Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Pipeline Partners, L.P.

We have audited the accompanying consolidated balance sheets of Atlas Pipeline Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Pipeline Partners, L.P. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2015 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 27, 2015

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

 

		December 31, 2014				December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents		$	8,103			$	4,914
Accounts receivable			240,576				219,297
Current portion of derivative assets			88,007				174
Prepaid expenses and other			17,368				17,393
Total current assets			354,054				241,778
Property, plant and equipment, net			3,249,973				2,724,192
Goodwill			365,763				368,572
Intangible assets, net			596,261				696,271
Equity method investment in joint ventures			177,212				248,301
Long-term portion of derivative assets			37,398				2,270
Other assets, net			44,072				46,461
Total assets		$	4,824,733			$	4,327,845
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt		$	224			$	524
Accounts payable – affiliates			4,438				2,912
Accounts payable			87,076				79,051
Accrued liabilities			49,729				47,449
Accrued interest payable			26,924				26,737
Current portion of derivative liabilities			—				11,244
Accrued producer liabilities			161,208				152,309
Total current liabilities			329,599				320,226
Long-term portion of derivative liabilities			—				320
Long-term debt, less current portion			1,938,886				1,706,786
Deferred income taxes, net			30,914				33,290
Other long-term liabilities			6,867				7,318
Commitments and contingencies
Equity:
Class D convertible preferred limited partners’ interests			538,814				450,749
Class E preferred limited partners’ interests			121,852				—
Common limited partners’ interests			1,731,764				1,703,778
General Partner’s interest			47,775				46,118
Total partners’ capital			2,440,205				2,200,645
Non-controlling interest			78,262				59,260
Total equity			2,518,467				2,259,905
Total liabilities and equity		$	4,824,733			$	4,327,845

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

 

		Years Ended December 31,
		2014				2013				2012
Revenue:
Natural gas and liquids sales		$	2,621,428			$	1,959,144			$	1,137,261
Transportation, processing and other fees – third parties			200,787				164,874				66,287
Transportation, processing and other fees – affiliates			286				303				435
Derivative gain (loss), net			131,064				(28,764	)			31,940
Other income, net			21,555				11,292				10,097
Total revenues			2,975,120				2,106,849				1,246,020
Costs and expenses:
Natural gas and liquids cost of sales			2,291,914				1,690,382				927,946
Operating expenses			113,606				94,527				62,098
General and administrative			68,893				55,856				43,406
Compensation reimbursement – affiliates			5,050				5,000				3,800
Other expenses			6,073				20,005				15,069
Depreciation and amortization			202,543				168,617				90,029
Interest			93,147				89,637				41,760
Total costs and expenses			2,781,226				2,124,024				1,184,108
Equity income (loss) in joint ventures			(14,007	)			(4,736	)			6,323
Gain (loss) on asset dispositions			47,381				(1,519	)			—
Goodwill impairment loss			—				(43,866	)			—
Loss on early extinguishment of debt			—				(26,601	)			—
Income (loss) before tax			227,268				(93,897	)			68,235
Income tax expense (benefit)			(2,376	)			(2,260	)			176
Net income (loss)			229,644				(91,637	)			68,059
Income attributable to non-controlling interests			(13,164	)			(6,975	)			(6,010	)
Preferred unit imputed dividend effect			(45,513	)			(29,485	)			—
Preferred unit dividends in kind			(42,552	)			(23,583	)			—
Preferred unit dividends			(8,233	)			—				—
Net income (loss) attributable to common limited partners and the General Partner		$	120,182			$	(151,680	)		$	62,049
Allocation of net income (loss) attributable to:
Common limited partner interest		$	93,684				(165,923	)			52,391
General Partner interest			26,498				14,243				9,658
		$	120,182			$	(151,680	)		$	62,049
Net income (loss) attributable to common limited partners per unit:
Basic		$	0.95			$	(2.23	)		$	0.95
Weighted average common limited partner units (basic)			82,257				74,364				54,326
Diluted		$	0.95			$	(2.23	)		$	0.95
Weighted average common limited partner units (diluted)			98,384				74,364				55,138

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

 

		Years Ended December 31,
		2014				2013				2012
Net income (loss)		$	229,644			$	(91,637	)		$	68,059
Other comprehensive income:
Adjustment for realized losses on cash flow hedges reclassified to net income (loss)			—				—				4,390
Total other comprehensive income			—				—				4,390
Comprehensive income (loss)		$	229,644			$	(91,637	)		$	72,449
Comprehensive income attributable to non-controlling interests		$	13,164			$	6,975			$	6,010
Preferred unit imputed dividend effect			45,513				29,485				—
Preferred unit dividends in kind			42,552				23,583				—
Preferred unit dividends			8,233				—				—
Comprehensive income (loss) attributable to common limited partners and the General Partner			120,182				(151,680	)			66,439
Comprehensive income (loss)		$	229,644			$	(91,637	)		$	72,449

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands, except unit data)

 

		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				Accumulated Other Comprehensive Loss				Non-controlling Interest				Total
Balance at January 1, 2012			—				—				53,617,183			$	—			$	—			$	1,245,163			$	23,856			$	(4,390	)		$	(28,401	)		$	1,236,228
Issuance of units and General Partner capital contribution			—				—				10,782,462				—				—				321,491				6,865				—				—				328,356
Equity compensation under incentive plans			—				—				180,417				—				—				11,549				—				—				—				11,549
Purchase and retirement of treasury units			—				—				(24,052	)			—				—				(695	)			—				—				—				(695	)
Distributions paid			—				—				—				—				—				(122,223	)			(8,878	)			—				—				(131,101	)
Contributions from non-controlling interests			—				—				—				—				—				—				—				—				182				182
Other comprehensive income			—				—				—				—				—				—				—				4,390				—				4,390
Increase in non-controlling interest related to business combination			—				—				—				—				—				—				—				—				89,440				89,440
Net income			—				—				—				—				—				52,391				9,658				—				6,010				68,059
Balance at December 31, 2012			—				—				64,556,010			$	—			$	—			$	1,507,676			$	31,501			$	—			$	67,231			$	1,606,408

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY CONTINUED

(in thousands, except unit data)

 

		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				Accumulated Other Comprehensive Loss				Non- controlling Interest				Total
Balance at January 1, 2013			—				—				64,556,010			$	—			$	—			$	1,507,676			$	31,501			$	—			$	67,231			$	1,606,408
Issuance of units and General Partner capital contribution			13,445,383				—				15,740,679				397,681				—				526,263				19,359				—				—				943,303
Equity compensation under incentive plans			—				—				288,459				—				—				19,143				—				—				—				19,143
Distributions paid in kind units			378,486				—				—				—				—				—				—				—				—				—
Distributions paid			—				—				—				—				—				(183,381	)			(18,985	)			—				—				(202,366	)
Contributions from non-controlling interests			—				—				—				—				—				—				—				—				17,021				17,021
Distributions to non-controlling interests			—				—				—				—				—				—				—				—				(1,432	)			(1,432	)
Decrease in non-controlling interest related to business combination			—				—				—				—				—				—				—				—				(30,535	)			(30,535	)
Net income (loss)			—				—				—				53,068				—				(165,923	)			14,243				—				6,975				(91,637	)
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				121,583				2,523				—				—				246,364
Equity compensation under incentive plans			—				—				459,232				—				—				25,005				—				—				—				25,005
Purchase and retirement of treasury units			—				—				(66,321	)			—				—				(2,210	)							—				—				(2,210	)
Distributions paid in kind units			1,195,581				—				—				—				—				—				—				—				—				—
Distributions paid			—				—				—				—				(6,030	)			(210,076	)			(27,364	)			—				—				(243,470	)
Distributions payable			—				—				—				—				(2,609	)			—				—				—				—				(2,609	)
Contributions from non-controlling interests			—				—				—				—				—				—				—				—				11,720				11,720
Distributions to non-controlling interests			—				—				—				—				—				—				—				—				(5,882	)			(5,882	)
Net income			—				—				—				88,065				8,233				93,684				26,498				—				13,164				229,644
Balance at December 31, 2014			15,019,450				5,060,000				84,536,064			$	538,814			$	121,852			$	1,731,764			$	47,775			$	—			$	78,262			$	2,518,467

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

		Years Ended December 31,
		2014				2013				2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	229,644			$	(91,637	)		$	68,059
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization			202,543				168,617				90,029
Loss on goodwill impairment			—				43,866				—
Equity loss (income) in joint ventures			14,007				4,736				(6,323	)
Distributions received from equity method joint ventures			5,264				7,400				7,200
Non-cash compensation expense			25,116				19,344				11,635
Amortization of deferred finance costs			7,082				6,965				4,672
Loss on early extinguishment of debt			—				26,601				—
Loss (gain) on asset dispositions			(47,381	)			1,519				—
Income tax expense (benefit)			(2,376	)			(2,260	)			176
Change in operating assets and liabilities, net of business combinations:
Accounts receivable, prepaid expenses and other			(22,334	)			(73,307	)			(31,417	)
Accounts payable and accrued liabilities			13,963				61,449				37,952
Accounts payable and accounts receivable – affiliates			1,526				(2,588	)			2,825
Derivative accounts payable and receivable			(134,525	)			40,139				(10,170	)
Net cash provided by operating activities			292,529				210,844				174,638
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(647,747	)			(450,560	)			(373,533	)
Cash paid for business combinations, net of cash received			—				(975,887	)			(633,610	)
Net proceeds from asset disposition			130,966				—				—
Capital contributions to joint ventures			(8,061	)			(13,366	)			—
Other			503				(3,270	)			502
Net cash used in investing activities		$	(524,339	)		$	(1,443,083	)		$	(1,006,641	)

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS CONTINUED

(in thousands)

 

		Years Ended December 31,
		2014				2013				2012
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		$	1,271,000			$	1,267,000			$	1,170,500
Repayments under credit facility			(1,038,000	)			(1,408,000	)			(1,019,500	)
Net proceeds from issuance of long-term debt			—				1,028,092				495,374
Repayment of long-term debt			—				(365,822	)			—
Payment of premium on retirement of debt			—				(25,581	)			—
Payment of deferred financing costs			(3,323	)			(929	)			(4,542	)
Payment for acquisition-based contingent consideration			—				(6,000	)			—
Principal payments on capital lease			(525	)			(10,750	)			(2,523	)
Net proceeds from issuance of common and preferred limited partner units			243,841				923,944				321,491
Purchase and retirement of treasury units			(2,210	)			—				(695	)
General Partner capital contributions			2,523				19,359				6,865
Contributions from non-controlling interest holders			11,720				17,021				182
Distributions to non-controlling interest holders			(5,882	)			(1,432	)			—
Distributions paid to common limited partners, preferred limited partners and the General Partner			(243,470	)			(202,366	)			(131,101	)
Other			(675	)			(781	)			(818	)
Net cash provided by financing activities			234,999				1,233,755				835,233
Net change in cash and cash equivalents			3,189				1,516				3,230
Cash and cash equivalents, beginning of period			4,914				3,398				168
Cash and cash equivalents, end of period		$	8,103			$	4,914			$	3,398

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. 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 December 31, 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 December 31, 2014, the Partnership had 84,536,064 common units outstanding, including 1,641,026 common units held by the General Partner and 4,113,227 common units held by ATLS; 15,019,450 Class D convertible preferred units (“Class D Preferred Units”) outstanding (see Note 6); and 5,060,000 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) outstanding (see Note 6).

Certain amounts have been reclassified in prior period consolidated financial statements to conform to the current year presentation.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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.

The Partnership’s consolidated financial statements include its 95% interest in joint ventures, which individually own a 100% interest in the WestOK natural gas gathering system and processing plants and a 72.8% undivided interest in the WestTX natural gas gathering system and processing plants. These joint ventures have a $1.9 billion note receivable from the holder of the non-controlling interest in the joint ventures, which is reflected within non-controlling interests on the Partnership’s consolidated balance sheets.

The Partnership’s consolidated financial statements also include its 60% interest in Centrahoma Processing LLC (“Centrahoma”). The remaining 40% ownership interest is held by MarkWest Oklahoma Gas Company LLC (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE).

The Partnership consolidates 100% of these joint ventures and reflects the non-controlling interest in the joint ventures on its statements of operations. The Partnership also reflects the non-controlling interest in the net assets of the joint venture as a component of equity on its consolidated balance sheets.

The WestTX joint venture has a 72.8% undivided joint interest in the WestTX system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”). Due to the ownership of the WestTX system being in the form of an undivided interest, the WestTX joint venture proportionally consolidates its 72.8% ownership interest in the assets and liabilities and operating results of the WestTX system.

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)” and, for the Partnership, only include the effective portion of changes in the

 

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fair value of unsettled derivative contracts, which were previously accounted for as cash flow hedges (see Note 11). These contracts were wholly-owned by the Partnership and the related gains and losses were not shared with the non-controlling interests. The Partnership does not have any other types of transactions that would be included within other comprehensive income (loss). During the year ended December 31, 2012, the Partnership reclassified $4.4 million from other comprehensive income to natural gas and liquids sales within the Partnership’s consolidated statements of operations. During the years ended December 31, 2014 and 2013, no amounts were reclassified from other comprehensive income and the Partnership had no amounts outstanding within accumulated other comprehensive income.

Equity Method Investments

The Partnership’s consolidated financial statements include its previous interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”), which was sold in May 2014 (see Note 5), and its interests in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), and T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen”) (the “T2 Joint Ventures”), which were acquired as part of the acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) (the “TEAK Acquisition”) (see Notes 4 and 5).

The Partnership accounts for its investments in these joint ventures under the equity method of accounting. Under this method, the Partnership records its proportionate share of the joint ventures’ net income (loss) as equity income (loss) on its consolidated statements of operations. Investments in excess of the underlying net assets of equity method investees identifiable to property, plant and equipment or finite lived intangible assets are amortized over the useful life of the related assets and recorded as a reduction to equity investment on the Partnership’s consolidated balance sheet with an offsetting reduction to equity income on the Partnership’s consolidated statements of operations. Excess investment representing equity method goodwill is not subject to amortization and is accounted for as a component of the investment. No goodwill was recorded on the acquisition of WTLPG or the T2 Joint Ventures. Equity method investments are subject to impairment evaluation as necessary when events and circumstances indicate the carrying value of an equity investment may be less than its fair value. The Partnership noted no indicators of impairment for its equity method investments, and thus no impairment charges were recognized for the years ended December 31, 2014, 2013 and 2012.

Use of Estimates

The preparation of the Partnership’s consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depreciation and amortization, asset impairment, the fair value of derivative instruments, the probability of forecasted transactions, the allocation of purchase price to the fair value of assets acquired and other items. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results were recorded using estimated volumes and commodity market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management of the Partnership believes the operating results presented represent actual results in all material respects (see “–Revenue Recognition” accounting policy for further description).

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 December 31, 2014 and 2013, the Partnership reclassified the balances related to book overdrafts of $23.9 million and $28.8 million, respectively, from cash and cash equivalents to accounts payable on its consolidated balance sheets.

 

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Receivables

In evaluating the realizability of its accounts receivable, the Partnership performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Partnership’s review of its customers’ credit information. The Partnership extends credit on an unsecured basis to many of its customers. At December 31, 2014 and 2013, there were no material uncollectible accounts receivable.

NGL Linefill

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 current 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 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 year ended December 31, 2014, the contracts related to this linefill on the WestTX and SouthTX systems were revised and the settlement and valuation was converted from a FIFO method to a fair value method. The Partnership’s NGL linefill is included within prepaid expenses and other on its consolidated balance sheets. See Note 12 for more information regarding the Partnership’s NGL linefill.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs which generally do not extend the useful life of an asset for two or more years through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two or more years through the replacement of critical components are capitalized. The Partnership capitalizes interest on borrowed funds related to capital projects for periods during which activities are in progress to bring these projects to their intended use. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. The Partnership follows the composite method of depreciation and has determined the composite groups to be the major asset classes of its gathering, processing and treating systems. Under the composite depreciation method, any gain or loss upon disposition or retirement of pipeline, gas gathering, processing and treating components, is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Partnership’s results of operations.

Leased property and equipment meeting capital lease criteria are capitalized based on the minimum payments required under the lease and are included within property, plant and equipment on the Partnership’s consolidated balance sheets (see Note 7). Obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on the Partnership’s consolidated balance sheets (see Note 14). Amortization is calculated on a straight-line method based upon the estimated useful lives of the assets.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or circumstances indicate the carrying amount of an asset may not be recoverable. If it is determined an asset’s estimated future undiscounted cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value, if such carrying amount exceeds the fair value. The fair value measurement of a long-lived asset is based on inputs that are not observable in the market and therefore represent Level 3 inputs (see “–Fair Value of Financial Instruments”). No impairment charges were recognized for the years ended December 31, 2014, 2013 and 2012.

Asset Retirement Obligation

The Partnership performs ongoing analysis of asset removal and site restoration costs that the Partnership may be required to perform under law or contract once an asset has been permanently taken out of service. The Partnership has property, plant and equipment at locations owned by the Partnership and at sites leased or under

 

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right of way agreements. The Partnership is under no contractual obligation to remove the assets at locations it owns. In evaluating its asset retirement obligation, the Partnership reviews its lease agreements, right of way agreements, easements and permits to determine which agreements, if any, require an asset removal and restoration obligation. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted-risk-free interest rates. However, the Partnership was not able to reasonably measure the fair value of the asset retirement obligation as of December 31, 2014 or 2013 because the settlement dates were indeterminable. Any cost incurred in the future to remove assets and restore sites will be expensed as incurred.

Goodwill

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). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available, and segment management regularly reviews the operating results of that component. The Partnership evaluates goodwill for impairment annually, on December 31st for all reporting units, except SouthTX, which is evaluated on April 30th. The Partnership also evaluates goodwill for impairment whenever events or changes in circumstances indicate it is more likely than not the fair value of a reporting unit is less than its carrying amount. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. If a two-step process goodwill impairment test is required, the first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as a reduction of goodwill on the Partnership’s consolidated balance sheets and a goodwill impairment loss on the Partnership’s consolidated statements of operations (see Note 8).

Intangible Assets

The Partnership amortizes intangible assets with finite useful lives over their estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At a minimum, the Partnership will assess the useful lives of all intangible assets on an annual basis, on December 31, to determine if adjustments are required. The estimated useful life for the Partnership’s customer contract intangible assets is based upon the approximate average length of customer contracts in existence and expected renewals at the date of acquisition. The estimated useful life for the Partnership’s customer relationship intangible assets is based upon the estimated average length of non-contracted customer relationships in existence at the date of acquisition, adjusted for management’s estimate of whether these individual relationships will continue in excess or less than the average length (see Note 8).

Derivative Instruments

The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates. The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty, measured at fair value (see “–Fair Value of Financial Instruments”). The Partnership no longer applies hedge accounting for its derivatives; as such, changes in fair value of these derivatives are recognized immediately within derivative gain (loss), net in its consolidated statements of operations. Prior to discontinuance of hedge accounting, the change in the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive loss within equity on the Partnership’s consolidated balance sheets. Amounts in accumulated other comprehensive loss were reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. The Partnership has reclassified all earnings out of accumulated other comprehensive loss, within equity on the Partnership’s consolidated balance sheets and had no amounts in accumulated other comprehensive loss as of December 31, 2014 and 2013.

 

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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.

The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 12). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership has a financial risk management committee (the “Financial Risk Management Committee”), which sets the policies, procedures and valuation methods utilized by the Partnership to value its derivative contracts. The Financial Risk Management Committee members include, among others, the Chief Executive Officer, the Chief Financial Officer and the Vice Chairman of the managing board of the General Partner. The Financial Risk Management Committee receives daily reports and meets on a weekly basis to review the risk management portfolio and changes in the fair value in order to determine appropriate actions.

Income Taxes

The Partnership is generally not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements as of December 31, 2014 or 2013.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2014 except for an ongoing examination by the Texas Comptroller of Public Accounts related to the Partnership’s Texas Franchise Tax for franchise report years 2008 through 2011.

APL Arkoma, Inc. is subject to federal and state income tax. The Partnership’s corporate subsidiary accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is

 

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assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value. The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level. See Note 10 for discussion of the Partnership’s federal and state income tax expense (benefits) of its taxable subsidiary as well as the Partnership’s net deferred income tax assets (liabilities).

Unit-Based Compensation

All unit-based payments to employees are recognized in the financial statements based on their fair values on the date of grant and are classified as equity on the Partnership’s consolidated balance sheets. Unit-based awards to non-employees, which have a cash option, are recognized in the financial statements based on their current fair value and are classified as liabilities on the Partnership’s consolidated balance sheets. Compensation expense associated with unit-based payments is recognized within general and administrative expenses on the Partnership’s statements of operations from the date of the grant through the date of vesting, amortized on a straight-line method. Generally, no expense is recorded for awards that do not vest due to forfeiture. See Note 17 for more information regarding the Partnership’s unit-based compensation.

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 6), 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 17), 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 6), 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.

 

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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 6), 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):

 

		Years Ended December 31,
		2014				2013				2012
Net income (loss)		$	229,644			$	(91,637	)		$	68,059
Income attributable to non-controlling interests			(13,164	)			(6,975	)			(6,010	)
Preferred unit imputed dividend effect			(45,513	)			(29,485	)			—
Preferred unit dividends in kind			(42,552	)			(23,583	)			—
Preferred unit dividends			(8,233	)			—				—
Net income (loss) attributable to common limited partners and the General Partner			120,182				(151,680	)			62,049
General Partner’s cash incentive distributions			24,576				17,646				8,583
General Partner’s ownership interest			1,922				(3,403	)			1,075
Net income attributable to the General Partner’s ownership interests			26,498				14,243				9,658
Net income (loss) attributable to common limited partners			93,684				(165,923	)			52,391
Net income attributable to participating securities – phantom units(1)			1,630				—				772
Net income attributable to participating securities – Class D Preferred Units(2)			13,932				—				—
Net income attributable to participating securities			15,562				—				772
Net income (loss) utilized in the calculation of net income (loss) attributable to common limited partners per unit		$	78,122			$	(165,923	)		$	51,619

 

(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 year ended December 31, 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 1,240,000 weighted average phantom units 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 year ended December 31, 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 9,110,000 weighted average Class D Preferred Units 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.

 

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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):

 

		Years Ended December 31,
		2014				2013				2012
Weighted average number of common limited partner units – basic			82,257				74,364				54,326
Add effect of dilutive securities – phantom units(1)			1,713				—				812
Add effect of convertible preferred limited partner units(2)			14,414				—				—
Weighted average common limited partner units – diluted			98,384				74,364				55,138

 

(1)	For the year ended December 31, 2013, approximately 1,240,000 weighted average phantom units 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 year ended December 31, 2013, approximately 9,110,000 weighted average Class D Preferred Units 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.

Environmental Matters

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures, including legislation related to greenhouse gas emissions. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At this time, the Partnership is unable to assess the timing and/or effect of potential liabilities related to greenhouse gas emissions or other environmental issues. The Partnership maintains insurance, which may cover, in whole or in part, certain environmental expenditures. At December 31, 2014 and 2013, the Partnership had no material environmental matters requiring specific disclosure or requiring the recognition of a liability.

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 5), 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, Ardmore 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 southern 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.

 

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Revenue Recognition

The Partnership’s revenue primarily consists of the sale of natural gas and NGLs along with the fees earned from its gathering, processing and treating operations. Under certain agreements, the Partnership purchases natural gas from producers and moves it into receipt points on its pipeline systems, and then sells the natural gas, and produced NGLs and condensate, if any, off delivery points on its systems. Under other agreements, the Partnership gathers natural gas across its systems, from receipt to delivery point, without taking title to the natural gas. Revenue associated with the physical sale of natural gas and NGLs is recognized upon physical delivery. Revenue related to fees for providing natural gas gathering, processing and treating services is recognized based on throughput volumes during the period, with throughput volumes generally measured at the wellhead.

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 December 31, 2014 and 2013 of $175.3 million and $134.9 million, respectively, which are included in accounts receivable within its consolidated balance sheets.

Cost of Sales and Accrued Producer Liabilities

The Partnership’s cost of sales primarily consists of sales proceeds required to be remitted to producers and shippers under POP contracts and natural gas purchases made in order to satisfy obligations under Keep-Whole contracts. Accrued producer liabilities on the Partnership’s consolidated balance sheets represent accrued purchase commitments payable to producers related to gas gathered and processed through its system under its POP and Keep-Whole contracts. The following describes how cost of sales are recognized for POP contracts and Keep-Whole contracts:

POP Contracts. These contracts provide for the Partnership to retain a negotiated percentage of the sale proceeds from residue gas and NGLs it gathers and processes, with the remainder being remitted to the producer. In this contract-type, the Partnership and the producer are directly dependent on the volume of the commodity and its value; the Partnership effectively owns a percentage of the commodity and revenues are directly correlated to its market value. The Partnership’s cost of sales are equal to the proceeds required to be remitted to the producers in connection with natural gas and liquids sold during the period.

Keep-Whole Contracts. These contracts require the Partnership, as the processor and gatherer, to gather or purchase raw natural gas at current market rates per MMBTU. The volume and energy content of gas gathered or purchased is based on the measurement at an agreed upon location (generally at the wellhead). The BTU quantity of gas redelivered or sold at the tailgate of the Partnership’s processing facility may be lower than the BTU quantity purchased at the wellhead primarily due to the NGLs extracted from the natural gas when processed through a plant. The Partnership must make up or “keep the producer whole” for this loss in BTU quantity. To offset the make-up obligation, the Partnership retains the NGLs, which are extracted, and sells them for its own account. The Partnership recognizes the purchases of natural gas during the period to keep producers whole as costs of sales under Keep-Whole contracts. During 2014, the Partnership renegotiated most of its Keep-Whole contracts and converted them into POP contracts. As a result, the Partnership does not expect Keep-Whole contracts to have any material impact to its cost of sales going forward.

Fee-based or POP contracts sometimes include fixed recovery terms, which mean products returned to the producer are calculated using an agreed NGL recovery factor, regardless of the volumes of NGLs actually recovered through processing.

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

 

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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 Standard Updates

On February 18, 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which is intended to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations, and securitization structures. The amendment simplifies the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The Partnership does not expect the ASU to impact how it currently consolidates its legal entities. The amendments in this ASU will be effective for periods beginning after December 15, 2015, for public companies. The Partnership plans to apply the amendment to annual and interim periods beginning on January 1, 2016.

In November 2014, the FASB issued ASU 2014-17, Business Combinations (Topic 805): Pushdown Accounting (a consensus of the FASB Emerging Issues Task Force). The amendments in this ASU apply to the separate financial statements of an acquired entity and its subsidiaries upon the occurrence of an event in which an acquirer obtains control of the acquired entity. The amendments provide an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. An acquired entity may elect the option to apply pushdown accounting in the reporting period in which the change-in-control event occurs, or in a subsequent reporting period to the acquired entity’s most recent change-in-control event. The amendments in this ASU are effective on November 18, 2014. After the effective date, the Partnership can make an election to apply the guidance to future change-in-control events or to its most recent change-in-control event. The Partnership will analyze its option to apply pushdown accounting upon a change-in-control event, but does not expect the new standard to have a material impact 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.

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, however, the Partnership does not expect the new standard to have a material impact on the results of operations.

 

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NOTE 3 – TARGA RESOURCES PARTNERS LP MERGER

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. Pursuant to the terms and conditions of the Merger Agreement, the Partnership exercised its right under the certificate of designation of the Class D Preferred Units to convert all outstanding Class D Preferred Units into common units, which occurred on January 22, 2015 (see Note 6 –Class D Preferred Units). Additionally, on January 27, 2015, the Partnership announced its intention to exercise its right under the certificate of designation of the Class E Preferred Units to redeem the Class E Preferred Units. TRP has agreed to deposit the funds for redemption with the paying agent (see Note 6 –Class E Preferred Units).

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”). Upon completion of the ATLS Merger, holders of ATLS common units will have the right to receive (i) 0.1809 TRC shares of common stock, par value $0.001 per share, and (ii) $9.12 in cash, without interest, for each ATLS common unit.

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”).

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 General Partner’s board of directors were named as defendants in five putative unitholder class action lawsuits challenging the Merger, one of which has subsequently been voluntarily dismissed. In addition, ATLS, Atlas Energy GP LLC (“ATLS GP”), TRC, Trident GP Merger Sub LLC and members of ATLS GP’s board of directors were named as defendants in two putative unitholder class action lawsuits challenging the ATLS Merger, one of which has subsequently been voluntarily dismissed. 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 and ATLS unitholders, respectively, in the Merger and ATLS Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and rescissory damages, attorney’s fees, other expenses and costs.

ATLS has also been named as a defendant in a putative class action and derivative lawsuit brought on January 28, 2015 and amended on February 23, 2015, by a shareholder of TRC against TRC and its directors. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, approving the ATLS Merger and failing to disclose purportedly material information concerning the ATLS Merger. The lawsuit seeks, among other things, injunctive relief, compensatory and rescissory damages, attorney’s fees, interest and costs.

All of the above referenced lawsuits, except for the January 2015 lawsuit and the two lawsuits that have been voluntarily dismissed, were settled, subject to court approval, pursuant to memoranda of understanding executed in February 2015, which are conditioned upon, among other things, the execution of an appropriate stipulations of settlement. The stipulations of settlement will be subject to customary conditions, including, among other things, judicial approval of the proposed settlements contemplated by the memoranda of understanding. There can be no assurance that the parties will ultimately enter into stipulations of settlement, that the court will approve the settlements, that the settlements will not be terminated according to their terms or that some unitholders will not opt-out of the settlements.

At this time, the Partnership cannot reasonably estimate the range of possible loss as a result of the lawsuits. See “Item 3: Legal Proceedings” for more information regarding these lawsuits.

 

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The Partnership incurred $6.1 million of expenses related to the Merger for the year ended December 31, 2014, which is included in other expenses on its consolidated statements of operations.

The closing of the Merger is subject to approval by holders of a majority of the Partnership’s common units and other closing conditions, including the closing of the ATLS Merger and the Spin-Off. On February 20, 2015, the Partnership held a special meeting, where holders of a majority of its common units approved the Merger. In addition, at special meetings held on the same day: (i) a majority of the holders of ATLS common units approved the ATLS Merger and (ii) a majority of the holders of TRC common stock approved the issuance of TRC shares in connection with the Merger. Completion of each of the ATLS Merger and the Spin-Off are also conditioned on the parties standing ready to complete the Merger. The Merger is expected to close on February 27, 2015.

On February 27, 2015, the Partnership agreed to transfer 100% of the Partnership’s interest in gas gathering assets located in the Appalachian Basin of Tennessee to the Partnership’s affiliate, Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP”), for $1.0 million plus working capital adjustments, concurrent with the closing of the Merger on February 27, 2015.

NOTE 4 – ACQUISITIONS

TEAK Midstream, LLC

On May 7, 2013, the Partnership completed the TEAK Acquisition, which includes 100% of the equity interests of TEAK, for $974.7 million in cash, including final purchase price adjustments, less cash received. The assets of these companies include gas gathering and processing facilities in Texas, which are referred to as SouthTX. The acquisition included a 75% interest in T2 LaSalle; a 50% interest in T2 Eagle Ford; and a 50% interest in T2 Co-Gen.

The Partnership funded the purchase price for the TEAK Acquisition in part from the private placement of $400.0 million of Class D Preferred Units for net proceeds of $397.7 million, plus the General Partner’s contribution of $8.2 million to maintain its 2.0% general partner interest in the Partnership (see Note 6); and in part from the sale of 11,845,000 common limited partner units in a public offering for net proceeds of approximately $388.4 million, plus the General Partner’s contribution of $8.3 million to maintain its 2.0% general partner interest in the Partnership (see Note 6). The Partnership funded the remaining purchase price from its senior secured revolving credit facility, and issued $400.0 million of 4.75% unsecured senior notes due November 15, 2021 (“4.75% Senior Notes”) on May 10, 2013 for net proceeds of $391.2 million to reduce the level of borrowings under the revolving credit facility as part of the TEAK Acquisition (see Note 14).

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

 

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Cardinal Midstream, LLC

On December 20, 2012, the Partnership completed the acquisition of 100% of the equity interests held by Cardinal Midstream, LLC (“Cardinal”) in three wholly-owned subsidiaries for $598.9 million in cash, including final purchase price adjustments, less cash received (the “Cardinal Acquisition”). The assets of these companies include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas. The acquisition includes a 60% interest in Centrahoma. The remaining 40% ownership interest in Centrahoma is held by MarkWest, a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE).

The Partnership funded the purchase price for the Cardinal Acquisition in part from the private placement of $175.0 million of its 6.625% senior unsecured notes due October 1, 2020 (“6.625% Senior Notes”) at a premium of 3.0%, for net proceeds of $176.1 million (see Note 14); and from the sale of 10,507,033 common limited partner units in a public offering at a negotiated purchase price of $31.00 per unit, generating net proceeds of approximately $319.3 million, including the General Partner’s contribution of $6.7 million to maintain its 2.0% general partner interest in the Partnership (see Note 6). The Partnership funded the remaining purchase price from its senior secured revolving credit facility (see Note 14).

The Partnership accounted for this transaction as a business combination. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values. The following table presents the values assigned to the assets acquired and liabilities assumed in the Cardinal Acquisition, based on their final estimated fair values as of the date of acquisition, including the 40% non-controlling interest of Centrahoma held by MarkWest (in thousands):

 

Cash		$	1,184
Accounts receivable			13,783
Prepaid expenses and other			1,289
Property, plant and equipment			246,787
Intangible assets			232,740
Goodwill			214,090
Total assets acquired			709,873
Current portion of long-term debt			(341	)
Accounts payable and accrued liabilities			(14,596	)
Deferred tax liability, net			(35,353	)
Long-term debt, less current portion			(604	)
Total liabilities acquired			(50,894	)
Non-controlling interest			(58,905	)
Net assets acquired			600,074
Less cash received			(1,184	)
Net cash paid for acquisition		$	598,890

The fair value of MarkWest’s 40% non-controlling interest in Centrahoma was based upon the purchase price allocated to the 60% controlling interest the Partnership acquired using an income approach. This measurement uses significant inputs that are not observable in the market and thus represents a fair value measurement categorized within Level 3 of the fair value hierarchy. The 40% non-controlling interest in Centrahoma was reduced by a 5.0% adjustment for lack of control that market participants would consider when measuring its fair value.

NOTE 5 – EQUITY METHOD INVESTMENTS

West Texas LPG Pipeline Limited Partnership

On May 14, 2014, the Partnership completed the sale of two subsidiaries, which held an aggregate 20% interest in 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 14). As a result of the sale, the Partnership recorded a $47.8 million gain on asset dispositions, which is included in its consolidated statements of operations for the year ended December 31, 2014.

 

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WTLPG owns a common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. 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 the T2 Joint Ventures as part of the TEAK Acquisition (see Note 4). 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 and have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures.

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 T2 Joint Ventures 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 December 31, 2014 and 2013 (in thousands):

 

		December 31, 2014				December 31, 2013
WTLPG		$	—			$	85,790
T2 LaSalle			55,911				50,534
T2 Eagle Ford			109,517				97,437
T2 EF Co-Gen			11,784				14,540
Equity method investment in joint ventures		$	177,212			$	248,301

The following table presents the Partnership’s equity income (loss) in joint ventures for the years ended December 31, 2014, 2013 and 2012 (in thousands):

 

		Years Ended December 31,
		2014				2013				2012
WTLPG		$	2,611			$	4,988			$	6,323
T2 LaSalle			(4,271	)			(3,127	)			—
T2 Eagle Ford			(8,754	)			(4,408	)			—
T2 EF Co-Gen			(3,593	)			(2,189	)			—
Equity income (loss) in joint ventures		$	(14,007	)		$	(4,736	)		$	6,323

NOTE 6 – EQUITY

Common Units

In November 2012, the Partnership entered into an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, the Partnership offered and sold through Citigroup, as its sales agent, common units for $150.0 million. Sales were at market prices prevailing at the time of the sale. During the years ended December 31, 2013 and 2012, the Partnership issued 3,895,679 and 275,429 common units, respectively, under the equity distribution program for proceeds of $137.8 million and $8.7 million, respectively, net of $2.8 million and $0.2 million, respectively, in commissions incurred from Citigroup, and other expenses. The Partnership also received capital contributions from the General Partner of $2.9 million and $0.2 million during the years ended December 31, 2013 and 2012, respectively, to maintain its 2.0% general partner interest in the Partnership. The net proceeds from the common unit offering were utilized for general partnership purposes.

 

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In December 2012, the Partnership sold 10,507,033 common units in a public offering at a price of $31.00 per unit, yielding net proceeds of approximately $319.3 million, including $6.7 million contributed by the General Partner to maintain its 2.0% general partner interest. The Partnership utilized the net proceeds from the common unit offering to partially finance the Cardinal Acquisition (see Note 4).

In April 2013, the Partnership sold 11,845,000 common units in a public offering at a price of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. The Partnership also received a capital contribution from the General Partner of $8.3 million to maintain its 2.0% general partnership interest. The Partnership used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see Note 3).

On May 12, 2014, the Partnership entered into an Equity Distribution Agreement (the “2014 EDA”) with Citigroup, Wells Fargo Securities, LLC and MLV & Co. LLC, as sales agents. Pursuant to this program, 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. However, the Partnership is currently restricted from selling common units by the Merger Agreement (see Note 3).

During the year ended December 31, 2014, the Partnership issued 3,558,005 common units, under the 2014 EDA for proceeds of $121.6 million, net of $1.2 million in commissions paid to the sales agents. The Partnership also received capital contributions from the General Partner of $2.5 million during the year ended December 31, 2014 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 December 31, 2011 through September 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)
December 31, 2011		February 14, 2012		$	0.55			$	29,489			$	2,031
March 31, 2012		May 15, 2012			0.56				30,030				2,217
June 30, 2012		August 14, 2012			0.56				30,085				2,221
September 30, 2012		November 14, 2012			0.57				30,641				2,409
December 31, 2012		February 14, 2013			0.58				37,442				3,117
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
September 30, 2014		November 14, 2014			0.64				54,080				8,115

 

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On January 9, 2015, 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 December 31, 2014. The $62.2 million distribution, including $8.1 million to the General Partner for its general partner interest and incentive distribution rights, was paid on February 13, 2015 to unitholders of record at the close of business on January 21, 2015.

Class D Preferred Units

In November 2012, the Partnership entered into a unit purchase agreement for a private placement of $200.0 million of newly-created Class D Preferred Units to third party investors. The unit purchase agreement was intended to provide financing for a portion of the Cardinal Acquisition. The unit purchase agreement was terminated when the Partnership raised more than $150.0 million in common unit equity. The Partnership paid each investor a commitment fee equal to 2.0% of its commitment at the time of termination for a total expense of $4.0 million, which was recorded as other costs on the Partnership’s consolidated statements of operations.

On May 7, 2013, the Partnership completed a private placement of $400.0 million of its Class D Preferred Units to third party investors, at a negotiated price per unit of $29.75, resulting in net proceeds of $397.7 million pursuant to the Class D preferred unit purchase agreement dated April 16, 2013 (the “Commitment Date”). The General Partner contributed $8.2 million to maintain its 2.0% general partnership interest upon the issuance of the Class D Preferred Units. The Partnership used the proceeds to fund a portion of the purchase price of the TEAK Acquisition (see Note 4). The Class D Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. The Partnership had the right to convert the Class D Preferred Units plus any unpaid distributions, in whole but not in part, beginning one year following their issuance, into common units.

The fair value of the Partnership’s common units on the Commitment Date was $36.52 per unit, resulting in an embedded beneficial conversion discount (“discount”) on the Class D Preferred Units of $91.0 million. The Partnership recognized the fair value of the Class D Preferred Units with the offsetting intrinsic value of the discount within Class D preferred limited partner interests on its consolidated balance sheets as of December 31, 2014 and 2013. The discount is being accreted and recognized as imputed dividends over the term of the Class D Preferred Units as a reduction to net income attributable to the common limited partners and the General Partner on the Partnership’s consolidated statements of operations. The Partnership’s Class D Preferred Units are presented combined with a net $16.0 million and $61.5 million unaccreted discount on the Partnership’s consolidated balance sheets as of December 31, 2014 and 2013, respectively. The Partnership recorded $45.5 million and $29.5 million in the years ended December 31, 2014 and 2013, respectively, within preferred unit imputed dividend effect on the Partnership’s consolidated statements of operations to recognize the accretion of the discount.

The Class D Preferred Units received distributions of additional Class D Preferred Units in each of the quarterly periods following their issuance in May 2013. The amount of the distribution was determined based upon the cash distribution per unit paid each quarter on the Partnership’s common limited partner units plus a preferred yield premium. The Partnership recorded Class D Preferred Unit distributions in kind of $42.6 million and $23.6 million for the years ended December 31, 2014 and 2013, respectively, as preferred unit dividends in kind on the Partnership’s consolidated statements of operations.

Class D Preferred Unit distributions paid in kind by the Partnership for quarters ending from June 30, 2013 through September 30, 2014 were as follows:

 

For Quarter Ended		Date Preferred Unit Distributions Paid in Kind		Preferred Unit Distributions Paid in Kind(1)
June 30, 2013		August 14, 2013			138,598
September 30, 2013		November 14, 2013			239,888
December 31, 2013		February 14, 2014			274,785
March 31, 2014		May 15, 2014			305,983
June 30, 2014		August 14, 2014			294,439
September 30, 2014		November 14, 2014			320,374

 

(1)	The partnership considers preferred unit distributions paid in kind to be non-cash financing activity.

 

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On January 22, 2015, the Partnership exercised its right under the certificate of designation of the Class D Preferred Units (“Class D Certificate of Designation”) to convert all outstanding Class D Preferred Units and unpaid distributions into common limited partner units, based upon the Execution Date Unit Price of $29.75 per unit, as defined by the Class D Certificate of Designation. As a result of the conversion, 15,389,575 common limited partner units were issued.

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 made cumulative cash distributions on the Class E Preferred Units from the date of original issue. The cash distributions were payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year. 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. Thereafter, the Partnership paid 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.

Class E Preferred Unit distributions paid by the Partnership for the period from March 14, 2014 through October 14, 2014 were as follows:

 

Preferred Units Distribution Period		Date Class E Preferred Limited Partner Unit Distribution Paid		Cash Distribution Per Class E Preferred Limited Partner Unit				Total Cash Distribution on Class E Preferred Limited Partner Units (in thousands)
March 17, 2014 - July 14, 2014		July 15, 2014		$	0.676040			$	3,421
July 15, 2014 - October 14, 2014		October 15, 2014			0.515625				2,609

On January 15, 2015, 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 October 15, 2014 through January 14, 2015. For the year ended December 31, 2014, the Partnership allocated net income of $8.2 million 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.

On January 27, 2015, the Partnership delivered notice of its intention to redeem all outstanding shares of its Class E Preferred Units. The redemption of the Class E Preferred Units will occur immediately prior to the close of the Merger (See Note 3). The Partnership expects the Merger to close on February 27, 2015 and, accordingly, the redemption would also be on February 27, 2015. The Class E Preferred Units will be redeemed at a redemption price of $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions on the Class E Preferred Units as of the redemption date. TRP has agreed to deposit the funds for such redemption with the paying agent.

NOTE 7 – 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 14) (in thousands):

 

		December 31. 2014				December 31, 2013				Estimated Useful Lives in Years
Pipelines, processing and compression facilities		$	3,527,004			$	2,885,303			2 - 40
Rights of way			208,310				203,136			40
Buildings			10,447				10,291			40
Furniture and equipment			14,725				13,800			3 - 7
Other			15,185				15,805			3 - 10
			3,775,671				3,128,335
Less – accumulated depreciation			(525,698	)			(404,143	)
		$	3,249,973			$	2,724,192

 

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The Partnership recorded depreciation expense on property, plant and equipment, including capital lease arrangements (see Note 14), of $122.5 million, $99.7 million and $66.2 million for the years ended December 31, 2014, 2013 and 2012, 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 5.5%, 5.8% and 6.4% for the years ended December 31, 2014, 2013, and 2012, respectively. The amount of interest capitalized was $12.7 million, $7.5 million and $8.7 million for the years ended December 31, 2014, 2013 and 2012, respectively.

The Partnership owns and leases certain gas treating assets that are used to remove impurities from natural gas before it is delivered into gathering systems and transmission pipelines to ensure it meets pipeline quality specifications. These assets are included within pipelines, processing and compression facilities within property, plant and equipment on the Partnership’s consolidated balance sheet. Revenues from these lease arrangements are recorded within transportation, processing and other fee revenues on the Partnership’s consolidated statement of operations. Future minimum rental income related to these lease arrangements is estimated to be as follows for each of the next five calendar years: 2015 - $3.2 million; 2016 - $1.0 million; 2017 - 2019 - none.

NOTE 8 – GOODWILL AND INTANGIBLE ASSETS

The Partnership evaluates goodwill for impairment annually, on December 31, for all reporting units, except SouthTX, which is evaluated on April 30. The Partnership completed the first step of the goodwill impairment test for its SouthTX reporting unit as of April 30, 2014 and determined there was no impairment. The Partnership completed a qualitative test for goodwill impairment on its Barnett, SouthOK and WestOK reporting units as of December 31, 2014 and determined there were no indications of impairment. Due to recent declines in commodity prices, the Partnership also performed a qualitative test for goodwill impairment on its SouthTX reporting unit as of December 31, 2014 and determined there was no impairment.

In 2013, the Partnership determined that a portion of goodwill recorded in connection with the Cardinal Acquisition was impaired. A qualitative assessment was performed on the Gas Treating reporting unit. The assessment indicated the potential for goodwill recorded on Gas Treating to be impaired due to lower forecasted cash flows as compared to original forecasts. Using a combination of discounted cash flow models and market multiples for similar businesses, the Partnership measured the amount of goodwill impairment on Gas Treating to be $43.9 million. The Partnership recorded a goodwill impairment loss of $43.9 million on its consolidated statements of operations for the year ended December 31, 2013.

The following table reflects the carrying amounts of goodwill by reporting unit at December 31, 2014 and 2013 (in thousands):

 

		December 31, 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 due to an adjustment of the fair value of assets acquired and liabilities assumed from the TEAK Acquisition (See Note 4). 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.

 

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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 December 31, 2014 and 2013 (in thousands):

 

		December 31, 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			(1,281	)			(779	)
Customer relationships			(273,530	)			(194,022	)
			(274,811	)			(194,801	)
Net carrying amount:
Customer contracts			2,138				2,640
Customer relationships			594,123				693,631
Net carrying amount		$	596,261			$	696,271

The change in the gross carrying amount of finite-lived intangible assets is related to a $20.0 million adjustment of the fair value of the customer relationships acquired from the TEAK Acquisition (See Note 4). The fair values assigned to the assets acquired in the TEAK Acquisition were finalized during second quarter 2014.

The weighted-average amortization period for customer contracts and customer relationships, as of December 31, 2014, is 10.0 years and 11.5 years, respectively. The Partnership recorded amortization expense on intangible assets of $80.0 million, $68.9 million and $23.8 million for the years ended December 31, 2014, 2013 and 2012, 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: 2015 through 2016 - $74.0 million per year; 2017 - $68.0 million; 2018 through 2019 - $59.5 million per year.

NOTE 9 – OTHER ASSETS

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

 

		December 31, 2014				December 31, 2013
Deferred finance costs, net of accumulated amortization of $29,116 and $22,034 at December 31, 2014 and 2013, respectively		$	37,334			$	41,094
Security deposits			2,238				5,367
Other long-term receivable			4,500				—
		$	44,072			$	46,461

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 14). The Partnership incurred $3.3 million, $22.8 million and $14.4 million deferred finance costs during the years ended December 31, 2014, 2013 and 2012, respectively, related to various financing activities (see Note 14).

During the year ended December 31, 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 14) and recognized $5.3 million expense related to accelerated amortization of deferred financing costs, which is 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 years ended December 31, 2014 and 2012. Amortization expense of deferred finance costs, excluding accelerated amortization expense, was $7.1 million, $7.0 million and $4.7 million for the years ended December 31, 2014, 2013 and 2012, respectively, which is recorded within interest expense on the Partnership’s consolidated statements of operations.

 

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NOTE 10 – INCOME TAXES

As part of the Cardinal Acquisition (see Note 4), the Partnership acquired APL Arkoma, Inc., a taxable subsidiary. The components of the federal and state income tax expense (benefit) of the Partnership’s taxable subsidiary for the years ended December 31, 2014, 2013 and 2012 are summarized as follows (in thousands):

 

		Years Ended December 31,
		2014				2013				2012
Income tax expense (benefit):
Federal		$	(2,128	)		$	(2,024	)		$	158
State			(248	)			(236	)			18
Total income tax expense (benefit)		$	(2,376	)		$	(2,260	)		$	176

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

 

		December 31, 2014				December 31, 2013
Deferred tax assets:
Net operating loss tax carryforwards and alternative minimum tax credits		$	17,269			$	14,900
Deferred tax liabilities:
Excess of asset carrying value over tax basis			(48,183	)			(48,190	)
Net deferred tax liabilities		$	(30,914	)		$	(33,290	)

As of December 31, 2014, the Partnership had net operating loss carry forwards for federal income tax purposes of approximately $44.7 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 11 – DERIVATIVE INSTRUMENTS

The Partnership uses derivative instruments in connection with its commodity price risk management activities. The Partnership uses financial swaps and over-the-counter (“OTC”) purchased put options to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices.

Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under its swap agreements, the Partnership receives a fixed price and remits a floating price, which is based on certain indices for the relevant contract period, on an agreed upon quantity. The swap agreement sets a fixed price for the product being hedged and is (i) an asset if the floating price is lower than the fixed price or (ii) a liability if the floating price is higher than the fixed price.

OTC put options are contractual agreements whereby the purchaser pays a premium for the right, if the floating price is lower than the fixed price, to receive the difference between (i) a fixed, or strike, price and (ii) a floating price, which is based on certain indices for the relevant contract period, on an agreed upon quantity. The purchased put option instrument sets a floor price for commodity sales being hedged and is an asset.

The Partnership uses costless collars to reduce the cost of OTC purchased put options. A costless collar is a combination of an OTC purchased put option and an OTC sold call option, in which the premiums net to zero. OTC sold call options are contractual agreements whereby the seller receives a premium and grants the purchaser the right, if the floating price is higher than the strike price, to receive the difference between (i) a strike price and (ii) a floating price, which is based on certain indices for the relevant contract period, for an agreed upon quantity. The OTC sold call option sets a ceiling price for commodity sales being hedged and is a liability. The costless collar sets a range of prices, between the floor price of the OTC purchased put option and the ceiling price of the OTC sold call option, the Partnership will receive for the commodity sales being hedged.

The Partnership does not apply hedge accounting for derivatives and thus changes in the fair value of derivatives are recognized immediately within derivative gain (loss), net in its consolidated statements of operations. In previous years, the Partnership applied hedge accounting for derivatives and the effective portion of the gain (loss), due to the change in the fair value of the derivative instruments, was recognized in accumulated other comprehensive loss within equity on the Partnership’s consolidated balance sheets. The effective portion of the gain (loss) was reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings, which occurred through the year ending December 31, 2012. The Partnership has reclassified all earnings out of accumulated other comprehensive income (loss), within equity on the Partnership’s consolidated balance sheet and there was no balance outstanding as of the years ended December 31, 2014 and 2013.

 

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The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of setoff at the time of settlement of the derivatives. 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. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options, or received for sold call options, are recorded on the Partnership’s consolidated balance sheets as the initial value of the options. Changes in the fair value of the options are recognized within derivative gain (loss), net as unrealized gain (loss) on the Partnership’s consolidated statements of operations. Premiums are reclassified to realized gain (loss) within derivative gain (loss), net at the time the option expires or is exercised. The Partnership reflected net derivative assets on its consolidated balance sheet of $125.4 million at December 31, 2014, and net derivative liabilities of $9.1 million at December 31, 2013.

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 December 31, 2014:
Current portion of derivative assets		$	88,007			$	—			$	88,007
Long-term portion of derivative assets			37,398				—				37,398
Total derivative assets, net		$	125,405			$	—			$	125,405
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 December 31, 2014:
Current portion of derivative assets		$	—			$	—			$	—
Long-term portion of derivative assets			—				—				—
Total derivative liabilities, net		$	—			$	—			$	—
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	)

 

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The following table summarizes the Partnership’s commodity derivatives as of December 31, 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
2015		Natural gas			27,010				4.18			$	30,945
2016		Natural gas			13,800				4.15				9,381
2017		Natural gas			6,600				4.11				2,137
2015		NGLs			71,442				1.22				43,094
2016		NGLs			34,650				1.03				16,822
2017		NGLs			10,080				1.04				4,777
2015		Crude oil			210				90.26				7,274
2016		Crude oil			30				90.00				848
Total fixed price swaps													115,278
Purchased put options
2015		NGLs			3,150				0.94				1,353
2015		Crude oil			270				89.18				8,774
Sold call options
2015		NGLs			1,260				1.28				—
Total options													10,127
Total derivatives												$	125,405

 

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

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

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

 

		For the Years Ended December 31,
		2014				2013				2012
Derivatives previously designated as cash flow hedges
Loss reclassified from accumulated other comprehensive loss into natural gas and liquid sales		$	—			$	—			$	(4,390	)
Derivatives not designated as hedges
Gain (loss) recognized in derivative gain (loss), net:
Commodity contract—realized(1)		$	(9,960	)		$	(324	)		$	10,993
Commodity contract—unrealized(2)			141,024				(28,440	)			20,947
Derivative gain (loss), net		$	131,064			$	(28,764	)		$	31,940

 

(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 12 – 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 Levels 1, 2 and 3 (see Note 2 –“Fair Value of Financial Instruments”).

 

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Derivative Instruments

At December 31, 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 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 December 31, 2014 and 2013 (in thousands):

 

		Level 1				Level 2				Level 3				Total
December 31, 2014
Assets
Commodity swaps		$	—			$	50,585			$	64,693			$	115,278
Commodity options			—				8,774				1,353				10,127
Total assets			—				59,359				66,046				125,405
Liabilities
Commodity swaps			—				—				—				—
Commodity options			—				—				—				—
Total liabilities			—				—				—				—
Total derivatives		$	—			$	59,359			$	66,046			$	125,405
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	)

 

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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 years ended December 31, 2014 and 2013 (in thousands):

 

		NGL Fixed Price Swaps								NGL Put Options								NGL Call Options								Total
		Gallons				Amount				Gallons				Amount				Gallons				Amount				Amount
Balance – January 1, 2013			87,066			$	16,814				38,556			$	6,269				—			$	—			$	23,083
New contracts(1)			104,328				—				7,560				816				—				—				816
Cash settlements from unrealized (gain) loss(2)(3)			(61,236	)			(11,496	)			(39,816	)			8,545				—				—				(2,951	)
Net change in unrealized loss(2)			—				(17,284	)			—				(2,367	)			—				—				(19,651	)
Deferred option premium recognition(3)			—				—				—				(13,053	)			—				—				(13,053	)
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)			(84,546	)			3,406				(8,190	)			100				(3,780	)			(121	)			3,385
Net change in unrealized gain (loss)(2)			—				73,253				—				1,448				—				200				74,901
Deferred option premium recognition(3)			—				—				—				(605	)			—				121				(484	)
Balance – December 31, 2014			116,172			$	64,693				3,150			$	1,353				1,260			$	—			$	66,046

 

(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 December 31, 2014 and 2013 (in thousands):

 

		Gallons				Third Party Quotes(1)				Adjustments(2)				Total Amount
As of December 31, 2014
Propane swaps			101,556			$	50,201			$	—			$	50,201
Natural gasoline swaps			14,616				14,859				(367	)			14,492
Total NGL swaps – December 31, 2014			116,172			$	65,060			$	(367	)		$	64,693
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.

 

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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				Adjustment based upon Regression Coefficient
		Swap Fair Value Adjustments				Lower 95%				Upper 95%				Average
As of December 31, 2014:
Natural gasoline		$	(367	)			0.9714				0.9748				0.9731
Total Level 3 adjustments – December 31, 2014		$	(367	)
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 $14.6 million and $14.5 million of NGL linefill at December 31, 2014 and 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 December 31, 2014 and 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 FIFO basis. During the year ended December 31, 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 years ended December 31, 2014 and 2013 (in thousands):

 

		Linefill Valued at Market								Linefill Valued on FIFO								Total NGL Linefill
		Gallons				Amount				Gallons				Amount				Gallons				Amount
Balance – January 1, 2013			9,148			$	7,783				—			$	—				9,148			$	7,783
Deliveries into NGL linefill			—				—				80,758				60,565				80,758				60,565
NGL linefill sales			(3,360	)			(2,795	)			(71,433	)			(52,155	)			(74,793	)			(54,950	)
Net change in NGL linefill valuation(1)			—				(249	)			—				—				—				(249	)
Acquired NGL linefill(2)			—				—				2,213				1,368				2,213				1,368
Balance – December 31, 2013			5,788			$	4,739				11,538			$	9,778				17,326			$	14,517
Deliveries into NGL linefill			4,385				2,919				59,273				38,451				63,658				41,370
NGL linefill sales			(4,629	)			(3,917	)			(49,335	)			(31,470	)			(53,964	)			(35,387	)
Adjustments for linefill contract revision			11,982				9,846				(11,982	)			(9,846	)			—				—
Net change in NGL linefill valuation(1)			—				(5,888	)			—				—				—				(5,888	)
Balance – December 31, 2014			17,526			$	7,699				9,494			$	6,913				27,020			$	14,612

 

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

(2)	NGL linefill acquired as part of the TEAK and Cardinal Acquisitions (see Note 4).

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 December 31, 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 14) 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 December 31, 2014 and 2013, which consists principally of borrowings under the revolving credit facility and the Senior Notes, were $1,933.2 million and $1,663.6 million, respectively, compared with the carrying amounts of $1,939.1 million and $1,707.3 million, respectively.

Acquisitions

On May 7, 2013, the Partnership completed the TEAK Acquisition (see Note 4). On December 20, 2012, the Partnership completed the Cardinal Acquisitions (see Note 4). 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. The fair values assigned to the assets acquired and liabilities assumed in the Cardinal Acquisition were finalized during 2013.

NOTE 13 – ACCRUED LIABILITIES

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

 

		December 31, 2014				December 31, 2013
Accrued capital expenditures		$	13,233			$	17,898
Acquisition-related liabilities			4,779				8,933
Accrued ad valorem and production taxes			4,298				3,551
Distributions payable			2,609				—
Merger-related liabilities			6,056				—
Unconditional purchase obligations			6,521				—
Other			12,233				17,067
		$	49,729			$	47,449

 

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NOTE 14 – DEBT

Total debt consists of the following (in thousands):

 

		December 31, 2014				December 31, 2013
Revolving credit facility		$	385,000			$	152,000
6.625% Senior notes – due 2020			503,881				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			229				754
Total debt			1,939,110				1,707,310
Less current maturities			(224	)			(524	)
Total long term debt		$	1,938,886			$	1,706,786

The aggregate amount of the Partnership’s debt maturities is as follows (in thousands):

 

Years Ended December 31:
2015		$	224
2016			5
2017			—
2018			—
2019			385,000
Thereafter			1,550,000
Total principal maturities			1,935,229
Unamortized premium			3,881
Total debt		$	1,939,110

Cash payments for interest related to debt, net of capitalized interest, were $85.9 million, $66.3 million and $28.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Revolving Credit Facility

At December 31, 2014, the Partnership had an $800.0 million senior secured revolving credit facility with a syndicate of banks that matures in August 2019. Borrowings under the revolving credit facility bear interest, at the Partnership’s option, at either (1) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%, or (2) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate for borrowings on the revolving credit facility, at December 31, 2014, was 2.7%. Up to $50.0 million of the revolving credit facility may be utilized for letters of credit, of which $4.2 million was outstanding at December 31, 2014. These outstanding letters of credit amounts were not reflected as borrowings on the Partnership’s consolidated balance sheets. At December 31, 2014, the Partnership had $410.8 million of remaining committed capacity under its revolving credit facility.

Borrowings under the revolving credit facility are secured by (i) a lien on and security interest in all the Partnership’s property and that of its subsidiaries, except for the assets owned by Atlas Pipeline Mid-Continent WestOk, LLC (“WestOK LLC”) and Atlas Pipeline Mid-Continent WestTex, LLC (“WestTX LLC”), entities in which the Partnership has 95% interests, and Centrahoma, in which the Partnership has a 60% interest; and their respective subsidiaries; and (ii) by the guaranty of each of the Partnership’s consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including requirements that the Partnership maintain certain financial thresholds and restrictions on the Partnership’s ability to (1) incur additional indebtedness, (2) make certain acquisitions, loans or investments, (3) make distribution payments to its unitholders if an event of default exists, or (4) enter into a merger or sale of assets, including the sale or transfer of interests in its subsidiaries, without approval of the lenders. The Partnership is unable to borrow under its revolving credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to its partnership agreement.

 

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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) the LIBOR rate plus 1.0%, or (ii) the LIBOR rate for the applicable period, in each case plus the applicable margin.

As of December 31, 2014, the Partnership was in compliance with all covenants under the credit facility.

Senior Notes

At December 31, 2014, the Partnership had $500.0 million principal outstanding of the 6.625% Senior Notes, $650.0 million principal outstanding of the 5.875% unsecured senior notes due August 1, 2023 (“5.875% Senior Notes”), and $400.0 million of the 4.75% Senior Notes (with the 6.625% Senior Notes and 5.875% Senior Notes, the “Senior Notes”).

On January 15, 2015, TRP announced cash tender offers to redeem any and all of the outstanding $500.0 million aggregate principal amount of the 6.625% Senior Notes; $400.0 million aggregate principal amount of the 4.75% Senior Notes; and $650.0 million aggregate principal amount of the 5.875% Senior Notes. TRP made the cash tender offers in connection with, and conditioned upon, the consummation of the Merger (see Note 3). The Merger, however, is not conditioned on the consummation of the tender offers. On February 2, 2015, TRP announced as of January 29, 2015, it had received tenders pursuant to its previously announced cash tender offers on January 15, 2015 from holders representing:

 

•

less than a majority of the total outstanding $500.0 million of the 6.625% Senior Notes;

 

•

approximately 98.3% of the total outstanding $400.0 million of the 4.75% Senior Notes; and

 

•

approximately 91.0% of the total outstanding $650.0 million of the 5.875% Senior Notes.

Also on February 2, 2015, TRP announced a change of control cash tender offer for any and all of the outstanding $500.0 million of the 6.625% Senior Notes. TRP made the change of control cash tender offer in connection with, and conditioned upon, the consummation of the Merger. The Merger, however, is not conditioned on the consummation of the change in control cash tender offer. The change in control cash tender offer was made independently of TRP’s January 15, 2015 cash tender offers.

The Senior Notes are subject to repurchase by the Partnership at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if the Partnership does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to the Partnership’s secured debt, including the Partnership’s obligations under its revolving credit facility.

 

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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, without consent. The Partnership is in compliance with these covenants as of December 31, 2014.

6.625% Senior Notes

The 6.625% Senior Notes are presented combined with a net $3.9 million unamortized premium as of December 31, 2014. Interest on the 6.625% Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% Senior Notes are due on October 1, 2020 and redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

On September 28, 2012, the Partnership issued $325.0 million of the 6.625% Senior Notes in a private placement transaction, at par. The Partnership received net proceeds of $318.9 million after underwriting commissions and other transaction costs and utilized the proceeds to reduce the outstanding balance on its revolving credit facility.

On December 20, 2012, the Partnership issued $175.0 million of the 6.625% Senior Notes in a private placement transaction. The 6.625% Senior Notes were issued at a premium of 103.0% of the principal amount for a yield of 6.0%. The Partnership received net proceeds of $176.1 million after underwriting commissions and other transaction costs and utilized the proceeds to partially finance the Cardinal Acquisition (see Note 4). Of the $176.1 million net proceeds, $176.5 million was received during the year ended December 31, 2012, while additional expenses of $0.4 million were incurred during the year ended December 31, 2013.

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. Interest on the 5.875% Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% Senior Notes are due on August 1, 2023, and redeemable any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

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 4). Interest on the 4.75% Senior Notes is payable semi-annually in arrears on May 15 and November 15. The 4.75% Senior Notes are due on November 15, 2021 and are redeemable any time after March 15, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption.

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.

 

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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. During the year ended December 31, 2013, the Partnership recorded a loss of $26.6 million within loss on early extinguishment of debt on the Partnership’s consolidated statements of operations, related to the redemption of the 8.75% Senior Notes. The loss includes $17.5 million premiums paid; $8.0 million consent payment; $5.3 million write off of deferred financing costs, offset by $4.2 million recognition of unamortized premium.

NOTE 15 – COMMITMENTS AND CONTINGENCIES

The Partnership has noncancelable operating leases for equipment and office space that expire at various dates. Certain operating leases provide the Partnership with the option to renew for additional periods. Where operating leases contain escalation clauses, rent abatements, and/or concessions, the Partnership applies them in the determination of straight-line rent expense over the lease term. Leasehold improvements are amortized over the shorter of the lease term or asset life, which may include renewal periods where the renewal is reasonably assured, and is included in the determination of straight-line rent expense. Total rental expense for the years ended December 31, 2014, 2013 and 2012 was $15.2 million, $11.3 million and $5.5 million, respectively. The aggregate amount of remaining future minimum annual lease payments as of December 31, 2014 is as follows (in thousands):

 

Years Ended December 31:
2015		$	12,621
2016			8,610
2017			5,126
2018			4,469
2019			644
Thereafter			322
		$	31,792

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 $28.3 million, $34.8 million and $10.5 million for the years ended December 31, 2014, 2013 and 2012, respectively. The unrecorded future fixed and determinable portion of the obligations as of December 31, 2014 was as follows: 2015 - $20.7 million; 2016 to 2017 - $23.9 million per year; 2018 - $21.8 million; and 2019 - $16.9 million.

The Partnership had committed approximately $179.1 million for the purchase of property, plant and equipment at December 31, 2014.

The Partnership is involved in class action lawsuits arising from events related to the Merger (see Part I. – Item 3. Legal Proceedings”). At this time, the Partnership cannot reasonably estimate the range of possible loss as a result of the 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 16 – CONCENTRATIONS OF RISK

The Partnership sells natural gas, NGLs and condensate under contract to various purchasers in the normal course of business. For the year ended December 31, 2014, the Partnership had three customers that individually accounted for approximately 26%, 13% and 11%, respectively, of the Partnership’s consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, the Partnership had three customers that individually accounted for approximately 29%, 17% and 14%, respectively, of the Partnership’s consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, the Partnership had two customers that individually accounted for approximately

 

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48% and 15%, respectively, of the Partnership’s consolidated total third party revenues, excluding the impact of all financial derivative activity. Additionally, the Partnership had two customers that individually accounted for approximately 15% and 10%, respectively, of the Partnership’s consolidated accounts receivable at December 31, 2014, and three customers that individually accounted for approximately 23%, 20% and 10%, respectively, of the Partnership’s consolidated accounts receivable at December 31, 2013.

The Partnership has certain producers that supply a majority of the natural gas to its gathering systems and processing facilities. A reduction in the volume of natural gas that any one of these producers supply to the Partnership could adversely affect its operating results unless comparable volume could be obtained from other producers in the surrounding region.

The Partnership places its temporary cash investments in high quality short-term money market instruments and deposits with high quality financial institutions. At December 31, 2014, the Partnership and its subsidiaries had $8.5 million in deposits at banks, of which $7.8 million was over the insurance limits of the Federal Deposit Insurance Corporation and the Securities Investor Protection Corporation. No losses have been experienced on such investments.

NOTE 17 – BENEFIT PLANS

Share-based payments are made to employees and non-employees in the form of phantom units or unit options. A phantom unit entitles a grantee to receive a common limited partner unit upon vesting of the phantom unit. The compensation committee appointed by the General Partner’s managing board (the “Compensation Committee”) determines the vesting period for phantom units.

A unit option entitles a grantee to purchase a common limited partner unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option is equal to the fair market value of the common unit on the date of grant of the option. The Compensation Committee determines how the exercise price may be paid by the grantee as well as the vesting and exercise period for unit options.

In tandem with phantom unit grants, participants may be granted a distribution equivalent right (“DER”), which is the right 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.

Phantom units and unit options granted to employees, which are not to be cash settled, are recognized within equity in the financial statements based on their fair values on the date of the grant. Phantom units and unit options granted to non-employees that have a cash settlement option are recognized within liabilities in the financial statements based upon their current fair market value.

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. 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 December 31, 2014, the Partnership had 1,684,289 phantom units outstanding under the Partnership’s LTIPs, with 139,218 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 December 31, 2014, there were 614,415 phantom units outstanding under the LTIPs that will vest within twelve months.

 

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The Partnership is authorized to purchase common units from employees to cover employee tax obligations when phantom units have vested. During the years ended December 31, 2014 and 2012, the Partnership purchased and retired 66,321 and 24,052 common units, respectively, for a cost of $2.2 million and $0.7 million, respectively. The purchased and retired units were recorded as reductions of equity on the Partnership’s consolidated balance sheets. There were no common units purchased and retired during the year ended December 31, 2013.

All phantom units outstanding under the LTIPs at December 31, 2014 include DERs granted to the participants by the Compensation Committee. The amounts paid with respect to LTIP DERs were $4.3 million, $3.1 million and $2.0 million during the years ended December 31, 2014, 2013 and 2012, 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:

 

		Years Ended December 31,
		2014								2013								2012
		Number of Units				Fair Value(1)				Number of Units				Fair Value(1)				Number of Units				Fair Value(1)
Outstanding, beginning of period			1,446,553			$	36.32				1,053,242			$	33.21				394,489			$	21.63
Granted			738,727				33.03				744,997				38.96				907,637				34.94
Forfeited			(37,075	)			37.09				(61,550	)			36.11				(67,675	)			29.83
Vested and issued(2)(3)			(463,916	)			34.71				(290,136	)			31.88				(181,209	)			17.88
Outstanding, end of period(4)(5)			1,684,289			$	35.30				1,446,553			$	36.32				1,053,242			$	33.21
Non-cash compensation expense recognized (in thousands)						$	25,116							$	19,344							$	11,635

 

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

(2)	The intrinsic values for phantom unit awards vested and issued during the years ended December 31, 2014, 2013 and 2012 were $15.4 million, $10.7 million and $5.5 million, respectively.

(3)	There were 4,684, 1,677 and 792 vested phantom units, which were settled for $155 thousand, $58 thousand and $26 thousand cash during the years ended December 31, 2014, 2013 and 2012, respectively.

(4)	The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 and 2013 was $45.9 million and $50.7 million, respectively.

(5)	There were 25,778 and 22,539 outstanding phantom unit awards at December 31, 2014 and 2013, respectively, which were classified as liabilities due to a cash option available on the related phantom unit awards.

At December 31, 2014, the Partnership had approximately $27.9 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 1.9 years.

Partnership Unit Options

The Partnership had no unit options outstanding at December 31, 2014, and there were no exercises of unit options during the years ended December 31, 2014, 2013 and 2012.

NOTE 18 – 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 $5.1 million, $5.0 million and $3.8 million during years ended

 

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December 31, 2014, 2013 and 2012, respectively, 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 years ended December 31, 2014, 2013 and 2012. The General Partner believes the method utilized in allocating costs to the Partnership is reasonable.

The Partnership compresses and gathers gas for 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 $0.3 million, $0.3 million and $0.4 million in compression and gathering fees for the years ended December 31, 2014, 2013 and 2012, respectively.

The Partnership agreed to provide design, procurement and construction management services for ARP with respect to a pipeline located in Lycoming County, Pennsylvania (the “Lycoming Pipeline”). The Partnership was reimbursed approximately $1.8 million by ARP for these services during the year ended December 31, 2013.

On February 27, 2015, the Partnership agreed to transfer 100% of the Partnership’s interest in its Tennessee gas gathering assets to ARP, for $1.0 million plus working capital adjustments, concurrent with the closing of the Merger on February 27, 2015.

NOTE 19 – 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 5), the Partnership assessed its reportable segments and realigned its reportable segments into two new segments: Oklahoma and 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, Ardmore 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 southern 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. On February 27, 2015, the Partnership agreed to transfer 100% of the Partnership’s interest in natural gas gathering assets located in the Appalachian Basin in Tennessee to the Partnership’s affiliate, ARP (see Note 3). The Tennessee gathering assets were formerly included in the previous Gathering and Processing Segment, but are now included within Corporate and Other.

 

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

 

		Oklahoma				Texas				Corporate and Other				Consolidated
Year Ended December 31, 2014:
Revenue:
Revenues – third party(1)		$	1,722,810			$	1,115,545			$	136,479			$	2,974,834
Revenues – affiliates			—				—				286				286
Total revenues			1,722,810				1,115,545				136,765				2,975,120
Costs and Expenses:
Natural gas and liquids cost of sales			1,383,137				908,777				—				2,291,914
Operating expenses			62,758				48,700				2,148				113,606
General and administrative(1)			—				—				73,943				73,943
Other expenses(2)			—				—				6,073				6,073
Depreciation and amortization			102,614				95,203				4,726				202,543
Interest expense(1)			—				—				93,147				93,147
Total costs and expenses			1,548,509				1,052,680				180,037				2,781,226
Equity income (loss) in joint ventures			—				(16,619	)			2,612				(14,007	)
Gain (loss) on asset disposition			(448	)			—				47,829				47,381
Income before tax			173,853				46,246				7,169				227,268
Income tax benefit			(2,376	)			—				—				(2,376	)
Net income		$	176,229			$	46,246			$	7,169			$	229,644
		Oklahoma				Texas				Corporate and Other				Consolidated
Year Ended December 31, 2013:
Revenue:
Revenues – third party(1)		$	1,385,342			$	743,412			$	(22,208	)		$	2,106,546
Revenues – affiliates			—				—				303				303
Total revenues			1,385,342				743,412				(21,905	)			2,106,849
Costs and Expenses:
Natural gas and liquids cost of sales			1,087,245				603,137				—				1,690,382
Operating expenses			58,848				33,716				1,963				94,527
General and administrative(1)			—				—				60,856				60,856
Other expenses(2)			—				—				20,005				20,005
Depreciation and amortization			98,240				65,797				4,580				168,617
Interest expense(1)			—				—				89,637				89,637
Total costs and expenses			1,244,333				702,650				177,041				2,124,024
Equity income (loss) in joint ventures			—				(9,724	)			4,988				(4,736	)
Loss on asset disposition			(1,519	)			—				—				(1,519	)
Goodwill impairment loss			—				—				(43,866	)			(43,866	)
Loss on early extinguishment of debt			—				—				(26,601	)			(26,601	)
Income (loss) before tax			139,490				31,038				(264,425	)			(93,897	)
Income tax benefit			(2,260	)			—				—				(2,260	)
Net income (loss)		$	141,750			$	31,038			$	(264,425	)		$	(91,637	)
		Oklahoma				Texas				Corporate and Other				Consolidated
Year Ended December 31, 2012:
Revenue:
Revenues – third party(1)		$	757,909			$	459,103			$	28,573			$	1,245,585
Revenues – affiliates			—				—				435				435
Total revenues			757,909				459,103				29,008				1,246,020
Costs and Expenses:
Natural gas and liquids cost of sales			551,420				376,526				—				927,946
Operating expenses			39,627				21,712				759				62,098
General and administrative(1)			—				—				47,206				47,206
Other expenses(2)			5				(308	)			15,372				15,069

 

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		Oklahoma				Texas				Corporate and Other				Consolidated
Depreciation and amortization			56,154				33,284				591				90,029
Interest expense(1)			—				—				41,760				41,760
Total costs and expenses			647,206				431,214				105,688				1,184,108
Equity income in joint ventures			—				—				6,323				6,323
Income (loss) before tax			110,703				27,889				(70,357	)			68,235
Income tax expense			176				—				—				176
Net income (loss)		$	110,527			$	27,889			$	(70,357	)		$	68,059

 

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

(2)

Includes merger related costs in connection with the Merger for the year ended December 31, 2014 (see Note 3), and acquisition costs related to the Cardinal and TEAK Acquisitions for the year ended December 31, 2013 (see –Note 4), and the Cardinal Acquisition for the year ended December 31, 2012 (see –Note 4), which are carried at the corporate level.

 

		Years Ended December 31,
		2014				2013				2012
Capital Expenditures:
Oklahoma		$	347,984			$	235,748			$	248,009
Texas			298,443				211,056				124,910
Corporate and other			1,320				3,756				614
		$	647,747			$	450,560			$	373,533

 

		December 31, 2014				December 31, 2013
Balance Sheet
Equity method investment in joint ventures:
Texas		$	177,212			$	162,511
Corporate and other			—				85,790
		$	177,212			$	248,301
Goodwill:
Oklahoma		$	178,762			$	178,762
Texas			187,001				189,810
		$	365,763			$	368,572
Total assets:
Oklahoma		$	2,553,802			$	2,265,231
Texas			2,045,305				1,872,165
Corporate and other			225,626				190,449
		$	4,824,733			$	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):

 

		Years Ended December 31,
		2014				2013				2012
Natural gas and liquids sales:
Natural gas		$	1,138,110			$	708,817			$	396,867
NGLs			1,347,111				1,132,481				657,271
Condensate			142,094				118,095				85,234
Other			(5,887	)			(249	)			(2,111	)
Total		$	2,621,428			$	1,959,144			$	1,137,261

 

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NOTE 20 – 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 include the financial statements of WestOK, LLC, WestTex, LLC and 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 5), 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, WTLPG 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 December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012. 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 December 31, 2014		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Assets
Cash and cash equivalents		$	—			$	174			$	7,929			$	—			$	8,103
Accounts receivable – affiliates			—				206,617				—				(206,617	)			—
Other current assets			121				150,649				196,267				(1,086	)			345,951
Total current assets			121				357,440				204,196				(207,703	)			354,054
Property, plant and equipment, net			—				915,956				2,334,017				—				3,249,973
Intangible assets, net			—				525,730				70,531				—				596,261
Goodwill			—				320,869				44,894				—				365,763
Equity method investment in joint ventures			—				—				177,212				—				177,212
Long term portion of derivative assets			—				37,398				—				—				37,398
Long term notes receivable			—				—				1,852,928				(1,852,928	)			—
Equity investments			4,277,668				903,831				—				(5,181,499	)			—
Other assets, net			37,335				6,287				450				—				44,072
Total assets		$	4,315,124			$	3,067,511			$	4,684,228			$	(7,242,130	)		$	4,824,733
Liabilities and Equity
Accounts payable – affiliates		$	(169,727	)		$	—			$	380,782			$	(206,617	)		$	4,438
Other current liabilities			27,325				68,562				229,274				—				325,161
Total current liabilities			(142,402	)			68,562				610,056				(206,617	)			329,599
Long-term debt, less current portion			1,938,881				5				—				—				1,938,886
Deferred income taxes, net			—				30,914				—				—				30,914
Other long-term liabilities			178				689				6,000				—				6,867
Equity			2,518,467				2,967,341				4,068,172				(7,035,513	)			2,518,467
Total liabilities and equity		$	4,315,124			$	3,067,511			$	4,684,228			$	(7,242,130	)		$	4,824,733
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 ventures			—				—				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

 

44

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December 31, 2013		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
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

 

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Statements of Operations and Comprehensive Income		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Year Ended December 31, 2014
Total revenues		$	—			$	707,037			$	2,276,607			$	(8,524	)		$	2,975,120
Total costs and expenses			(93,716	)			(638,352	)			(2,057,682	)			8,524				(2,781,226	)
Equity income (loss)			310,196				191,306				(14,007	)			(501,502	)			(14,007	)
Gain on asset disposition			—				47,829				(448	)			—				47,381
Income (loss), before tax			216,480				307,820				204,470				(501,502	)			227,268
Income tax benefit			—				(2,376	)			—				—				(2,376	)
Net income (loss)			216,480				310,196				204,470				(501,502	)			229,644
Income attributable to non-controlling interest			—				—				(13,164	)			—				(13,164	)
Preferred unit imputed dividend effect			(45,513	)			—				—				—				(45,513	)
Preferred unit dividends in kind			(42,552	)			—				—				—				(42,552	)
Preferred unit dividends			(8,233	)			—				—				—				(8,233	)
Net income (loss) attributable to common limited partners and the General Partner		$	120,182			$	310,196			$	191,306			$	(501,502	)		$	120,182
Year Ended December 31, 2013
Total revenues		$	—			$	504,392			$	1,684,625			$	(82,168	)		$	2,106,849
Total costs and expenses			(86,965	)			(610,208	)			(1,507,806	)			80,955				(2,124,024	)
Equity income (loss)			14,954				160,371				(4,736	)			(175,325	)			(4,736	)
Loss on asset disposition			—				(1,519	)			—				—				(1,519	)
Goodwill impairment loss			—				(43,866	)			—				—				(43,866	)
Loss on early extinguishment of debt			(26,601	)			—				—				—				(26,601	)
Income (loss), before tax			(98,612	)			9,170				172,083				(176,538	)			(93,897	)
Income tax benefit			—				(2,260	)			—				—				(2,260	)
Net income (loss)			(98,612	)			11,430				172,083				(176,538	)			(91,637	)
Income attributable to non-controlling interest			—				—				(6,975	)			—				(6,975	)
Preferred unit imputed dividend effect			(29,485	)			—				—				—				(29,485	)
Preferred unit dividends in kind			(23,583	)			—				—				—				(23,583	)
Net income (loss) attributable to common limited partners and the General Partner		$	(151,680	)		$	11,430			$	165,108			$	(176,538	)		$	(151,680	)
Year Ended December 31, 2012
Total revenues		$	—			$	240,679			$	1,005,341			$	—			$	1,246,020
Total costs and expenses			(39,462	)			(272,284	)			(872,362	)			—				(1,184,108	)
Equity income (loss)			101,511				139,339				—				(234,527	)			6,323
Income (loss), before tax			62,049				107,734				132,979				(234,527	)			68,235
Income tax expense			—				176				—				—				176
Net income (loss)			62,049				107,558				132,979				(234,527	)			68,059
Income attributable to non-controlling interest			—				—				(6,010	)			—				(6,010	)
Net income (loss) attributable to common limited partners and the General Partner		$	62,049			$	107,558			$	126,969			$	(234,527	)		$	62,049
Other comprehensive income:
Adjustment for realized losses on derivatives reclassified to net income (loss)			4,390				4,390				—				(4,390	)			4,390
Comprehensive income (loss) attributable to common limited partners and the General Partner		$	66,439			$	111,948			$	126,969			$	(238,917	)		$	66,439

 

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Statements of Cash Flows		Parent				Guarantor Subsidiaries				Non- Guarantor Subsidiaries				Consolidating Adjustments				Consolidated
Year Ended December 31, 2014
Net cash provided by (used in):
Operating activities		$	111,086			$	269,713			$	277,409			$	(365,679	)		$	292,529
Investing activities			(346,610	)			(247,910	)			(306,057	)			376,238				(524,339	)
Financing activities			235,524				(21,797	)			31,831				(10,559	)			234,999
Net change in cash and cash equivalents			—				6				3,183				—				3,189
Cash and cash equivalents, beginning of period			—				168				4,746				—				4,914
Cash and cash equivalents, end of period		$	—			$	174			$	7,929			$	—			$	8,103
Year Ended December 31, 2013
Net cash provided by (used in):
Operating activities		$	(493,139	)		$	136,862			$	281,141			$	285,980			$	210,844
Investing activities			(757,365	)			(806,159	)			(577,527	)			697,968				(1,443,083	)
Financing activities			1,250,504				669,308				297,891				(983,948	)			1,233,755
Net change in cash and cash equivalents			—				11				1,505				—				1,516
Cash and cash equivalents, beginning of period			—				157				3,241				—				3,398
Cash and cash equivalents, end of period		$	—			$	168			$	4,746			$	—			$	4,914
Year Ended December 31, 2012
Net cash provided by (used in):
Operating activities		$	(432,255	)		$	133,153			$	186,494			$	287,246			$	174,638
Total investing activities			(405,501	)			(431,835	)			(419,427	)			250,122				(1,006,641	)
Financing activities			837,756				298,671				236,174				(537,368	)			835,233
Net change in cash and cash equivalents			—				(11	)			3,241				—				3,230
Cash and cash equivalents, beginning of period			—				168				—				—				168
Cash and cash equivalents, end of period		$	—			$	157			$	3,241			$	—			$	3,398

NOTE 21 – QUARTERLY FINANCIAL DATA (Unaudited)

 

		Fourth Quarter(1)				Third Quarter(2)				Second Quarter(3)				First Quarter(4)
		(in thousands, except per unit data)
Year ended December 31, 2014:
Revenue		$	799,978			$	761,182			$	713,956			$	700,004
Costs and expenses			(684,124	)			(707,084	)			(698,543	)			(691,475	)
Equity loss in joint ventures			(3,543	)			(4,711	)			(3,875	)			(1,878	)
Gain (loss) on asset disposition			(448	)			(636	)			48,465				—
Income before tax			111,863				48,751				60,003				6,651
Income tax benefit			857				623				498				398
Net income			112,720				49,374				60,501				7,049
Income attributable to non-controlling interests			(2,708	)			(4,029	)			(3,965	)			(2,462	)
Preferred unit imputed dividend effect			(11,379	)			(11,378	)			(11,378	)			(11,378	)
Preferred unit dividends in kind			(11,019	)			(11,408	)			(10,406	)			(9,719	)
Preferred unit dividends			(2,609	)			(2,609	)			(2,609	)			(406	)
Net income (loss) attributable to common limited partners and the General Partner			85,005				19,950				32,143				(16,916	)
Net income (loss) attributable to common limited partners per unit – basic and diluted(5)(6)		$	0.76			$	0.13			$	0.27			$	(0.27	)

 

(1)	Net income includes a $112.9 million non-cash derivative gain.

(2)	Net income includes a $26.7 million non-cash derivative gain.

(3)	Net income includes a $0.3 million non-cash derivative gain.

(4)	Net income includes a $1.2 million non-cash derivative gain.

(5)	For the first quarter of the year ended December 31, 2014, approximately 1,543,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit as the impact of the conversion would have been anti-dilutive.

 

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(6)	For the first quarter of the year ended December 31, 2014, approximately 13,964,000 weighted average Class D Preferred Units were excluded from the computation of diluted earnings attributable to common limited partners per unit as the impact of the conversion would have been anti-dilutive.

 

		Fourth Quarter(1)				Third Quarter(2)				Second Quarter(3)				First Quarter(4)
		(in thousands, except per unit data)
Year ended December 31, 2013:
Revenue		$	580,128			$	557,870			$	560,939			$	407,912
Costs and expenses			(581,918	)			(582,369	)			(548,866	)			(410,871	)
Equity income (loss) in joint ventures			(4,422	)			(1,882	)			(472	)			2,040
Loss on asset disposition			—				—				(1,519	)			—
Goodwill impairment loss			(43,866	)			—				—				—
Loss on early extinguishment of debt			—				—				(19	)			(26,582	)
Income (loss) before tax			(50,078	)			(26,381	)			10,063				(27,501	)
Income tax benefit			1,406				817				28				9
Net income (loss)			(48,672	)			(25,564	)			10,091				(27,492	)
Income attributable to non-controlling interests			(2,282	)			(1,514	)			(1,810	)			(1,369	)
Preferred unit imputed dividend effect			(11,378	)			(11,378	)			(6,729	)			—
Preferred unit dividends in kind			(9,170	)			(9,072	)			(5,341	)			—
Net loss attributable to common limited partners and the General Partner			(71,502	)			(47,528	)			(3,789	)			(28,861	)
Net loss attributable to common limited partners per unit – basic and diluted(5)(6)		$	(0.94	)		$	(0.66	)		$	(0.11	)		$	(0.48	)

 

(1)	Net income includes a $15.4 million non-cash derivative loss.

(2)	Net income includes a $23.6 million non-cash derivative loss.

(3)	Net income includes a $24.3 million non-cash derivative gain.

(4)	Net income includes a $13.7 million non-cash derivative loss.

(5)

For the fourth, third, second, and first quarters of the year ended December 31, 2013, approximately 1,476,000, 1,455,000, 967,000, and 1,055,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such phantom units would have been anti-dilutive.

(6)

For the fourth, third, and second quarters of the year ended December 31, 2013, approximately 13,709,000, 13,518,000, and 9,013,000 weighted average Class D Preferred Units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit as the impact of the conversion would have been anti-dilutive.

NOTE 22 – SUBSEQUENT EVENTS

On January 9, 2015, 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 December 31, 2014. The $62.2 million distribution, including $8.1 million to the General Partner for its general partner interest and incentive distribution rights, was paid on February 13, 2015 to unitholders of record at the close of business on January 21, 2015 (see Note 6).

On January 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 October 15, 2014 through January 14, 2015 (See Note 6).

On January 15, 2015, TRP announced cash tender offers to redeem any and all of the outstanding $500.0 million aggregate principal amount of the 6.625% Senior Notes; $400.0 million aggregate principal amount of the 4.75% Senior Notes; and $650.0 million aggregate principal amount of the 5.875% Senior Notes (see Note 14). TRP made the cash tender offers in connection with, and conditioned upon, the consummation of the Merger (see Note 3). The Merger, however, is not conditioned on the consummation of the tender offers. On February 2, 2015, TRP announced as of January 29, 2015, it had received tenders pursuant to its previously announced cash tender offers on January 15, 2015 from holders representing:

 

•

less than a majority of the total outstanding $500.0 million of the 6.625% Senior Notes;

 

48

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•

approximately 98.3% of the total outstanding $400.0 million of the 4.75% Senior Notes; and

 

•

approximately 91.0% of the total outstanding $650.0 million of the 5.875% Senior Notes.

Also on February 2, 2015, TRP announced a change of control cash tender offer for any and all of the outstanding $500.0 million of the 6.625% Senior Notes. TRP made the change of control cash tender offer in connection with, and conditioned upon, the consummation of the Merger. The Merger, however, is not conditioned on the consummation of the change in control cash tender offer. The change in control cash tender offer was made independently of TRP’s January 15, 2015 cash tender offers (see Note 14).

On January 22, 2015, the Partnership exercised its right under the Class D Certificate of Designation to convert all outstanding Class D Preferred Units and unpaid distributions into common limited partner units, based upon the Execution Date Unit Price of $29.75 per unit, as defined by the Class D Certificate of Designation. As a result of the conversion, 15,389,575 common limited partner units were issued (see Note 6).

On January 27, 2015, the Partnership delivered notice of its intention to redeem all outstanding shares of its Class E Preferred Units. The redemption of the Class E Preferred Units will occur immediately prior to the close of the Merger (See Note 3). The Partnership expects the Merger to close on February 27, 2015 and, accordingly, the redemption would also be on February 27, 2015. The Class E Preferred Units will be redeemed at a redemption price of $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions on the Class E Preferred Units as of the redemption date. TRP has agreed to deposit the funds for such redemption with the paying agent (see Note 6).

On February 20, 2015, the Partnership held a special meeting, where holders of a majority of its common units approved the Merger. In addition, at special meetings held on the same day: (i) a majority of the holders of ATLS common units approved the ATLS Merger and (ii) a majority of the holders of TRC common stock approved the issuance of TRC shares in connection with the Merger. Completion of each of the ATLS Merger and the Spin-Off are also conditioned on the parties standing ready to complete the Merger. The Merger is expected to close on February 27, 2015 (see Note 3).

On February 27, 2015, the Partnership agreed to transfer 100% of the Partnership’s interest in gas gathering assets located in the Appalachian Basin of Tennessee to the Partnership’s affiliate, ARP, for $1.0 million plus working capital adjustments, concurrent with the closing of the Merger on February 27, 2015.

 

49