Targa Resources (TRGP) 8-K/A Report of Independent Certified Public Accountants

Exhibit 99.1

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Board of Directors

Atlas Energy L.P. (“RemainCo”)

We have audited the accompanying consolidated financial statements of RemainCo (see Note 1), which comprise the consolidated balance sheets as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, equity and cash flows for the three years then ended, and the related notes to the financial statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of RemainCo as of December 31, 2014 and 2013, and the results of its operations and its cash flows for the three years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 27, 2015

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CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31, 2014		December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	24,852	$	12,876
Accounts receivable		240,576		219,297
Current portion of derivative assets		88,007		174
Prepaid expenses and other		17,407		17,431
Total current assets		370,842		249,778
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		47,310		50,298
Total assets	$	4,844,759	$	4,339,682
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	1,124	$	1,424
Accounts payable – affiliates		4,438		2,912
Accounts payable		87,076		79,051
Accrued liabilities		52,421		50,662
Accrued interest payable		26,940		26,753
Current portion of derivative liabilities		—		11,244
Accrued producer liabilities		161,208		152,309
Total current liabilities		333,207		324,355
Long-term portion of derivative liabilities		—		320
Long-term debt, less current portion		2,026,861		1,795,661
Deferred income taxes, net		30,914		33,290
Other long-term liabilities		7,203		7,815
Commitments and contingencies
Equity:
ATLS Common limited partners’ interests		9,960		3,875
Total partners’ capital		9,960		3,875
Non-controlling interest		2,436,614		2,174,366
Total equity		2,446,574		2,178,241
Total liabilities and equity	$	4,844,759	$	4,339,682

See accompanying notes to consolidated financial statements

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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		21,559			11,295			10,098
Total revenues		2,975,124			2,106,852			1,246,021
Costs and expenses:
Natural gas and liquids cost of sales		2,291,914			1,690,382			927,946
Plant operating		113,606			94,572			62,098
General and administrative		115,771			81,072			71,102
Compensation reimbursement – affiliates		5,050			5,000			3,800
Other costs		6,073			20,005			15,069
Depreciation and amortization		202,543			168,617			90,029
Interest		99,922			92,870			41,972
Total costs and expenses		2,834,879			2,152,473			1,212,016
Equity income (loss) in joint ventures		(14,007	)		(4,736	)		6,323
Gain (loss) on asset sales and other		47,381			(1,519	)		—
Goodwill impairment loss		—			(43,866	)		—
Loss on early extinguishment of debt		—			(26,601	)		—
Income (loss) from continuing operations before tax		173,619			(122,343	)		40,328
Income tax expense (benefit)		(2,376	)		(2,260	)		176
Net Income (loss)		175,995			(120,083	)		40,152
(Income) loss attributable to non-controlling interests		(196,745	)		93,281			(52,716	)
Net income (loss) attributable to common limited partners	$	(20,750	)	$	(26,802	)	$	(12,564	)
Net income (loss) attributable to common limited partners per unit – basic and diluted:
Basic and Diluted	$	(0.40	)	$	(0.52	)	$	(0.24	)
Weighted average common limited partner units		51,810			51,387			51,327

See accompanying notes to consolidated financial statements

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Years Ended December 31,
	2014			2013			2012
Net income (loss)	$	175,995		$	(120,083	)	$	40,152
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)	$	175,995		$	(120,083	)	$	44,542
Comprehensive (income) loss attributable to non-controlling interests	$	(196,745	)	$	93,281		$	(56,553	)
Comprehensive income (loss)	$	(20,750	)	$	(26,802	)	$	(12,011	)

See accompanying notes to consolidated financial statements

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CONSOLIDATED STATEMENTS OF EQUITY

(in thousands, except unit data)

	Common Limited Partners’ Capital					Accumulated Other Comprehensive Income/(Loss)			Non- Controlling Interest			Total Partners’ Capital
	Units		Amount
Balance at January 1, 2012		51,278,362	$	99,581		$	(553	)	$	1,159,705		$	1,258,733
Distributions to non-controlling interests		—		—			—			(107,173	)		(107,173	)
Net issued and unissued units under incentive plans		87,220		17,837			—			10,855			28,692
Distributions paid to common limited partners		—		(51,837	)		—			—			(51,837	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(2,070	)		—			(1,984	)		(4,054	)
Gain on sale of Atlas Pipeline Partners, L.P.’s unit issuances		—		7,948			—			(7,948	)		—
Atlas Pipeline Partners, L.P. purchase price allocation		—		—			—			89,440			89,440
Non-controlling interests’ capital contributions		—		—			—			321,491			321,491
Net investment from Atlas Energy		—		31,176			—			—			31,176
Other comprehensive income		—		—			553			3,837			4,390
Net income (loss)		—		(12,564	)		—			52,716			40,152
Balance December 31, 2012		51,365,582	$	90,071		$	—		$	1,520,939		$	1,611,010
Distributions to non-controlling interests		—		—			—			(167,853	)		(167,853	)
Contributions from Atlas Pipeline Partners, L.P.’s non-controlling interests		—		—			—			17,021			17,021
Net issued and unissued units under incentive plans		47,982		22,532			—			19,143			41,675
Distributions paid to common limited partners		—		(77,598	)		—			—			(77,598	)
Distribution equivalent rights paid on unissued units under incentive plans		—		(3,473	)		—			(3,092	)		(6,565	)
Gain on sale of Atlas Pipeline Partners, L.P.’s unit issuances		—		11,920			—			(11,920	)		—
Atlas Pipeline Partners, L.P. purchase price allocation		—		—			—			(30,535	)		(30,535	)
Non-controlling interests’ capital contributions		—		—			—			923,944			923,944
Net distribution to Atlas Energy		—		(12,775	)		—			—			(12,775	)
Net loss		—		(26,802	)		—			(93,281	)		(120,083	)
Balance at December 31, 2013		51,413,564	$	3,875		$	—		$	2,174,366		$	2,178,241
Distributions to non-controlling interests		—		—			—			(203,295	)		(203,295	)
Contributions from Atlas Pipeline Partners, L.P.’s non-controlling interests		—		—			—			11,720			11,720
Net issued and unissued units under incentive plans		548,737		42,739			—			22,795			65,534
Distributions paid to common limited partners		—		(99,996	)		—			—			(99,996	)

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	Common Limited Partners’ Capital					Accumulated Other Comprehensive Income/(Loss)		Non- Controlling Interest			Total Partners’ Capital
	Units		Amount
Distribution equivalent rights paid on unissued units under incentive plans		—		(5,429	)		—		(4,250	)		(9,679	)
Gain on sale of Atlas Pipeline Partners, L.P.’s unit issuances		—		2,699			—		(2,699	)		—
Atlas Pipeline Partners, L.P. distributions payable		—		—			—		(2,609	)		(2,609	)
Non-controlling interests’ capital contributions		—		—			—		243,841			243,841
Net investment from Atlas Energy		—		86,822			—		—			86,822
Net loss		—		(20,750	)		—		196,745			175,995
Balance at December 31, 2014		51,962,301	$	9,960		$	—	$	2,436,614		$	2,446,574

See accompanying notes to consolidated financial statements

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Years Ended December 31,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	175,995		$	(120,083	)	$	40,152
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 (income) loss in joint ventures		14,007			4,736			(6,323	)
Distributions received from equity method joint ventures		5,264			7,400			7,200
Distributions paid to non-controlling interests		(203,295	)		(167,853	)		(107,173	)
Non-cash compensation expense		69,558			38,487			29,473
Amortization of deferred finance costs		7,844			7,386			4,758
Loss on early extinguishment of debt		—			26,601			—
Loss (gain) on asset disposition		(47,381	)		1,519			—
Deferred 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		(22,335	)		(73,302	)		(15,300	)
Accounts payable and accrued liabilities		13,457			66,136			23,222
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		80,282			38,801			58,869
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	)
Capital contributions to joint ventures		(8,061	)		(13,366	)		—
Net proceeds from asset disposition		130,966			—			—
Other		340			(7,278	)		1,170
Net cash used in investing activities	$	(524,502	)	$	(1,447,091	)	$	(1,005,973	)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

(in thousands)

	Years Ended December 31,
	2014			2013			2012
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities	$	1,271,000		$	1,267,000		$	1,173,875
Repayments under credit facilities		(1,038,900	)		(1,408,000	)		(1,019,500	)
Net proceeds from issuance of Atlas Pipeline Partners, L.P.’s common and preferred limited partner units		243,841			923,944			321,491
Net proceeds from issuance of long term debt		—			1,114,492			495,374
Repayment of long-term debt		—			(365,822	)		—
Principal payments on capital leases		(525	)		(10,750	)		(2,523	)
Contributions from non-controlling interest holders		11,720			17,021			—
Premium paid on retirement of Atlas Pipeline Partners, L.P. long-term debt		—			(25,581	)		—
Payment of deferred financing costs		(3,323	)		(929	)		(4,542	)
Payment for acquisition-based contingent consideration		—			(6,000	)		—
Net investment from (distribution to) Atlas Energy, L.P.		86,822			(12,775	)		31,176
Distributions paid to unitholders		(99,996	)		(77,598	)		(51,837	)
Other		(14,443	)		(7,346	)		(5,568	)
Net cash provided by financing activities		456,196			1,407,656			937,946
Net change in cash and cash equivalents		11,976			(634	)		(9,158	)
Cash and cash equivalents, beginning of year		12,876			13,510			22,668
Cash and cash equivalents, end of year	$	24,852		$	12,876		$	13,510

See accompanying notes to consolidated financial statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PRESENTATION

On October 13, 2014, Atlas Energy, L.P. (“Atlas Energy”; NYSE: ATLS) and Atlas Pipeline Partners, L.P. (“APL”; NYSE: APL), both publicly-traded Delaware master-limited partnerships, announced their respective entries into definitive merger agreements with Targa Resources Corp. (“TRC”; NYSE: TRGP) and Targa Resources Partners, L.P. (“TRP”; NYSE: NGLS), whereby Atlas Energy and APL would merge into TRC and TRP, respectively. In connection with the merger agreements, the board of directors of Atlas Energy also intends to transfer all of its interests not related to APL to Atlas Energy Group, LLC (“SpinCo”). Subsequent to the formation of SpinCo, Atlas Energy’s remaining operations will consist solely of its interests in APL, including its 2.0% general partner interest, ownership of all of the incentive distribution rights, and 5,754,253 common limited partner units, which represented an approximate 5.5% limited partner interest at December 31, 2014 (“RemainCo”).

The accompanying consolidated financial statements present the assets, liabilities, revenues and expenses of (1) Atlas Energy, excluding those to be transferred to SpinCo, and (2) APL.

The transfer of assets to SpinCo is contingent upon the execution of Atlas Energy’s and APL’s merger agreements with TRC and TRP.

APL is engaged in gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States; natural gas gathering services in the Appalachian Basin in the northeastern region of the United States; and the transportation of NGLs in the southwestern region of the United States.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated balance sheets at December 31, 2014 and 2013 and the related consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions that would have existed or the results of operations if RemainCo had been operated as an unaffiliated entity. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the consolidated balance sheets and related consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of RemainCo. Actual balances and results could be different from those estimates. Transactions between RemainCo and other Atlas Energy operations have been identified in the consolidated financial statements as transactions between affiliates.

RemainCo combines the financial statements of APL into its consolidated financial statements rather than present its ownership interest as an equity investment, as RemainCo will control APL through its general partnership interests therein. As such, the non-controlling interests in APL are reflected as (income) loss attributable to non-controlling interests in its consolidated statements of operations and as a component of equity on its consolidated balance sheets. All material intercompany transactions have been eliminated.

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RemainCo’s consolidated financial statements include APL’s 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 RemainCo’s consolidated balance sheets.

RemainCo’s consolidated financial statements also include APL’s 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).

RemainCo consolidates 100% of these joint ventures and reflects the non-controlling interest in the joint ventures on its statements of operations. RemainCo 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 RemainCo only include the effective portion of APL’s changes in the fair value of unsettled derivative contracts, which were previously accounted for as cash flow hedges (see Note 10). These contracts were wholly-owned by APL and the related gains and losses were not shared with APL’s non-controlling interests. RemainCo does not have any other types of transactions which would be included within other comprehensive income (loss). During the year ended December 31, 2012, RemainCo reclassified $4.4 million from other comprehensive income to natural gas and liquids sales within RemainCo’s consolidated statements of operations. As of December 31, 2014 and 2013, all amounts had been reclassified out of accumulated other comprehensive income and RemainCo had no amounts outstanding within accumulated other comprehensive income.

Equity Method Investments

RemainCo’s consolidated financial statements include APL’s previous interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) which was sold in May 2014 (see Note 5); and APL’s 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. (“T2Co-Gen”) (the “T2 Joint Ventures”), which were acquired as part of APL’s acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) (the “TEAK Acquisition”) (see Notes 4 and 5).

RemainCo accounts for its investments in these joint ventures under the equity method of accounting. Under this method, RemainCo records its proportionate share of the joint ventures’ net income (loss) as equity income 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

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lived intangible assets are amortized over the useful life of the related assets and recorded as a reduction to equity investment on RemainCo’s consolidated balance sheet with an offsetting reduction to equity income on RemainCo’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. RemainCo noted no indicators of impairment for its equity method investments, and thus no impairment charges were recognized for the years ended as of December 31, 2014, 2013 and 2012.

Use of Estimates

The preparation of RemainCo’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 RemainCo’s consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods. RemainCo’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 RemainCo believes the operating results presented represent actual results in all material respects (see “–Revenue Recognition” accounting policy for further description).

Cash and Cash Equivalents

RemainCo 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, RemainCo reclassified the balance related to book overdrafts of $23.9 million and $28.8 million, respectively, from cash and cash equivalents to accounts payable on RemainCo’s consolidated balance sheets.

Receivables

The amounts included within accounts receivable on RemainCo’s consolidated balance sheets at December 31, 2014 and 2013 are associated entirely with APL’s operating activity. In evaluating the realizability of its accounts receivable, APL performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by APL’s review of its customers’ credit information. APL extends credit on an unsecured basis to many of its customers. At December 31, 2014 and 2013, APL had no material uncollectable accounts receivable.

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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. APL’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 APL’s NGL fixed price swaps. APL’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 SouthTXsystem were revised and the settlement and valuation was converted from a FIFO method to a fair value method. APL’s NGL linefill is included within prepaid expenses and other on RemainCo’s consolidated balance sheets. See Note 12 for more information regarding APL’s NGL linefill.

Property, Plant and Equipment

The amounts included within property, plant and equipment on RemainCo’s consolidated balance sheets at December 31, 2014 and 2013 are associated entirely with APL’s operating activity. 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. APL 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. APL 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 RemainCo’s results of operations.

APL’s 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 RemainCo’s consolidated balance sheets (see Note 7). APL’s obligations under capital leases are accounted for as current and noncurrent liabilities and are included within debt on RemainCo’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 ofLong-Lived Assets

RemainCo reviews itslong-lived assets other than goodwill 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.

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Asset Retirement Obligation

APL performs ongoing analysis of asset removal and site restoration costs that it may be required to perform under law or contract once an asset has been permanently taken out of service. APL has property, plant and equipment at locations owned by APL and at sites leased or under right of way agreements. APL is under no contractual obligation to remove the assets at locations it owns. In evaluating its asset retirement obligation, APL 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, APL 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

The amounts included within goodwill on RemainCo’s consolidated balance sheets at December 31, 2014 and 2013 are associated entirely with APL’s operating activity. 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. APL evaluates goodwill for impairment annually, on December 31 for all reporting units, except SouthTX, which is evaluated on April 30. APL 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. APL 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 RemainCo’s consolidated balance sheets and a goodwill impairment loss on RemainCo’s consolidated statements of operations (see Note 8).

Intangible Assets

The amounts included within intangible assets on RemainCo’s consolidated balance sheets at December 31, 2014 and 2013 are associated entirely with APL’s operating activity. APL 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, APL 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 APL’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 APL’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).

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Derivative Instruments

APL enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates. APL 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”). APL 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 RemainCo’s consolidated statements of operations. Prior to discontinuance of hedge accounting, the change in APL’s fair value of these commodity derivative instruments was recognized in accumulated other comprehensive loss within equity on RemainCo’s consolidated balance sheets. Amounts in accumulated other comprehensive loss were reclassified to RemainCo’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. RemainCo has reclassified all earnings out of accumulated other comprehensive loss within equity on its consolidated balance sheets and had no amounts in accumulated other comprehensive loss as of December 31, 2014 and 2013.

Fair Value of Financial Instruments

RemainCo 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 RemainCo’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.

RemainCo uses a market approach fair value methodology to value APL’s assets and liabilities for its outstanding derivative contracts (see Note 12). APL manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. APL has a financial risk management committee (the “Financial Risk Management Committee”), which sets the policies, procedures and valuation methods utilized by APL to value its derivative contracts. The Financial Risk Management Committee members include, among others, APL’s Chief Executive Officer, Chief Financial Officer and Vice Chairman of the managing board of APL’s 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

APL and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying consolidated financial statements. Certain corporate subsidiaries of APL are subject to federal and state income tax.

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Each of the entities which comprise RemainCo evaluate tax positions taken or expected to be taken in the course of preparing their respective 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. RemainCo’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. RemainCo’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. RemainCo has not recognized any potential interest or penalties in its consolidated financial statements for the years ended December 31, 2014 and 2013.

RemainCo files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, RemainCo is no longer subject to income tax examinations by major tax authorities for years prior to 2011. RemainCo 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 APL’s Texas Franchise Tax for franchise report years 2008 through 2011.

APL Arkoma, Inc. is subject to federal and state income tax. APL’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 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 APL earnings that are generally not subject to federal and state income taxes at RemainCo level. See Note 10 for discussion of APL’s federal and state income tax expense (benefits) of its taxable subsidiary as well as its net deferred income tax assets (liabilities).

General and Administrative Expenses

For the years ended December 31, 2014, 2013 and 2012, Atlas Energy has allocated $46.6 million, $25.2 million and $27.7 million, respectively, of its historical general and administrative expenses to RemainCo relating to the amounts associated with the management of RemainCo’s operations, including the Atlas Energy long-term incentive plan (see Note 16). RemainCo has reviewed Atlas Energy’s general and administrative expense allocation methodology and believes the methodology is reasonable and reflects the approximate general and administrative costs of the management of its operations.

Interest Expense

For the year ended December 31, 2014, 2013 and 2012, Atlas Energy has allocated $6.8 million, $3.2 million and $0.2 million, respectively, of its historical interest expense to RemainCo relating to the amounts associated with the financing of RemainCo’s operations. RemainCo has reviewed Atlas Energy’s interest expense allocation methodology and believes the methodology is reasonable and reflects the approximate interest expense associated with the management of its operations.

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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 RemainCo’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 RemainCo’s consolidated balance sheets. Compensation expense associated with unit-based payments is recognized within general and administrative expenses on RemainCo’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 APL’s unit-based compensation.

Environmental Matters

APL is subject to various federal, state and local laws and regulations relating to the protection of the environment. APL 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, APL is unable to assess the timing and/or effect of potential liabilities related to greenhouse gas emissions or other environmental issues. APL maintains insurance, which may cover, in whole or in part, certain environmental expenditures. At December 31, 2014 and 2013, APL 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 APL’s subsidiaries that owned an interest in WTLPG on May 14, 2014 (see Note 5), RemainCo 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 RemainCo will manage its operations going forward. RemainCo has adjusted its segment presentation from the amounts previously presented to reflect the realignment of the segments.

The Oklahoma segment consists of APL’s 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) APL’s 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) APL’s 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) APL’s gas treating operations, which own contract gas treating facilities located in various shale plays; and (2) APL’s former

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subsidiaries’ interest in WTLPG, has been eliminated and the financial information is now included within Corporate and Other. APL’s 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.

Revenue Recognition

RemainCo’s revenue primarily consists of APL’s sales of natural gas and NGLs along with the fees earned from APL’s gathering, processing and treating operations. Under certain agreements, APL 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, APL 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.

APL 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 APL’s records and management estimates of the related gathering and compression fees and applicable product prices. RemainCo 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

APL’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 RemainCo’s consolidated balance sheets represent APL’s 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 APL 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, APL and the producer are directly dependent on the volume of the commodity and its value; APL effectively owns a percentage of the commodity and revenues are directly correlated to its market value. APL’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 APL, 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 APL’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. APL must make up or “keep the producer whole” for this loss in BTU quantity. To offset themake-up obligation, APL retains the NGLs, which are extracted, and sells them for its own account. APL recognizes the purchases of natural gas during the period to keep producers whole as costs of sales under Keep-Whole contracts. During 2014, APL renegotiated most of its Keep-Whole contracts and converted them into POP contracts. As a result, APL does not expect Keep-Whole contracts to have any material impact to its cost of sales going forward.

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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.

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, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common limited partner units outstanding during the period.

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. Atlas Energy’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 Atlas Energy. The participation rights result in a non-contingent transfer of value each time Atlas Energy 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. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

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

	Year Ended December 31,
Continuing Operations:	2014			2013			2012
Net income (loss)	$	175,995		$	(120,083	)	$	40,152
(Income) loss attributable to non-controlling interests		(196,745	)		93,281			(52,716	)
Net loss attributable to common limited partners		(20,750	)		(26,802	)		(12,564	)
Less: Net income attributable to participating securities – phantom units(1)		—			—			—
Net loss utilized in the calculation of net loss attributable to common limited partners per unit	$	(20,750	)	$	(26,802	)	$	(12,564	)

⁽¹⁾  Net income attributable to common limited partners’ ownership interests 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 years ended December 31, 2013 and 2012, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 2,827,000 and 2,278,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating

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securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, as calculated by the treasury stock method. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of Atlas Energy’s long-term incentive plans (see Note 16).

The following table sets forth the reconciliation of Atlas Energy’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):

	Year Ended December 31,		Year Ended December 31,		Year Ended December 31,
	2014		2013		2012
Weighted average number of common limited partners per unit—basic		51,810		51,387		51,327
Add effect of dilutive incentive awards(1)		—		—		—
Weighted average number of common limited partners per unit—diluted		51,810		51,387		51,327

⁽¹⁾  For the years ended December 31, 2014, 2013 and 2012 approximately 4,473,000, 3,995,000 and 2,867,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

Recently Adopted Accounting Standards

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

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Recently Issued Accounting Standard Updates

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 RemainCo can make an election to apply the guidance to future change-in-control events or to its most recent change-in-control event. RemainCo 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. RemainCo plans on applying the new standard for the annual period ending December 31, 2016. RemainCo 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. RemainCo 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, RemainCo does not expect the new standard to have a material impact on the results of operations.

NOTE 3 – TARGA RESOURCES PARTNERS LP MERGER

On October 13, 2014, APL, ATLS and Atlas Pipeline Partners GP, LLC (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

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to acquire APL through a merger of a newly-formed, wholly-owned subsidiary of TRP with and into APL (the “Merger”). Upon completion of the Merger, holders of APL’s common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each APL common unit. Persuant to the terms and conditions of the Merger Agreement, APL 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, APL 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 and TRP has agreed to deposit the funds for redemption with its 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 APL, 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”).

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

The closing of the Merger is subject to approval by holders of a majority of APL’s common units and other closing conditions, including the closing of the ATLS Merger and the Spin-Off. On February 20, 2015, APL held a special meeting, where holders of a majority of its common units approved the Merger. In addition, at special meetings held on the sameday: (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, APL agreed to transfer 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee to APL’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, APL 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.

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APL 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 APL (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 APL (see Note 6). APL 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).

APL accounted for this transaction as a business combination. Accordingly, APL 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

Cardinal Midstream, LLC

On December 20, 2012, APL 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).

APL 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 APL (see Note 6). APL funded the remaining purchase price from its senior secured revolving credit facility (see Note 14).

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APL accounted for this transaction as a business combination. Accordingly, APL 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 APL 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, APL completed the sale of two subsidiaries, which held an aggregate 20% interest in WTLPG, to a subsidiary of Martin Midstream Partners LP (NYSE: MMLP). APL received $131.0 million in proceeds, net of selling costs and final working capital adjustments, which were used to pay down APL’s revolving credit facility (see Note 14). As a result of the sale, APL recorded a $47.8 million gain on asset dispositions, which is included in RemainCo’s consolidated statements of operations for the year ended December 31, 2014.

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, APL 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 RemainCo’s consolidated statements of operations.

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T2 Joint Ventures

On May 7, 2013, APL 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.

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

The following table presents the value of APL’s equity method investments in joint ventures as of December 31, 2014 and December 31, 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 APL’s equity income (loss) in joint ventures for each of the three 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

APL Common Units

In November 2012, APL entered into an equity distribution program with Citigroup Global Markets, Inc. (“Citigroup”). Pursuant to this program, APL 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

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sale. During the years ended December 31, 2013 and 2012, APL 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. APL also received capital contributions from Atlas Energy 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 APL. The net proceeds from the common unit offering were utilized for general partnership purposes.

In December 2012, APL 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 Atlas Energy to maintain its 2.0% general partner interest. APL utilized the net proceeds from the common unit offering to partially finance the Cardinal Acquisition (see Note 4).

In April 2013, APL 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. APL also received a capital contribution from Atlas Energy of $8.3 million to maintain its 2.0% general partnership interest. APL used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see Note 3). In connection with the issuance of APL common units during the years ended December 31, 2014 and 2013, RemainCo recorded gains of $2.7 million and $11.9 million, respectively, within partners’ capital and a corresponding decrease in non-controlling interests on its consolidated balance sheets and consolidated statement of partners’ capital.

On May 12, 2014, APL 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, APL 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 APL is currently restricted from selling common units by the Merger Agreement (see Note 3).

During the year ended December 31, 2014, APL 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. APL 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 APL. The net proceeds from the common unit offerings and General Partner contributions were utilized for general partnership purposes.

Cash Distributions

APL 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 APL’s securities with the right to share in APL’s cash distributions) and to RemainCo as general partner. If common unit distributions in any quarter exceed specified target levels, RemainCo will receive between 15% and 50% of such distributions in excess of the specified target levels, including its 2.0% interest. RemainCo, which holds all the incentive distribution rights in APL, has agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to APL after RemainCo receives an initial $7.0 million per quarter pursuant to its incentive distribution rights.

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Common unit and general partner distributions declared by APL 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		Total Cash Distribution to the General Partner
				(in thousands)		(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

On January 9, 2015, APL 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, 2013. 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, APL 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 APL raised more than $150.0 million in common unit equity. APL 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 RemainCo’s consolidated statements of operations.

On May 7, 2013, APL 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”). Atlas Energy contributed $8.2 million to maintain its 2.0% general partnership interest upon the issuance of the Class D Preferred Units. APL 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. APL has 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 APL’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

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million. RemainCo 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 within net income attributable to non-controlling interests on RemainCo’s consolidated statements of operations. APL’s Class D Preferred Units are presented combined with a net $16.0 million and $61.5 million unaccreted discount on RemainCo’s consolidated balance sheets as of December 31, 2014 and 2013, respectively. APL 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 RemainCo’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 per unit paid each quarter on APL’s common limited partner units plus a preferred yield premium. APL 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 RemainCo’s consolidated statements of operations.

Class D Preferred Unit distributions paid in kind by APL 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) APL considers preferred unit distributions paid in kind to be non-cash financing activity.

On January 22, 2015, APL 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, APL 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. APL received $122.3 million in net proceeds. The proceeds were used to pay down APL’s revolving credit facility.

APL 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

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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, APL 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 APL 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, APL 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, APL 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, APL 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). APL 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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RemainCo recorded depreciation expense on APL’s 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.

APL 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.

APL 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 RemainCo’s consolidated balance sheet. Revenues from these lease arrangements are recorded within transportation, processing and other fee revenues on RemainCo’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

APL evaluates goodwill for impairment annually, on December 31, for all its reporting units, except SouthTX, which is evaluated on April 30. APL 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. APL 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, APL 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, APL 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, APL measured the amount of goodwill impairment on Gas Treating to be $43.9 million. RemainCo 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

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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. RemainCo expects all goodwill recorded to be deductible for tax purposes.

RemainCo has recorded intangible assets with finite lives in connection with certain of APL’s 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. RemainCo recorded amortization expense on APL’s 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; 2017 - $68.0 million per year; 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 $30,348 and $22,504 at December 31, 2014 and 2013, respectively	$	40,572	$	44,931
Security deposits		2,238		5,367
Other long-term receivable		4,500		—
	$	47,310	$	50,298

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Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreement (see Note 14). During the year ended December 31, 2013, APL redeemed all of its outstanding $365.8 million 8.75% unsecured senior notes due June 15, 2018 (“8.75% Senior Notes”) (see Note 14). During the year ended December 31, 2013, APL recorded $5.3 million related to accelerated amortization of deferred financing costs, which is included in loss on early extinguishment of debt on RemainCo’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 $7.8 million, $7.4 million and $4.8 million for the years ended December 31, 2014, 2013 and 2012, respectively, which is recorded within interest expense on RemainCo’s consolidated statements of operations.

NOTE 10 – INCOME TAXES

As part of the Cardinal Acquisition (see Note 4), APL acquired APL Arkoma, Inc., a taxable subsidiary. The components of the federal and state income tax expense (benefit) of APL’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, APL 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 believes it more likely than not that the deferred tax asset will be fully utilized.

NOTE 11 — DERIVATIVE INSTRUMENTS

APL uses derivative instruments in connection with its commodity price risk management activities. APL 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.

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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, APL 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.

APL 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, APL will receive for the commodity sales being hedged.

APL 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 RemainCo’s consolidated statements of operations In previous years, APL 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 RemainCo’s consolidated balance sheets. The effective portion of the gain (loss) was reclassified to RemainCo’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings, which occurred through the year ending December 31, 2012. RemainCo has reclassified all earnings out of accumulated other comprehensive income (loss), within equity on RemainCo’s consolidated balance sheet and there was no balance outstanding as of the years ended December 31, 2014 and 2013.

APL 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 RemainCo’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 RemainCo’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 RemainCo’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. RemainCo 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.

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The following tables summarize APL’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets and liabilities on RemainCo’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

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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	)

The following table summarizes APL’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 12 for discussion on fair value methodology.

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The following tables summarize the gross effect of APL’s derivative instruments on RemainCo’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 or loss recognized on open derivative contracts, which have not yet settled.

NOTE 12 — FAIR VALUE OF FINANCIAL INSTRUMENTS

RemainCo 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 RemainCo’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”).

Derivative Instruments

At December 31, 2014, the valuations for all APL’s derivative contracts are defined as Level 2 assets and liabilities within the same class of nature and risk, with the exception of APL’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.

APL’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 APL’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 APL utilizes the valuations provided by the financial institutions that provide the NGL options for trade. APL tests these valuations for reasonableness through the use of an internal valuation model.

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Valuations for APL’s NGL fixed price swaps are based on forward price curves provided by a third party, which APL 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 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 APL’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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APL’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 APL’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 gain (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 RemainCo’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 APL’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 APL’s NGL fixed price swaps for the periods indicated (in thousands):

	Level 3 NGL Swap Fair			Adjustment based upon Regression Coefficient
	Value Adjustments			Lower 95%		Upper 95%		Average
As of 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

APL 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 RemainCo’s 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. APL’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 APL’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 reduction $0.4 million as of December 31, 2014 and 2013, respectively. APL’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.

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The following table provides a summary of changes in fair value of APL’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

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

(2) NGL linefill acquired as part of the Teak and Cardinal Acquisitions (see Note 3).

Contingent Consideration

In February 2012, APL acquired a gas gathering system and related assets for an initial net purchase price of $19.0 million. APL 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 APL 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 RemainCo’s consolidated balance sheets. The range of the undiscounted amount APL could pay related to the remaining contingent payment is between $0.0 and $6.0 million.

Other Financial Instruments

The estimated fair value of APL’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 APL could realize upon the sale or refinancing of such financial instruments.

APL’s current assets and liabilities on RemainCo’s 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 values of outstanding borrowings under APL’s revolving credit facility and Atlas Energy’s term loan facility, both of which bear interest at variable interest rates, approximates their estimated fair values and thus are categorized as Level 1 value. The estimated fair value of APL’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 RemainCo and APL’s total debt at December 31, 2014 and 2013, which consists principally of borrowings under the revolving credit facility and the Senior Notes, were $2,019.4 million and $1,753.4 million, respectively, compared with the carrying amounts of $2,028.0 million and $1,797.1 million, respectively.

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Acquisitions

On May 7, 2013, APL completed the TEAK Acquisition (see Note 3). On December 20, 2012, APL completed the Cardinal Acquisition (see Note 3). On May 7, 2013, APL completed the TEAK Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. These inputs require significant judgments and estimates at the time of the valuation. The fair values assigned to the assets acquired and liabilities assumed in the TEAK Acquisition were finalized during the second quarter 2014. 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		14,925		20,280
	$	52,421	$	50,662

NOTE 14 — DEBT

Total debt consists of the following (in thousands):

	December 31, 2014			December 31, 2013
Term loan facility	$	88,875		$	89,775
APL Revolving credit facility		385,000			152,000
APL 6.625% Senior notes – due 2020		503,881			504,556
APL 5.875% Senior notes – due 2023		650,000			650,000
APL 4.750% Senior notes – due 2021		400,000			400,000
APL Capital lease obligations		229			754
Total debt		2,027,985			1,797,085
Less current maturities		(1,124	)		(1,424	)
Total long term debt	$	2,026,861		$	1,795,661

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

Years Ended December 31:
2015	$	1,124
2016		905
2017		900
2018		900
2019		385,900
Thereafter		1,634,375
Total principal maturities		2,024,104
Unamortized premium		3,881
Total debt	$	2,027,985

Cash payments for interest related to debt, net of capitalized interest, were $91.8 million, $69.0 million and $28.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Term Loan Facility

In July 2013, Atlas Energy entered into a $240.0 million secured term loan credit facility (“Term Facility”). At December 31, 2014, $88.9 million of the Term Facility was attributable to RemainCo. The Term Facility has a maturity date of July 31, 2019. Borrowings under the Term Facility bear interest, at Atlas Energy’s election at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest is generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy is required to repay principal at the rate of $0.2 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance is due. At December 31, 2014, the weighted average interest rate on its outstanding Term Facility borrowings was 6.5%.

The Term Facility contains customary covenants that limit Atlas Energy’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of Atlas Energy’s assets. The Term Facility also contains covenants that require (i) Atlas Energy to maintain a ratio of Total Funded Debt (as defined in the Term Facility) to EBITDA (as defined in the Term Facility), calculated over a period of four consecutive fiscal quarters, of not greater than 4.5 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2014; 4.0 to 1.0 as of the last day of each of the quarters ending on or before September 30, 2015; and 3.5 to 1.0 for the last day of each of the quarters thereafter, and (ii) the entry into swap agreements with respect to the assets acquired in certain 2013 acquisitions (see Note 4). At December 31, 2014, Atlas Energy was in compliance with these covenants. The events which constitute events of default are also customary for credit facilities of this nature, including payment defaults, breaches of representations, warranties or covenants, defaults in the payment of other indebtedness over a specified threshold, insolvency and change of control. Based on the definition in Atlas Energy’s Term Facility, RemainCo’s ratio of Total Funded Debt to EBITDA was 2.0 to 1.0.

Atlas Energy’s obligations under the Term Facility are secured by first priority security interests in substantially all of its assets, including all of its ownership interests in its material subsidiaries and its

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ownership interests in Atlas Resource Partners, L.P. (“ARP”). Additionally, Atlas Energy’s obligations under its Term Facility are guaranteed by its wholly-owned subsidiaries and may be guaranteed by future subsidiaries. The Term Facility is subject to an intercreditor agreement, which provides for certain rights and procedures, between the lenders under the Term Facility and Atlas Energy’s credit facility, with respect to enforcement of rights, collateral and application of payment proceeds.

At December 31, 2014, RemainCo has not guaranteed any of ARP’s debt obligations.

APL Revolving Credit Facility

At December 31, 2014, APL 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 APL’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 RemainCo’s consolidated balance sheets. At December 31, 2014, APL 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 APL has 95% interests, and Centrahoma, in which APL has a 60% interest; and their respective subsidiaries; and (ii) by the guaranty of each of APL’s consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including requirements that APL maintain certain financial thresholds and restrictions on APL’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. APL 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.

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 APL in excess of a specified amount, and a change of control of the General Partner.

On August 28, 2014, APL 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 APL’s Consolidated Funded Debt Ratio, as defined in the Revised Credit Agreement;

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• allows APL 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, APL was in compliance with all covenants under the credit facility.

APL Senior Notes

At December 31, 2014, APL 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 APL 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 APL does not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to APL’s secured debt, including APL’s obligations under its revolving credit facility.

Indentures governing the Senior Notes contain covenants, including limitations of APL’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. APL is in compliance with these covenants as of December 31, 2014.

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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, APL issued $325.0 million of the 6.625% Senior Notes in a private placement transaction, at par. APL 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, APL 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%. APL 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, APL issued $650.0 million of the 5.875% Senior Notes in a private placement transaction. The 5.875% Senior Notes were issued at par. APL 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 revolving credit agreement. 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, APL issued $400.0 million of the 4.75% Senior Notes in a private placement transaction. The 4.75% Senior Notes were issued at par. APL 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 is payable semi-annually in arrears on May 15 and November 15. APL’s 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, APL 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, APL accepted for purchase all 8.75% Senior Notes validly tendered as of the expiration of the consent

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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. APL entered into a supplemental indenture amending and supplementing the 8.75% Senior Notes Indenture.

On March 12, 2013, APL paid $105.6 million to redeem the remaining $97.3 million outstanding 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. APL 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, RemainCo recorded a loss of $26.6 million within loss on early extinguishment of debt on its 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

APL has noncancelable operating leases for equipment and office space that expire at various dates. Certain operating leases provide APL with the option to renew for additional periods. Where operating leases contain escalation clauses, rent abatements, and/or concessions, APL 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

APL 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 APL’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 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.

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

APL is involved in class action lawsuits arising from events related to the Merger (see Part I. – Item 3. Legal Proceedings).

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RemainCo is also party to various routine legal proceedings arising out of the ordinary course of its business. Management of RemainCo 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

APL sells natural gas, NGLs and condensate under contract to various purchasers in the normal course of business, within the Gathering and Processing segment (see Note 19). For the year ended December 31, 2014, APL had three customers that individually accounted for approximately 26%, 13% and 11%, respectively, of RemainCo’s consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, APL had three customers that individually accounted for approximately 29%, 17% and 14%, respectively, of RemainCo’s consolidated total third party revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, APL had two customers that individually accounted for approximately 48% and 15%, respectively, of RemainCo’s consolidated total third party revenues, excluding the impact of all financial derivative activity. Additionally, APL had two customers that individually accounted for approximately 15%, and 10%, respectively, of RemainCo’s consolidated accounts receivable at December 31, 2014, and three customers that individually accounted for approximately 23%, 20%, and 10%, respectively, of RemainCo’s consolidated accounts receivable at December 31, 2013.

APL 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 APL could adversely affect its operating results unless comparable volume could be obtained from other producers in the surrounding region.

APL places its temporary cash investments in high quality short-term money market instruments and deposits with high quality financial institutions. At December 31, 2014, RemainCo had $25.6 million in deposits at banks, of which $23.8 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

2010 Long-Term Incentive Plan

The Board of Directors of the General Partner approved and adopted Atlas Energy’s 2010 Long-Term Incentive Plan (“2010 LTIP”) effective February 2011. The 2010 LTIP provides equity incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for Atlas Energy. The 2010 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”), which is the Compensation Committee of the General Partner’s board of directors. Under the 2010 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,763,781 common limited partner units. At December 31, 2014, Atlas Energy had 4,911,209 phantom units and unit options outstanding under the 2010 LTIP, with 283,650 phantom units and unit options available for grant.

In the case of awards held by eligible employees, following a “change in control”, as defined in the 2010 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2010 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

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In connection with a change in control, the committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which Atlas Energy’s general partner (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason):

• cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity);

• accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to Atlas Energy’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction;

• provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);

• terminate all or some awards upon the consummation of the change-in-control transaction, but only if the committee provides for full vesting of awards immediately prior to the consummation of such transaction; and

• make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the committee deems necessary or appropriate.

2010 Phantom Units.A phantom unit entitles a Participant to receive an Atlas Energy common unit upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Participant Distribution Equivalent Rights (“DERs”), which are the right to receive cash per phantom unit in an amount equal to, and at the same time as, the cash distributions Atlas Energy makes on a common unit during the period such phantom unit is outstanding. Generally, phantom units granted to employees under the 2010 LTIP will vest over a three or four year period from the date of grant and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2010 LTIP at December 31, 2014, there are 1,601,974 units that will vest within the following twelve months. All phantom units outstanding under the 2010 LTIP at December 31, 2014 include DERs. During the years ended December 31, 2014, 2013 and 2012, the Partnership paid $4.3 million, $3.1 million and $2.0 million, respectively, with respect to the 2010 LTIP DERs.

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The following table sets forth the 2010 LTIP phantom unit activity for the periods indicated:

	Years Ended December 31,
	2014					2013					2012
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		2,054,534		$	22.58		2,044,227		$	20.90		1,838,164		$	22.11
Granted		961,000			44.93		112,000			50.26		133,080			29.95
Vested(1)		(486,321	)		20.76		(25,684	)		19.87		(19,677	)		20.11
Forfeited		(32,549	)		32.53		(76,009	)		20.67		(72,808	)		20.65
ARP anti-dilution adjustment(2)		—			—		—			—		165,468			—
Outstanding, end of year(3)		2,496,664		$	31.41		2,054,534		$	22.58		2,044,227		$	20.90
Non-cash compensation expense recognized (in thousands)				$	22,624				$	11,848				$	11,612

⁽¹⁾  The aggregate intrinsic values of phantom unit awards vested were $21.1 million, $1.3 million and $0.7 million, respectively, for the years ended December 31, 2014, 2013 and 2012.

⁽²⁾  The number of 2010 phantom units was adjusted concurrently with the distribution of ARP common units.

⁽³⁾  The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2014 was $77.8 million.

At December 31, 2014, Atlas Energy had approximately $35.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2010 LTIP based upon the fair value of the awards.

2010 Unit Options.A unit option entitles a Participant to receive a common unit of Atlas Energy 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 Atlas Energy’s common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2010 LTIP generally will vest over a three or four year period from the date of grant. There are 1,770,877 unit options outstanding under the 2010 LTIP at December 31, 2014 that will vest within the following twelve months. For the years ended December 31, 2014, 2013 and 2012, Atlas Energy received cash of $0.6 million, $0.1 million and $0.1 million, respectively, from the exercise of options.

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The following table sets forth the 2010 LTIP unit option activity for the periods indicated:

	Years Ended December 31,
	2014					2013					2012
	Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		2,452,412		$	20.52		2,504,703		$	20.51		2,304,300		$	22.12
Granted		—			—		—			—		77,167			27.55
Exercised(1)		(28,473	)		20.68		(3,262	)		20.44		(5,438	)		18.44
Forfeited		(9,394	)		18.79		(49,029	)		20.38		(79,119	)		20.33
ARP anti-dilution adjustment(2)		—			—		—			—		207,793			—
Outstanding, end of year(3)(4)		2,414,545		$	20.53		2,452,412		$	20.52		2,504,703		$	20.51
Options exercisable, end of year(5)		584,162		$	20.34		13,865		$	20.03		3,398		$	20.85
Non-cash compensation expense recognized (in thousands)				$	4,535				$	5,768				$	5,966

⁽¹⁾  The intrinsic values of options exercised during the years ended December 31, 2014, 2013 and 2012 were $0.6 million, $0.1 million and $0.1 million, respectively.

⁽²⁾  The number of 2010 unit options and exercise price was adjusted concurrently with the distribution of ARP common units.

⁽³⁾  The weighted average remaining contractual life for outstanding options at December 31, 2014 was 6.3 years.

⁽⁴⁾  The options outstanding at December 31, 2014 had an aggregate intrinsic value of $25.7 million.

⁽⁵⁾  The weighted average remaining contractual lives for exercisable options at December 31, 2014 and 2013 were 6.3 years and 7.6 years, respectively. The intrinsic values of exercisable options at December 31, 2014 and 2013 were $6.1 million and $0.4 million, respectively.

At December 31, 2014, RemainCo had approximately $1.1 million in unrecognized compensation expense related to unvested unit options outstanding under the 2010 LTIP based upon the fair value of the awards. Atlas Energy used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The following weighted average assumptions were used for the periods indicated:

	Years Ended December 31,
	2014			2013			2012
Expected dividend yield		—	%		—	%		3.7	%
Expected unit price volatility		—	%		—	%		45.0	%
Risk-free interest rate		—	%		—	%		1.4	%
Expected term (in years)		—			—			6.84
Fair value of unit options granted	$	—		$	—		$	8.08

2006 Long-Term Incentive Plan

The Board of Directors approved and adopted Atlas Energy’s 2006 Long-Term Incentive Plan (“2006 LTIP”), which provides equity incentive awards to Participants who perform services for Atlas Energy. The 2006 LTIP is administered by the LTIP Committee. The LTIP Committee may grant such awards of either phantom units or unit options for an aggregate of 2,261,516 common limited partner units. At December 31, 2014, Atlas Energy had 1,721,121 phantom units and unit options outstanding under the 2006 LTIP, with 133,951 phantom units and unit options available for grant. Share based payments to non-employees, which have a cash settlement option, are recognized within liabilities in the financial statements based upon their current fair market value.

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In the case of awards held by eligible employees, following a “change in control”, as defined in the 2006 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2006 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.

2006 Phantom Units.Generally, phantom units granted to employees under the 2006 LTIP will vest over a three or four year period from the date of grant and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2006 LTIP at December 31, 2014, 311,387 units will vest within the following twelve months. All phantom units outstanding under the 2006 LTIP at December 31, 2014 include DERs. During the years ended December 31, 2014, 2013 and 2012, respectively, Atlas Energy paid approximately $1.1 million, $0.4 million and approximately $42,000 with respect to 2006 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on RemainCo’s consolidated balance sheets.

The following table sets forth the 2006 LTIP phantom unit activity for the periods indicated:

	Years Ended December 31,
	2014					2013					2012
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		234,940		$	35.82		50,759		$	21.02		32,641		$	15.99
Granted		629,525			43.76		207,363			38.05		25,248			29.70
Vested(1) (2)		(83,283	)		33.86		(20,182	)		21.34		(10,107	)		20.26
Forfeited		—			—		(3,000	)		36.45		—			—
ARP anti-dilution adjustment(3)		—			—		—			—		2,977			—
Outstanding, end of year(4)(5)		781,182		$	42.43		234,940		$	35.82		50,759		$	21.02
Non-cash compensation expense recognized (in thousands)				$	16,797				$	5,317				$	660

(1) The intrinsic values for phantom unit awards vested during the years ended December 31, 2014, 2013 and 2012 were $3.8 million, $1.0 million and $0.3 million, respectively.

(2) There were 6,380 and 1,146 vested units during the years ended December 31, 2014 and 2013, respectively, that were settled for approximately $0.3 million and $0.1 million cash, respectively. No units were settled in cash during the year ended December 31, 2012.

(3) The number of 2006 phantom units was adjusted concurrently with the distribution of ARP common units.

(4) The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2014 was $24.3 million.

(5) There were $0.8 million and $1.1 million recognized as liabilities on RemainCo’s consolidated balance sheets at December 31, 2014 and 2013, respectively, representing 41,113 and 41,525, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units are $36.94 and $29.67 as of December 31, 2014 and 2013, respectively.

At December 31, 2014, RemainCo had approximately $14.1 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2006 LTIP based upon the fair value of the awards.

2006 Unit Options.The exercise price of the unit option may be equal to or more than the fair market value of Atlas Energy’s common unit on the date of grant of the option. Unit option awards expire 10 years from the date of grant. Generally, unit options granted under the 2006 LTIP will vest over a three or four year period from the date of grant. There are 2,500 unit options outstanding under the 2006 LTIP at December 31, 2014 that will vest within the following twelve months. For the year ended December 31, 2012, Atlas Energy received cash of $0.2 million from the exercise of options. No cash was received from the exercise of options for the years ended December 31, 2014 and 2013.

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The following table sets forth the 2006 LTIP unit option activity for the periods indicated:

	Years Ended December 31,
	2014				2013				2012
	Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options		Weighted Average Exercise Price		Number of Unit Options			Weighted Average Exercise Price
Outstanding, beginning of year		939,939	$	20.94		929,939	$	20.75		903,614		$	21.52
Granted		—		—		10,000		38.51		—			—
Exercised(1)		—		—		—		—		(51,998	)		3.03
Forfeited		—		—		—		—		—			—
ARP anti-dilution adjustment(2)		—		—		—		—		78,323			—
Outstanding, end of year(3)(4)		939,939	$	20.94		939,939	$	20.94		929,939		$	20.75
Options exercisable, end of year(5)		932,439	$	20.80		929,939	$	20.75		929,939		$	20.75
Non-cash compensation expense recognized (in thousands)			$	22			$	36				$	—

(1) The intrinsic value of options exercised during the year ended December 31, 2012 was $1.5 million. No options were exercised during the years ended December 31, 2014 and 2013.

(2) The number of 2006 unit options and exercise price was adjusted concurrently with the distribution of ARP common units.

(3) The weighted average remaining contractual life for outstanding options at December 31, 2014 was 1.9 years.

(4) The aggregate intrinsic value of options outstanding at December 31, 2014 was approximately $9.7 million.

(5) The weighted average remaining contractual lives for exercisable options at December 31, 2014 and 2013 were 1.9 years and 2.9 years, respectively. The aggregate intrinsic values of options exercisable at December 31, 2014 and 2013 were $9.7 million and $24.3 million, respectively.

At December 31, 2014, Atlas Energy had approximately $17,000 of unrecognized compensation expense related to unvested unit options outstanding under the 2006 LTIP based upon the fair value of the awards. Atlas Energy uses the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.

The following weighted average assumptions were used for the periods indicated:

	Years Ended December 31,
	2014			2013			2012
Expected dividend yield		—	%		3.2	%		—	%
Expected unit price volatility		—	%		30.0	%		—	%
Risk-free interest rate		—	%		0.7	%		—	%
Expected term (in years)		—			6.25			—
Fair value of unit options granted	$	—		$	7.54		$	—

The transfer of assets to ARP on March 5, 2012 and the subsequent distribution of ARP common units on March 13, 2012 resulted in an adjustment to Atlas Energy’s 2010 and 2006 long-term incentive plans. Concurrent with the distribution of ARP common units, the number of phantom units, restricted units and options in the plans were increased in an amount equivalent to the percentage change in Atlas Energy’s publicly traded unit price from the closing price on March 13, 2012 to the opening price on March 14, 2012. In addition, the strike price of unit option awards was decreased by the same percentage change.

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APL Long-Term Incentive Plans

APL has a 2004 Long-Term Incentive Plan (“2004 APL LTIP”) and a 2010 Long-Term Incentive Plan (“2010 APL LTIP” and collectively with the 2004 LTIP, the “APL LTIPs”) in which officers, employees, non-employee managing board members of APL’s general partner, employees of APL’s general partner’s affiliates and consultants are eligible to participate. The APL LTIPs are administered by its compensation committee (the “APL LTIP Committee”). Under the APL LTIPs, the APL LTIP Committee may make awards of either phantom units or unit options for an aggregate of 3,435,000 common units. At December 31, 2014, APL had 1,684,289 phantom units outstanding under the APL LTIPs, with 139,218 phantom units and unit options available for grant. APL generally issues new common units for phantom units and unit options that have vested and have been exercised.

APL Phantom Units

Phantom units granted to employees under the APL LTIPs generally had vesting periods of four years. However, in February 2014, the APL 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 APL LTIPs. At December 31, 2014, there were 614,415 units outstanding under the APL LTIPs that will vest within the following twelve months.

APL is authorized to purchase common units from employees to cover employee-related taxes when certain phantom units have vested. During the years ended December 31, 2014 and 2012, APL 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 a reduction of non-controlling interests on RemainCo’s consolidated balance sheets. There were no phantom units purchased and retired during the year ended December 31, 2013.

All phantom units outstanding under the APL LTIPs at December 31, 2014 include DERs granted to the participants by the APL LTIP Committee. The amounts paid with respect to APL 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 non-controlling interests on RemainCo’s consolidated balance sheets.

The following table sets forth the APL LTIPs phantom unit activity for the periods indicated:

	Years Ended December 31,
	2014					2013					2012
	Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding, beginning of year		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(1)(2)		(463,916	)		34.71		(290,136	)		31.88		(181,209	)		17.88
Outstanding, end of year(3)(4)		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

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

(2) There were 4,684, 1,677 and 792 vested phantom units, which were settled for approximately $155,000, $58,000 and $26,000 cash during the years ended December 31, 2014, 2013 and 2012, respectively.

(3) The aggregate intrinsic values for phantom unit awards outstanding at December 31, 2014 and 2013 were $45.9 million and $50.7 million, respectively.

(4) 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, RemainCo had approximately $27.9 million of unrecognized compensation expense related to APL’s unvested phantom units outstanding under the APL LTIPs based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.9 years.

APL Unit Options

APL 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

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

The partnership agreement provides that the General Partner will determine the costs and expenses allocable to APL in any reasonable manner determined by the General Partner at its sole discretion. APL reimbursed the General Partner and its affiliates $5.1 million, $5.0 million and $3.8 million for the years ended 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 APL is reasonable.

APL compresses and gathers gas for ARP on its gathering systems located in Tennessee. ARP’s general partner is wholly-owned by Atlas Energy, and two members of the General Partner’s managing board are members of ARP’s board of directors. APL entered into an agreement to provide these services, which extends for the life of ARP’s leases, in February 2008. APL 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.

APL agreed to provide design, procurement and construction management services for ARP with respect to a pipeline located in Lycoming County, Pennsylvania (the “Lycoming Pipeline”). APL was approximately $1.8 million by ARP for these services during the year ended December 31, 2014.

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NOTE 19 — SEGMENT INFORMATION

As a result of the sale of APL’s subsidiaries that owned an interest in WTLPG on May 14, 2014 (see Note 5), RemainCo 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 RemainCo will manage its operations going forward. RemainCo has adjusted its segment presentation from the amounts previously presented to reflect the realignment of the segments.

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

The following summarizes APL’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		$	136,483		$	2,974,838
Revenues – affiliates		—			—			286			286
Total revenues		1,722,810			1,115,545			136,769			2,975,124
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)		—			—			120,821			120.821
Other expenses(2)		—			—			6,073			6,073
Depreciation and amortization		102,614			95,203			4,726			202,543
Interest expense(1)		—			—			99,922			99,922
Total costs and expenses		1,548,509			1,052,680			233,690			2,834,879
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			(46,480	)		173,619
Income tax benefit		(2,376	)		—			—			(2,376	)
Net income (loss)	$	176,229		$	46,246		$	(46,480	)	$	175,995

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	Oklahoma			Texas			Corporate and Other			Consolidated
Year Ended December 31, 2013:
Revenue:
Revenues – third party(1)	$	1,385,342		$	743,412		$	(22,205	)	$	2,106,549
Revenues – affiliates		—			—			303			303
Total revenues		1,385,342			743,412			(21,902	)		2,106,852
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)		—			—			86,072			86,072
Other expenses(2)		—			—			20,005			20,005
Depreciation and amortization		98,240			65,797			4,580			168,617
Interest expense(1)		—			—			92,870			92,870
Total costs and expenses		1,244,333			702,650			205,490			2,152,473
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			(292,871	)		(122,343	)
Income tax benefit		(2,260	)		—			—			(2,260	)
Net income (loss)	$	141,750		$	31,038		$	(292,871	)	$	(120,083	)

	Oklahoma		Texas			Corporate and Other			Consolidated
Year Ended December 31, 2012:
Revenue:
Revenues – third party(1)	$	757,909	$	459,103		$	28,574		$	1,245,586
Revenues – affiliates		—		—			435			435
Total revenues		757,909		459,103			29,009			1,246,021
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)		—		—			74,902			74,902
Other expenses(2)		5		(308	)		15,372			15,069
Depreciation and amortization		56,154		33,284			591			90,029
Interest expense(1)		—		—			41,972			41,972
Total costs and expenses		647,206		431,214			133,596			1,212,016
Equity income in joint ventures		—		—			6,323			6,323
Income (loss) before tax		110,703		27,889			(98,264	)		40,328
Income tax expense		176		—			—			176
Net income (loss)	$	110,527	$	27,889		$	(98,264	)	$	40,152

(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.

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	Years Ended December 31,
Capital Expenditures:	2014		2013		2012
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

Balance Sheet	December 31, 2014		December 31, 2013
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		245,652		202,286
	$	4,844,759	$	4,339,682

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 — SUBSEQUENT EVENTS

On January 9, 2015, APL 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, 2015, APL 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 tender offers to redeem any and all of the outstanding Senior Notes in connection with, and conditioned upon, the consummation of the Merger. The Merger, however, is not conditioned on the consummation of the tender offers (see Note 14).

On January 22, 2015, APL 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, APL 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). APL expects the Merger to close on February 28, 2015 and, accordingly, the redemption would also be on February 28, 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 our paying agent (see Note 6).

On February 20, 2015, APL 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, APL agreed to transfer 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee to APL’s affiliate, ARP, for $1.0 million plus working capital adjustments, concurrent with the closing of the Merger on February 27, 2015.

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