (Unaudited)		4

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2014 and 2013 (Unaudited)		5

	Consolidated Statement of Equity for the Nine Months Ended September 30, 2014 (Unaudited)		6

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013 (Unaudited)		7

	Notes to Consolidated Financial Statements (Unaudited)		9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		46

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		70

Item 4.	Controls and Procedures		70

PART II.	OTHER INFORMATION		71

Item 1.	Legal Proceedings		71

Item 1A.	Risk Factors		71

Item 6.	Exhibits		72

SIGNATURES			76

Glossary of Terms

Definitions of terms and acronyms generally used in the energy industry and in this report are as follows:


BPD		Barrels per day. Barrel - measurement for a standard US barrel is 42 gallons. Crude oil and condensate are generally reported in barrels.

BTU		British thermal unit, a basic measure of heat energy

Condensate		Liquid hydrocarbons present in casinghead gas that condense within the gathering system and are removed prior to delivery to the gas plant. This product is generally sold on terms more closely tied to crude oil pricing.

EBITDA		Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is a non-GAAP measure.

FASB		Financial Accounting Standards Board

Fractionation		The process used to separate an NGL stream into its individual components.

GAAP		Generally Accepted Accounting Principles

G.P.		General Partner or General Partnership

Keep-Whole		A contract with a natural gas producer whereby the plant operator pays for or returns gas having an equivalent BTU content to the gas received at the well-head.

L.P.		Limited Partner or Limited Partnership

MCF		Thousand cubic feet

MCFD		Thousand cubic feet per day

MMBTU		Million British thermal units

MMCFD		Million cubic feet per day

NGL(s)		Natural Gas Liquid(s), primarily ethane, propane, normal butane, isobutane and natural gasoline

Percentage of Proceeds (“POP”)		A contract with a natural gas producer whereby the plant operator retains a negotiated percentage of the sale proceeds.

Residue gas		The portion of natural gas remaining after natural gas is processed for removal of NGLs and impurities.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)


	September 30, 2014		December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	6,736	$	4,914
Accounts receivable		253,830		219,297
Current portion of derivative assets		8,017		174
Prepaid expenses and other		24,428		17,393
Total current assets		293,011		241,778
Property, plant and equipment, net		3,132,810		2,724,192
Goodwill		365,763		368,572
Intangible assets, net		614,817		696,271
Equity method investment in joint ventures		180,602		248,301
Long-term portion of derivative assets		6,138		2,270
Other assets, net		45,271		46,461

Total assets	$	4,638,412	$	4,327,845

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	274	$	524
Accounts payable – affiliates		5,473		2,912
Accounts payable		101,659		79,051
Accrued liabilities		68,653		47,449
Accrued interest payable		13,604		26,737
Current portion of derivative liabilities		—		11,244
Accrued producer liabilities		188,994		152,309

Total current liabilities		378,657		320,226
Long-term portion of derivative liabilities		—		320
Long-term debt, less current portion		1,754,093		1,706,786
Deferred income taxes, net		31,771		33,290
Other long-term liabilities		6,960		7,318
Commitments and contingencies
Equity:
Class D convertible preferred limited partners’ interests		516,416		450,749
Class E preferred limited partners’ interests		121,852		—
Common limited partners’ interests		1,704,949		1,703,778
General Partner’s interest		47,451		46,118

Total partners’ capital		2,390,668		2,200,645
Non-controlling interest		76,263		59,260

Total equity		2,466,931		2,259,905

Total liabilities and equity	$	4,638,412	$	4,327,845

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenue:
Natural gas and liquids sales	$	673,888		$	535,719		$	2,004,567		$	1,410,797
Transportation, processing and other fees – third parties		49,513			43,651			142,847			116,534
Transportation, processing and other fees – affiliates		65			74			211			222
Derivative gain (loss), net		24,155			(24,517	)		9,117			(9,493	)
Other income, net		13,561			2,943			18,400			8,661

Total revenues		761,182			557,870			2,175,142			1,526,721

Costs and expenses:
Natural gas and liquids cost of sales		586,448			463,564			1,742,801			1,213,320
Operating expenses		29,837			24,806			81,948			71,435
General and administrative		16,824			16,637			50,680			40,481
Compensation reimbursement – affiliates		1,250			1,250			3,750			3,750
Other expenses		(1	)		685			16			19,585
Depreciation and amortization		50,173			51,080			148,632			127,921
Interest		22,553			24,347			69,275			65,614

Total costs and expenses		707,084			582,369			2,097,102			1,542,106

Equity loss in joint ventures		(4,711	)		(1,882	)		(10,464	)		(314	)
Gain (loss) on asset dispositions		(636	)		—			47,829			(1,519	)
Loss on early extinguishment of debt		—			—			—			(26,601	)

Income (loss) before tax		48,751			(26,381	)		115,405			(43,819	)
Income tax benefit		(623	)		(817	)		(1,519	)		(854	)

Net income (loss)		49,374			(25,564	)		116,924			(42,965	)
Income attributable to non-controlling interests		(4,029	)		(1,514	)		(10,456	)		(4,693	)
Preferred unit imputed dividend effect		(11,378	)		(11,378	)		(34,134	)		(18,107	)
Preferred unit dividends in kind		(11,408	)		(9,072	)		(31,533	)		(14,413	)
Preferred unit dividends		(2,609	)		—			(5,624	)		—

Net income (loss) attributable to common limited partners and the General Partner	$	19,950		$	(47,528	)	$	35,177		$	(80,178	)

Allocation of net income (loss) attributable to:
Common limited partner interest	$	12,822		$	(51,376	)	$	17,118		$	(90,990	)
General Partner interest		7,128			3,848			18,059			10,812

	$	19,950		$	(47,528	)	$	35,177		$	(80,178	)

Net income (loss) attributable to common limited partners per unit:
Basic	$	0.13		$	(0.66	)	$	0.18		$	(1.25	)

Weighted average common limited partner units (basic)		82,892			78,398			81,497			72,512

Diluted	$	0.13		$	(0.66	)	$	0.18		$	(1.25	)

Weighted average common limited partner units (diluted)		99,368			78,398			97,465			72,512

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

(in thousands, except unit data)

(Unaudited)


	Class D Preferred Limited Partner Units		Class E Preferred Limited Partner Units		Common Limited Partner Units			Class D Preferred Limited Partners		Class E Preferred Limited Partners			Common Limited Partners			General Partner			Non- controlling Interest			Total
Balance at December 31, 2013		13,823,869		—		80,585,148		$	450,749	$	—		$	1,703,778		$	46,118		$	59,260		$	2,259,905
Issuance of units and General Partner capital contributions		—		5,060,000		3,558,005			—		122,258			121,599			2,523			—			246,380
Equity compensation under incentive plans		—		—		405,018			—		—			19,076			—			—			19,076
Purchase and retirement of treasury units		—		—		(52,741	)		—		—			(1,733	)		—			—			(1,733	)
Distributions paid in kind units		875,207		—		—			—		—			—			—			—			—
Distributions paid		—		—		—			—		(3,421	)		(154,889	)		(19,249	)		—			(177,559	)
Distributions payable		—		—		—			—		(2,609	)		—			—			—			(2,609	)
Contributions from non-controlling interests		—		—		—			—		—			—			—			10,680			10,680
Distributions to non-controlling interests		—		—		—			—		—			—			—			(4,133	)		(4,133	)
Net income		—		—		—			65,667		5,624			17,118			18,059			10,456			116,924

Balance at September 30, 2014		14,699,076		5,060,000		84,495,430		$	516,416	$	121,852		$	1,704,949		$	47,451		$	76,263		$	2,466,931

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Nine Months Ended September 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	116,924		$	(42,965	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		148,632			127,921
Equity loss in joint ventures		10,464			314
Distributions received from equity method joint ventures		5,264			5,400
Non-cash compensation expense		19,258			13,818
Amortization of deferred finance costs		5,502			5,119
Loss on early extinguishment of debt		—			26,601
Loss (gain) on asset dispositions		(47,829	)		1,519
Income tax benefit		(1,519	)		(854	)
Change in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		(42,643	)		(88,225	)
Accounts payable and accrued liabilities		40,822			83,841
Accounts payable and accounts receivable – affiliates		2,561			(895	)
Derivative accounts payable and receivable		(23,275	)		19,527

Net cash provided by operating activities		234,161			151,121

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(473,147	)		(327,861	)
Cash paid for business combinations, net of cash received		—			(1,000,785	)
Net proceeds from asset disposition		130,966			—
Capital contributions to joint ventures		(7,908	)		(9,813	)
Other		—			310

Net cash used in investing activities	$	(350,089	)	$	(1,338,149	)

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS CONTINUED

(in thousands)

(Unaudited)


	Nine Months Ended September 30,
	2014			2013
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	$	838,500		$	979,000
Repayments under credit facility		(790,500	)		(1,172,000	)
Net proceeds from issuance of long term debt		—			1,028,369
Repayment of long-term debt		—			(365,822	)
Payment of premium on retirement of debt		—			(25,581	)
Payment of deferred financing costs		(2,942	)		(917	)
Payment for acquisition-based contingent consideration		—			(6,000	)
Principal payments on capital lease		(436	)		(10,577	)
Net proceeds from issuance of common and preferred limited partner units		243,857			888,887
Purchase and retirement of treasury units		(1,733	)		—
General Partner capital contributions		2,523			18,614
Contributions from non-controlling interest holders		10,680			8,277
Distributions to non-controlling interest holders		(4,133	)		(1,432	)
Distributions paid to common limited partners, preferred limited partners and the General Partner		(177,559	)		(146,132	)
Other		(507	)		(617	)

Net cash provided by financing activities		117,750			1,194,069

Net change in cash and cash equivalents		1,822			7,041
Cash and cash equivalents, beginning of period		4,914			3,398

Cash and cash equivalents, end of period	$	6,736		$	10,439

See accompanying notes to consolidated financial statements

ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

NOTE 1 – BASIS OF PRESENTATION

Atlas Pipeline Partners, L.P. (the “Partnership”) is a publicly-traded (NYSE: APL) Delaware limited partnership engaged in the gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States and natural gas gathering services in the Appalachian Basin in the northeastern region of the United States. The Partnership’s operations are conducted through subsidiary entities whose equity interests are owned by Atlas Pipeline Operating Partnership, L.P. (the “Operating Partnership”), a majority-owned subsidiary of the Partnership. At September 30, 2014, Atlas Pipeline Partners GP, LLC (the “General Partner”) owned a combined 2.0% general partner interest in the consolidated operations of the Partnership, through which it manages and effectively controls both the Partnership and the Operating Partnership. The General Partner is a wholly-owned subsidiary of Atlas Energy, L.P. (“ATLS”), a publicly-traded limited partnership (NYSE: ATLS). The remaining 98.0% ownership interest in the consolidated operations of the Partnership consists of limited partner interests. At September 30, 2014, the Partnership had 84,495,430 common units outstanding, including 1,641,026 common units held by the General Partner and 4,113,227 common units held by ATLS; 14,699,076 Class D convertible preferred units (“Class D Preferred Units”) outstanding (see Note 5); and 5,060,000 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) outstanding (see Note 5).

The accompanying consolidated financial statements, which are unaudited, except the balance sheet dated December 31, 2013, which is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim reporting. The accompanying consolidated financial statements and notes thereto do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. Certain amounts in the prior year’s consolidated financial statements have been reclassified to conform to the current year presentation. The results of operations for the nine month period ended September 30, 2014 may not necessarily be indicative of the results of operations for the full year ending December 31, 2014.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further within this note, a more thorough discussion of the Partnership’s significant accounting policies is included in its audited consolidated financial statements and notes thereto in its Annual Report on Form 10-K for the year ended December 31, 2013.

Principles of Consolidation and Non-Controlling Interest

The consolidated financial statements include the accounts of the Partnership, the Operating Partnership, a Variable Interest Entity (“VIE”) of which the Partnership is the primary beneficiary, and the Operating Partnership’s wholly-owned and majority-owned subsidiaries. The General Partner’s interest in the Operating Partnership is reported as part of its overall 2.0% general partner interest in the Partnership. All material intercompany transactions have been eliminated.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss).” The Partnership does not have any type of transaction that would be included within other comprehensive income (loss), thus comprehensive income (loss) is equal to net income (loss).

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners by the weighted average number of common limited partner units outstanding during the period. Net income (loss) attributable to common limited partners is determined by deducting net income attributable to participating securities, if applicable, and net income (loss) attributable to the General Partner’s and the preferred unitholders’ interests. The General Partner’s interest in net income (loss) is calculated on a quarterly basis based upon its 2.0% general partner interest and incentive distributions to be distributed for the quarter (see Note 5), with a priority allocation of net income to the General Partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the General Partner’s and limited partners’ ownership interests.

The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, which considers whether the incentive distributions of a master limited partnership represent a participating security when considered in the calculation of earnings per unit under the two-class method. The two-class method considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes the partnership agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Partnership’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 15), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. Therefore, the net income (loss) utilized in the calculation of net income (loss) per unit must be determined based upon the allocation of only net income to the phantom units on a pro-rata basis.

Class D Preferred Units participate in distributions with the common limited partner units according to a predetermined formula (see Note 5), thus they are considered participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The participation rights result in a non-contingent transfer of value each time the Partnership declares a distribution.

However, the contractual terms of the Class D Preferred Units do not require the holders to share in the losses of the entity, therefore the net income (loss) utilized in the calculation of net income (loss) per unit must be determined based upon the allocation of only net income to the Class D Preferred Units on a pro-rata basis.

Class E Preferred Units do not participate in distributions with the common limited partner units according to a predetermined formula, but rather receive distributions based upon a set percentage rate (see Note 5), thus they are not considered participating securities. However, income available to common limited partners is reduced by the distributions accumulated for the period on the Class E Preferred Units, whether declared or not, since the distributions on Class E Preferred Units are cumulative.

The following is a reconciliation of net income (loss) allocated to the General Partner and common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Net income (loss)	$	49,374		$	(25,564	)	$	116,924		$	(42,965	)
Income attributable to non-controlling interests		(4,029	)		(1,514	)		(10,456	)		(4,693	)
Preferred unit imputed dividend effect		(11,378	)		(11,378	)		(34,134	)		(18,107	)
Preferred unit dividends in kind		(11,408	)		(9,072	)		(31,533	)		(14,413	)
Preferred unit dividends		(2,609	)		—			(5,624	)		—

Net income (loss) attributable to common limited partners and the General Partner		19,950			(47,528	)		35,177			(80,178	)

General Partner’s cash incentive distributions		6,865			4,901			17,708			12,678
General Partner’s ownership interest		263			(1,053	)		351			(1,866	)

Net income attributable to the General Partner’s ownership interests		7,128			3,848			18,059			10,812

Net income (loss) attributable to common limited partners		12,822			(51,376	)		17,118			(90,990	)
Net income attributable to participating securities – phantom units⁽¹⁾		248			—			300			—
Net income attributable to participating securities – Class D Preferred Units⁽²⁾		1,907			—			2,542			—

Net income attributable to participating securities		2,155			—			2,842			—

Net income (loss) utilized in the calculation of net income (loss) attributable to common limited partners per unit	$	10,667		$	(51,376	)	$	14,276		$	(90,990	)

(1)

Net income attributable to common limited partners’ ownership interest is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the three and nine months ended September 30, 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 1,455,000 and 1,160,000 weighted average phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

(2)

Net income attributable to common limited partners’ ownership interest is allocated to the Class D Preferred Units on a pro-rata basis (weighted average Class D Preferred Units outstanding, plus a contractual yield premium of 1.5%, as a percentage of the sum of the weighted average Class D Preferred Units and common limited partner units outstanding). For the three and nine months ended September 30, 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 13,518,000 and 7,560,000 weighted average Class D Preferred Units, respectively, because the contractual terms of the Class D Preferred Units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, plus income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding plus the dilutive effect of outstanding participating securities and the effects of outstanding convertible securities. The phantom units and Class D Preferred Units are participating securities included in the calculation of diluted net income (loss) attributable to common units, due to their participation rights and due to their dilution if converted. The Class E Preferred Units are not participating securities and are not convertible and thus are not included in the units outstanding for calculation of diluted net income (loss) attributable to common limited partners per unit.

The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Weighted average number of common limited partner units – basic		82,892		78,398		81,497		72,512
Add effect of dilutive securities – phantom units⁽¹⁾		1,918		—		1,706		—
Add effect of convertible preferred limited partner units⁽²⁾		14,558		—		14,262		—

Weighted average common limited partner units – diluted		99,368		78,398		97,465		72,512

(1)

For the three and nine months ended September 30, 2013, approximately 1,455,000 and 1,160,000 weighted average phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common limited partners per unit, because the inclusion of such phantom units would have been anti-dilutive.

(2)

For the three and nine months ended September 30, 2013, approximately 13,518,000 and 7,560,000 weighted average Class D Preferred Units, respectively, were excluded from the computation of diluted net income (loss) attributable to common limited partners as the impact of the conversion would have been anti-dilutive.

Revenue Recognition

The Partnership accrues unbilled revenue and the related purchase costs due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. This revenue is recorded based upon volumetric data from the Partnership’s records and management estimates of the related gathering and compression fees and applicable product prices. The Partnership had unbilled revenues at September 30, 2014 and December 31, 2013 of $181.3 million and $134.9 million, respectively, which are included in accounts receivable within its consolidated balance sheets.

Cash and Cash Equivalents

The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments. Checks outstanding at the end of a period that exceed available cash balances held at the bank are considered to be book overdrafts and are reclassified to accounts payable. At September 30, 2014 and December 31, 2013, the Partnership reclassified the balances related to book overdrafts of $11.1 million and $28.8 million, respectively, from cash and cash equivalents to accounts payable on the Partnership’s consolidated balance sheets.

Recently Adopted Accounting Standards

In July 2013, the FASB issued Accounting Standard Update (“ASU”) 2013-11, “Income Taxes (Topic 740) –Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists,” which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. The Partnership applied these requirements upon the adoption of ASU 2013-11 on January 1, 2014. The application had no material impact on the Partnership’s financial position or results of operations.

Recently Issued Accounting Standards

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606).” ASU 2014-09 will supersede the revenue recognition requirements in Topic 605 “Revenue Recognition”, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

The amendments in ASU 2014-09 are effective for interim and annual reporting periods beginning after December 15, 2016. Early application is not permitted. An entity should apply the amendments in this ASU using one of the following methods: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect of initially applying the standard recognized at the date of initial application.

These requirements will be applied upon the application of ASU 2014-09 on January 1, 2017. The Partnership is currently in the process of evaluating which method to use for application of ASU 2014-09 and is still determining the impacts of ASU 2014-09 on its financial position, results of operations and disclosures.

In August 2014, the FASB issued ASU 2014-15, “Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern”. ASU 2014-15 is intended to define management’s responsibility to evaluate whether there is substantial doubt about an organization’s ability to continue as a going concern and to provide related footnote disclosures. The amendments in ASU 2014-15 are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Partnership plans on applying the new standard for the annual period ending December 31, 2016. The Partnership does not expect the new standard to have an impact on its disclosures.

NOTE 3 – ACQUISITIONS

On May 7, 2013, the Partnership completed the acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) for $974.7 million in cash, including final purchase price adjustments, less cash received (the “TEAK Acquisition”). The assets of these companies include gas gathering and processing facilities in Texas. The acquisition included a 75% interest in T2 LaSalle Gathering Company

L.L.C. (“T2 LaSalle”); a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”); and a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen” and together with T2 Eagle Ford and T2 LaSalle, the “T2 Joint Ventures”).

The Partnership accounted for this transaction as a business combination. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their acquisition date fair values. The following table presents the values assigned to the assets acquired and liabilities assumed in the TEAK Acquisition, based on their final estimated fair values at the date of the acquisition (in thousands):


Cash	$	8,074
Accounts receivable		11,055
Prepaid expenses and other		1,626
Property, plant and equipment		197,683
Intangible assets		430,000
Goodwill		186,050
Equity method investment in joint ventures		184,327

Total assets acquired		1,018,815

Accounts payable and accrued liabilities		(34,995	)
Other long term liabilities		(1,075	)

Total liabilities acquired		(36,070	)

Net assets acquired		982,745
Less cash received		(8,074	)

Net cash paid for acquisition	$	974,671

NOTE 4 – EQUITY METHOD INVESTMENTS

West Texas LPG Pipeline Limited Partnership

On May 14, 2014, the Partnership completed the sale of two indirect subsidiaries, which held an aggregate 20% interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”), to a subsidiary of Martin Midstream Partners LP (NYSE: MMLP). The Partnership received $131.0 million in proceeds, net of selling costs and final working capital adjustments, which were used to pay down the Partnership’s revolving credit facility (see Note 13). As a result of the sale, the Partnership recorded a $0.6 million loss and a $47.8 million gain on asset dispositions on its consolidated statements of operations for the three and nine months ended September 30, 2014, respectively.

WTLPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. WTLPG is operated by Chevron Pipeline Company, an affiliate of Chevron Corporation, a Delaware corporation (NYSE: CVX), which owns the remaining 80% interest. Prior to the sale of WTLPG, the Partnership accounted for its subsidiaries’ ownership interest in WTLPG under the equity method of accounting, with recognition of income of WTLPG as equity income in joint ventures on its consolidated statements of operations.

T2 Joint Ventures

On May 7, 2013, the Partnership acquired a 75% interest in T2 LaSalle, a 50% interest in T2 Eagle Ford and a 50% interest in T2 EF Co-Gen as part of the TEAK Acquisition (see Note 3). The T2 Joint Ventures are operated by a subsidiary of Southcross Holdings, L.P. (“Southcross”), the investor owning the remaining interests. The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. The Partnership accounts for its investments in the joint ventures under the equity method of accounting.

The Partnership evaluated whether the T2 Joint Ventures should be subject to consolidation. The T2 Joint Ventures do meet the qualifications of a VIE, but the Partnership does not meet the qualifications as the primary beneficiary. Even though the Partnership owns a 50% or greater interest in the T2 Joint Ventures, the Partnership does not have controlling financial interests in these entities. Since the Partnership shares equal management rights with Southcross, and Southcross is the operator of the T2 Joint Ventures, the Partnership determined that it is not the primary beneficiary of the VIEs and should not consolidate the T2 Joint Ventures. The Partnership accounts for its investment in the T2 Joint Ventures under the equity method, since the Partnership does not have a controlling financial interest, but does have a significant influence. The Partnership’s maximum exposure to loss as a result of its involvement with the VIEs includes its equity investment, any additional capital contribution commitments and the Partnership’s share of any approved operating expenses incurred by the VIEs.

The following table presents the value of the Partnership’s equity method investments in joint ventures as of September 30, 2014 and December 31, 2013 (in thousands):


	September 30, 2014		December 31, 2013
WTLPG	$	—	$	85,790
T2 LaSalle		56,449		50,534
T2 Eagle Ford		110,845		97,437
T2 EF Co-Gen		13,308		14,540

Equity method investment in joint ventures	$	180,602	$	248,301

The following table presents the Partnership’s equity loss in joint ventures for the three and nine months ended September 30, 2014 and 2013 (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
WTLPG	$	—		$	1,389		$	2,611		$	5,116
T2 LaSalle		(1,246	)		(1,263	)		(3,724	)		(2,162	)
T2 Eagle Ford		(2,611	)		(1,120	)		(7,349	)		(2,198	)
T2 EF Co-Gen		(854	)		(888	)		(2,002	)		(1,070	)

Equity loss in joint ventures	$	(4,711	)	$	(1,882	)	$	(10,464	)	$	(314	)

NOTE 5 – EQUITY

Common Units

On May 12, 2014, the Partnership entered into an Equity Distribution Agreement (the “2014 EDA”) with Citigroup Global Markets Inc. (“Citigroup”), Wells Fargo Securities, LLC and MLV & Co. LLC, as sales agents. Pursuant to the 2014 EDA, the Partnership may offer and sell from time to time through its sales agents, common units having an aggregate value up to $250.0 million. Sales are at market prices prevailing at the time of the sale.

In November 2012, the Partnership entered into an Equity Distribution Agreement (the “2012 EDA” and together, with the 2014 EDA, the “EDAs”) with Citigroup. Pursuant to this program, the Partnership offered and sold through Citigroup, as its sales agent, common units for $150.0 million. The Partnership used the full capacity under the 2012 EDA during the year ended 2013.

During the three months ended September 30, 2014 and 2013, the Partnership issued 2,095,818 and 1,772,800 common units, respectively, under the EDAs for net proceeds of $74.2 million and $63.7 million, respectively, net of $0.8 million and $1.3 million, respectively, in commissions paid to the sales agents. During the nine months ended September 30, 2014 and 2013, the Partnership issued 3,558,005 and 2,863,080 common units, respectively, under the EDAs for net proceeds of $121.6 million and $102.7 million, respectively, net of $1.2 million and $2.1 million, respectively, in commissions paid to the sales agents. The Partnership also received capital contributions from the General Partner of $1.5 million and $1.3 million, respectively, during the three months ended September 30, 2014 and 2013, and $2.5 million and $2.1 million, respectively, during the nine months ended September 30, 2014 and 2013, to maintain its 2.0% general partner interest in the Partnership. The net proceeds from the common unit offerings and General Partner contributions were utilized for general partnership purposes.

Cash Distributions

The Partnership is required to distribute, within 45 days after the end of each quarter, all its available cash (as defined in its partnership agreement) for that quarter to its common unitholders (subject to the rights of any other class or series of the Partnership’s securities with the right to share in the Partnership’s cash distributions) and to the General Partner. If common unit distributions in any quarter exceed specified target levels, the General Partner will receive between 15% and 50% of such distributions in excess of the specified target levels, including the General Partner’s 2.0% interest. The General Partner, which holds all the incentive distribution rights in the Partnership, has agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to the Partnership after the General Partner receives an initial $7.0 million per quarter pursuant to its incentive distribution rights.

Common unit and General Partner distributions declared by the Partnership for quarters ending from March 31, 2013 through June 30, 2014 were as follows:


For Quarter Ended	Date Cash Distribution Paid	Cash Distribution Per Common Limited Partner Unit		Total Cash Distribution to Common Limited Partners (in thousands)		Total Cash Distribution to the General Partner (in thousands)
March 31, 2013	May 15, 2013	$	0.59	$	45,382	$	3,980
June 30, 2013	August 14, 2013		0.62		48,165		5,875
September 30, 2013	November 14, 2013		0.62		49,298		6,013
December 31, 2013	February 14, 2014		0.62		49,969		6,095
March 31, 2014	May 15, 2014		0.62		49,998		6,099
June 30, 2014	August 14, 2014		0.63		51,781		7,055

Class D Preferred Units

The Partnership’s Class D Preferred Units are presented combined with a net $27.4 million unaccreted beneficial conversion discount on the Partnership’s consolidated balance sheets as of September 30, 2014. The Partnership recorded $11.4 million in each of the three months ended September 30, 2014 and 2013, and $34.1 million and $18.1 million for the nine months ended September 30, 2014 and 2013, respectively, within preferred unit imputed dividend effect on the Partnership’s consolidated statements of operations to recognize the accretion of the beneficial conversion discount.

The Class D Preferred Units received distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance in May 2013, and, thereafter, will continue to receive distributions in Class D Preferred Units, cash or a combination of Class D Preferred Units and cash, at the discretion of the General Partner. The Partnership recorded Class D Preferred Unit distributions in kind of $11.4 million and $9.1 million for the three months ended September 30, 2014 and 2013, respectively, and $31.5 million and $14.4 million for the nine months ended September 30, 2014 and 2013, respectively, as preferred unit dividends in kind on the Partnership’s consolidated statements of operations. The Partnership distributed 294,439 and 138,598 Class D Preferred Units during the three months ended September 30, 2014 and 2013, respectively, and 875,207 and 138,598 Class D Preferred Units during the nine months ended September 30, 2014 and 2013, respectively, to the holders of the Class D Preferred Units. The Partnership considers preferred unit distributions paid in kind to be a non-cash financing activity.

On October 28, 2014, the Partnership declared a cash distribution of $0.64 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2014. In addition, distributions for the Class D Preferred Units will be paid in kind for the quarter ended September 30, 2014. Accordingly, on November 14, 2014, the Partnership will issue approximately 321,000 Class D Preferred Units as a preferred unit distribution in kind for the quarter ended September 30, 2014 to the preferred unitholders of record at the close of business on November 10, 2014.

Class E Preferred Units

On March 17, 2014, the Partnership issued 5,060,000 of its Class E Preferred Units to the public at an offering price of $25.00 per Class E Preferred Unit. The Partnership received $122.3 million in net proceeds. The proceeds were used to pay down the Partnership’s revolving credit facility.

The Partnership will make cumulative cash distributions on the Class E Preferred Units from the date of original issue. The cash distributions are payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year, when, and if, declared by the board of directors. The initial distribution on the Class E Preferred Units was paid on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million, representing the distribution for the period March 17, 2014 through July 14, 2014. Going forward, the Partnership will pay cumulative distributions in cash on the Class E Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year. On October 15, 2014, the Partnership paid a cash distribution of $2.6 million on its outstanding Class E Preferred Units, representing the cash distribution for the period from July 15, 2014 through October 14, 2014. For the three and nine months ended September 30, 2014, the Partnership allocated net income of $2.6 million and $5.6 million, respectively, to the Class E Preferred Units for the dividends earned during the period, which was recorded as preferred unit dividends on its consolidated statements of operations.

At any time on or after March 17, 2019, or in the event of a liquidation or certain changes of control, the Partnership may redeem the Class E Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions on the date of redemption, whether or not declared. If the Partnership does not exercise this redemption right upon a change of control, then the holders of the Class E Preferred Units will have the option to convert their Class E Preferred Units into a number of the Partnership’s common units, as set forth in the Certificate of Designation relating to the Class E Preferred Units.

NOTE 6 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment, including leased property and equipment meeting capital lease criteria (see Note 13) (in thousands):


	September 30, 2014			December 31, 2013			Estimated Useful Lives in Years
Pipelines, processing and compression facilities	$	3,377,946		$	2,885,303		2 – 40
Rights of way		205,914			203,136		40
Buildings		10,447			10,291		40
Furniture and equipment		13,884			13,800		3 – 7
Other		15,165			15,805		3 – 10

		3,623,356			3,128,335
Less – accumulated depreciation		(490,546	)		(404,143	)

	$	3,132,810		$	2,724,192

The Partnership recorded depreciation expense on property, plant and equipment, including capital lease arrangements (see Note 13), of $30.9 million and $27.2 million for the three months ended September 30, 2014 and 2013, respectively, and $87.2 million and $73.7 million for the nine months ended September 30, 2014 and 2013, respectively, on its consolidated statements of operations.

The Partnership capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rate used to capitalize interest on borrowed funds was 5.6% and 5.7% for the three months ended September 30, 2014 and 2013, respectively, and 5.6% and 5.9% for the nine months ended September 30, 2014 and 2013, respectively. The amount of interest capitalized was $3.8 million and $1.5 million for the three months ended September 30, 2014 and 2013, respectively, and $9.9 million and $5.3 million for the nine months ended September 30, 2014 and 2013, respectively.

NOTE 7 – GOODWILL AND INTANGIBLE ASSETS

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. Impairment testing for goodwill is done at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (also known as a component). The Partnership evaluates goodwill for impairment annually, on December 31, for all reporting units, except SouthTX, which is evaluated on April 30. The Partnership tested the SouthTX reporting unit goodwill for impairment as of April 30, 2014. The results indicated the fair value of the SouthTX reporting unit was higher than its carrying value, and thus, goodwill recorded on the SouthTX reporting unit was not impaired as of April 30, 2014. The following table reflects the carrying amounts of goodwill by reporting unit at September 30, 2014 and December 31, 2013 (in thousands):


	September 30, 2014		December 31, 2013
Carrying amount of goodwill by reporting unit:
Barnett system	$	951	$	951
SouthOK system		170,381		170,381
SouthTX system		186,050		188,859
WestOK system		8,381		8,381

	$	365,763	$	368,572

The change in goodwill is related to a $2.8 million decrease in goodwill related to an adjustment of the fair value of assets acquired and liabilities assumed from the TEAK Acquisition (See Note 3). The fair values assigned to the assets acquired in the TEAK Acquisition were finalized during the second quarter 2014. The Partnership expects all goodwill recorded to be deductible for tax purposes.

The Partnership has recorded intangible assets with finite lives in connection with certain consummated acquisitions. The following table reflects the components of intangible assets being amortized at September 30, 2014 and December 31, 2013 (in thousands):


	September 30, 2014			December 31, 2013			Estimated Useful Lives In Years
Gross carrying amount:
Customer contracts	$	3,419		$	3,419		2–10
Customer relationships		867,653			887,653		7–15

		871,072			891,072

Accumulated amortization:
Customer contracts		(1,155	)		(779	)
Customer relationships		(255,100	)		(194,022	)

		(256,255	)		(194,801	)

Net carrying amount:
Customer contracts		2,264			2,640
Customer relationships		612,553			693,631

Net carrying amount	$	614,817		$	696,271

The weighted-average amortization period for customer contracts and customer relationships, as of September 30, 2014, is 9.8 years and 11.5 years, respectively. The Partnership recorded amortization expense on intangible assets of $19.3 million and $23.9 million for the three months ended September 30, 2014 and 2013, respectively, and $61.5 million and $54.2 million for the nine months ended September 30, 2014 and 2013, respectively, on its consolidated statements of operations. Amortization expense related to intangible assets is estimated to be as follows for each of the next five calendar years: remainder of 2014 - $18.6 million; 2015 through 2016 - $74.0 million per year; 2017 - $68.0 million; 2018 - $59.5 million.

NOTE 8 – OTHER ASSETS

The following is a summary of other assets (in thousands):


	September 30, 2014		December 31, 2013
Deferred finance costs, net of accumulated amortization of $27,536 and $22,034 at September 30, 2014 and December 31 2013, respectively	$	38,535	$	41,094
Security deposits		2,236		5,367
Other long-term receivable		4,500		—

	$	45,271	$	46,461

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 13). The Partnership incurred $2.6 million and $0.1 million of deferred finance costs during the three months ended September 30, 2014 and 2013, respectively, and $2.9 million and $22.5 million deferred finance costs during the nine months ended September 30, 2014 and 2013, respectively, related to various financing activities (see Note 13).

During the nine months ended September 30, 2013, the Partnership redeemed all of its outstanding $365.8 million 8.75% unsecured senior notes due June 15, 2018 (“8.75% Senior Notes”) (see Note 13) and recognized $5.3 million of accelerated amortization of deferred financing costs, included in loss on early extinguishment of debt on the Partnership’s consolidated statement of operations. There was no accelerated amortization of deferred financing costs during the nine months ended September 30, 2014. Amortization expense of deferred finance costs, excluding accelerated amortization expense, was $1.8 million for each of the three months ended September 30, 2014 and 2013, and $5.5 million and $5.1 million for the nine months ended September 30, 2014 and 2013, respectively, which is recorded within interest expense on the Partnership’s consolidated statements of operations.

NOTE 9 – INCOME TAXES

The Partnership owns APL Arkoma, Inc., a taxable subsidiary. The components of the federal and state income tax benefit of the Partnership’s taxable subsidiary for the three and nine months ended September 30, 2014 and 2013 are summarized as follows (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Income tax benefit:
Federal	$	(558	)	$	(732	)	$	(1,360	)	$	(765	)
State		(65	)		(85	)		(159	)		(89	)

Total income tax benefit	$	(623	)	$	(817	)	$	(1,519	)	$	(854	)

The components of net deferred tax liabilities as of September 30, 2014 and December 31, 2013 consist of the following (in thousands):


	September 30, 2014			December 31, 2013
Deferred tax assets:
Net operating loss tax carryforwards and alternative minimum tax credits	$	16,211		$	14,900
Deferred tax liabilities:
Excess of asset carrying value over tax basis		(47,982	)		(48,190	)

Net deferred tax liabilities	$	(31,771	)	$	(33,290	)

As of September 30, 2014, the Partnership had net operating loss carry forwards for federal income tax purposes of approximately $41.9 million, which expire at various dates from 2029 to 2034. Management of the General Partner believes it more likely than not that the deferred tax asset will be fully utilized.

NOTE 10 – DERIVATIVE INSTRUMENTS

The Partnership uses derivative instruments in connection with its commodity price risk management activities. The Partnership uses financial swap and option instruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Changes in fair value of derivatives are recognized immediately within derivative gain (loss), net in its consolidated statements of operations. Due to the right of setoff, derivatives are recorded on the Partnership’s consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty.

The following tables summarize the Partnership’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets and liabilities on the Partnership’s consolidated balance sheets for the periods indicated (in thousands):

Offsetting of Derivative Assets


	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts of Assets Presented in the Consolidated Balance Sheets
As of September 30, 2014:
Current portion of derivative assets	$	10,960	$	(2,943	)	$	8,017
Long-term portion of derivative assets		6,647		(509	)		6,138

Total derivative assets, net	$	17,607	$	(3,452	)	$	14,155

As of December 31, 2013:
Current portion of derivative assets	$	1,310	$	(1,136	)	$	174
Long-term portion of derivative assets		5,082		(2,812	)		2,270
Current portion of derivative liabilities		1,612		(1,612	)		—
Long-term portion of derivative liabilities		949		(949	)		—

Total derivative assets, net	$	8,953	$	(6,509	)	$	2,444

Offsetting of Derivative Liabilities


	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Consolidated Balance Sheets
As of September 30, 2014:
Current portion of derivative assets	$	(2,943	)	$	2,943	$	—
Long-term portion of derivative assets		(509	)		509		—

Total derivative liabilities, net	$	(3,452	)	$	3,452	$	—

As of December 31, 2013:
Current portion of derivative assets	$	(1,136	)	$	1,136	$	—
Long-term portion of derivative assets		(2,812	)		2,812		—
Current portion of derivative liabilities		(12,856	)		1,612		(11,244	)
Long-term portion of derivative liabilities		(1,269	)		949		(320	)

Total derivative liabilities, net	$	(18,073	)	$	6,509	$	(11,564	)

The following table summarizes the Partnership’s commodity derivatives as of September 30, 2014, (fair value and volumes in thousands):


Production Period	Commodity	Volumes⁽¹⁾		Average Fixed Price ($/Volume)		Fair Value⁽²⁾Asset/ (Liability)
Sold fixed price swaps
2014	Natural gas		5,350	$	4.15	$	298
2015	Natural gas		19,810		4.26		4,877
2016	Natural gas		9,300		4.26		1,356
2017	Natural gas		1,800		4.43		106
2014	NGLs		19,278		1.25		(110	)
2015	NGLs		71,442		1.22		2,642
2016	NGLs		34,650		1.03		1,476
2017	NGLs		10,080		1.04		565
2014	Crude oil		69		91.71		90
2015	Crude oil		210		90.26		444
2016	Crude oil		30		90.00		110

Total fixed price swaps							11,854

Purchased put options
2014	NGLs		2,520		0.96		26
2015	NGLs		3,150		0.94		111
2014	Crude oil		117		91.57		463
2015	Crude oil		270		89.18		1,712
Sold call options
2014	NGLs		1,260		1.34		—
2015	NGLs		1,260		1.28		(11	)

Total options							2,301

Total derivatives						$	14,155

(1)	NGL volumes are stated in gallons. Crude oil volumes are stated in barrels. Natural gas volumes are stated in MMBTUs.

(2)	See Note 11 for discussion on fair value methodology.

The following table summarizes the gross effect of all derivative instruments on the Partnership’s consolidated statements of operations for the periods indicated (in thousands):


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
Derivatives not designated as hedges
Gain (loss) recognized in derivative gain (loss), net:
Commodity contract - realized⁽¹⁾	$	(2,529	)	$	(907	)	$	(18,983	)	$	3,573
Commodity contract - unrealized⁽²⁾		26,684			(23,610	)		28,100			(13,066	)

Derivative gain (loss), net	$	24,155		$	(24,517	)	$	9,117		$	(9,493	)

(1)	Realized gain (loss) represents the gain or loss incurred when the derivative contract expires and/or is cash settled.

(2)	Unrealized gain (loss) represents the mark-to-market gain (loss) recognized on open derivative contracts, which have not yet settled.

NOTE 11 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following hierarchy:

Level 1– Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Derivative Instruments

At September 30, 2014, the valuations for all the Partnership’s derivative contracts are defined as Level 2 assets and liabilities within the same class of nature and risk, with the exception of the Partnership’s NGL fixed price swaps and NGL options, which are defined as Level 3 assets and liabilities within the same class of nature and risk.

The Partnership’s Level 2 commodity derivatives include natural gas and crude oil swaps and options, which are valued based upon observable market data related to the change in price of the underlying commodity. The value for these swaps and options are calculated by utilizing the New York Mercantile Exchange (“NYMEX”) quoted prices for futures and option contracts traded on NYMEX that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.

Valuations for the Partnership’s NGL options are based on forward price curves developed by financial institutions, and therefore are defined as Level 3 assets and liabilities. The NGL options are over-the-counter instruments that are not actively traded in an open market, thus the Partnership utilizes the valuations provided by the financial institutions that provide the NGL options for trade. The Partnership tests these valuations for reasonableness through the use of an internal valuation model.

Valuations for the Partnership’s NGL fixed price swaps are based on forward price curves provided by a third party, which the Partnership considers to be Level 3 inputs. The prices are adjusted based upon the relationship between the prices for the product/locations quoted by the third party and the underlying product/locations utilized for the swap contracts, as determined by a regression model of the historical settlement prices for the different product/locations. The regression model is recalculated on a quarterly basis. This adjustment is considered to be an unobservable Level 3 input. The NGL fixed price swaps are over-the-counter instruments, which are not actively traded in an open market. However, the prices for the underlying products and locations do have a direct correlation to the prices for the products and locations provided by the third party, which are based upon trading activity for the products and locations quoted. A change in the relationship between these prices would have a direct impact upon the unobservable adjustment utilized to calculate the fair value of the NGL fixed price swaps.

The following table represents the Partnership’s derivative assets and liabilities recorded at fair value as of September 30, 2014 and December 31, 2013 (in thousands):


	Level 1		Level 2			Level 3			Total
September 30, 2014
Assets
Commodity swaps	$	—	$	8,166		$	7,129		$	15,295
Commodity options		—		2,175			137			2,312

Total assets		—		10,341			7,266			17,607

Liabilities
Commodity swaps		—		(885	)		(2,556	)		(3,441	)
Commodity options		—		—			(11	)		(11	)

Total liabilities		—		(885	)		(2,567	)		(3,452	)

Total derivatives	$	—	$	9,456		$	4,699		$	14,155

December 31, 2013
Assets
Commodity swaps	$	—	$	2,994		$	1,412		$	4,406
Commodity options		—		4,337			210			4,547

Total assets		—		7,331			1,622			8,953

Liabilities
Commodity swaps		—		(4,695	)		(13,378	)		(18,073	)

Total liabilities		—		(4,695	)		(13,378	)		(18,073	)

Total derivatives	$	—	$	2,636		$	(11,756	)	$	(9,120	)

The Partnership’s Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps and NGL options. The following table provides a summary of changes in fair value of the Partnership’s Level 3 derivative instruments for the nine months ended September 30, 2014 (in thousands):


	NGL Fixed Price Swaps						NGL Put Options						NGL Call Options						Total
	Gallons			Amount			Gallons			Amount			Gallons			Amount			Amount
Balance – December 31, 2013		130,158		$	(11,966	)		6,300		$	210			—		$	—		$	(11,756	)
New contracts⁽¹⁾		70,560			—			5,040			200			5,040			(200	)		—
Cash settlements from unrealized (gain) loss⁽²⁾⁽³⁾		(65,268	)		9,326			(5,670	)		402			(2,520	)		(63	)		9,665
Net change in unrealized gain (loss)⁽²⁾		—			7,213			—			(273	)		—			189			7,129
Deferred option premium recognition⁽³⁾		—			—			—			(402	)		—			63			(339	)

Balance – September 30, 2014		135,450		$	4,573			5,670		$	137			2,520		$	(11	)	$	4,699

(1)	Swaps are entered into with no value on the date of trade. Options include premiums paid, which are included in the value of the derivatives on the date of trade.

(2)	Included within derivative gain (loss), net on the Partnership’s consolidated statements of operations.

(3)	Includes option premium cost reclassified from unrealized gain (loss) to realized gain (loss) at time of option expiration.

The following table provides a summary of the unobservable inputs used in the fair value measurement of the Partnership’s NGL fixed price swaps at September 30, 2014 and December 31, 2013 (in thousands):


	Gallons		Third Party Quotes⁽¹⁾			Adjustments⁽²⁾			Total Amount
As of September 30, 2014
Propane swaps		114,408	$	1,403		$	—		$	1,403
Isobutane swaps		1,260		(174	)		109			(65	)
Normal butane swaps		1,260		321			31			352
Natural gasoline swaps		18,522		3,787			(904	)		2,883

Total NGL swaps – September 30, 2014		135,450	$	5,337		$	(764	)	$	4,573

As of December 31, 2013
Propane swaps		100,296	$	(10,260	)	$	—		$	(10,260	)
Isobutane swaps		6,300		(2,342	)		955			(1,387	)
Normal butane swaps		7,560		40			322			362
Natural gasoline swaps		16,002		132			(813	)		(681	)

Total NGL swaps – December 31, 2013		130,158	$	(12,430	)	$	464		$	(11,966	)

(1)	Based upon the difference between the quoted market price provided by the third party and the fixed price of the swap.

(2)

Product and location basis differentials calculated through the use of a regression model, which compares the difference between the settlement prices for the products and locations quoted by the third party and the settlement prices for the actual products and locations underlying the derivatives, using a three year historical period.

The following table provides a summary of the regression coefficient utilized in the calculation of the unobservable inputs for the Level 3 fair value measurements for the NGL fixed price swaps for the periods indicated (in thousands):


	Level 3 NGL Swap Fair			Adjustment based upon Regression Coefficient
	Value Adjustments			Lower 95%		Upper 95%		Average
As of September 30, 2014:
Isobutane	$	109			1.1011		1.1117		1.1064
Normal butane		31			1.0292		1.0329		1.0311
Natural gasoline		(904	)		0.9704		0.9738		0.9721

Total Level 3 adjustments – September 30, 2014	$	(764	)

As of December 31, 2013:
Isobutane	$	955			1.1184		1.1284		1.1234
Normal butane		322			1.0341		1.0386		1.0364
Natural gasoline		(813	)		0.9727		0.9751		0.9739

Total Level 3 adjustments – December 31, 2013	$	464

NGL Linefill

The Partnership had $20.5 million and $14.5 million of NGL linefill at September 30, 2014 and December 31, 2013, respectively, which was included within prepaid expenses and other on its consolidated balance sheets. The NGL linefill represents amounts receivable for NGLs delivered to counterparties, for which the counterparty will pay at a designated later period at a price determined by the then market price. The Partnership’s NGL linefill held by some counterparties will be settled at various periods in the future and is defined as a Level 3 asset, which is valued at fair value using the same forward price curve utilized to value the Partnership’s NGL fixed price swaps. The product/location adjustment based upon the multiple regression analysis, which was included in the value of the linefill, was an increase of $0.1 million and a decrease of $0.4 million as of September 30, 2014 and December 31, 2013, respectively. The Partnership’s NGL linefill held by other counterparties is adjusted on a monthly basis according to the volumes delivered to the counterparties each period and is valued on a first in first out (“FIFO”) basis. During the quarter ended September 30, 2014, the contracts related to this linefill on the WestTX system were revised and the settlement and valuation was converted from a FIFO method to a fair value method.

The following table provides a summary of changes in fair value of the Partnership’s NGL linefill for the nine months ended September 30, 2014 (in thousands):


	Linefill Valued at Market					Linefill Valued on FIFO						Total NGL Linefill
	Gallons		Amount			Gallons			Amount			Gallons			Amount
Balance – December 31, 2013		5,788	$	4,738			11,538		$	9,778			17,326		$	14,516
Deliveries into NGL linefill		1,050		1,013			55,432			35,936			56,482			36,949
NGL linefill sales		—		—			(49,165	)		(30,256	)		(49,165	)		(30,256	)
Adjustments for linefill contract revision		10,791		9,134			(10,791	)		(9,134	)		—			—
Net change in NGL linefill valuation⁽¹⁾		—		(717	)		—			—			—			(717	)

Balance – September 30, 2014		17,629	$	14,168			7,014		$	6,324			24,643		$	20,492

(1)	Included within natural gas and liquids sales on the Partnership’s consolidated statements of operations.

Contingent Consideration

In February 2012, the Partnership acquired a gas gathering system and related assets for an initial net purchase price of $19.0 million. The Partnership agreed to pay up to an additional $12.0 million in contingent payments, payable in two equal amounts, if certain volumes are achieved on the acquired gathering system within a specified time period. Sufficient volumes were achieved in December 2012 and the Partnership paid the first contingent payment of $6.0 million in January 2013. As of September 30, 2014, the fair value of the remaining contingent payment resulted in a $6.0 million long term liability, which was recorded within other long term liabilities on the Partnership’s consolidated balance sheets. The range of the undiscounted amount the Partnership could pay related to the remaining contingent payment is between $0.0 and $6.0 million.

Other Financial Instruments

The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts the Partnership could realize upon the sale or refinancing of such financial instruments.

The Partnership’s current assets and liabilities on its consolidated balance sheets, other than the derivatives, NGL linefill and contingent consideration discussed above, are considered to be financial instruments for which the estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1 values. The carrying value of outstanding borrowings under the revolving credit facility, which bear interest at a variable interest rate, approximates their estimated fair value and thus is categorized as a Level 1 value. The estimated fair value of the Partnership’s Senior Notes (see Note 13) is based upon the market approach and calculated using the yield of the Senior Notes as provided by financial institutions and thus is categorized as a Level 3 value. The estimated fair values of the Partnership’s total debt at September 30, 2014 and December 31, 2013, which consists principally of borrowings under the revolving credit facility and the Senior Notes, were $1,705.2 million and $1,663.6 million, respectively, compared with the carrying amounts of $1,754.4 million and $1,707.3 million, respectively.

Acquisitions

On May 7, 2013, the Partnership completed the TEAK Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. These inputs require significant judgments and estimates at the time of the valuation. The fair values assigned to the assets acquired and liabilities assumed in the TEAK acquisition were finalized during the second quarter 2014.

NOTE 12 – ACCRUED LIABILITIES

The following is a summary of accrued liabilities (in thousands):


	September 30, 2014		December 31, 2013
Accrued capital expenditures	$	22,418	$	17,898
Acquisition-related liabilities		5,543		8,933
Accrued ad valorem and production taxes		17,808		3,551
Distributions payable		2,609		—
Unconditional purchase obligations		2,647		—
Other		17,628		17,067

	$	68,653	$	47,449

NOTE 13 – DEBT

Total debt consists of the following (in thousands):


	September 30, 2014			December 31, 2013
Revolving credit facility	$	200,000		$	152,000
6.625% Senior notes – due 2020		504,050			504,556
5.875% Senior notes – due 2023		650,000			650,000
4.750% Senior notes – due 2021		400,000			400,000
Capital lease obligations		317			754

Total debt		1,754,367			1,707,310
Less current maturities		(274	)		(524	)

Total long term debt	$	1,754,093		$	1,706,786

Cash payments for interest related to debt, net of capitalized interest, were $17.4 million and $17.8 million for the three months ended September 30, 2014 and 2013, respectively, and $60.3 million and $40.3 million for the nine months ended September 30, 2014 and 2013, respectively.

Revolving Credit Facility

At September 30, 2014, the Partnership had an $800.0 million senior secured revolving credit facility with a syndicate of banks that matures in August 2019. The weighted average interest rate for borrowings on the revolving credit facility, at September 30, 2014, was 2.7%. Up to $50.0 million of the revolving credit facility may be utilized for letters of credit, of which $3.4 million was outstanding at

September 30, 2014. These outstanding letters of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheets. At September 30, 2014, the Partnership had $596.6 million of remaining committed capacity under its revolving credit facility.

The events that constitute an event of default for the revolving credit facility are also customary for loans of this size, including payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against the Partnership in excess of a specified amount, and a change of control of the General Partner.

On August 28, 2014, the Partnership entered into a Second Amended and Restated Credit Agreement (the “Revised Credit Agreement”) which, among other changes:

•

extended the maturity date to August 28, 2019;

•

increased the revolving credit commitment from $600 million to $800 million and the incremental revolving credit amount from $200 million to $250 million;

•

reduced by 0.25% the applicable margin used to determine interest rates for LIBOR Rate Loans, as defined in the Revised Credit Agreement, and for Base Rate Loans, as defined in the Revised Credit Agreement, depending on the Partnership’s Consolidated Funded Debt Ratio, as defined in the Revised Credit Agreement;

•

allows the Partnership to request incremental term loans, provided the sum of any revolving credit commitments and incremental term loans may not exceed $1.05 billion; and

•

changed the per annum interest rate on borrowings to (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) three-month LIBOR plus 1.0%, or (ii) the LIBOR rate for the applicable period (each plus the applicable margin). Previously, part (c) was stated as: one-month LIBOR plus 1.0%.

On March 11, 2014, the Partnership entered into an amendment to the credit agreement governing the revolving credit facility which, among other changes:

•

adjusted the duration of, and maximum ratios allowed during, the Acquisition Period, as defined in the credit agreement, for the Consolidated Funded Debt Ratio, as defined in the credit agreement; and

•

permitted the payment of cash distributions, if any, on the Class E Preferred Units so long as the Partnership has a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50 million.

As of September 30, 2014, the Partnership was in compliance with all covenants under the credit facility.

Senior Notes

At September 30, 2014, the Partnership had $500.0 million principal outstanding of 6.625% unsecured senior notes due October 1, 2020 (“6.625% Senior Notes”), $650.0 million principal outstanding of 5.875% unsecured senior notes due August 1, 2023 (“5.875% Senior Notes”), and $400.0 million of 4.75% unsecured senior notes due November 15, 2021 (“4.75% Senior Notes” and with the 6.625% Senior Notes and 5.875% Senior Notes, the “Senior Notes”). The 6.625% Senior Notes are presented combined with a net $4.1 million unamortized premium as of September 30, 2014.

Indentures governing the Senior Notes contain covenants, including limitations of the Partnership’s ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all its assets. The Partnership is in compliance with these covenants as of September 30, 2014.

4.75% Senior Notes

On May 10, 2013, the Partnership issued $400.0 million of the 4.75% Senior Notes in a private placement transaction. The 4.75% Senior Notes were issued at par. The Partnership received net proceeds of $391.2 million after underwriting commissions and other transactions costs and utilized the proceeds to repay a portion of the outstanding indebtedness under the revolving credit agreement as part of the TEAK Acquisition (see Note 3).

5.875% Senior Notes

On February 11, 2013, the Partnership issued $650.0 million of the 5.875% Senior Notes in a private placement transaction. The 5.875% Senior Notes were issued at par. The Partnership received net proceeds of $637.3 million after underwriting commissions and other transactions costs and utilized the proceeds to redeem the 8.75% Senior Notes and repay a portion of the outstanding indebtedness under the credit facility.

8.75% Senior Notes

On January 28, 2013, the Partnership commenced a cash tender offer for any and all of its outstanding 8.75% Senior Notes and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% Senior Notes (“8.75% Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% Senior Notes were validly tendered as of the expiration date of the consent solicitation. In February 2013, the Partnership accepted for purchase all 8.75% Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million make-whole premium, $3.7 million accrued interest and $8.0 million consent payment. The Partnership entered into a supplemental indenture amending and supplementing the 8.75% Senior Notes Indenture.

On March 12, 2013, the Partnership paid $105.6 million to redeem the remaining $97.3 million 8.75% Senior Notes not purchased in connection with the January 28, 2013 tender offer, plus a $6.3 million make-whole premium and $2.0 million in accrued interest. The Partnership funded the redemption with a portion of the net proceeds from the issuance of the 5.875% Senior Notes.

Capital Leases

The following is a summary of the leased property under capital leases as of September 30, 2014 and December 31, 2013, which are included within property, plant and equipment (see Note 6) (in thousands):


	September 30, 2014			December 31, 2013
Pipelines, processing and compression facilities	$	946		$	2,281
Less – accumulated depreciation		(175	)		(330	)

	$	771		$	1,951

During the three and nine months ended September 30, 2014, the Partnership took ownership of $0.2 million and $1.3 million, respectively, of facilities in connection with the conclusion of capital leases. Depreciation expense for leased properties was $27 thousand and $44 thousand for the three months ended September 30, 2014 and 2013, respectively, and $91 thousand and $293 thousand for the nine months ended September 30, 2014 and 2013, respectively, which is included within depreciation and amortization expense on the Partnership’s consolidated statements of operations (see Note 6).

NOTE 14 – COMMITMENTS AND CONTINGENCIES

The Partnership has certain long-term unconditional purchase obligations and commitments, consisting primarily of transportation contracts. These agreements provide for transportation services to be used in the ordinary course of the Partnership’s operations. Transportation fees paid related to these contracts, including minimum shipment payments, were $7.2 million during each of the three month periods ended September 30, 2014 and 2013, and $22.4 million and $24.8 million for the nine months ended September 30, 2014 and 2013, respectively. The unrecorded future fixed and determinable portion of the obligations as of September 30, 2014 was as follows: remainder of 2014 - $4.7 million; 2015 - $21.3 million; 2016 to 2017 - $23.9 million per year; and 2018 - $21.8 million.

The Partnership had committed approximately $165.8 million for the purchase of property, plant and equipment at September 30, 2014.

The Partnership is involved in class action lawsuits arising from events occurring subsequent to September 30, 2014 (see Note 19 and “Part II. Other Information – Item 1. Legal Proceedings” for more information regarding these lawsuits).

The Partnership is also party to various routine legal proceedings arising out of the ordinary course of its business. Management of the Partnership believes the ultimate resolution of these actions, individually or in the aggregate, will not have a material adverse effect on its financial condition or results of operations.

NOTE 15 – BENEFIT PLANS

Long-Term Incentive Plans

The Partnership has a 2004 Long-Term Incentive Plan (“2004 LTIP”) and a 2010 Long-Term Incentive Plan (“2010 LTIP” and collectively with the 2004 LTIP, the “LTIPs”) in which officers, employees, non-employee managing board members of the General Partner, employees of the General Partner’s affiliates and consultants are eligible to participate. The LTIPs are administered by the compensation committee appointed by the General Partner’s managing board (the “Compensation Committee”). Under the LTIPs, the Compensation Committee may make awards of either phantom units or unit options for an aggregate of 3,435,000 common units. At September 30, 2014, the Partnership had

1,755,028 phantom units outstanding under the Partnership’s LTIPs, with 122,968 phantom units and unit options available for grant. The Partnership generally issues new common units for phantom units and unit options that have vested and have been exercised.

Partnership Phantom Units

Phantom units granted to employees under the LTIPs generally have vesting periods of four years. However, in February 2014, the Partnership granted 227,000 phantom units with a vesting period of three years. Phantom units awarded to non-employee managing board members will vest over a four year period. Awards to non-employee members of the board automatically vest upon a change of control, as defined in the LTIPs. At September 30, 2014, there were 619,378 phantom units outstanding under the LTIPs that will vest within twelve months.

The Partnership is authorized to withhold common units from employees to cover employee tax obligations when certain phantom units have vested. During the three and nine months ended September 30, 2014, the Partnership withheld and retired 52,741 common units, for a cost of $1.7 million. The withheld and retired units were recorded as a reduction of equity on the Partnership’s consolidated balance sheet. There were no common units withheld and retired during the three and nine months ended September 30, 2013.

All phantom units outstanding under the LTIPs at September 30, 2014 include distribution equivalent rights (“DERs”), which are rights to receive cash per phantom unit in an amount equal to and at the same time as the cash distributions the Partnership makes on a common unit during the period the phantom unit is outstanding. The DERs were granted to the participants by the Compensation Committee. The amounts paid with respect to LTIP DERs were $1.2 million and $1.0 million during the three months ended September 30, 2014 and 2013, respectively, and $3.1 million and $2.2 million during the nine months ended September 30, 2014 and 2013, respectively. These amounts were recorded as reductions of equity on the Partnership’s consolidated balance sheets.

The following table sets forth the Partnership’s LTIPs phantom unit activity for the periods indicated:


	Three Months Ended September 30,										Nine Months Ended September 30,
	2014					2013					2014					2013
	Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾		Number of Units			Fair Value⁽¹⁾
Outstanding, beginning of period		2,046,819		$	35.45		909,012		$	33.54		1,446,553		$	36.32		1,053,242		$	33.21
Granted		16,153			35.27		697,122			39.07		738,727			33.03		740,897			38.97
Forfeited		(17,175	)		36.81		(24,200	)		36.74		(20,825	)		37.06		(26,300	)		36.44
Vested and issued⁽²⁾⁽³⁾		(290,769	)		36.21		(59,112	)		27.81		(409,427	)		34.68		(245,017	)		31.44

Outstanding, end of period⁽⁴⁾⁽⁵⁾		1,755,028		$	35.31		1,522,822		$	36.24		1,755,028		$	35.31		1,522,822		$	36.24

Vested and not issued⁽⁶⁾		12,774		$	34.22		2,450		$	32.95		12,774		$	34.22		2,450		$	32.95
Non-cash compensation expense recognized (in thousands)				$	6,376				$	5,998				$	19,258				$	13,818

(1)	Fair value based upon weighted average grant date price.

(2)	The intrinsic values for phantom unit awards exercised during the three months ended September 30, 2014 and 2013 were $9.7 million and $2.2 million, respectively, and $13.5 million and $8.9 million during the nine months ended September 30, 2014 and 2013, respectively.

(3)

During the three months ended September 30, 2014, there were 1,383 vested phantom units, which were settled for $49 thousand cash. There were no vested phantom units settled in cash during the three months ended September 30, 2013. During the nine months ended September 30, 2014 and 2013, there were 4,409 and 1,677 vested phantom units, respectively, which were settled for $145 thousand and $58 thousand cash, respectively.

(4)	The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2014 and December 31, 2013 was $64.0 million and $50.7 million, respectively.

(5)	There were 26,812 and 22,539 outstanding phantom unit awards at September 30, 2014 and December 31, 2013, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards.

(6)	The aggregate intrinsic value for phantom unit awards vested but not issued at September 30, 2014 was $0.4 million. There were no vested but not issued phantom unit awards at December 31, 2013.

At September 30, 2014, the Partnership had approximately $35.0 million of unrecognized compensation expense related to unvested phantom units outstanding under the LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 2.0 years.

NOTE 16 – RELATED PARTY TRANSACTIONS

The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by the General Partner and employees of ATLS. The General Partner does not receive a management fee in connection with its management of the Partnership apart from its interest as general partner and its right to receive incentive distributions. The Partnership reimburses the General Partner and its affiliates for compensation and benefits related to its employees who perform services for the Partnership based upon an estimate of the time spent by such persons on activities for the Partnership. Other indirect costs, such as rent for offices, are allocated to the Partnership by ATLS based on the number of its employees who devote their time to activities on the Partnership’s behalf.

The partnership agreement provides that the General Partner will determine the costs and expenses allocable to the Partnership in any reasonable manner determined by the General Partner at its sole discretion. The Partnership reimbursed the General Partner and its affiliates $1.3 million during each of the three month periods ended September 30, 2014 and 2013, and $3.8 million during each of the nine month periods ended September 30, 2014 and 2013, for compensation and benefits related to its employees. There were no reimbursements for direct expenses incurred by the General Partner and its affiliates for the nine months ended September 30, 2014 and 2013. The General Partner believes the method utilized in allocating costs to the Partnership is reasonable.

The Partnership compresses and gathers gas for Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP”) on its gathering systems located in Tennessee. ARP’s general partner is wholly-owned by ATLS, and two members of the General Partner’s managing board are members of ARP’s board of directors. The Partnership entered into an agreement to provide these services, which extends for the life of ARP’s leases, in February 2008. The Partnership charged ARP approximately $0.1 million in compression and gathering fees for each of the three months ended September 30, 2014 and 2013, and $0.2 million in compression and gathering fees for each of the nine months ended September 30, 2014 and 2013.

NOTE 17 – SEGMENT INFORMATION

As a result of the sale of the Partnership’s subsidiaries that owned an interest in WTLPG on May 14, 2014 (see Note 4), the Partnership assessed its reportable segments and realigned its reportable segments into two new segments: Oklahoma Gathering and Processing (“Oklahoma”) and Texas Gathering and Processing (“Texas”). These reportable segments reflect the way the Partnership will manage its operations going forward. The Partnership has adjusted its segment presentation from the amounts previously presented to reflect the realignment of the segments.

The Oklahoma segment consists of the SouthOK and WestOK operations, which are comprised of natural gas gathering, processing and treating assets servicing drilling activity in the Anadarko and Arkoma Basins and which were formerly included within the previous Gathering and Processing segment. Oklahoma revenues are primarily derived from the sale of residue gas and NGLs and the gathering, processing and treating of natural gas within the state of Oklahoma.

The Texas segment consists of (1) the SouthTX and WestTX operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Permian Basin and the Eagle Ford Shale play in south Texas; and (2) the natural gas gathering assets located in the Barnett Shale play in Texas. These assets were formerly included within the previous Gathering and Processing segment. Texas revenues are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas within the state of Texas.

The previous Transportation and Treating segment, which consisted of (1) the gas treating operations, which own contract gas treating facilities located in various shale plays; and (2) the former subsidiaries’ interest in WTLPG, has been eliminated and the financial information is now included within Corporate and Other. The natural gas gathering assets located in the Appalachian Basin in Tennessee, which were formerly included in the previous Gathering and Processing Segment, are now included within Corporate and Other.

The following summarizes the Partnership’s reportable segment data for the periods indicated (in thousands):


	Oklahoma			Texas			Corporate and Other			Consolidated
Three Months Ended September 30, 2014:
Revenue:
Revenues – third party⁽¹⁾	$	439,078		$	296,656		$	25,383		$	761,117
Revenues – affiliates		—			—			65			65

Total revenues		439,078			296,656			25,448			761,182

Costs and Expenses:
Natural gas and liquids cost of sales		352,960			233,488			—			586,448
Operating expenses		16,701			12,538			598			29,837
General and administrative⁽¹⁾		—			—			18,074			18,074
Other expenses		—			—			(1	)		(1	)
Depreciation and amortization		25,181			23,851			1,141			50,173
Interest expense⁽¹⁾		—			—			22,553			22,553

Total costs and expenses		394,842			269,877			42,365			707,084

Equity loss in joint ventures		—			(4,711	)		—			(4,711	)
Loss on asset disposition		—			—			(636	)		(636	)

Income (loss) before tax		44,236			22,068			(17,553	)		48,751
Income tax benefit		(623	)		—			—			(623	)

Net income (loss)	$	44,859		$	22,068		$	(17,553	)	$	49,374


	Oklahoma			Texas			Corporate and Other			Consolidated
Three Months Ended September 30, 2013:
Revenue:
Revenues – third party⁽¹⁾	$	354,039		$	226,364		$	(22,607	)	$	557,796
Revenues – affiliates		—			—			74			74

Total revenues		354,039			226,364			(22,533	)		557,870

Costs and Expenses:
Natural gas and liquids cost of sales		279,846			183,718			—			463,564
Operating expenses		14,373			9,891			542			24,806
General and administrative⁽¹⁾		—			—			17,887			17,887
Other expenses		—			—			685			685
Depreciation and amortization		26,103			23,391			1,586			51,080
Interest expense⁽¹⁾		—			—			24,347			24,347

Total costs and expenses		320,322			217,000			45,047			582,369

Equity income (loss) in joint ventures		—			(3,271	)		1,389			(1,882	)

Income (loss) before tax		33,717			6,093			(66,191	)		(26,381	)
Income tax benefit		(817	)		—			—			(817	)

Net income (loss)	$	34,534		$	6,093		$	(66,191	)	$	(25,564	)


	Oklahoma			Texas			Corporate and Other			Consolidated
Nine Months Ended September 30, 2014:
Revenue:
Revenues – third party⁽¹⁾	$	1,305,448		$	856,436		$	13,047		$	2,174,931
Revenues – affiliates		—			—			211			211

Total revenues		1,305,448			856,436			13,258			2,175,142

Costs and Expenses:
Natural gas and liquids cost of sales		1,045,315			697,486			—			1,742,801
Operating expenses		45,844			34,452			1,652			81,948
General and administrative⁽¹⁾		—			—			54,430			54,430
Other expenses		—			—			16			16
Depreciation and amortization		76,832			68,346			3,454			148,632
Interest expense⁽¹⁾		—			—			69,275			69,275

Total costs and expenses		1,167,991			800,284			128,827			2,097,102

Equity income (loss) in joint ventures		—			(13,076	)		2,612			(10,464	)
Gain on asset disposition		—			—			47,829			47,829

Income (loss) before tax		137,457			43,076			(65,128	)		115,405
Income tax benefit		(1,519	)		—			—			(1,519	)

Net income (loss)	$	138,976		$	43,076		$	(65,128	)	$	116,924


	Oklahoma			Texas			Corporate and Other			Consolidated
Nine Months Ended September 30, 2013:
Revenue:
Revenues – third party⁽¹⁾	$	1,011,669		$	519,493		$	(4,663	)	$	1,526,499
Revenues – affiliates		—			—			222			222

Total revenues		1,011,669			519,493			(4,441	)		1,526,721

Costs and Expenses:
Natural gas and liquids cost of sales		789,746			423,574			—			1,213,320
Operating expenses		46,361			23,575			1,499			71,435
General and administrative⁽¹⁾		—			—			44,231			44,231
Other expenses		—			—			19,585			19,585
Depreciation and amortization		77,605			45,562			4,754			127,921
Interest expense⁽¹⁾		—			—			65,614			65,614

Total costs and expenses		913,712			492,711			135,683			1,542,106

Equity income (loss) in joint ventures		—			(5,430	)		5,116			(314	)
Loss on asset disposition		(1,519	)		—			—			(1,519	)
Loss on early extinguishment of debt		—			—			(26,601	)		(26,601	)

Income (loss) before tax		96,438			21,352			(161,609	)		(43,819	)
Income tax benefit		(854	)		—			—			(854	)

Net income (loss)	$	97,292		$	21,352		$	(161,609	)	$	(42,965	)

(1)	Derivative contracts are carried at the corporate level and interest and general and administrative expenses have not been allocated to the reportable segments as it would be unfeasible to reasonably do so.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Capital Expenditures:
Oklahoma	$	111,261	$	48,612	$	237,813	$	167,415
Texas		80,865		62,779		234,177		157,552
Corporate and other		442		761		1,157		2,894

	$	192,568	$	112,152	$	473,147	$	327,861


	September 30, 2014		December 31, 2013
Balance Sheet
Equity method investment in joint ventures:
Texas	$	180,602	$	162,511
Corporate and other		—		85,790

	$	180,602	$	248,301

Goodwill:
Oklahoma	$	178,762	$	178,762
Texas		187,001		189,810

	$	365,763	$	368,572

Total assets:
Oklahoma	$	2,487,585	$	2,265,231
Texas		2,039,900		1,872,165
Corporate and other		110,927		190,449

	$	4,638,412	$	4,327,845

The following table summarizes the Partnership’s natural gas and liquids sales by product or service for the periods indicated (in thousands):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
Natural gas and liquids sales:
Natural gas	$	280,598		$	181,345	$	836,847		$	514,715
NGLs		353,294			315,824		1,055,744			803,894
Condensate		40,806			37,511		112,694			92,520
Other		(810	)		1,039		(718	)		(332	)

Total	$	673,888		$	535,719	$	2,004,567		$	1,410,797

NOTE 18 – SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Partnership’s Senior Notes and revolving credit facility are guaranteed by its wholly-owned subsidiaries. The guarantees are full, unconditional, joint and several. The Partnership’s consolidated financial statements as of September 30, 2014 and December 31, 2013 and for the three and nine months ended September 30, 2014 and 2013 include the financial statements of Atlas Pipeline Mid-Continent WestOK, LLC (“WestOK, LLC”), Atlas Pipeline Mid-Continent WestTex, LLC (“WestTex, LLC”) and Centrahoma Processing, LLC (“Centrahoma”), as well as the equity interests in WTLPG held by two of the Partnership’s subsidiaries, prior to their sale on May 14, 2014 (see Note 4), and the equity interests in the T2 Joint Ventures. Under the terms of the Senior Notes and the revolving credit facility, WestOK, LLC, WestTex, LLC, Centrahoma and the T2 Joint Ventures are non-guarantor subsidiaries as they are not wholly-owned by the Partnership. The following supplemental condensed consolidating financial information reflects the Partnership’s stand-alone accounts, the combined accounts of the guarantor subsidiaries, the combined accounts of the non-guarantor subsidiaries, the consolidating adjustments and eliminations and the Partnership’s consolidated accounts as of September 30, 2014 and December 31, 2013 and for the three and nine months ended September 30, 2014 and 2013. For the purpose of the following financial information, the Partnership’s investments in its subsidiaries and the guarantor subsidiaries’ investments in their subsidiaries are presented in accordance with the equity method of accounting (in thousands):

Balance Sheets


September 30, 2014	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Assets
Cash and cash equivalents	$	—	$	172	$	6,564	$	—		$	6,736
Accounts receivable – affiliates		—		238,278		—		(238,278	)		—
Other current assets		65		50,764		236,463		(1,017	)		286,275

Total current assets		65		289,214		243,027		(239,295	)		293,011
Property, plant and equipment, net		—		887,502		2,245,308		—			3,132,810
Intangible assets, net		—		539,984		74,833		—			614,817
Goodwill		—		320,869		44,894		—			365,763
Equity method investment in joint ventures		—		—		180,602		—			180,602
Long term portion of derivative assets		—		6,138		—		—			6,138
Long term notes receivable		—		—		1,852,928		(1,852,928	)		—
Equity investments		4,207,593		939,310		—		(5,146,903	)		—
Other assets, net		38,535		6,286		450		—			45,271

Total assets	$	4,246,193	$	2,989,303	$	4,642,042	$	(7,239,126	)	$	4,638,412

Liabilities and Equity
Accounts payable – affiliates	$	10,949	$	—	$	232,802	$	(238,278	)	$	5,473
Other current liabilities		14,072		57,142		301,970		—			373,184

Total current liabilities		25,021		57,142		534,772		(238,278	)		378,657
Long-term debt, less current portion		1,754,050		43		—		—			1,754,093
Deferred income taxes, net		—		31,771		—		—			31,771
Other long-term liabilities		191		769		6,000		—			6,960
Equity		2,466,931		2,899,578		4,101,270		(7,000,848	)		2,466,931

Total liabilities and equity	$	4,246,193	$	2,989,303	$	4,642,042	$	(7,239,126	)	$	4,638,412

December 31, 2013


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Assets
Cash and cash equivalents	$	—	$	168	$	4,746	$	—		$	4,914
Accounts receivable – affiliates		765,236		—		—		(765,236	)		—
Other current assets		215		52,910		185,975		(2,236	)		236,864

Total current assets		765,451		53,078		190,721		(767,472	)		241,778
Property, plant and equipment, net		—		723,302		2,000,890		—			2,724,192
Intangible assets, net		—		603,533		92,738		—			696,271
Goodwill		—		323,678		44,894		—			368,572
Equity method investment in joint venture		—		—		248,301		—			248,301
Long term portion of derivative assets		—		2,270		—		—			2,270
Long term notes receivable		—		—		1,852,928		(1,852,928	)		—
Equity investments		3,186,938		1,487,358		—		(4,674,296	)		—
Other assets, net		41,094		1,787		3,580		—			46,461

Total assets	$	3,993,483	$	3,195,006	$	4,434,052	$	(7,294,696	)	$	4,327,845

Liabilities and Equity
Accounts payable – affiliates	$	—	$	423,078	$	345,070	$	(765,236	)	$	2,912
Other current liabilities		26,819		75,031		215,464		—			317,314

Total current liabilities		26,819		498,109		560,534		(765,236	)		320,226
Long-term portion of derivative liabilities		—		320		—		—			320
Long-term debt, less current portion		1,706,556		230		—		—			1,706,786
Deferred income taxes, net		—		33,290		—		—			33,290
Other long-term liabilities		203		1,115		6,000		—			7,318
Equity		2,259,905		2,661,942		3,867,518		(6,529,460	)		2,259,905

Total liabilities and equity	$	3,993,483	$	3,195,006	$	4,434,052	$	(7,294,696	)	$	4,327,845

Statements of Operations


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Three Months Ended September 30, 2014
Total revenues	$	—		$	165,650		$	596,193		$	(661	)	$	761,182
Total costs and expenses		(22,708	)		(148,128	)		(536,909	)		661			(707,084	)
Equity income (loss)		68,053			50,544			(4,711	)		(118,597	)		(4,711	)
Gain on asset disposition		—			(636	)		—			—			(636	)

Income (loss), before tax		45,345			67,430			54,573			(118,597	)		48,751
Income tax benefit		—			(623	)		—			—			(623	)

Net income (loss)		45,345			68,053			54,573			(118,597	)		49,374
Income attributable to non-controlling interest		—			—			(4,029	)		—			(4,029	)
Preferred unit imputed dividend effect		(11,378	)		—			—			—			(11,378	)
Preferred unit dividends in kind		(11,408	)		—			—			—			(11,408	)
Preferred unit dividends		(2,609	)		—			—			—			(2,609	)

Net income (loss) attributable to common limited partners and the General Partner	$	19,950		$	68,053		$	50,544		$	(118,597	)	$	19,950

Three Months Ended September 30, 2013
Total revenues	$	—		$	123,858		$	453,862		$	(19,850	)	$	557,870
Total costs and expenses		(23,510	)		(172,901	)		(405,503	)		19,545			(582,369	)
Equity income (loss)		(3,568	)		43,081			(1,882	)		(39,513	)		(1,882	)

Income (loss), before tax		(27,078	)		(5,962	)		46,477			(39,818	)		(26,381	)
Income tax benefit		—			(817	)		—			—			(817	)

Net income (loss)		(27,078	)		(5,145	)		46,477			(39,818	)		(25,564	)
Income attributable to non-controlling interest		—			—			(1,514	)		—			(1,514	)
Preferred unit imputed dividend effect		(11,378	)		—			—			—			(11,378	)
Preferred unit dividends in kind		(9,072	)		—			—			—			(9,072	)

Net income (loss) attributable to common limited partners and the General Partner	$	(47,528	)	$	(5,145	)	$	44,963		$	(39,818	)	$	(47,528	)

Statements of Operations


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Nine Months Ended September 30, 2014
Total revenues	$	—		$	441,990		$	1,740,979		$	(7,827	)	$	2,175,142
Total costs and expenses		(69,728	)		(473,344	)		(1,561,857	)		7,827			(2,097,102	)
Equity income (loss)		176,196			158,201			(10,464	)		(334,397	)		(10,464	)
Gain on asset disposition		—			47,829			—			—			47,829

Income (loss), before tax		106,468			174,676			168,658			(334,397	)		115,405
Income tax benefit		—			(1,519	)		—			—			(1,519	)

Net income (loss)		106,468			176,195			168,658			(334,397	)		116,924
Income attributable to non-controlling interest		—			—			(10,456	)		—			(10,456	)
Preferred unit imputed dividend effect		(34,134	)		—			—			—			(34,134	)
Preferred unit dividends in kind		(31,533	)		—			—			—			(31,533	)
Preferred unit dividends		(5,624	)		—			—			—			(5,624	)

Net income (loss) attributable to common limited partners and the General Partner	$	35,177		$	176,195		$	158,202		$	(334,397	)	$	35,177

Nine Months Ended September 30, 2013
Total revenues	$	—		$	373,713		$	1,214,750		$	(61,742	)	$	1,526,721
Total costs and expenses		(63,441	)		(452,077	)		(1,087,432	)		60,844			(1,542,106	)
Equity income (loss)		42,384			121,997			(314	)		(164,381	)		(314	)
Loss on early extinguishment of debt		(26,601	)		—			—			—			(26,601	)
Loss on asset disposition		—			(1,519	)		—			—			(1,519	)

Income (loss), before tax		(47,658	)		42,114			127,004			(165,279	)		(43,819	)
Income tax benefit		—			(854	)		—			—			(854	)

Net income (loss)		(47,658	)		42,968			127,004			(165,279	)		(42,965	)
Income attributable to non-controlling interest		—			—			(4,693	)		—			(4,693	)
Preferred unit imputed dividend effect		(18,107	)		—			—			—			(18,107	)
Preferred unit dividends in kind		(14,413	)		—			—			—			(14,413	)

Net income (loss) attributable to common limited partners and the General Partner	$	(80,178	)	$	42,968		$	122,311		$	(165,279	)	$	(80,178	)

Statements of Cash Flows


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Nine Months Ended September 30, 2014
Net cash provided by (used in):
Operating activities	$	158,349		$	224,688		$	226,701		$	(375,577	)	$	234,161
Investing activities		(276,535	)		(237,278	)		(177,918	)		341,642			(350,089	)
Financing activities		118,186			12,594			(46,965	)		33,935			117,750

Net change in cash and cash equivalents		—			4			1,818			—			1,822
Cash and cash equivalents, beginning of period		—			168			4,746			—			4,914

Cash and cash equivalents, end of period	$	—		$	172		$	6,564		$	—		$	6,736

Nine Months Ended September 30, 2013
Net cash provided by (used in):
Operating activities	$	(392,444	)	$	100,288		$	197,958		$	245,319		$	151,121
Investing activities		(818,206	)		(822,467	)		(455,359	)		757,883			(1,338,149	)
Financing activities		1,210,650			722,188			264,433			(1,003,202	)		1,194,069

Net change in cash and cash equivalents		—			9			7,032			—			7,041
Cash and cash equivalents, beginning of period		—			157			3,241			—			3,398

Cash and cash equivalents, end of period	$	—		$	166		$	10,273		$	—		$	10,439

NOTE 19 – SUBSEQUENT EVENTS

On October 13, 2014, the Partnership, ATLS and the General Partner entered into a definitive merger agreement with Targa Resources Corp. (“TRC”), Targa Resources Partners LP (“TRP”) and certain other parties (the “Merger Agreement”), pursuant to which TRP agreed to acquire the Partnership through a merger of a newly formed wholly-owned subsidiary of TRP with and into the Partnership (the “Merger”). Upon completion of the Merger, holders of the Partnership’s common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each Partnership common unit. Subject to the terms and conditions of the Merger Agreement, the Partnership has agreed to exercise its right under the certificate of designation of the Class D Preferred Units to convert all outstanding Class D Preferred Units into common units and to exercise its right under the certificate of designation of the Class E Preferred Units to redeem the Class E Preferred Units, and TRP has agreed to deposit the funds for such redemption with the paying agent.

Concurrently with the Merger Agreement, ATLS announced that it entered into a definitive merger agreement with TRC (the “ATLS Merger Agreement”), pursuant to which TRC agreed to acquire ATLS through a merger of a newly formed wholly-owned subsidiary of TRC with and into ATLS (the “ATLS Merger”).

Concurrently with the Merger Agreement and the ATLS Merger Agreement, ATLS agreed to (i) transfer its assets and liabilities, other than those related to the Partnership, to Atlas Energy Group, LLC (“Atlas Energy Group”), which is currently a subsidiary of ATLS and (ii) immediately prior to the ATLS Merger, effect a pro rata distribution to the ATLS unitholders of common units of Atlas Energy Group representing a 100% interest in Atlas Energy Group (the “Spin-Off”).

The closing of the Merger is subject to approval by the Partnership’s unitholders and other closing conditions, including the completion of the ATLS Merger and the Spin-Off. Completion of each of the ATLS Merger and Spin-Off are also conditioned on the parties standing ready to complete the Merger.

Following the announcement on October 13, 2014 of the Merger, the Partnership, the General Partner, ATLS, TRC, TRP, Targa Resources GP LLC, Trident MLP Merger Sub LLC and the members of the managing board of the General Partner have been named as defendants in three putative unitholder class action lawsuits challenging the Merger. In addition, ATLS, Atlas Energy GP, LLC, TRC, Trident GP Sub and the members of ATLS’s board have been named as defendants in two putative unitholder class action lawsuits challenging the ATLS Merger.

The lawsuits filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for the Partnership’s unitholders in the Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorneys’ fees, other expenses and costs. At this time, the Partnership cannot reasonably estimate the range of possible loss as a result of the lawsuit. See “Part II. Other Information – Item 1. Legal Proceedings” for more information regarding the class action lawsuits filed against the Partnership.

On October 15, 2014, the Partnership paid a cash distribution of $0.515625 per unit, or approximately $2.6 million, on its Class E Preferred Units, representing the cash distribution for the period July 15, 2014 through October 14, 2014.

On October 28, 2014, the Partnership declared a cash distribution of $0.64 per unit on its outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2014. The $62.2 million distribution, including $8.1 million to the General Partner for its general partner interest and incentive distribution rights, will be paid on November 14, 2014 to unitholders of record at the close of business on November 10, 2014 (see Note 5). The Partnership also determined that distributions for the Class D Preferred Units would be paid in-kind for the quarter ended September 30, 2014. Accordingly, the Partnership will issue approximately 321,000 additional Class D Preferred Units to the holders of the Class D Preferred Units as a preferred unit distribution in kind for the quarter ended September 30, 2014.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

When used in this Form 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties more particularly described in Item 1A under the caption “Risk Factors”, in our Annual Report on Form 10-K for the year ended December 31, 2013 as supplemented by this Form 10-Q. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes thereto appearing elsewhere in this report and with our Annual Report on Form 10-K for the year ended December 31, 2013.

General

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” We are a leading provider of natural gas gathering, processing and treating services in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States, and a provider of natural gas gathering services in the Appalachian Basin in the northeastern region of the United States.

As a result of the May 2014 sale of two former subsidiaries holding an interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 4 – West Texas LPG Limited Partnership), we assessed our reportable segments and realigned them into two new segments: Oklahoma Gathering and Processing (“Oklahoma”) and Texas Gathering and Processing (“Texas”). These reportable segments reflect the way we will manage our operations going forward.

The Oklahoma segment consists of the SouthOK and WestOK operations, which are comprised of natural gas gathering, processing and treating assets servicing drilling activity in the Anadarko and Arkoma Basins of Oklahoma. The Texas segment consists of (1) the SouthTX and WestTX operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Permian Basin and the Eagle Ford Shale play in south Texas; and (2) natural gas gathering assets located in the Barnett Shale play in Texas. Revenues for both segments are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas.

The previous Transportation and Treating segment, which consisted of (1) the gas treating operations, which own contract gas treating facilities located in various shale plays; and (2) two subsidiaries holding an interest in WTLPG, has been eliminated and the financial information is now included within Corporate and Other. The natural gas gathering assets located in the Appalachian Basin in Tennessee, which were formerly included in the previous Gathering and Processing Segment, are now included within Corporate and Other.

As of September 30, 2014, our Oklahoma segment owns, has interests in and operates ten natural gas processing plants with aggregate capacity of approximately 950 MMCFD, a gas treating facility and approximately 7,100 miles of active natural gas gathering systems located in Oklahoma and Kansas. As of September 30, 2014, our Texas segment owns, has interests in and operates seven natural gas processing plants with aggregate capacity of approximately 1,050 MMCFD and approximately 4,100 miles of active natural gas gathering systems located in Texas. Our gathering systems gather natural gas from oil and natural gas wells and central delivery points and deliver this gas to processing plants, as well as third-party pipelines.

Our Oklahoma and Texas segments are all located in or near areas of abundant and long-lived natural gas production. In Oklahoma, our operations are in or near the Golden Trend, Mississippian Limestone and Hugoton field in the Anadarko Basin and the Woodford Shale. In Texas, our operations are in or near the Spraberry Trend, which is an oil play with associated natural gas in the Permian Basin; the Barnett Shale; and the Eagle Ford Shale. Our gathering systems are connected to primarily individual well connections and, secondarily, central delivery points, which are linked to multiple wells. We believe we have significant scale in each of our primary service areas. We provide gathering, processing and treating services to the wells connected to our systems, primarily under long-term contracts. As a result of the location and capacity of our gathering, processing and treating assets, we believe we are strategically positioned to capitalize on the drilling activity in our service areas.

Recent Events

On September 15, 2014, we placed in service a new 200 MMCFD cryogenic processing plant, known as the Edward plant, in our WestTX system in the Permian Basin of West Texas, increasing the WestTX system capacity to 655 MMCFD.

On August 28, 2014, we entered into a Second Amended and Restated Credit Agreement (the “Revised Credit Agreement”) which, among other changes:

•

extended the maturity date to August 28, 2019;

•

increased the revolving credit commitment from $600 million to $800 million and the incremental revolving credit amount from $200 million to $250 million;

•

reduced by 0.25% the applicable margin used to determine interest rates for LIBOR Rate Loans, as defined in the Revised Credit Agreement, and for Base Rate Loans, as defined in the Revised Credit Agreement, depending on the Consolidated Funded Debt Ratio, as defined in the Revised Credit Agreement;

•

allows us to request incremental term loans, provided the sum of any revolving credit commitments and incremental term loans may not exceed $1.05 billion; and

•

On June 25, 2014, we placed in service a new 200 MMCFD cryogenic processing plant, known as the Silver Oak II plant, in our SouthTX system in the Eagleford Shale play of South Texas, increasing the SouthTX system capacity to 400 MMCFD.

On May 14, 2014, we completed the sale of two indirect subsidiaries, which held an aggregate 20% interest in WTLPG, to a subsidiary of Martin Midstream Partners L.P. (NYSE: MMLP). We received $131.0 million in proceeds, net of selling costs and working capital adjustments, which were used to pay down the revolving credit facility. As a result of the sale, we recorded a $0.6 million loss and a $47.8 million gain on asset dispositions on our consolidated statements of operations for the three and nine months ended September 30, 2014, respectively. (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 4 – West Texas LPG Pipeline Limited Partnership”).

On May 12, 2014, we entered into an Equity Distribution Agreement (the “2014 EDA”) with Citigroup Global Markets Inc., Wells Fargo Securities, LLC and MLV & Co. LLC (together, the “Sales Agents”). Pursuant to the 2014 EDA, we may offer and sell from time to time through our Sales Agents, common units having an aggregate value of up to $250.0 million. Sales are at market prices prevailing at the time of the sale. (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 5 – Common Units”).

On May 1, 2014, we placed in service a new 120 MMCFD cryogenic processing plant, known as the Stonewall plant, in our SouthOK system in the Arkoma Basin of Oklahoma, increasing the SouthOK system capacity to 500 MMCFD.

On March 17, 2014, we issued 5,060,000 of our 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to the public at an offering price of $25.00 per Class E Preferred Unit. We received $122.3 million in net proceeds. The proceeds were used to pay down the revolving credit facility (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 5 – Class E Preferred Units”).

On March 11, 2014, we entered into an amendment to the credit agreement governing our revolving credit facility which, among other changes:

•

permitted the payment of cash distributions, if any, on the Class E Preferred Units so long as we have a pro forma Minimum Liquidity, as defined in the credit agreement, of greater than or equal to $50 million.

Subsequent Events

On October 13, 2014, Atlas Energy, L.P. (“ATLS”), Atlas Pipeline Partners GP, LLC, (the “General Partner”), and we entered into a definitive merger agreement with Targa Resources Corp. (“TRC”), Targa Resources Partners LP (“TRP”) and certain other parties (the “Merger Agreement”), pursuant to which TRP agreed to acquire us through a merger of a newly formed wholly-owned subsidiary of TRP with and into us (the “Merger”). Upon completion of the Merger, holders of our common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each of our common units. Subject to the terms and conditions of the Merger Agreement, we have agreed to exercise our right under the certificate of designation of the Class D convertible preferred units (“Class D Preferred Units”) to convert all outstanding Class D Preferred Units into common units and to exercise our right under the certificate of designation of the Class E Preferred Units to redeem the Class E Preferred Units, and TRP has agreed to deposit the funds for such redemption with the paying agent.

Concurrently with the Merger Agreement and the ATLS Merger Agreement, ATLS agreed to (i) transfer its assets and liabilities, other than those related to us, to Atlas Energy Group, LLC (“Atlas Energy Group”), which is currently a subsidiary of ATLS and (ii) immediately prior to the ATLS Merger, effect a pro rata distribution to the ATLS unitholders of common units of Atlas Energy Group representing a 100% interest in Atlas Energy Group (the “Spin-Off”)

The closing of the Merger is subject to approval by our unitholders and other closing conditions, including the completion of the ATLS Merger and the Spin-Off. Completion of each of the ATLS Merger and the Spin-Off are also conditioned on the parties standing ready to complete the Merger.

Following the announcement on October 13, 2014 of the Merger, we, our General Partner, ATLS, TRC, TRP, Targa Resources GP LLC, Trident MLP Merger Sub LLC and the members of the managing board of our General Partner have been named as defendants in three putative unitholder class action lawsuits challenging the Merger. In addition, ATLS, Atlas Energy GP, LLC, TRC, Trident GP Sub and the members of ATLS’s board have been named as defendants in two putative unitholder class action lawsuits challenging the ATLS Merger.

The lawsuits filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for our unitholders in the Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorneys’ fees, other expenses and costs. At this time, we cannot reasonably estimate the range of possible loss as a result of the lawsuit. See “Part II. Other Information – Item 1. Legal Proceedings” for more information regarding the class action lawsuits filed against us.

On October 15, 2014, we paid a cash distribution of $0.515625 per unit, or approximately $2.6 million, on our Class E Preferred Units, representing the cash distribution for the period July 15, 2014 through October 14, 2014 (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 5 – Class E Preferred Units”).

On October 28, 2014, we declared a cash distribution of $0.64 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended September 30, 2014. The $62.2 million distribution, including $8.1 million to the General Partner for its general partner interest and incentive distribution rights, will be paid on November 14, 2014 to unitholders of record at the close of business on November 10, 2014 (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 5 – Cash Distributions”). We also determined that distributions for the Class D Preferred Units would be paid in-kind for the quarter ended September 30, 2014. Accordingly, we will distribute approximately 321,000 additional Class D Preferred Units to the holders of the Class D Preferred Units as a preferred unit distribution for the quarter ended September 30, 2014.

Recent Trends and Uncertainties

The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry group is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

We face competition in obtaining natural gas supplies for our processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, quality of assets, flexibility, service history and maintenance of high-quality customer relationships. Many of our competitors operate as master limited partnerships and enjoy a cost of capital comparable to, and in some cases lower than, ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We believe the primary difference between us and some of our competitors is that we provide an integrated and responsive package of midstream services, while some of our competitors provide only certain services. We believe offering an integrated package of services, while remaining flexible in the types of contractual arrangements that we offer producers, allows us to compete more effectively for new natural gas supplies in our regions of operations.

As a result of our POP and Keep-Whole contracts, our results of operations and financial condition substantially depend upon the price of natural gas, NGLs and crude oil. We believe future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, energy market uncertainty has negatively impacted North American drilling activity in the past. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered, processed and treated.

We are exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash. We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various commodity-based derivative instruments such as natural gas, crude oil and NGL financial contracts to hedge a portion of the value of our assets and operations from such price risks.

Currently, there is a significant level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us. These risks include the availability and costs associated with our borrowing capabilities and ability to raise additional capital, and an increase in the volatility of the price of our common units.

How We Evaluate Our Operations

Our principal revenue is generated from the gathering, processing and treating of natural gas and the sale of natural gas, NGLs and condensate. Our profitability is a function of the difference between the revenues we receive and the costs associated with conducting our operations, including the cost of natural gas, NGLs and condensate we purchase as well as operating and general and administrative costs and the impact of our commodity

hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Variables that affect our profitability include:

•

the volumes of natural gas we gather, process and treat, which in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas the wells produce, and the demand for natural gas, NGLs and condensate;

•

the price of the natural gas we gather; process and treat; and the NGLs and condensate we recover and sell, which is a function of the relevant supply and demand in the mid-continent and northeastern areas of the United States;

•

the NGL and BTU content of the gas gathered and processed;

•

the contract terms with each producer; and

•

the efficiency of our gathering systems and processing and treating plants.

Our management uses a variety of financial measures and operational measurements other than our GAAP financial statements to analyze our performance. These include: (1) volumes, (2) operating expenses and (3) the following non-GAAP measures – gross margin, EBITDA, adjusted EBITDA and distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.

Volumes. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our gathering, processing and treating systems. This is achieved by connecting new wells and adding new volumes in existing areas of production. Our performance at our plants is also significantly impacted by the quality of the natural gas we process, the NGL content of the natural gas and the plants’ recovery capability. In addition, we monitor fuel consumption and losses because they have a significant impact on the gross margin realized from our processing operations.

Operating Expenses. Plant operating, transportation and compression expenses generally include the costs required to operate and maintain our pipelines and processing facilities, including salaries and wages, repair and maintenance expense, ad valorem taxes and other overhead costs.

Gross Margins. We define gross margin as natural gas and liquids sales revenue plus transportation, processing and other fee revenues less purchased product costs, subject to certain non-cash adjustments. Product costs include the cost of natural gas, NGLs and condensate we purchase from third parties. Gross margin, as we define it, does not include plant operating expenses; transportation and compression expenses; and derivative gain (loss) related to undesignated hedges, as movements in gross margin generally do not result in directly correlated movements in these categories.

Gross margin is a non-GAAP measure. The GAAP measure most directly comparable to gross margin is net income. Gross margin is not an alternative to GAAP net income and has important limitations as an analytical tool. Investors should not consider gross margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of gross margin may not be comparable to gross margin measures of other companies, thereby diminishing its utility.

EBITDA and Adjusted EBITDA. EBITDA represents net income (loss) before interest expense, income taxes, depreciation and amortization. Adjusted EBITDA is calculated by adding to EBITDA other non-cash items such as compensation expenses associated with unit issuances, principally to directors and employees, impairment charges and other cash items such as non-recurring cash derivative early termination expense. The GAAP measure most directly comparable to EBITDA and Adjusted EBITDA is net income. EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. The Adjusted EBITDA calculation is similar to the Consolidated EBITDA calculation utilized within the financial covenants under our credit facility, with the exception that Adjusted EBITDA includes certain non-cash items specifically excluded under our credit facility and excludes the capital expansion add back included in Consolidated EBITDA as defined in the credit facility (see “–Revolving Credit Facility”).

Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity’s financial performance, such as cost of capital and historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDA because they provide investors and management with additional information to better understand our operating performance and are presented solely as a supplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as indicators of our operating performance or liquidity. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.

Distributable Cash Flow. We define distributable cash flow as net income plus tax, depreciation and amortization; amortization of deferred financing costs included in interest expense; and non-cash gain (losses) on derivative contracts, less income attributable to non-controlling interests, preferred unit dividends, maintenance capital expenditures, gains (losses) on asset sales and other non-cash gains (losses).

Distributable cash flow is a significant performance metric used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can compute the ratio of distributable cash flow per unit to the declared cash distribution per unit to determine the rate at which the distributable cash flow covers the distribution. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit’s yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.

The GAAP measure most directly comparable to distributable cash flow is net income. Distributable cash flow should not be considered as an alternative to GAAP net income or GAAP cash flows from operating activities. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measurements used by management to their most directly comparable GAAP measures for the three and nine months ended September 30, 2014 and 2013 (in thousands):

RECONCILIATION OF GROSS MARGIN


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Net income (loss)	$	49,374		$	(25,564	)	$	116,924		$	(42,965	)
Adjustments:
Derivative (gain) loss, net		(24,155	)		24,517			(9,117	)		9,493
Other income, net		(13,561	)		(2,943	)		(18,400	)		(8,661	)
Operating expenses⁽¹⁾		29,836			25,491			81,964			91,020
General and administrative expense⁽²⁾		18,074			17,887			54,430			44,231
Depreciation and amortization		50,173			51,080			148,632			127,921
Interest		22,553			24,347			69,275			65,614
Income tax benefit		(623	)		(817	)		(1,519	)		(854	)
Equity loss in joint ventures		4,711			1,882			10,464			314
Loss on early extinguishment of debt		—			—			—			26,601
(Gain) loss on asset sales and other		636			—			(47,829	)		1,519
Non-cash linefill (gain) loss⁽³⁾		811			(1,039	)		717			332

Gross margin	$	137,829		$	114,841		$	405,541		$	314,565

(1)	Operating expenses include plant operating expenses; transportation and compression expenses; and other expenses.

(2)	General and administrative includes compensation reimbursement to affiliates.

(3)	Represents the non-cash impact of commodity price movements on pipeline linefill.

RECONCILIATION OF EBITDA, ADJUSTED EBITDA AND DISTRIBUTABLE CASH FLOW


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Net income (loss)	$	49,374		$	(25,564	)	$	116,924		$	(42,965	)
Adjustments:
Interest expense		22,553			24,347			69,275			65,614
Income tax benefit		(623	)		(817	)		(1,519	)		(854	)
Depreciation and amortization		50,173			51,080			148,632			127,921

EBITDA		121,477			49,046			333,312			149,716
Adjustments:
Income attributable to non-controlling interests⁽¹⁾		(4,029	)		(1,514	)		(10,456	)		(4,693	)
Non-controlling interest depreciation, amortization and interest expense⁽²⁾		(1,018	)		(917	)		(2,630	)		(2,888	)
Equity loss in joint ventures		4,711			1,882			10,464			314
Distributions from joint ventures		1,064			1,800			5,264			5,400
Loss on early extinguishment of debt		—			—			—			26,601
(Gain) loss on asset disposition		636			—			(47,829	)		1,519
Non-cash gain on derivatives		(26,684	)		23,610			(28,100	)		13,066
Premium expense on derivative instruments		1,311			4,824			4,826			11,844
Unrecognized economic impact of acquisitions		—			42			—			1,168
Other expenses		(1	)		685			16			19,585
Non-cash compensation		6,376			5,998			19,258			13,818
Non-cash line fill (gain) loss⁽³⁾		811			(1,039	)		717			332
Minimum volume adjustment⁽⁴⁾		1,935			(216	)		5,438			2,437

Adjusted EBITDA		106,589			84,201			290,280			238,219
Adjustments:
Interest expense		(22,553	)		(24,347	)		(69,275	)		(65,614	)
Preferred dividend obligation		(2,609	)		—			(5,624	)		—
Amortization of deferred finance costs		1,772			1,836			5,502			5,119
Premium expense on derivative instruments		(1,311	)		(4,824	)		(4,826	)		(11,844	)
Maintenance capital, net⁽⁵⁾		(7,277	)		(6,232	)		(17,815	)		(13,759	)

Distributable Cash Flow	$	74,611		$	50,634		$	198,242		$	152,121

(1)

Represents Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) non-controlling interest in the operating results of Atlas Pipeline Mid-Continent WestOk, LLC (“WestOK”) and Atlas Pipeline Mid-Continent WestTex, LLC (“WestTX”); and MarkWest Oklahoma Gas Company, LLC’s, (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE) non-controlling interest in Centrahoma Processing, LLC (“Centrahoma”).

(2)	Represents the depreciation, amortization and interest expense included in income attributable to non-controlling interest for MarkWest’s interest in Centrahoma.

(3)	Represents the non-cash impact of commodity price movements on pipeline linefill.

(4)	Represents minimum volume adjustments on certain producer throughput contracts.

(5)	Net of non-controlling interest maintenance capital of $140 thousand and $184 thousand for the three months ended September 30, 2014 and 2013, respectively, and $482 thousand and $360 thousand for the nine months ended September 30, 2014 and 2013, respectively.

Results of Operations

The following tables illustrate selected pricing before the effect of derivatives and volumetric information for the periods indicated:


	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Percent Change			2014		2013		Percent Change
Pricing:
Weighted Average Market Prices:
NGL price per gallon – Conway hub	$	0.80	$	0.81		(1.2	)%	$	0.89	$	0.80		11.3	%
NGL price per gallon – Mt. Belvieu hub		0.82		0.85		(3.5	)%		0.89		0.83		7.2	%
Oklahoma
Natural gas sales ($/MMBTU):
SouthOK		3.80		3.37		12.8	%		4.23		3.47		21.9	%
WestOK		3.70		3.30		12.1	%		4.17		3.45		20.9	%
NGL sales ($/gallon):
SouthOK		1.03		0.87		18.4	%		1.03		0.74		39.2	%
WestOK		1.08		1.08		—	%		1.12		1.01		10.9	%
Condensate sales ($/barrel):
SouthOK		91.10		103.45		(11.9	)%		92.43		94.53		(2.2	)%
WestOK		91.49		96.86		(5.5	)%		91.41		88.10		3.8	%
Texas
Natural gas sales ($/MMBTU):
SouthTX		4.02		N/A		N/A			4.29		N/A		N/A
WestTX		3.80		3.32		14.5	%		4.21		3.40		23.8	%
NGL sales ($/gallon):
SouthTX		0.82		0.75		9.3	%		0.90		0.73		23.3	%
WestTX		0.92		0.92		—	%		0.94		0.90		4.4	%
Condensate sales ($/barrel):
SouthTX		83.43		92.94		(10.2	)%		85.79		91.05		(5.8	)%
WestTX		88.41		106.27		(16.8	)%		92.91		98.78		(5.9	)%
Weighted Average
Natural gas sales ($/MMBTU):		3.75		3.34		12.3	%		4.19		3.46		21.1	%
NGL sales ($/gallon):		0.98		0.92		6.5	%		1.01		0.87		16.1	%
Condensate sales ($/barrel):		90.09		101.48		(11.2	)%		91.78		92.82		(1.1	)%


	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Percent Change			2014		2013		Percent Change
Operating data:
Oklahoma
SouthOK system⁽¹⁾:
Gathered gas volume (MCFD)		435,018		423,322		2.8	%		422,800		412,715		2.4	%
Processed gas volume (MCFD)		409,452		397,358		3.0	%		397,041		385,854		2.9	%
Residue gas volume (MCFD)		376,350		338,369		11.2	%		363,508		322,804		12.6	%
NGL volume (BPD)		28,298		32,951		(14.1	)%		28,638		36,425		(21.4	)%
Condensate volume (BPD)		530		441		20.2	%		639		513		24.6	%
WestOK system:
Gathered gas volume (MCFD)		573,957		505,222		13.6	%		553,434		488,219		13.4	%
Processed gas volume (MCFD)		545,301		479,270		13.8	%		528,768		462,932		14.2	%
Residue gas volume (MCFD)		498,451		442,304		12.7	%		484,762		428,056		13.2	%
NGL volume (BPD)		26,223		21,522		21.8	%		24,315		20,021		21.4	%
Condensate volume (BPD)		2,533		1,759		44.0	%		2,374		1,892		25.5	%
Texas
SouthTX system:
Gathered gas volume (MCFD)		134,064		141,282		(5.1	)%		116,315		131,815		(11.8	)%
Processed gas volume (MCFD)		133,719		140,557		(4.9	)%		114,180		131,000		(12.8	)%
Residue gas volume (MCFD)		106,332		114,287		(7.0	)%		92,399		105,495		(12.4	)%
NGL volume (BPD)		16,336		17,990		(9.2	)%		14,020		16,524		(15.2	)%
Condensate volume (BPD)		191		108		76.9	%		170		85		100.0	%
WestTX system⁽¹⁾:
Gathered gas volume (MCFD)		508,010		383,466		32.5	%		459,348		349,894		31.3	%
Processed gas volume (MCFD)		473,644		355,203		33.3	%		434,675		316,760		37.2	%
Residue gas volume (MCFD)		348,921		265,648		31.3	%		321,510		235,310		36.6	%
NGL volume (BPD)		62,086		47,663		30.3	%		56,215		40,322		39.4	%
Condensate volume (BPD)		2,490		2,598		(4.2	)%		1,972		1,881		4.8	%
Barnett system:
Average throughput volumes (MCFD)		20,327		22,727		(10.6	)%		20,296		21,408		(5.2	)%

(1)	Operating data for SouthOK and WestTX represent 100% of operating activity for these systems. SouthOK gathered volumes include volumes gathered by MarkWest and processed through the Arkoma facilities.

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

The following table and discussion is a summary of our consolidated results of operations for the three months ended September 30, 2014 and 2013 (in thousands):


	Three Months Ended September 30,									Percent Change
	2014			2013			Variance			Percent Change
Gross margin⁽¹⁾
Natural gas and liquids sales	$	673,888		$	535,719		$	138,169			25.8	%
Transportation, processing and other fees		49,578			43,725			5,853			13.4	%
Less: non-cash line fill gain (loss)⁽²⁾		(811	)		1,039			(1,850	)		(178.1	)%
Less: natural gas and liquids cost of sales		586,448			463,564			122,884			26.5	%

Gross margin		137,829			114,841			22,988			20.0	%
Gross margin %		20.5	%		21.4	%
Expenses:
Operating expenses		29,837			24,806			5,031			20.3	%
General and administrative⁽³⁾		18,074			17,887			187			1.0	%
Other expenses		(1	)		685			(686	)		(100.1	)%
Depreciation and amortization		50,173			51,080			(907	)		(1.8	)%
Interest expense		22,553			24,347			(1,794	)		(7.4	)%

Total expenses		120,636			118,805			1,831			1.5	%
Other income items:
Derivative gain (loss), net		24,155			(24,517	)		48,672			198.5	%
Other income, net		13,561			2,943			10,618			360.8	%
Non-cash line fill gain (loss)⁽²⁾		(811	)		1,039			(1,850	)		(178.1	)%
Equity loss in joint ventures		(4,711	)		(1,882	)		(2,829	)		(150.3	)%
Gain on asset disposition		(636	)		—			(636	)		(100.0	)%
Income tax benefit		623			817			(194	)		(23.7	)%
Income attributable to non-controlling interests⁽⁴⁾		(4,029	)		(1,514	)		(2,515	)		(166.1	)%
Preferred unit imputed dividend effect		(11,378	)		(11,378	)		—			—	%
Preferred unit dividends in kind		(11,408	)		(9,072	)		(2,336	)		(25.7	)%
Preferred unit dividends		(2,609	)		—			(2,609	)		(100.0	)%

Net income (loss) attributable to common limited partners and General Partner	$	19,950		$	(47,528	)	$	67,478			142.0	%

Non-GAAP financial data:
EBITDA⁽¹⁾	$	121,477		$	49,046		$	72,431			147.7	%
Adjusted EBITDA⁽¹⁾		106,589			84,201			22,388			26.6	%
Distributable cash flow⁽¹⁾		74,611			50,634			23,977			47.4	%

(1)	Gross margin, EBITDA, Adjusted EBITDA and distributable cash flow are non-GAAP financial measures (see “–How We Evaluate Our Operations” and “Non-GAAP Financial Measures”).

(2)	Includes the non-cash impact of commodity price movements on pipeline linefill.

(3)	General and administrative also includes compensation reimbursement to affiliates.

(4)	Represents Anadarko’s non-controlling interest in the operating results of the WestOK and WestTX systems and MarkWest’s non-controlling interest in Centrahoma.

Gross margin

Gross margin from natural gas and liquids sales and transportation, processing and other fees and the related natural gas and liquids cost of sales for the three months ended September 30, 2014 increased primarily due to higher production volumes. Overall gross margin percentages are lower for the three months ended September 30, 2014 due to an increase in POP contracts during the period, which reduced our commodity price risk, but negatively impacted our gross margin rate.

•

Oklahoma For the three months ended September 30, 2014, Oklahoma gross margins increased $12.5 million compared to the prior year period. Gathering and processing volumes on the WestOK system for the three months ended September 30, 2014 increased as a result of increased production on the gathering systems, which continue to be expanded to meet producer demand.

•

Texas For the three months ended September 30, 2014, Texas gross margins increased $10.8 million compared to the prior year period. The WestTX system’s gathering and processing volumes for the three months ended September 30, 2014 increased compared to the prior year period due to continued increased volumes from Pioneer Natural Resources Company (NYSE: PXD) and others as a result of their continued drilling programs.

Expenses

Operating expenses, comprised primarily of plant operating expenses and transportation and compression expenses, for the three months ended September 30, 2014 increased due to continued expansion of our gathering and processing systems across both the Oklahoma and Texas segments (see “–Recent Events”).

Other expenses for the three months ended September 30, 2013 represented acquisition costs related to the TEAK Acquisition.

Interest expense for the three months ended September 30, 2014 decreased primarily due to a $2.3 million increase in capitalized interest offset by a $0.6 million increase on the senior secured revolving credit facility. The increase in capitalized interest is due to increased capital expenditures over the same period last year. The increase in the interest on senior secured revolving credit facility is due to increased borrowings compared to the prior year period. (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 13 –Revolving Credit Facility”).

Other income items

Derivative gain (loss), net for the three months ended September 30, 2014 had a $50.3 million favorable mark-to-market gain (loss) compared to the prior year period primarily due to a $26.7 million mark-to-market gain in the current year period as a result of a decrease in forward prices combined with an increase in forward prices during the prior year period resulting in $23.6 million mark-to-market losses on derivatives, offset by a $1.7 million unfavorable variance in cash settlements in the current year period compared to the prior year period mainly due to favorable propane swap settlements in the prior year period. While we utilize either quoted market prices or observable market data to calculate the fair value of natural gas and crude oil derivatives, valuations of NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGLs for similar geographic locations, and valuations of NGL options are based on forward price curves developed by third-party financial institutions. The use of unobservable market data for NGL fixed price swaps and NGL options has no impact on the settlement of these derivatives. However, a change in management’s estimated fair values for these derivatives could impact net income, although it would have no impact on liquidity or capital

resources (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 10” for further discussion of derivative instrument valuations). We recognized a $9.4 million mark-to-market gain and a $21.5 million mark-to-market loss on derivatives valued based upon unobservable inputs for the three months ended September 30, 2014 and 2013, respectively. We enter into derivative instruments solely to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under “Item 3: Quantitative and Qualitative Disclosures About Market Risk.”

Other income had a favorable variance for the three months ended September 30, 2014 compared to the prior year period primarily due to an arrangement with respect to our SouthTX system.

Non-cash linefill gain (loss) had an unfavorable variance for the three months ended September 30, 2014 compared to the prior year period primarily due to the changes in the forward prices as described for the derivative gain (loss), net. (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 11 –Fair Value of Financial Instruments –NGL Linefill”).

Equity loss in joint ventures had an unfavorable variance for the three months ended September 30, 2014 mainly due to $1.4 million income in the prior year period related to WTLPG, which was sold on May 14, 2014 (see “Recent Events”) and due to a $1.5 million dollar increase in the loss on the T2 Eagle Ford joint venture. The T2 LaSalle and T2 Eagle Ford joint ventures are structured to earn revenues equal to their operating costs, exclusive of depreciation expense. The loss primarily represents depreciation expense.

Income tax benefit for the three months ended September 30, 2014 represents the deferred income tax benefit related to the loss incurred by APL Arkoma, Inc. The unfavorable variance compared to the prior period is due to APL Arkoma, Inc. incurring a smaller taxable loss compared to the prior period.

Income attributable to non-controlling interests for the three months ended September 30, 2014 increased $2.2 million in our Oklahoma segment primarily due to Anadarko’s non-controlling interest in higher net income for the WestOK joint venture, and due to MarkWest’s non-controlling interest in higher net income for the Centrahoma joint venture. The increase in net income of the WestOK joint venture was principally due to higher gross margins on the sale of commodities, resulting from higher volumes. The increase in net income of the Centrahoma joint venture was due to the start-up of the Stonewall Plant on May 1, 2014 (see “–Recent Events”), which resulted in higher processing revenues during the period.

Income attributable to non-controlling interests for the three months ended September 30, 2014 increased $0.3 million in our Texas segment primarily due to Anadarko’s non-controlling interest in higher net income for the WestTX joint venture. The increase in net income of the WestTX joint venture was principally due to higher gross margins on the sale of commodities, resulting from higher volumes.

Preferred unit dividends in-kind for the three months ended September 30, 2014 represent the distributions to the Class D Preferred Units, which have been declared (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 5 – Class D Preferred Units”). The unfavorable variance compared to the prior period is due to an increased distribution per unit and increased preferred units outstanding over the prior year period.

Preferred unit dividends for the three months ended September 30, 2014 represent the distributions to the Class E Preferred Units, attributable to the three month period ended September 30, 2014 (see “–Class E Preferred Units”).

Non-GAAP financial data

EBITDA had a favorable variance for the three months ended September 30, 2014 compared to the prior year period mainly due to mark-to-market gains on derivatives in the current year period compared to mark-to-market losses on derivatives in the prior year period, as discussed above in “–Other income items,” and due to the favorable gross margin variance, as discussed above in “–Gross margin.”

Adjusted EBITDA had a favorable variance for the three months ended September 30, 2014 compared to the prior year period mainly due to the improved gross margin variance, as discussed above in “–Gross margin,” partially offset by higher operating expenses discussed above in “–Expenses.”

Distributable cash flow had a favorable variance for the three months ended September 30, 2014 compared to the prior year period mainly due to the favorable Adjusted EBITDA variance, as discussed above, partially offset by preferred unit dividends, as discussed above in “–Other income items,” and by higher maintenance capital expenditures (see further discussion of capital expenditures under “–Capital Requirements”).

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

The following table and discussion is a summary of our consolidated results of operations for the nine months ended September 30, 2014 and 2013 (in thousands):


	Nine Months Ended September 30,
	2014			2013			Variance			Percent Change
Gross margin⁽¹⁾
Natural gas and liquids sales	$	2,004,567		$	1,410,797		$	593,770			42.1	%
Transportation, processing and other fees		143,058			116,756			26,302			22.5	%
Less: non-cash line fill loss⁽²⁾		(717	)		(332	)		(385	)		(116.0	)%
Less: natural gas and liquids cost of sales		1,742,801			1,213,320			529,481			43.6	%

Gross margin		405,541			314,565			90,976			28.9	%
Gross margin %		20.2	%		22.3	%
Expenses:
Operating expenses		81,948			71,435			10,513			14.7	%
General and administrative⁽³⁾		54,430			44,231			10,199			23.1	%
Other expenses		16			19,585			(19,569	)		(99.9	)%
Depreciation and amortization		148,632			127,921			20,711			16.2	%
Interest expense		69,275			65,614			3,661			5.6	%

Total expenses		354,301			328,786			25,515			7.8	%
Other income items:
Derivative gain (loss), net		9,117			(9,493	)		18,610			196.0	%
Other income, net		18,400			8,661			9,739			112.4	%
Non-cash line fill loss⁽²⁾		(717	)		(332	)		(385	)		(116.0	)%
Equity loss in joint ventures		(10,464	)		(314	)		(10,150	)		(3,232.5	)%
Gain (loss) on asset disposition		47,829			(1,519	)		49,348			3,248.7	%
Loss on early extinguishment of debt		—			(26,601	)		26,601			(100.0	)%
Income tax benefit		1,519			854			665			77.9	%
Income attributable to non-controlling interests⁽⁴⁾		(10,456	)		(4,693	)		(5,763	)		(122.8	)%
Preferred unit imputed dividend effect		(34,134	)		(18,107	)		(16,027	)		(88.5	)%
Preferred unit dividends in kind		(31,533	)		(14,413	)		(17,120	)		(118.8	)%
Preferred unit dividends		(5,624	)		—			(5,624	)		(100.0	)%

Net income (loss) attributable to common limited partners and General Partner	$	35,177		$	(80,178	)	$	115,355			143.9	%

Non-GAAP financial data:
EBITDA⁽¹⁾	$	333,312		$	149,716		$	183,596			122.6	%
Adjusted EBITDA⁽¹⁾		290,280			238,219			52,061			21.9	%
Distributable cash flow⁽¹⁾		198,242			152,121			46,121			30.3	%

(1)	Gross Margin, EBITDA, Adjusted EBITDA and Distributable cash flow are non-GAAP financial measures (see “–How We Evaluate Our Operations” and “–Non-GAAP Financial Measures”).

(2)	Includes the non-cash impact of commodity price movements on pipeline linefill.

(3)	General and administrative also includes any compensation reimbursement to affiliates.

(4)	Represents Anadarko’s non-controlling interest in the operating results of the WestOK and WestTX systems and MarkWest’s non-controlling interest in the operating results of Centrahoma.

Gross margin

Gross margin from natural gas and liquids sales and transportation, processing and other fees and the related natural gas and liquids cost of sales for the nine months ended September 30, 2014 increased primarily due to higher production volumes. Overall gross margin percentages are lower for the nine months ended September 30, 2014 due to the increase in natural gas prices, which increased at a higher rate than NGL prices, negatively impacting the gross margin rate achieved on Keep-Whole contracts. Additionally, we had an increase in POP contracts during the period, which reduced our commodity price risk, but negatively impacted our gross margin rate.

•

Oklahoma For the nine months ended September 30, 2014, Oklahoma gross margins increased $38.7 million compared to the prior year period. Gathering and processing volumes on the WestOK system for the nine months ended September 30, 2014 increased as a result of increased production on the gathering systems, which continue to be expanded to meet producer demand.

•

Texas For the nine months ended September 30, 2014, Texas gross margins increased $52.9 million compared to the prior year period. The WestTX system’s gathering and processing volumes for the nine months ended September 30, 2014 increased compared to the prior year period due to continued increased volumes from Pioneer Natural Resources Company (NYSE: PXD) and others as a result of their continued drilling programs, and due to the April 2013 start-up of the Driver plant during the prior year period. Gross margins also increased compared to the prior year period due to the acquisition of the SouthTX system as part of the TEAK Acquisition (see “Item 1. Notes to the Consolidated Financial Statements (Unaudited) – Note 3”) during the second quarter of 2013.

Expenses

Operating expenses, comprised primarily of plant operating expenses and transportation and compression expenses, for the nine months ended September 30, 2014 increased mainly in our Texas segment due to $4.7 million in additional expenses from the SouthTX systems acquired in the TEAK Acquisition (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 3”) and $6.3 million in additional expenses from the WestTX systems due to the completion of the Driver Plant in April 2013.

General and administrative expense, including amounts reimbursed to affiliates, increased for the nine months ended September 30, 2014 mainly due to a $5.4 million increase in share-based compensation related to phantom units granted to employees (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) –Note 15”) and a $4.2 million increase in salaries and wages partially due to the increase in the number of employees as a result of the TEAK Acquisition (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 3”), and continued growth in our other operating areas.

Other expenses for the nine months ended September 30, 2014 decreased mainly due to acquisition costs related to the TEAK Acquisition (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 3”) recorded in the prior year period.

Depreciation and amortization expense for the nine months ended September 30, 2014 increased primarily in our Texas segment mainly due to $17.8 million additional expense related to assets acquired in the TEAK Acquisition (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 3”), and due to growth capital expenditures incurred subsequent to September 30, 2013.

Interest expense for the nine months ended September 30, 2014 increased primarily due to $6.9 million additional interest related to the 4.75% Senior Notes and $4.2 million of additional interest related to the 5.875% unsecured senior notes due August 1, 2023 (“5.875% Senior Notes”); offset by $4.2 million reduced interest expense on the 8.75% unsecured senior notes due June 15, 2018 (“8.75% Senior Notes”) and a $4.5 million increase in capitalized interest expense. The increase in the interest on the 4.75% Senior Notes and the 5.875% Senior Notes is due to their issuance in 2013 (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 13 – Senior Notes”). The decrease in the interest for the 8.75% Senior Notes is due to their redemption in February 2013 (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 13 – Senior Notes”). The increase in capitalized interest is due to increased capital expenditures over the same period last year.

Other income items

Derivative income (loss), net for the nine months ended September 30, 2014 had a $41.2 million favorable mark-to-market gain (loss) variance compared to the prior year period primarily due to a $28.1 million gain in the current year period due to a decrease in forward prices and an increase in forward prices during the prior year period resulting in $13.1 million mark-to-market losses. This is partially offset by a $22.6 million unfavorable variance in cash settlements in the current year period compared to the prior year period mainly due to losses on NGL swap settlements. We recognized a $7.1 million mark-to-market gain and a $6.1 million mark-to-market loss on derivatives valued based upon unobservable inputs for the nine months ended September 30, 2014 and 2013, respectively.

Other income had a favorable variance for the nine months ended September 30, 2014 compared to the prior year period primarily due to an arrangement with respect to our SouthTX system.

Non-cash linefill loss had an unfavorable variance for the nine months ended September 30, 2014 compared to the prior year period primarily due to a mark-to-market loss on linefill volumes in the WestTX system.

Equity income (loss) in joint ventures decreased for the nine months ended September 30, 2014 primarily due to a $7.6 million increased loss in the current period from the SouthTX equity method investments and due to a $2.5 million decrease in revenues from WTLPG due to its sale in May 2014 (see “Recent Events”). The T2 LaSalle and T2 Eagle Ford joint ventures are structured to earn revenues equal to their operating costs, exclusive of depreciation expense. The loss primarily represents depreciation expense.

Income tax benefit for the nine months ended September 30, 2014 represents the deferred income tax benefit related to the loss incurred at APL Arkoma, Inc. The favorable variance compared to the prior period is due to APL Arkoma, Inc. incurring a larger taxable loss compared to the prior period.

Income attributable to non-controlling interests for the nine months ended September 30, 2014 increased $4.3 million in our Oklahoma segment primarily due to Anadarko’s non-controlling interest in higher net income for the WestOK joint venture and MarkWest’s non-controlling interest in higher net income for the Centrahoma joint venture. The increase in net income in the WestOK joint venture was principally due to higher gross margins on the sale of commodities, resulting from higher volumes. The increase in net income of the Centrahoma joint venture was due to the start-up of the Stonewall Plant on May 1, 2014 (see “–Recent Events”), which resulted in higher processing revenues during the period.

Income attributable to non-controlling interests for the nine months ended September 30, 2014 increased $1.4 million in our Texas segment primarily due to Anadarko’s non-controlling interest in higher net income for the WestTX joint venture. The increase in net income in the WestTX joint venture was principally due to higher gross margins on the sale of commodities, resulting from higher volumes.

Preferred unit imputed dividend effect for the nine months ended September 30, 2014 represents the accretion of the beneficial conversion discount of the Class D Preferred Units (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 5 – Class D Preferred Units”). The unfavorable variance compared to the prior period is due to the issuance of the Class D Preferred Units during May 2013.

Preferred unit dividends in-kind for the nine months ended September 30, 2014 represent the distributions to the Class D Preferred Units, which have been declared (see “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 5 – Class D Preferred Units”). The unfavorable variance compared to the prior period is due to the issuance of the Class D Preferred Units during May 2013.

Preferred unit dividends for the nine months ended September 30, 2014 represent the distributions to the Class E Preferred Units, attributable to the nine month period ended September 30, 2014 (see “–Class E Preferred Units”).

Non-GAAP financial data

EBITDA had a favorable variance for the nine months ended September 30, 2014 compared to the prior year period mainly due to the favorable gross margin as discussed above in “–Gross margin”; the prior year loss on early extinguishment of debt as discussed in “–Other income items” above; the gain on sale of WTLPG during the current year period as discussed above in “–Other income items”; and the favorable derivative gain (loss), net as discussed above in “–Other income items.”

Adjusted EBITDA had a favorable variance for the nine months ended September 30, 2014 compared to the prior year period mainly due to the improved gross margin variance, as discussed above in “–Gross margin,” partially offset by higher operating expenses and general and administrative expenses as discussed above in “–Expenses”.

Distributable cash flow had a favorable variance for the nine months ended September 30, 2014 compared to the prior year period mainly due to the favorable Adjusted EBITDA variance, as discussed above, partially offset by higher interest expense and preferred unit dividends as discussed above in “–Expenses” and “–Other income items,” respectively.

Liquidity and Capital Resources

General

At September 30, 2014, we had $200.0 million outstanding borrowings under our $800.0 million senior secured revolving credit facility and $3.4 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheets, with $596.6 million of remaining committed capacity under the revolving credit facility, (see “–Revolving Credit Facility”). We were in compliance with the credit facility’s covenants at September 30, 2014. We had a working capital deficit of $85.6 million at September 30, 2014 compared with a $78.4 million working capital deficit at December 31, 2013. We believe we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, we are subject to business, operational and other risks that could adversely affect our cash flows. We may need to supplement our cash generation with proceeds from financing activities, including borrowings under our revolving credit facility and other borrowings, the issuance of additional limited partner units and sales of our assets.

Cash Flows – Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

The following table details the cash flow changes between the nine months ended September 30, 2014 and 2013 (in thousands):


	Nine Months Ended September 30,									Percent Change
	2014			2013			Variance			Percent Change
Net cash provided by (used in):
Operating activities	$	234,161		$	151,121		$	83,040			54.9	%
Investing activities		(350,089	)		(1,338,149	)		988,060			73.8	%
Financing activities		117,750			1,194,069			(1,076,319	)		(90.1	)%

Net change in cash and cash equivalents	$	1,822		$	7,041		$	(5,219	)		—

Net cash provided by operating activities for the nine months ended September 30, 2014 increased compared to the prior year period primarily due to a $77.0 million increase in net earnings from continuing operations excluding non-cash charges. The increase is primarily due to increased gross margins from the sale of natural gas and NGLs offset by an increase in operating expense and general and administrative expense (see “–Results of Operations”).

Net cash used in investing activities for the nine months ended September 30, 2014 decreased compared to the prior year period mainly due to the $1.0 billion TEAK Acquisition (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 3”) in the prior year period and due to the receipt of $131.0 million in net proceeds from the sale of WTLPG (see “–Recent Events”), partially offset by an increase in capital expenditures of $145.3 million in the current year period compared to the prior year period (see further discussion of capital expenditures under “–Capital Requirements”).

Net cash provided by financing activities for the nine months ended September 30, 2014 decreased compared to the prior year period mainly due to (i) $637.3 million provided by the issuance of the 5.875% Senior Notes in the prior year period; (ii) $397.7 million provided by the issuance of Class D Preferred Units in the prior year period; (iii) $391.2 million provided by the issuance of the 4.75% Senior Notes in the prior year period; and (iv) $388.4 million provided by the April 2013 common unit issuance of 11,845,000 common units in the prior year period. These decreases were partially offset by (i) the

$391.4 million redemption of the 8.75% Senior Notes, including the cost of early retirement of debt in the prior year period; (ii) a $193.0 million net decrease in the prior year period to outstanding borrowings on the revolving credit facility; and (iii) $122.3 million provided by the issuance of the Class E Preferred Units in the current period (see “–Class E Preferred Units”). The gross amount of borrowings and repayments under the revolving credit facility included within net cash provided by financing activities in the consolidated combined statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of (i) cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facility, and (ii) payments, which generally occur throughout the period and increase borrowings under the revolving credit facility, which is generally common practice for the industry.

Capital Requirements

Our operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmental regulations. Our capital requirements consist primarily of:

•

maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

•

expansion capital expenditures to acquire complementary assets and to expand the capacity of our existing operations.

The following table summarizes maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Maintenance capital expenditures	$	7,417	$	6,416	$	18,297	$	14,119
Expansion capital expenditures		185,151		105,736		454,850		313,742

Total	$	192,568	$	112,152	$	473,147	$	327,861

The increase in maintenance capital expenditures for the three and nine months ended September 30, 2014 when compared with the corresponding prior year period was due to fluctuations in the timing of scheduled maintenance activity.

Expansion capital expenditures increased for the three and nine months ended September 30, 2014 primarily due to construction costs for (i) the Stonewall plant within SouthOK, which was placed in service May 1, 2014 (see “–Recent Events”), (ii) the Silver Oak II plant within SouthTX placed in service on June 25, 2014 (see “–Recent Events”), (iii) the Edward plant within WestTX placed in service on September 15, 2014 (see “–Recent Events”); and (iv) the construction of the Velma to Arkoma connection within SouthOK scheduled to be completed during the fourth quarter of 2014. As of September 30, 2014, we had approved additional expenditures of approximately $346.5 million on processing facility expansions, pipeline extensions and compressor station upgrades, of which approximately $165.8 million in purchase commitments had been made. We expect to fund these projects through operating cash flows and borrowings under our revolving credit facility.

Partnership Distributions

Our partnership agreement requires that we distribute 100% of available cash, for each calendar quarter, to our common unitholders and our General Partner within 45 days following the end of such calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

The Class D Preferred Units received distributions of additional Class D Preferred Units for the first four full quarterly periods following their issuance in May 2013, and thereafter will receive distributions in Class D Preferred Units, or cash, or a combination of Class D Preferred Units and cash, at the discretion of our General Partner.

Our General Partner is granted discretion by our partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our General Partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to our common limited partners and 2.0% to our General Partner. These distribution percentages are modified to provide for incentive distributions to be paid to our General Partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to our General Partner that are in excess of 2.0% of the aggregate amount of cash being distributed. Our General Partner, holder of all our incentive distribution rights, has agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to us after the General Partner receives an initial $7.0 million of incentive distribution rights per quarter. Incentive distributions of $5.9 million and $4.8 million were paid during the three months ended September 30, 2014 and 2013, respectively, and $15.8 million and $10.1 million were paid during the nine months ended September 30, 2014 and 2013, respectively.

Common Equity Offerings

On May 12, 2014, we entered into the 2014 EDA with the sales agents named therein (see “–Recent Events”). Pursuant to the 2014 EDA, we may offer and sell from time to time through the sales agents, common units having an aggregate value up to $250.0 million. Sales are at market prices prevailing at the time of the sale.

During the three months ended September 30, 2014 and 2013, we issued 2,095,818 and 1,772,800 common units, respectively, under the 2014 EDA and an Equity Distribution Agreement entered into in November 2012 (the “2012 EDA” and together with the 2014 EDA, the “EDAs”) for net proceeds of $74.2 million and $63.7 million, respectively, net of $0.8 million and $1.3 million, respectively, in commissions paid to the sales agents. During the nine months ended September 30, 2014 and 2013, we issued 3,558,005 and 2,863,080 common units, respectively, under the EDAs for net proceeds of $121.6 million and $102.7 million, respectively, net of $1.2 million and $2.1 million, respectively, in commissions paid to the sales agents. We also received capital contributions from the General Partner of $1.5 million and $1.3 million during the three months ended September 30, 2014 and 2013, respectively, and $2.5 million and $2.1 million during the nine months ended September 30, 2014 and 2013, respectively, to maintain its 2.0% general partner interest in us. The net proceeds from the common unit offerings were utilized for general partnership purposes. As of September 30, 2014, we had $127.0 million remaining capacity under the 2014 EDA (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) – Note 5”).

Class E Preferred Units

On March 17, 2014, we issued 5,060,000 of our Class E Preferred Units to the public at an offering price of $25.00 per Class E Preferred Unit. We received $122.3 million in net proceeds, which were used to pay down the revolving credit facility. We will make cumulative cash distributions on the Class E Preferred Units from the date of original issue. The cash distributions will be payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year, when, and if, declared by the board of directors. The initial distribution on the Class E Preferred Units was paid on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million. Going forward, we will pay cumulative distributions in cash on the Class E Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) –Note 5 –Class E Preferred Units”).

Off Balance Sheet Arrangements

As of September 30, 2014, our off balance sheet arrangements include our letters of credit, issued under the provisions of our revolving credit facility, totaling $3.4 million, and surety bonds under which our maximum liability is $10.4 million. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate, (ii) surety, and (iii) counterparty support.

We have certain long-term unconditional purchase obligations and commitments, primarily throughput contracts. These agreements provide transportation services to be used in the ordinary course of our operations.

Revolving Credit Facility

At September 30, 2014, we had an $800.0 million senior secured revolving credit facility with a syndicate of banks, which matures in August 2019. The weighted average interest rate for borrowings on the revolving credit facility, at September 30, 2014, was 2.7%. Up to $50.0 million of the revolving credit facility may be utilized for letters of credit, of which $3.4 million was outstanding at September 30, 2014. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheets.

On August 28, 2014, we entered into a Second Amended and Restated Credit Agreement which, among other changes, extended the maturity date; increased the revolving credit commitment and incremental revolving credit amount; and reduced the applicable margin used to determine interest rates by 0.25% (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) –Note 13 –Revolving Credit Facility”).

On March 11, 2014, we entered into an amendment to the credit agreement governing our revolving credit facility, which among other changes, adjusted the Acquisition Period for the Consolidated Funded Debt Ratio, and permitted the payment of cash distributions on the Class E Preferred Units (see “Item 1. Notes to Consolidated Financial Statements (Unaudited) –Note 13 –Revolving Credit Facility”).

The events that constitute an event of default for our revolving credit facility include payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against us in excess of a specified amount, and a change of control of our General Partner. As of September 30, 2014, we were in compliance with all covenants under the revolving credit facility.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires making 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 actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items subject to such estimates and assumptions include revenue and expense accruals, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired.

There have been no material changes in the methodology applied by management for critical accounting policies and estimates from those disclosed in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2013.

Recently Adopted Accounting Standards

See “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 2 – Recently Adopted Accounting Standards” for information regarding recently adopted accounting pronouncements.

Recently Issued Accounting Standards

See “Item 1: Notes to Consolidated Financial Statements (Unaudited) – Note 2 – Recently Issued Accounting Standards” for information regarding recently issued accounting pronouncements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All our market risk sensitive instruments were entered into for purposes other than trading.

General

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodic use of derivative instruments.

The information about commodity price risk and interest rate risk for the three and nine months ended September 30, 2014 does not differ materially from that discussed in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K” for the year ended December 31, 2013.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our General Partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our General Partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our General Partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2014, our disclosure controls and procedures were effective at the reasonable assurance level.

There have been no material changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

On October 13, 2014 we announced the transactions (the “Merger”) contemplated by the definitive Agreement and Plan of Merger (the “Merger Agreement”) between Atlas Pipeline Partners GP, LLC (our “General Partner”), Atlas Energy, L.P. (“ATLS”), Targa Resources Corp. (“TRC”), Targa Resources Partners LP (“TRP”), certain other parties and us. Concurrently with the Merger Agreement, ATLS announced that it entered into a definitive merger agreement with TRC, pursuant to which TRC agreed to acquire ATLS through a merger of a newly formed wholly-owned subsidiary of TRC with and into ATLS (the “ATLS Merger”).

In October 2014, three alleged public unitholders of the Partnership (the “APL Plaintiffs”) filed class action lawsuits against us, our General Partner, its managers, ATLS, TRC, TRP, Targa Resources GP LLC (“Targa GP”) and Trident MLP Merger Sub LLC (“Trident MLP Sub”) (the “APL Lawsuit Defendants”). These lawsuits are styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Alleghany County, Pennsylvania; (b) William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., in the District Court of Tulsa County, Oklahoma; and (c) Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Alleghany County, Pennsylvania (the “APL Lawsuits”).

On October 23, 2014, and November 3, 2014, respectively, two alleged public unitholders of ATLS (the “ATLS Plaintiffs” and, together with the APL Plaintiffs, “Plaintiffs”) filed class action lawsuits against ATLS, Atlas Energy Partners GP, LLC (“ATLS GP”), its managers, TRC and Trident GP Merger Sub LLC (“Trident GP Sub”) (the “ATLS Lawsuit Defendants” and, together with the APL Lawsuit Defendants, “Defendants”). These lawsuits are styled (a) Rick Kane v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Alleghany County, Pennsylvania; and (b) Jeffrey Ayers v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Alleghany County, Pennsylvania (the “ATLS Lawsuits” and, together with the APL Lawsuits, the “Lawsuits”).

Plaintiffs allege a variety of causes of action challenging the Merger and ATLS Merger. The APL Plaintiffs allege that (a) our managers have breached the covenant of good faith and/or their fiduciary duties and (b) we, our General Partner, ATLS, TRC, TRP, Targa GP and Trident MLP Sub have aided and abetted these alleged breaches of the covenant of good faith and/or fiduciary duties. One of the APL Plaintiffs also alleges that (a) we and our managers breached the Partnership Agreement and (b) we, our General Partner, ATLS, TRC, TRP, Targa GP and Trident MLP Sub aided and abetted our alleged breaches of the Partnership Agreement. Specifically, the APL Plaintiffs allege that (a) the premium offered to our unitholders is inadequate, (b) we agreed to contractual terms in the Merger Agreement that will allegedly dissuade other potential acquirers from seeking to acquire us, and (c) our General Partner’s managers favored their self-interests over the interests of our unitholders.

The ATLS Plaintiffs allege that (a) ATLS GP’s managers have breached the covenant of good faith and/or their fiduciary duties and (b) ATLS, ATLS GP, TRC and Trident GP Sub have aided and abetted these alleged breaches of the covenant of good faith and/or fiduciary duties. Specifically, the ATLS Plaintiffs allege that (a) the premium offered to ATLS’s unitholders is inadequate, (b) ATLS agreed to contractual terms that will allegedly dissuade other potential acquirers from seeking to acquire ATLS and (c) ATLS GP’s managers favored their self-interests over the interests of ATLS’s unitholders.

Based on these allegations, Plaintiffs seeks to enjoin Defendants from proceeding with or consummating the Merger and ATLS Merger. To the extent that the Merger and ATLS Merger are consummated before injunctive relief is granted, Plaintiffs seek to have the mergers rescinded. Plaintiffs also seek damages and attorneys’ fees. Plaintiffs have not yet served Defendants, and Defendants’ date to answer, move to dismiss or otherwise respond to the Lawsuits has not yet been set. We cannot predict the outcome of the Lawsuits or any others that might be filed subsequent to the date of this filing; nor can we predict the amount of time and expense that will be required to resolve the Lawsuits. Defendants intend to vigorously defend the Lawsuits.

ITEM 1A. RISK FACTORS

Due to the proposed Merger, there have been material changes to the risk factors disclosed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013. For a complete discussion of our risk factors see Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013 and the following risk factors relating to the Merger:

Completion of the Merger is subject to conditions, and if these conditions are not satisfied or waived, the Merger will not be completed.

The obligations of TRP and us to complete the Merger are subject to satisfaction or waiver, to the extent permitted under applicable law, of a number of conditions including, among others, approval of the Merger Agreement and the Merger by holders of a majority of our outstanding common units; consummation of the ATLS Merger; the performance by the other party of its respective obligations under the Merger Agreement in all material respects; and the accuracy of the representations and warranties by the other party under the Merger Agreement subject to, in most cases, a material adverse effect standard.

The requirement for the conditions to closing to be satisfied or waived could delay the completion of the Merger for a significant period of time or prevent it from occurring. Any delay in completing the Merger could cause the combined company not to realize some or all of the benefits that TRP expects to achieve if the Merger is successfully completed within its expected timeframe. Further, there can be no assurance the conditions to the closing of the Merger will be satisfied or waived or the Merger will be completed. See the risk factor entitled “Failure to complete the Merger could negatively impact our unit price and the future business and financial results,’’ below.

Combining the two companies may be more difficult, costly, or time consuming than expected and the anticipated benefits and cost savings of the Merger may not be realized.

TRP and we have operated and, until the completion of the Merger, will continue to operate, independently. The success of the Merger, including anticipated benefits and cost savings, will depend, in part, on TRP’s ability to successfully combine and integrate our businesses. It is possible the pending nature of the Merger and/or the integration process could result in the loss of key employees; higher than expected costs; diversion of TRP’s and our management’s attention; increased competition; the disruption of either company’s ongoing businesses; or inconsistencies in standards, controls, procedures and policies that adversely affect the combined company’s ability to maintain relationships with customers, suppliers, employees and other business partners or to achieve the anticipated benefits and cost savings of the Merger. If TRP experiences difficulties with the integration process, the anticipated benefits of the Merger may not be realized fully or at all, or may take longer to realize than expected. Integration efforts between the two companies will also divert management’s attention and resources. These integration matters could have an adverse effect on each of us and TRP during this transition period and for an undetermined period after completion of the Merger on the combined company. In addition, the actual cost savings and other benefits of the Merger could be less than anticipated.

Lawsuits have been filed against us, TRP and certain of our affiliates challenging the Merger, and an adverse ruling in such lawsuits may prevent the Merger from becoming effective or from becoming effective within the expected timeframe.

Following the announcement on October 13, 2014 of the Merger, we, our General Partner, ATLS, TRC, TRP, Targa GP, Trident MLP Sub and the members of the managing board of our General Partner have been named as defendants in three putative unitholder class action lawsuits challenging the Merger. In addition, ATLS, ATLS GP, TRC, Trident GP Sub and the members of ATLS’s board have been named as defendants in two putative unitholder class action lawsuits challenging the ATLS Merger.

The lawsuits filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for our unitholders in the Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses and costs. As such, if any of the plaintiffs are successful in obtaining an injunction or prohibiting the consummation of the Merger, then such injunction may prevent the Merger from becoming effective or from becoming effective within the expected timeframe.

Failure to complete the Merger could negatively impact our unit price and future business and financial results.

If the Merger is not completed for any reason, including as a result of our common unitholders failing to approve the Merger, our ongoing business may be adversely affected and, without realizing any of the benefits of having completed the Merger, we would be subject to a number of risks, including the following:

•

we may experience negative reactions from the financial markets, including negative impacts on our unit price;

•

we may experience negative reactions from our customers, suppliers, employees and other business partners;

•

we will be required to pay certain costs relating to the Merger, whether or not the Merger is completed;

•

the Merger Agreement places certain restrictions on our conduct of business prior to completion of the Merger. Such restrictions, the waiver of which is subject to the consent of TRP (in certain cases, not to be unreasonably withheld, conditioned or delayed), may prevent us from making certain acquisitions or taking certain other specified actions during the pendency of the Merger; and

•

matters relating to the Merger, including integration planning, will require substantial commitments of time and resources by our management, which would otherwise have been devoted to day-to-day operations and other opportunities that may have been beneficial to us as an independent company.

The Merger Agreement limits our ability to pursue alternatives to the Merger and may discourage other companies from trying to acquire us for greater consideration than what TRP has agreed to pay.

The Merger Agreement contains provisions that make it more difficult for us to sell our business to a party other than TRP. These provisions include a general prohibition of soliciting any acquisition proposal or offer for a competing transaction. In some circumstances upon termination of the Merger Agreement, we may be required to pay to TRP one of the following (depending on the circumstances giving rise to termination): (1) a termination fee of $122.9 million, (2) a payment of $40.9 million in respect of the other party’s expenses or (3) fifty percent (50%) of such termination fee or expense payment. Further, there are only limited exceptions to our agreement that our board of directors will not withdraw or modify, in a manner adverse to TRP, the recommendation of our board in favor of approval of the Merger and to our agreement not to enter into an agreement with respect to an alternative transaction proposal.

These provisions might discourage a third party that has an interest in acquiring all, or a significant part, of us from considering or proposing an acquisition, even if the party were prepared to pay consideration with a higher per unit value than the value proposed to be received or realized in the Merger; or might result in a potential competing acquirer proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the termination fee or expense payment that may become payable in certain circumstances.

The value of the equity portion of the Merger consideration is subject to changes based on fluctuations in the value of TRP common units.

The market value of TRP common units will fluctuate during the period before the date of the special meeting of our common unitholders to vote on approval of the Merger Agreement and will continue to fluctuate during the period prior to the effective time of the Merger, as well as thereafter.

Upon completion of the Merger, holders of our common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each of our common units. It is impossible to accurately predict the market price of TRP common units at the effective time and therefore impossible to accurately predict the value of the TRP common units that holders of our common units will receive in the Merger.

The market price of TRP common units after the Merger will continue to fluctuate and may be affected by factors different from those affecting our common units currently.

Upon completion of the Merger, holders of our common units will become holders of TRP common units. The market price of TRP common units may fluctuate significantly following consummation of the Merger and holders of our common units could lose some or all of the value of their investment in TRP common units. In addition, the stock market has experienced significant price and volume fluctuations in recent times, which could have a material adverse effect on the market for, or liquidity of, the TRP common units, regardless of TRP’s actual operating performance. In addition, TRP’s business differs in important respects from ours, and accordingly, the results of operations of the combined company and the market price of TRP common units after the completion of the Merger may be affected by factors different from those currently affecting the independent results of our operations and TRP’s operations.

Sales of TRP common units before and after the completion of the Merger may cause the market price of TRP common units to fall.

The issuance of new TRP common units in connection with the Merger could have the effect of depressing the market price for TRP common units. In addition, holders of our common units may decide not to hold the TRP common units they will receive in the Merger. Such sales of TRP common units could have the effect of depressing the market price for TRP common units and may take place promptly following the Merger.

ITEM 6. EXHIBITS


Exhibit No.		Description

1.1		Equity Distribution Agreement, dated May 12, 2014, among Atlas Pipeline Partners, L.P. and Citigroup Global Markets Inc., Wells Fargo Securities, LLC and MLV & Co. LLC⁽³⁸⁾

2.1		Agreement and Plan of Merger, by and among Targa Resources Corp., Trident GP Merger Sub LLC, Atlas Energy, L.P. and Atlas Energy GP, LLC, dated October 13, 2014. The schedules to the Agreement and Plan of Merger have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request⁽³⁹⁾

2.2		Agreement and Plan of Merger, by and among Targa Resources Corp., Targa Resources Partners LP, Targa Resources GP LLC, Trident MLP Merger Sub LLC, Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Atlas Pipeline Partners GP, LLC, dated October 13, 2014. The schedules to the Agreement and Plan of Merger have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request⁽³⁹⁾

2.3		Letter Agreement, by and between Atlas Energy, L.P. and Atlas Pipeline Partners, L.P., dated October 13, 2014⁽³⁹⁾

3.1(a)		Certificate of Limited Partnership⁽¹⁾

3.1(b)		Amendment to Certificate of Limited Partnership⁽¹²⁾

3.2(a)		Second Amended and Restated Agreement of Limited Partnership⁽²⁾

3.2(b)		Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership⁽³⁾

3.2(c)		Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership⁽⁴⁾

3.2(d)		Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership⁽⁵⁾

3.2(e)		Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership⁽⁶⁾

3.2(f)		Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership⁽⁸⁾

3.2(g)		Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership⁽⁹⁾

3.2(h)		Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership⁽¹⁴⁾

3.2(i)		Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership⁽¹⁵⁾

3.2(j)		Amendment No. 9 to Second Amended and Restated Agreement of Limited Partnership⁽¹²⁾

3.2(k)		Amendment No. 10 to Second Amended and Restated Agreement of Limited Partnership⁽³⁰⁾

3.2(j)		Amendment No. 11 to Second Amended and Restated Agreement of Limited Partnership⁽³⁶⁾

4.1		Common unit certificate (attached as Exhibit A to the Second Amended and Restated Agreement of Limited Partnership)⁽²⁾

4.2(a)		6 5/8% Senior Notes Indenture dated September 28, 2012⁽²⁶⁾

4.2(b)		Supplemental Indenture dated as of December 20, 2012⁽³²⁾

4.3(a)		5 7/8% Senior Notes Indenture dated as of February 11, 2013⁽¹⁰⁾

4.3(b)		Supplemental Indenture dated as of February 11, 2013⁽¹⁰⁾

4.4		4 3/4% Senior Notes Indenture dated May 10, 2013⁽⁷⁾

4.5(a)		Certificate of Designation of Class D Convertible Preferred Units⁽³⁰⁾

4.5(b)		Certificate of Amendment to Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional, and Other Special Rights and Qualifications, Limitations and Restrictions Thereof, dated as of March 12, 2014⁽³⁶⁾

4.6		Registration Rights Agreement, dated May 16, 2012, between Atlas Pipeline Partners, L.P., Wells Fargo Bank, National Association and the lenders named in the Credit Agreement dated May 16, 2012 by and among Atlas Energy, L.P. and the lenders named therein⁽²⁵⁾


Exhibit No.		Description

4.7		Certificate of Designation of the Powers, Preferences and Relative, Participating, Optional, and Other Special Rights of Preferred Units and Qualifications, Limitations and Restrictions Thereof, dated as of March 17, 2014⁽³⁶⁾

10.1(a)		Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Operating Partnership, L.P.⁽¹⁾

10.1(b)		Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Operating Partnership, L.P.⁽¹⁴⁾

10.1(c)		Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Operating Partnership, L.P.⁽¹²⁾

10.1(d)		Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Operating Partnership, L.P.⁽³⁶⁾

10.2		Second Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Partners GP, LLC.⁽¹⁹⁾

10.3(a)		Amended and Restated Credit Agreement dated July 27, 2007, amended and restated as of December 22, 2010, by and among Atlas Pipeline Partners, L.P., Wells Fargo Bank, National Association and the several guarantors and lenders hereto⁽¹⁶⁾

10.3(b)		Amendment No. 1 to the Amended and Restated Credit Agreement dated as of April 19, 2011⁽²²⁾

10.3(c)		Incremental Joinder Agreement to the Amended and Restated Credit Agreement dated as of July 8, 2011⁽²³⁾

10.3(d)		Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of May 31, 2012⁽²⁷⁾

10.3(e)		Amendment No. 3 to the Amended and Restated Credit Agreement⁽³¹⁾

10.3(f)		Amendment No. 4 to the Amended and Restated Credit Agreement⁽³⁴⁾

10.3(g)		Amendment No. 5 to the Amended and Restated Credit Agreement⁽⁴⁰⁾

10.3(h)		Amendment No. 6 to the Amended and Restated Credit Agreement⁽³⁷⁾

10.3(i)		Second Amended and Restated Credit Agreement, dated as of August 28, 2014⁽³³⁾

10.4		Long-Term Incentive Plan⁽³⁵⁾

10.5		Amended and Restated 2010 Long-Term Incentive Plan⁽²²⁾

10.6		Form of Grant of Phantom Units in Exchange for Bonus Units⁽¹⁷⁾

10.7		Form of 2010 Long-Term Incentive Plan Phantom Unit Grant Letter⁽¹⁸⁾

10.8		Form of 2004 Long-Term Incentive Plan Phantom Unit Grant Letter⁽²⁸⁾

10.9		Form of Grant of Phantom Units to Non-Employee Managers⁽¹¹⁾

10.10		Letter Agreement, by and between Atlas Pipeline Partners, L.P. and Atlas Pipeline Holdings, L.P., dated November 8, 2010⁽¹³⁾

10.11		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Edward E. Cohen, dated as of November 8, 2010⁽²⁰⁾

10.12		Non-Competition and Non-Solicitation Agreement, by and between Chevron Corporation and Jonathan Z. Cohen, dated as of November 8, 2010⁽²⁰⁾

10.13		Employment Agreement between Atlas Energy, L.P. and Edward E. Cohen dated as of May 13, 2011⁽²⁴⁾

10.14		Employment Agreement between Atlas Energy, L.P. and Jonathan Z. Cohen dated as of May 13, 2011⁽²⁴⁾

10.15		Employment Agreement between Atlas Energy, L.P. and Eugene N. Dubay dated as of November 4, 2011⁽²¹⁾

10.16		Employment Agreement between Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Patrick J. McDonie dated as of July 3, 2012⁽²⁵⁾

10.17		Registration Rights Agreement, dated February 11, 2013, by and among Atlas Pipeline Partners, L.P., Atlas Pipeline Finance Corporation, the subsidiaries named therein, and the initial purchasers listed therein ⁽¹⁰⁾


Exhibit No.		Description

10.18		Registration Rights Agreement, dated May 7, 2013 by and among Atlas Pipeline Partners, L.P. and the purchasers named therein⁽³⁰⁾

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges

31.1		Rule 13a-14(a)/15d-14(a) Certification

31.2		Rule 13a-14(a)/15d-14(a) Certification

32.1		Section 1350 Certification

32.2		Section 1350 Certification

99.1		Form of Voting and Support Agreement, by and between Atlas Energy, L.P. and the individual named on the signature page thereto⁽³⁹⁾

99.2		Form of Voting and Support Agreement, by and between Targa Resources Corp. and the individual named on the signature page thereto⁽³⁹⁾

99.3		Form of Voting and Support Agreement, by and between Targa Resources Partners LP and the individual named on the signature page thereto⁽³⁹⁾

99.4		Confidentiality, Non-Competition and Non-Solicitation Agreement, by and among Targa Resources Corp., Targa Resources Partners LP and Edward E. Cohen, dated October 13, 2014⁽³⁹⁾

99.5		Confidentiality, Non-Competition and Non-Solicitation Agreement, by and among Targa Resources Corp., Targa Resources Partners LP and Jonathan Z. Cohen, dated October 13, 2014⁽³⁹⁾

99.5		Confidentiality, Non-Competition and Non-Solicitation Agreement, by and among Targa Resources Corp., Targa Resources Partners LP and Eugene N. Dubay, dated October 13, 2014⁽³⁹⁾

101.INS		XBRL Instance Document⁽⁴¹⁾

101.SCH		XBRL Schema Document⁽⁴¹⁾

101.CAL		XBRL Calculation Linkbase Document⁽⁴¹⁾

101.LAB		XBRL Label Linkbase Document⁽⁴¹⁾

101.PRE		XBRL Presentation Linkbase Document⁽⁴¹⁾

101.DEF		XBRL Definition Linkbase Document⁽⁴¹⁾

(1)	Filed previously as an exhibit to registration statement on Form S-1 (Registration No. 333-85193).

(2)	Previously filed as an exhibit to registration statement on Form S-3 on April 2, 2004.

(3)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2007.

(4)	Previously filed as an exhibit to current report on Form 8-K on July 30, 2007.

(5)	Previously filed as an exhibit to current report on Form 8-K on January 8, 2008.

(6)	Previously filed as an exhibit to current report on Form 8-K on June 16, 2008.

(7)	Previously filed as an exhibit to current report on Form 8-K on May 13, 2013.

(8)	Previously filed as an exhibit to current report on Form 8-K on January 6, 2009.

(9)	Previously filed as an exhibit to current report on Form 8-K on April 3, 2009.

(10)	Previously filed as an exhibit to current report on Form 8-K filed on February 12, 2013.

(11)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2010.

(12)	Previously filed as an exhibit to current report on Form 8-K on December 13, 2011.

(13)	Previously filed as an exhibit to current report on Form 8-K on November 12, 2010.

(14)	Previously filed as an exhibit to current report on Form 8-K on April 2, 2010.

(15)	Previously filed as an exhibit to current report on Form 8-K on July 7, 2010.

(16)	Previously filed as an exhibit to current report on Form 8-K on December 23, 2010.

(17)	Previously filed as an exhibit to current report on Form 8-K filed on June 17, 2010.

(18)	Previously filed as an exhibit to current report on Form 8-K filed on June 23, 2010.

(19)	Previously filed as an exhibit to current report on Form 8-K on October 29, 2013.

(20)	Previously filed as an exhibit to Atlas Energy, Inc.’s current report on Form 8-K filed on November 12, 2010.

(21)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2011.

(22)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(23)	Previously filed as an exhibit to current report on Form 8-K filed on July 11, 2011.

(24)	Previously filed as an exhibit to Atlas Energy, L.P.’s quarterly report on Form 10-Q for the quarter ended March 31, 2011.

(25)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2012.

(26)	Previously filed as an exhibit to current report on Form 8-K filed on January 30, 2013.

(27)	Previously filed as an exhibit to current report on Form 8-K filed on May 31, 2012.

(28)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended September 30, 2012.

(29)	Previously filed as an exhibit to current report on Form 8-K filed on November 6, 2012.

(30)	Previously filed as an exhibit to current report on Form 8-K filed on May 8, 2013.

(31)	Previously filed as an exhibit to current report on Form 8-K filed on December 13, 2012.

(32)	Previously filed as an exhibit to current report on Form 8-K filed on December 26, 2012.

(33)	Previously filed as an exhibit to current report on Form 8-K filed on August 29, 2014.

(34)	Previously filed as an exhibit to current report on Form 8-K filed on April 23, 2013.

(35)	Previously filed as an exhibit to annual report on Form 10-K filed for the year ended December 31, 2009.

(36)	Previously filed as an exhibit to current report on Form 8-K filed on March 17, 2014.

(37)	Previously filed as an exhibit to current report on Form 8-K filed on March 11, 2014.

(38)	Previously filed as an exhibit to current report on Form 8-K filed on May 13, 2014.

(39)	Previously filed as an exhibit to current report on Form 8-K filed on October 16, 2014.

(40)	Previously filed as an exhibit to quarterly report on Form 10-Q for the quarter ended June 30, 2014.

(41)	Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

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.


	ATLAS PIPELINE PARTNERS, L.P.
	By:	Atlas Pipeline Partners GP, LLC, its General Partner

Date: November 6, 2014	By:	/s/ EUGENE N. DUBAY
		Eugene N. Dubay
		Chief Executive Officer, President and Managing Board Member of the General Partner

Date: November 6, 2014	By:	/s/ ROBERT W. KARLOVICH, III
		Robert W. Karlovich, III
		Chief Financial Officer and Chief Accounting Officer of the General Partner

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