EX-99.1 19 a2216316zex-99_1.htm EX-99.1

Exhibit 99.1

JP Energy Partners LP and Subsidiaries

Unaudited Condensed Consolidated Financial Statements

As of December 31, 2012 and March 31, 2013 and for the three months ended March 31, 2012 and 2013

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except units)

(Unaudited)

	December 31,		March 31,
	2012		2013
	(Restated and Recast)		(Restated and Recast)
ASSETS

Current assets
Cash and cash equivalents	$	10,099	$	14,891
Accounts receivable, net	80,551		64,676
Receivables from related parties	1,794		3,620
Inventory	19,635		28,037
Prepaid expenses and other current assets	7,500		6,157
Total current assets	119,579		117,381

Non-current assets
Property, plant and equipment, net	191,864		190,571
Goodwill	132,578		132,578
Intangible assets, net	113,736		110,201
Deferred financing costs and other assets, net	4,367		4,153
Total non-current assets	442,545		437,503
Total Assets	$	562,124	$	554,884

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities
Accounts payable	$	56,899	$	49,782
Accrued liabilities	16,076		15,366
Capital leases and short-term debt	3,932		2,650
Customer deposits and advances	2,705		1,723
Current portion of long-term debt	2,973		3,148
Total current liabilities	82,585		72,669

Non-current liabilities
Long-term debt	164,766		167,838
Other long-term liabilities	620		443
Total liabilities	247,971		240,950

Commitments and contingencies

Partners’ capital
Predecessor capital	51,138		55,313
Preferred units	20,966		20,969
General partner interest	404		404
Class A common units (6,868,004 units authorized, issued and outstanding at December 31, 2012 and March 31, 2013)	144,534		141,338
Class B common units (1,180,008 units authorized, and 1,153,505 and 1,149,505 units issued and outstanding at December 31, 2012 and March 31, 2013, respectively)	14,247		13,832
Class C common units (3,166,667 shares authorized, issued and outstanding as of December 31, 2012 and March 31, 2013, respectively)	82,864		82,078
Total partners’ capital	314,153		313,934
Total liabilities and partners’ capital	$	562,124	$	554,884

See accompanying notes to condensed consolidated financial statements.

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED INCOME STATEMENTS

(Dollars in thousands, except units and per unit data)

(Unaudited)

	Three Months Ended March 31,
	2012			2013
	(Restated)			(Restated and Recast)
REVENUES:
Crude oil sales	$	—		$	417,413
Gathering, transportation and storage fees	—			6,410
NGL and refined product sales (including amounts from related parties of $3,645 in the three months ending March 31, 2013)	28,362			50,301
Refined products terminaling and storage fees (including amounts from related parties of $1,555 in the three months ending March 31, 2013)	—			2,742
Other revenues	1,534			4,616
Total revenues	29,896			481,482

COSTS AND EXPENSES:
Cost of sales, excluding depreciation and amortization	22,777			445,634
Operating expense	2,760			14,118
General and administrative	2,631			8,806
Depreciation and amortization	1,112			8,226
Loss on disposal of assets	6			447
Total costs and expenses	29,286			477,231

OPERATING INCOME	610			4,251

OTHER INCOME (EXPENSE):
Interest expense	(330		)	(1,998		)
Other income	72			113

INCOME BEFORE INCOME TAXES	352			2,366

Income tax expense	(45		)	(160		)

NET INCOME	$	307		$	2,206

Net income attributable to preferred unitholders	$	(158	)	$	(571	)
Net income attributable to predecessor capital	—			(1,601		)
Net income attributable to common unitholders	$	149		$	34

Basic and diluted income per unit:
Weighted average number of common units outstanding	1,042,644			11,187,376
Basic and diluted income per common unit	$	0.14		$	—
Distribution per common unit	$	0.50		$	—

See accompanying notes to condensed consolidated financial statements.

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Dollars in thousands, except units and per unit data)

(Unaudited)

	Units
	Preferred	General Partner	Class A Common	Class B Common		Class C Common	Total

Balance - January 1, 2013	1,136,364	45	6,868,004	1,153,505		3,166,667	12,324,585

Forfeiture of restricted Class B common units	—	—	—	(4,000	)	—	(4,000	)

Balance - March 31, 2013	1,136,364	45	6,868,004	1,149,505		3,166,667	12,320,585

	Preferred			General Partner		Predecessor Capital		Class A Common			Class B Common			Class C Common			Total

Balance - January 1, 2013 - Restated and Recast	$	20,966		$	404	$	51,138	$	144,534		$	14,247		$	82,864		$	314,153

Contribution from the Predecessor	—			—		2,574		—			—			—			2,574
Unit-based compensation	—			—		—		—			128			—			128
Distributions to unitholders	(568		)	—		—		(3,217		)	(546		)	(796		)	(5,127		)
Net income	571			—		1,601		21			3			10			2,206

Balance - March 31, 2013 - Restated and Recast	$	20,969		$	404	$	55,313	$	141,338		$	13,832		$	82,078		$	313,934

See accompanying notes to condensed consolidated financial statements.

JP ENERGY PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2013
	(Restated)			(Restated and Recast)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	307		$	2,206
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,112			8,226
Derivative valuation changes	—			(342		)
Amortization of deferred financing costs	60			276
Unit-based compensation expenses	129			128
Loss on disposal of assets	6			447
Bad debt expense	92			216
Other non-cash items	21			40
Changes in working capital:
Accounts receivable	1,228			15,659
Receivable from related parties	—			(1,826		)
Inventory	84			(8,402		)
Prepaid expenses and current assets	(347		)	1,502
Accounts payable and other accrued liabilities	341			(6,692		)
Customer deposits and advances	61			(982		)
NET CASH PROVIDED BY OPERATING ACTIVITIES	3,094			10,456

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(400		)	(3,954		)
Acquisitions of businesses, net of cash acquired	(1,833		)	(1,003		)
Proceeds received on sale of assets	6			47
NET CASH USED IN INVESTING ACTIVITIES	(2,227		)	(4,910		)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from revolving line of credit	2,000			7,000
Payments on revolving line of credit	—			(3,000		)
Payments on long-term debt	(28		)	(785		)
Payments on capital leases	(48		)	(53		)
Payments on financed insurance premium	(272		)	(1,253		)
Debt issuance costs	(130		)	(110		)
Distributions to unitholders	(1,385		)	(5,127		)
Contributions from the Predecessor	—			2,574
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	137			(754		)

Net change in cash and cash equivalents	1,004			4,792
Cash and cash equivalents balance, beginning of period	4,432			10,099
Cash and cash equivalents balance, end of period	$	5,436		$	14,891

SUPPLEMENTAL DISCLOSURES:
Non-cash investing and financing transactions:
Accrued capital expenditures	$	—		$	1,208

See accompanying notes to condensed consolidated financial statements.

JP ENERGY PARTNERS LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts, except per unit data, are in thousands)

(Unaudited)

1. Business and Basis of Presentation

Business. The unaudited condensed consolidated financial statements presented herein contain the results of JP Energy Partners LP, a Delaware limited partnership, and its subsidiaries (“JPE” or the “Partnership”). The Partnership was formed in May 2010 by members of management and was further capitalized in June 2011 by ArcLight Capital Partners, LLC (“ArcLight”) to own, operate, develop and acquire a diversified portfolio of midstream energy assets. The Partnership’s operations currently consist of: (i) crude oil supply and logistics; (ii) crude oil pipelines and storage; (iii) refined products terminaling and storage; and (iv) natural gas liquid (“NGL”) distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States. JP Energy GP II LLC (“GP II”) is the Partnership’s general partner.

JP Development. On July 12, 2012, ArcLight and the owners of JPE formed JP Energy Development LP, a Delaware limited partnership (“JP Development”), for the express purpose of supporting JPE’s growth. Since its formation, JP Development has acquired a portfolio of midstream assets that have been developed for eventual sale to JPE. JPE and JP Development are under common control because a majority of the equity interests in each entity and their general partners are owned by ArcLight. JP Development made the following acquisitions since its formation in July 2012:

· On August 3, 2012, JP Development acquired Parnon Gathering LLC, a Delaware limited liability company (“Parnon Gathering”), which provides midstream gathering and transportation services to companies engaged in the production, distribution and marketing of crude oil. Subsequent to the acquisition, Parnon Gathering LLC was renamed to JP Energy Marketing LLC (“JPEM”).

· On July 15, 2013, JP Development acquired substantially all of the retail propane assets of BMH Propane, LLC, an Arkansas limited liability company (“BMH”), which is engaged in the retail and wholesale propane and refined fuel distribution business.

· On August 30, 2013, JP Development, through JPEM, acquired substantially all the operating assets of Alexander Oil Field Services, Inc., a Texas Corporation (“AOFS”), which is engaged in the crude oil trucking business.

· On October 7, 2013, JP Development acquired Wildcat Permian Services LLC, a Texas limited liability (“Wildcat Permian”) that was later merged with and into JP Energy Permian, LLC, a Delaware limited liability company (“JP Permian”). JP Permian is engaged in the transportation of crude oil by pipeline.

· On October 10, 2013, JP Liquids, LLC, a Delaware limited liability company and wholly owned subsidiary of JP Development (“JP Liquids”), acquired substantially all of the assets of Highway Pipeline, Inc., a Texas corporation (“Highway Pipeline”), which is engaged in the transportation of natural gas liquids and condensate via hard shell tank trucks.

Common Control Acquisition between JPE and JP Development. On February 12, 2014, pursuant to a Membership Interest and Asset Purchase Agreement, the Partnership acquired (i) certain marketing and trucking businesses of JPEM (the “Parnon Gathering Assets”), (ii) the assets and liabilities associated with AOFS, (iii) the retail propane assets acquired from BMH and (iv) all of the issued and outstanding membership interests in JP Permian and JP Liquids (collectively, the “Dropdown Assets”) from JP Development for an aggregate purchase price of approximately $319.1 million (the “Common Control Acquisition”), which comprised of 12,561,934 JPE

Class A Common Units and $52 million cash. The Partnership financed the cash portion of the purchase price through borrowings under its revolving credit facility.

Basis of Presentation. Because JPE and JP Development are under common control, JPE is required under generally accepted accounting principles in the United States (“GAAP”) to account for this Common Control Acquisition in a manner similar to the pooling of interest method of accounting. Under this method of accounting, JPE reflected in its balance sheet the Dropdown Assets at JP Development’s historical carryover basis instead of reflecting the fair market value of assets and liabilities of the Dropdown Assets. JPE also retrospectively adjusted its financial statements to include the operating results of the Dropdown Assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began).

The historical assets and liabilities and the operating results of the Dropdown Assets have been “carved out” from JP Development’s consolidated financial statements using JP Development’s historical basis in the assets and liabilities of the businesses and reflects assumptions and allocations made by management to separate the Dropdown Assets on a stand-alone basis. JPE’s recast historical consolidated financial statements include all revenues, costs, expenses, assets and liabilities directly attributable to the Dropdown Assets, as well as allocations that include certain expenses for services, including, but not limited to, general corporate expenses related to finance, legal, information technology, shared services, employee benefits and incentives and insurance. These expenses have been allocated based on the most relevant allocation method to the services provided, primarily on the relative percentage of revenue, relative percentage of headcount, or specific identification. Management believes the assumptions underlying the consolidated financial statements are reasonable. However, the combined financial statements do not fully reflect what the Partnership, including the Dropdown Assets’ balance sheets, results of operations and cash flows would have been, had the Dropdown Assets been under JPE management during the periods presented. As a result, historical financial information is not necessarily indicative of what the Partnership’s balance sheet, results of operations, and cash flows will be in the future.

JP Development has a centralized cash management that covers all of its subsidiaries. The net amounts due from/to JP Development by the Dropdown Assets relate to a variety of intercompany transactions including the collection of trade receivables, payment of accounts payable and accrued liabilities, charges of allocated corporate expenses and payments by JP Development on behalf of the Dropdown Assets. Such amounts have been treated as deemed contributions from/deemed distributions to JP Development for the quarter ended March 31, 2013. The total net effect of the deemed contributions is reflected as contribution from the predecessor in the statements of cash flows as a financing activity. The net balances due to JPE from the Dropdown Assets will be settled in cash based on the outstanding balances at the effective date of Common Control Acquisition.

The “predecessor capital” included in Partners’ Capital represented JP Development’s net investment in the Dropdown Assets, which included the net income or loss allocated to the Dropdown Assets, and contributions from and distributions to JP Development. Certain transactions between the Dropdown Assets and other related parties that are wholly-owned subsidiaries of JP Development were not cash settled, as a result, were considered deemed contributions or distributions and are included in JP Development’s net investment.

Net income attributable to the Dropdown Assets prior to the Partnership’s acquisition of such assets was not available for distribution to the Partnership’s unitholders. Therefore, this income was not allocated to the limited partners for the purpose of calculating net loss per common unit; instead, the income was allocated to predecessor capital.

The unaudited condensed consolidated financial statements have been prepared on the same basis as the audited consolidated financial statements for the year ended December 31, 2012. In the opinion of the Partnership’s management, such unaudited condensed consolidated financial statements reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All inter-company items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. Certain reclassifications have been made to conform previously reported balances to the current presentation. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2012.

2. Summary of Significant Accounting Policies

Principles of Consolidation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.

Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the condensed consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

Fair value measurement. The Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Partnership determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

Level 1 Inputs—Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

Level 2 Inputs—Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 Inputs—Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.

The fair value of the Partnership’s derivatives (see Note 7) was estimated using industry standard valuation models using market-based observable inputs, including commodity pricing and interest rate curves (Level 2). The Partnership does not have any other assets or liabilities measured at fair value on a recurring basis.

The Partnership’s other financial instruments consist primarily of cash and cash equivalents, trade and other receivables, accounts payable, accrued expenses and long term debt. The carrying value of the Partnership’s trade and other receivables, accounts payable and accrued expenses approximates fair value due to their highly liquid nature, short term maturity, or competitive rates assigned to these financial instruments. The fair value of long-term debt approximates the carrying value as the underlying instruments are at rates similar to current rates offered to the Partnership for debt with the same remaining maturities.

Reclassification. Certain previously reported amounts have been reclassified to conform to the current year presentation.

3. Restatement and Recast of December 31, 2012 and March 31, 2012 and 2013 Financial Statements

Restatement. During 2013, the Partnership determined that its previously issued unaudited condensed consolidated financial statements as of December 31, 2012 and March 31, 2013 and for the three months ended March 31, 2013 and 2012 contained errors. The Partnership evaluated those errors and determined that the impact of these errors was material to these financial statements. The Partnership concluded that it should restate its previously issued unaudited condensed consolidated balance sheet at December 31, 2012 and March 31, 2013 and the income statements and statements of cash flows for the three months ended March 31, 2012 and March 31, 2013 to correct the errors.

The following is a description of the nature of these errors for which the Partnership made correcting adjustments to its unaudited condensed consolidated balance sheet as of December 31, 2012:

1) Acquisitions—The Partnership identified and corrected an error related to the estimated unbilled revenue of Heritage Propane Express, LLC at the date of acquisition. As a result, accounts receivable increased by $246,000, inventory increased by $33,000, property, plant and equipment decreased by $201,000 and goodwill decreased by $755,000. Additionally, the Partnership identified and corrected errors in the unbilled revenue of SemStream Arizona Propane, L.L.C. (“SemStream) at the acquisition date. As a result, accounts receivable increased $187,000, goodwill decreased $55,000 and accrued liabilities increased $133,000. The Partnership also identified and corrected errors in the initial purchase price allocation of fair value to the assets acquired and liabilities assumed in the SemStream acquisition. As a result, accounts payable decreased by $1,080,000, goodwill decreased by $801,000, prepaid expenses and other current assets decreased by $207,000, and accrued liabilities increased by $72,000.

2) Cutoff—The Partnership identified and corrected errors from improper expense cutoff at December 31, 2012 relating to cost of sales, excluding depreciation and amortization, operating expenses and general and administrative expenses. The correction of these errors resulted in increases in property, plant and equipment, deferred financing costs and other assets, accounts payable and accrued liabilities of $630,000, $25,000, $665,000 and $460,000, respectively with a corresponding decrease in prepaid expenses and other current assets of $65,000.

3) Fixed Assets—The Partnership identified and corrected errors resulting from the improper capitalization of certain assets and the improper recognition of depreciation expense. The correction of these errors resulted in decreases of $1,908,000 in property, plant and equipment, $84,000 in accounts payable, and increases in inventory and goodwill of $501,000 and $976,000, respectively.

4) Reclassification and Presentation—In addition to the correction of errors noted above, certain reclassifications were made to correct improperly or inconsistently presented amounts at December 31, 2012. The primary change in presentation was a reclassification of prepaid expenses and other current assets to customer deposits and advances of $188,000, a reclassification of prepaid expenses and other current assets to accounts receivable of $8,000, a reclassification of accrued liabilities to customer deposits and advances of $82,000. In addition, the Partnership corrected the presentation of certain out of pocket expenses that were reimbursed from a customer and the presentation of accrued legal expenses for which the Partnership was fully insured. These corrections resulted in an increase in prepaid expenses and other current assets and accrued liabilities of $63,000 and an increase in deferred financing costs and other assets, net and other long-term liabilities of $150,000.

The following is a description of the areas in which these errors were identified and for which the Partnership made correcting adjustments to its unaudited condensed consolidated financial statements as of March 31, 2013 and for the three months ended March 31, 2013 and 2012:

5) Accruals—The Partnership identified and corrected errors resulting from the improper reversal in the first quarter of 2013 of certain revenue and accounts payable accruals recorded at December 31, 2012 related to its crude oil storage, gathering and transportation segment. The Partnership also identified and corrected errors resulting from the improper recognition of certain revenue and accounts payable accruals in the first quarter of 2013. The correction of these errors resulted in decreases in accounts receivable of $657,000, property, plant and equipment of $163,000, accrued liabilities of $451,000, crude oil storage, gathering and transportation revenue of $707,000 and crude oil storage, gathering and transportation cost of sales, excluding

depreciation and amortization, of $175,000, and increases in accounts payable of $70,000, customer deposits and advances of $95,000 and operating expenses of $2,000, for the three months ended March 31, 2013.

6) Cutoff—The Partnership identified and corrected errors resulting from the improper expense cutoff at March 31, 2013 relating to cost of sales, excluding depreciation and amortization, operating expenses, general and administrative expenses and loss on disposal of assets. The correction of these errors resulted in increases to cash of $57,000, prepaid expenses and other current assets of $223,000, property, plant and equipment of $577,000, accounts payable of $2,098,000, accrued liabilities of $498,000 and deferred financing costs and other assets of $58,000 as of March 31, 2013. The correction of these errors also resulted in increases in cost of sales, excluding depreciation and amortization of $218,000 operating expenses of $502,000 and general and administrative of $1,004,000, and a decrease in loss on disposal of assets of $43,000. In addition, improper expense cutoff at March 31, 2012 resulted in increases in cost of sales, excluding depreciation and amortization, operating expenses and general and administrative of $185,000, $171,000 and $91,000, respectively for the three months ended March 31, 2012.

7) Fixed Assets—The Partnership identified and corrected errors resulting from the improper capitalization of certain assets and the improper recognition of depreciation expense. The correction resulted in increases in accounts payable of $84,000, loss on disposal of assets of $287,000, cost of sales, excluding depreciation and amortization, of $55,000 and operating expenses of $33,000, and decreases in depreciation and amortization of $131,000, property, plant and equipment of $129,000 and inventory of $31,000 for the three months ended March 31, 2013.

8) Revenue—The Partnership identified and corrected an error in the calculations of the unbilled and deferred revenue associated with its NGL distribution and sales segment as of March 31, 2013. The correction of this error resulted in decreases in accounts receivable of $216,000 and accrued liabilities of $50,000 and increases in inventory of $19,000 and property, plant and equipment of $69,000 with decreases in NGL distribution and sales revenue and cost of sales, excluding depreciation and amortization, of $216,000 and $138,000, respectively for the three months ended March 31, 2013. In addition, the Partnership identified an error in the calculation of revenue associated with its crude oil storage, gathering and transportation segment. The correction of this error resulted in decreases in crude oil storage, gathering and transportation revenue and cost of sales, excluding depreciation and amortization of $1,391,000 for the three months ended March 31, 2013.

9) Effect of 2012 errors and reclassifications—In addition to the correction of errors noted above, certain reclassifications were made to correct improperly or inconsistently presented amounts. The correction of these errors for the three months ended March 31, 2013 resulted in increases in cash of $194,000, accounts receivable of $953,000, accounts payable of $141,000, crude oil storage, gathering and transportation revenue and cost of sales of $37,000, and operating expenses of $992,000 and decreases in receivables from related parties of $876,000, prepaid expenses and other current assets of $52,000, property, plant and equipment of $79,000, deferred financing costs and other assets $200,000, accrued liabilities of $16,000, customer deposits and advances $185,000 and general and administrative of $992,000. The correction of these errors for the three months ended March 31, 2012 resulted in a reclassification of general and administrative to operating expenses of $82,000.

The balance sheet as of March 31, 2013 was also impacted by the restatement of the Partnership’s audited financial statements for the year ended December 31, 2012. The correction of those errors resulted in increases in accounts receivable of $441,000, inventory of $534,000, deferred financing costs and other assets of $175,000, accrued liabilities of $645,000 and decreases in prepaid expenses and other current assets of $405,000, property, plant and equipment of

$1,479,000, goodwill of $635,000, accounts payable of $499,000, customer deposits and advances of $106,000 and partners’ capital of $1,559,000. Included in the correction of errors in 2012, there was a $150,000 correcting entry properly recorded as an other long-term liability and other assets-deferred charges as of December 31, 2012. During the three months ended March 31, 2013, this correction was properly reclassified to a short term nature by decreasing other long-term liabilities and other assets-deferred charges by $150,000 and increasing accruals, provisions and other liabilities and prepaids and other current assets by $150,000.

10) Corrections on statement of cash flow—The Partnership identified and corrected certain payments related to acquisition working capital true-ups and debt issuance costs that were previously included in net cash provided by operating activities in the statement of cash flow. The correction of these errors for the three months ended March 31, 2013 resulted in an increase in net cash provided by operating activities of $1,113,000 and increases in net cash used in investing activities and financing activities of $1,003,000 and $110,000, respectively.

Recast. As described in Note 1, as a result of the Common Control Acquisition, the Partnership has recast its financial statements for the three months ended March 31, 2013 to include the assets and liabilities of the Parnon Gathering Assets in its consolidated balance sheet as of March 31, 2013, and to include the operating results of the Parnon Gathering Assets in its consolidated statement of operations for the three months then ended.

The table below provides a reconciliation from the amounts previously reported in the Partnership’s unaudited condensed consolidated balance sheet as of December 31, 2012 to the restated and recast amounts and indicate the category of the adjustments by reference to the above descriptions of the errors:

	Consolidated Balance Sheet
	As of December 31, 2012
	As Previously Reported		Restatement Adjustments			Description of Adjustments	As Restated		Recast Adjustments			As Restated and Recast
ASSETS
Current assets
Cash and cash equivalents	$	4,394	$	—			$	4,394	$	5,705		$	10,099
Accounts receivable, net	23,936		441			(1) (4)	24,377		56,174			80,551
Receivables from related parties	2,976		—				2,976		(1,182		)	1,794
Inventory	4,946		534			(1) (3)	5,480		14,155			19,635
Prepaid expenses and other current assets	7,786		(405		)	(1) (2) (4)	7,381		119			7,500
Total current assets	44,038		570				44,608		74,971			119,579

Non-current assets
Property, plant and equipment, net	178,290		(1,479		)	(1) (2) (3)	176,811		15,053			191,864
Goodwill	125,315		(635		)	(1) (3)	124,680		7,898			132,578
Intangible assets, net	107,960		—				107,960		5,776			113,736
Deferred financing costs and other assets	3,039		175			(2) (4)	3,214		1,153			4,367
Total non-current assets	414,604		(1,939		)		412,665		29,880			442,545
Total assets	$	458,642	$	(1,369	)		$	457,273	$	104,851		$	562,124

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities
Accounts payable	$	9,338	$	(499	)	(1) (2) (3)	$	8,839	$	48,060		$	56,899
Accrued liabilities	9,778		645			(1) (2) (4)	10,423		5,653			16,076
Capital leases and short-term debt	3,932		—				3,932		—			3,932
Customer deposits and advances	2,811		(106		)	(4)	2,705		—			2,705
Current portion of long term-debt	2,973		—				2,973		—			2,973
Total current liabilities	28,832		40				28,872		53,713			82,585

Long-term debt	164,766		—				164,766		—			164,766
Other long-term liabilities	470		150			(4)	620		—			620
Total liabilities	194,068		190				194,258		53,713			247,971

Partners’ capital
Predecessor capital	—		—				—		51,138			51,138
Preferred units	21,271		(305		)		20,966		—			20,966
General partner interest	404		—				404		—			404
Class A common units	145,360		(826		)		144,534		—			144,534
Class B common units	14,531		(284		)		14,247		—			14,247
Class C common units	83,008		(144		)		82,864		—			82,864
Total partners’ capital	264,574		(1,559		)		263,015		51,138			314,153
Total liabilities and partners’ capital	$	458,642	$	(1,369	)		$	457,273	$	104,851		$	562,124

The tables below provide a reconciliation from the amounts previously reported in the Partnership’s unaudited condensed consolidated income statement and statement of cash flows for the three months ended March 31, 2012 to the restated and recast amounts and indicate the category of the adjustments by reference to the above descriptions of the errors:

	Income Statement
	For the three months ended March 31, 2012
	As Previously Reported			Restatement Adjustments			Description of Adjustments	As Restated
Cost of sales, excluding depreciation and amortization:	$	22,592		$	185		(6)	$	22,777
Operating expenses	2,589			171			(6) (9)	2,760
General and administrative	2,540			91			(6) (9)	2,631
Operating income	1,057			(447		)		610
Income before taxes	799			(447		)		352
Net income	754			(447		)		307
Net income attributable to preferred unitholders	(390		)	232				(158		)
Net income attributable to common unitholders	364			(215		)		149
Basic and diluted income per unit	0.35			(0.21		)		0.14

	Statement of Cash Flows
	For the three months ended March 31, 2012
	As Previously Reported		Restatement Adjustments and Reclassifications			Description of Adjustments	As Restated
Operating Activities
Net income	$	754	$	(447	)	(6)	$	307
Non-cash adjustments	1,328		92			(6)	1,420
Changes in working capital	1,012		355			(6)	1,367
Net cash provided by operating activities	$	3,094	$	—			$	3,094

The following tables provide a reconciliation from the amounts previously reported in the Partnerships’ consolidated financial statements as of and for the three months ended March 31, 2013 to the restated and recast amounts and indicates the category of the adjustments by reference to the above descriptions of the errors:

	Balance Sheet
	As of March 31, 2013
	As Previously Reported		Restatement Adjustments and Reclassifications			Description of Adjustments	As Restated		Recast Adjustments		As Restated and Recast
ASSETS
Current assets
Cash and cash equivalents	$	7,412	$	251		(6) (9)	$	7,663	$	7,228	$	14,891
Accounts receivable, net	22,463		521			(5) (8) (9)	22,984		41,692		64,676
Receivables from related parties	4,494		(876		)	(9)	3,618		2		3,620
Inventory	5,491		522			(7) (8) (9)	6,013		22,024		28,037
Prepaid expenses and other current assets	6,138		(84		)	(6) (9)	6,054		103		6,157
Total current assets	45,998		334				46,332		71,049		117,381

Non-current assets
Property, plant and equipment, net	176,962		(1,204		)	(5) (6) (7) (8) (9)	175,758		14,813		190,571
Goodwill	125,315		(635		)	(9)	124,680		7,898		132,578
Intangible assets, net	104,922		—				104,922		5,279		110,201
Deferred financing costs and other assets	3,117		(117		)	(6) (9)	3,000		1,153		4,153
Total non-current assets	410,316		(1,956		)		408,360		29,143		437,503
Total assets	$	456,314	$	(1,622	)		$	454,692	$	100,192	$	554,884

LIABILITIES AND PARTNERS’ CAPITAL

Current liabilities
Accounts payable	$	8,747	$	1,894		(5) (6) (7) (9)	$	10,641	$	39,141	$	49,782
Accrued liabilities	8,852		776			(5) (6) (8) (9)	9,628		5,738		15,366
Capital lease obligations and short-term debt	2,650		—				2,650		—		2,650
Customer deposits and advances	1,919		(196		)	(5) (9)	1,723		—		1,723
Current portion of long term-debt	3,148		—				3,148		—		3,148
Total current liabilities	25,316		2,474				27,790		44,879		72,669

Long-term debt	167,838		—				167,838		—		167,838
Other long-term liabilities	443		—				443		—		443
Total liabilities	193,597		2,474				196,071		44,879		240,950

Partners’ capital
Predecessor capital	—		—				—		55,313		55,313
Preferred units	21,509		(540		)		20,969		—		20,969
General partner interest	411		(7		)		404		—		404
Class A common units	143,577		(2,239		)		141,338		—		141,338
Class B common units	14,347		(515		)		13,832		—		13,832
Class C common units	82,873		(795		)		82,078		—		82,078
Total partners’ capital	262,717		(4,096		)		258,621		55,313		313,934
Total liabilities and partners’ capital	$	456,314	$	(1,622	)		$	454,692	$	100,192	$	554,884

	Income Statement
	For the three months ended March 31, 2013
	As Previously Reported			Restatement Adjustments			Description of Adjustments	As Restated			Recast Adjustments			As Restated and Recast
REVENUES:
Crude oil storage, gathering and transportation	$	13,146		$	(2,061	)	(5) (8) (9)	$	11,085		$	(11,085	)	$	—
Refined products terminaling and storage	7,702			—				7,702			(7,702		)	—
NGL distribution and sales	48,039			(216		)	(8)	47,823			(47,823		)	—
Crude oil sales	—			—				—			417,413			417,413
Gathering, transportation and storage fees	—			—				—			6,410			6,410
NGL and refined product sales	—			—				—			50,301			50,301
Refined products terminaling and storage fees	—			—				—			2,742			2,742
Other revenues	—			—				—			4,616			4,616
	68,887			(2,277		)		66,610			414,872			481,482

COSTS AND EXPENSES:
Cost of sales, excluding depreciation and amortization:	37,069			(1,394		)	(5) (6) (7) (8) (9)	35,675			409,959			445,634
Operating expenses	11,275			1,529			(5) (6) (7) (9)	12,804			1,314			14,118
General and administrative	7,827			12			(6) (9)	7,839			967			8,806
Depreciation and amortization	7,510			(131		)	(7)	7,379			847			8,226
Loss on disposal of assets	203			244			(6) (7)	447			—			447
Total costs and expenses	63,884			260				64,144			413,087			477,231

OPERATING INCOME (LOSS)	5,003			(2,537		)		2,466			1,785			4,251

OTHER INCOME (EXPENSE):
Interest expense	(1,814		)	—				(1,814		)	(184		)	(1,998		)
Other income	113			—				113			—			113

INCOME BEFORE INCOME TAXES	3,302			(2,537		)		765			1,601			2,366
Income tax expense	(160		)	—				(160		)	—			(160		)

NET INCOME (LOSS)	$	3,142		$	(2,537	)		$	605		$	1,601		$	2,206

Net income attributable to preferred unitholders	$	(806	)	$	235			$	(571	)	$	—		$	(571	)
Net income attributable to predecessor capital	—			—				—			(1,601		)	(1,601		)
Net income (loss) attributable to common unitholders	$	2,336		$	(2,302	)		$	34		$	—		$	34

Basic and diluted income per unit:
Basic and diluted income (loss) per unit	$	0.21		$	(0.21	)		$	—		$	—		$	—

	Statement of Cash Flows
	For the three months ended March 31, 2013
	As Previously Reported			Restatement Adjustments and Reclassifications			Description of Adjustments	As Restated			Recast Adjustments			As Restated and Recast
Operating Activities
Net income	$	3,142		$	(2,537	)	(5) (6) (7) (8)	$	605		$	1,601		$	2,206
Non-cash adjustments	8,026			118			(6) (7)	8,144			847			8,991
Changes in working capital	(1,528		)	4,103			(5) (6) (7) (8) (9) (10)	2,575			(3,316		)	(741		)
Net cash provided by operating activities	9,640			1,684				11,324			(868		)	10,456

Investing Activities
Capital expenditures	(3,352		)	(419		)	(7)	(3,771		)	(183		)	(3,954		)
Acquisitions of businesses, net of cash acquired	—			(1,003		)	(10)	(1,003		)	—			(1,003		)
Proceeds received from sale of assets	5			42			(7)	47			—			47

Financing Activities
Payments on financed insurance premium	(1,310		)	57			(9)	(1,253		)	—			(1,253		)
Debt issuance costs	—			(110		)	(10)	(110		)	—			(110		)
Contributions from the Predecessor	—			—				—			2,574			2,574

4. Net Income Per Unit

Income per limited partner unit is calculated in accordance with the two-class method for determining income per unit for master limited partnerships (“MLPs”) when incentive distribution rights (“IDRs”) and other participating securities are present. The two-class method requires that income per limited partner unit be calculated as if all earnings for the period were distributed as cash, and allocated by applying the provisions of the partnership agreement, and requires a separate calculation for each quarter and year-to-date period. Under the two-class method, any excess of distributions declared over net income is allocated to the partners based on their respective sharing of income specified in the partnership agreement.

The following table provides a reconciliation of the numerator and denominator of the basic and diluted income per common unit computations for the three months ended March 31, 2012:

	Quarter Ended March 31, 2012
	Income (Numerator) (Restated)		Units (Denominator)	Per-Unit Amount (Restated)
Basic loss per unit
Limited Partners’ interest	$	149	1,042,644	$	0.14
Effect of Dilutive Securities
Preferred Units	158		1,136,364
Diluted income per common unit	$	307	2,179,008	$	0.14

Income is allocated to preferred units for the purpose of basic income per unit. The Partnership did not include 1,136,364 convertible preferred units in the dilutive income per unit calculation under the if converted method for the quarter ended March 31, 2013 because to do so would be anti-dilutive for the period.

The preferred units earn cumulative distributions each quarter equal to the greater of (a) the amount of aggregate distributions in cash for such quarter that would be payable if the preferred units had been converted into common and (b) the minimum quarterly distribution of $0.50 per unit. The net income attributable to preferred units includes cumulative distributions declared and the preferred units’ proportionate share of net income for the three months ended March 31, 2012 and 2013.

On August 1, 2013, all then-outstanding preferred units were converted to common units on a one-for-one basis.

5. Inventory

Inventory consists of the following as of December 31, 2012 and March 31, 2013:

	December 31,		March 31,
	2012		2013
	(Restated and Recast)		(Restated and Recast)
Crude Oil	$	14,155	$	22,023
NGLs	2,654		3,034
Diesel	349		488
Materials, supplies and equipment	2,477		2,492
Total inventory	$	19,635	$	28,037

6. Long-Term Debt

Long-term debt consists of the following at December 31, 2012 and March 31, 2013:

	December 31, 2012			March 31, 2013
				(Reclassification)
Acquisition revolving loans	$	149,407		$	152,407
Working capital revolving loans	8,000			9,000
F&M bank loans	7,647			6,949
HBH notes payable	1,626			1,555
Reynolds note payable	618			626
Noncompete notes payable	441			449
Total long-term debt	$	167,739		$	170,986
Less: Current maturities	(2,973		)	(3,148		)
Total long-term debt, net of current maturities	$	164,766		$	167,838

Wells Fargo Credit Agreement. The Partnership has a $20,000,000 working capital revolving credit facility and $180,000,000 acquisition revolving credit facility with Wells Fargo Bank, N.A. that expires in December 2015 (the “WFB Credit Agreement”). The Partnership’s outstanding borrowings under the WFB Credit Agreement are collateralized by all of the Partnership’s assets and a certain letters of credit, as required.

As of March 31, 2013, the working capital revolving credit facility had $9,000,000 outstanding, and the amount available for future borrowings was $10,800,000 after taking into account letters of credit of $200,000. The acquisition revolving credit facility had $152,407,000 outstanding, and the amount available for future borrowings was $27,593,000. The weighted average interest rate on the total amount outstanding as of March 31, 2013 was 3.24%.

The Partnership was not in compliance with certain covenants during 2012 and the first quarter of 2013, including annual reporting requirements for the fiscal year ended December 31, 2012, paying distributions and making certain acquisitions without satisfying certain leverage covenants. In April 2013, the Partnership obtained waivers for the covenants which were out of compliance. On June 5, 2013 the Partnership received a waiver to further extend the annual reporting requirements for the fiscal year ended December 31, 2012. The Partnership was not in compliance with the leverage ratio covenant during the third quarter of 2013, which noncompliance was waived pursuant to a waiver received by the Partnership on December 6, 2013. As noted below, the WFB Credit Agreement was repaid on February 12, 2014.

On February 12, 2014, the Partnership entered into a credit agreement with Bank of America and used the borrowings under the Bank of America credit facility to repay all outstanding balances under the WFB Credit Agreement.

Bank of America Credit Agreement. On February 12, 2014, the Partnership entered into a credit agreement with Bank of America, N.A. (the “BOA Credit Agreement) for working capital requirements, for the acquisition of entities, and to pay off its existing WFB Commitments and F&M Loans. The BOA Credit Agreement consists of a $275,000,000 revolving loan. The BOA Credit Agreement will mature on February 12, 2019. The Partnership’s obligations under the BOA Credit Agreement are collateralized by substantially all of the Partnership’s assets.

Borrowings under the BOA Credit Agreement bear interest at a rate per annum equal to, at our option, either (a) a base rate determined by reference to the highest of (1) the federal funds effective rate plus 0.50%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, in each case plus an applicable margin. The initial applicable margin is (a) 2.00% for prime rate borrowings and 3.00% for LIBOR borrowings. The applicable margin is subject to an adjustment each quarter based on the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement.

The Partnership is required to pay a commitment fee on the unused commitments under the BOA Credit Agreement, which initially is 0.50% per annum. The commitment fee is subject to adjustment each quarter based on the Consolidated Total Leverage Ratio, as defined in the BOA Credit Agreement.

The BOA Credit Agreement contains various restrictive covenants and compliance requirements including:

· Maintenance of certain financial covenants including a leverage ratio, interest coverage ratio, and a current ratio.

· Financial statement reporting requirements, including quarterly unaudited financial statement reporting and annual audited financial statement reporting.

· Restrictions on cash distributions, including cash distributions to holders of equity units, unless certain leverage and coverage ratios are maintained before and after the cash distribution.

The Partnership was in compliance with all covenants under the BOA Credit Agreement since the inception of the agreement.

F&M Bank Loans. The F&M Bank loans had a credit commitment of $9,000,000 and an outstanding loan balance of $6,949,000 as of March 31, 2013. The F&M Bank loans were paid off in full on February 12, 2014, with the proceeds from the BOA Credit Agreement.

7. Derivative Instruments

The Partnership is exposed to certain market risks related to the volatility of commodity prices and changes in interest rates. To monitor and manage these market risks, the Partnership has established comprehensive risk management policies and procedures. The Board of Directors is responsible for the overall management of these risks, including monitoring exposure limits. The Partnership does not enter into derivative instruments for any purpose other than hedging commodity price risk and interest rate risk. That is, the Partnership does not speculate using derivative instruments.

By using derivative financial instruments to economically hedge exposures to changes in commodity prices and interest rates, the Partnership exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk for the Partnership. When the fair value of a derivative contract is negative, the Partnership owes the counterparty and, therefore, it does not possess credit risk. The Partnership minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties. The Partnership has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership’s maximum loss is $296,000, which would be fully reduced due to the netting feature. The commodity derivatives are presented on a gross basis as the instruments are with different counterparties and not subject to netting arrangements.

Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. The market risk associated with interest rates is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken.

Inventory

The Partnership’s NGL distribution and sales segment is exposed to market risks related to the volatility of propane prices. Management believes it is prudent to limit the variability of a portion of the Partnership’s propane purchases. To meet this objective, the Partnership uses a combination of financial instruments including, but not limited to, forward physical contracts and price swaps to manage its exposure to market fluctuations in propane prices.

The Partnership is also a party to a number of contracts that have elements of a derivative instrument. These contracts are primarily forward propane and crude oil purchase and sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sales exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

Debt Obligations

The Partnership is exposed to variable interest rate risk as a result of variable-rate borrowings under its credit facilities. Management believes it is prudent to limit the variability of a portion of the Partnership’s interest payments. To meet this objective, the Partnership entered into interest rate swap agreements to manage fluctuations in cash flows resulting from interest rate risk on a portion of its debt with a variable-rate component. These swaps change the variable-rate cash flow exposure on the debt obligations to fixed cash flows. Under the terms of the interest rate swaps, the Partnership receives variable interest rate payments and makes fixed interest rate payments, thereby creating the equivalent of fixed-rate debt for the portion of the debt that is swapped.

As of March 31, 2013, the Partnership had $161,407,000 of outstanding borrowings under the WFB Credit Agreement exposed to variable interest rate risk, of which $75,000,000 was economically hedged with interest rate swaps.

The Partnership measures derivative instruments at fair value using the income approach which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations utilize primarily observable (Level 2) inputs, including contractual terms, commodity prices, interest rates and yield curves observable at commonly quoted intervals. None of the Partnership’s derivative contracts are designated as hedging instruments.

The Partnership’s fair value of its commodity derivative assets and liabilities are recorded within prepaid expenses and other current assets and accrued liabilities, respectively, within the condensed consolidated balance sheets. The fair value of the current portion and long-term portions of the interest rate swap contracts are recorded within accrued liabilities and other long-term liabilities, respectively, on the condensed consolidated balance sheets. The fair value of the assets and liabilities associated with the derivative instruments within the condensed consolidated balance sheets at December 31, 2012 and March 31, 2013 were as follows:

	Assets				Liabilities
	December 31, 2012		March 31, 2013		December 31, 2012			March 31, 2013
*Mark-to-Market derivatives*
Current amounts
Commodity derivatives	$	221	$	296	$	(833	)	$	(618	)
Interest rate swap contracts	—		—		(180		)	(187		)
Long-term amounts
Interest rate swap contracts	—		—		(76		)	(53		)
Total derivatives	$	221	$	296	$	(1,089	)	$	(858	)

Fair value measurements at the reporting date were made using significant other observable data (Level 2).

There were no derivative instruments during the three months ended March 31, 2012. The Partnership’s condensed consolidated statement of operations for the three months ended March 31, 2013 was impacted by derivative instruments activities as detailed below.

8. Commitments and Contingencies

Legal Matters

The Partnership is involved in legal proceedings and litigation in the ordinary course of business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the partnership’s condensed consolidated financial position, results of operations, or liquidity.

Environmental Matters

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. Such environmental laws and regulations impose numerous obligations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable laws and restrictions on the generation, handling, treatment, storage, disposal and transportation of certain materials and wastes.

Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and even the issuance of injunctions restricting or prohibiting the Partnerships activities. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

The Partnership accounts for environmental contingencies in accordance with the ASC Topic 410 related to accounting for contingencies. 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 December 31, 2012 and March 31, 2013, the Partnership had no significant environmental matters.

9. Related Party Transactions

The Partnership entered into transactions with Enogex Holdings, an entity partially owned by ArcLight. Enogex Holdings is a provider of rack sales, propane and trucks. For the three months ended March 31, 2012, the Partnership purchased $171,000 of propane from Enogex Holdings, which is included in cost of sales in the condensed consolidated statement of operations. There were no amounts purchased from Enogex for the three months ended March 31, 2013 or due to Enogex Holdings at December 31, 2012 and March 31, 2013.

The Partnership entered into transactions with CAMS Bluewire, an entity in which ArcLight holds a non-controlling interest. CAMS Bluewire provides IT support for the Partnership. For the three months ended March 31, 2012 and 2013, the Partnership incurred $46,000 and $104,000, respectively, for IT support and consulting services, and for the purchases of IT equipment which are included in operating expenses, general and administrative expenses and property, plant and equipment in the condensed consolidated statements of operations and the consolidated balance sheets. The total amounts due to CAMS Bluewire as of December, 31 2012 was $224,000 and $123,000 as of March 31, 2013.

The Partnership performs certain management services for JP Development. The Partnership receives a monthly fee of $50,000 for these services which reduced the general and administrative expenses in the consolidated statement of operations by $150,000 for the three months ended March 31, 2013. The Partnership had total amounts due from JP Development of $50,000 and $1,609,000 as of December 31, 2012 and March 31, 2013 respectively, as a result of the timing of cash settlement on the monthly management fee as well as expenses incurred by JPE on behalf of JP Development.

As of August 2012, JP Development has a pipeline transportation business that provides crude oil pipeline transportation services to the Partnership’s crude oil supply and logistics segment. As a result of utilizing JP Development’s pipeline transportation services, the Partnership incurred pipeline tariff fees of $3,100,000, which is included in costs of sales on the consolidated statement of operations for the three months ended March 31, 2013.

As a result of the acquisition of ATT in November, 2012, Truman Arnold Companies (“TAC”) owns certain Class C common units in the Partnership. In addition, Mr. Greg Arnold, President and CEO of TAC, is also a director of the Partnership. The Partnership’s refined products, terminaling and storage segment sells refined products to TAC. As ATT was acquired in November 2012, there were no revenues from TAC to be reported for the three months ended March 31, 2012. For the three months ended March 31, 2013, the Partnership’s revenue from TAC was $5,200,000. As of December 31, 2012 and March 31, 2013, the Partnership had trade receivable balances due from from TAC of $1,744,000 and $2,011,000, respectively, which are included in receivables from related parties on the consolidated balance sheets.

10. Reportable Segments

The Partnership’s operations are located in the United States and are organized into four reportable segments: crude oil supply and logistics; crude oil pipelines and storage; refined products terminaling and storage; and NGL distribution and sales. During the first quarter of 2014, as a result of the Common Control Acquisition described in Note 1, the Partnership realigned the composition of its segments. Accordingly, the Partnership has recast and restated the items of segment information for the earlier periods to reflect this new segment realignment.

Crude oil pipelines and storage. The crude oil pipelines and storage segment consists of a crude oil pipeline operation and a crude oil storage facility. The crude oil pipeline operates in the Permian Basin and

consists of approximately 50 miles of high-pressure steel pipeline with throughput capacity of approximately 100,000 barrels per day and a related system of truck terminals, LACT bay facilities, crude oil receipt points and crude oil storage facilities with an aggregate of 40,000 barrels of storage capacity. The Partnership also operates a crude oil storage facility that has an aggregate storage capacity of approximately 3,000,000 barrels in Cushing, Oklahoma.

Crude oil supply and logistics. The crude oil supply and logistics segment consists of crude oil supply activities and a fleet of crude oil gathering and transportation trucks. The Partnership conducts crude oil supply activities by purchasing crude oil for its own account from producers, aggregators and traders and selling crude oil to traders and refiners. The Partnership also owns a fleet of crude oil gathering and transportation trucks operating in and around high-growth drilling areas such as the Bakken shale, the Eagle Ford shale, the Granite Wash play, the Mississippian Lime play and the Permian Basin.

Refined products terminaling and storage. The refined products terminaling and storage segment has aggregate storage capacity of 1.3 million barrels from two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. The North Little Rock terminal has storage capacity of 550,000 barrels from 11 tanks and is primarily served by the refined products pipeline operated by Enterprise TE Products Pipeline Company LLC. The Caddo Mills terminal has storage capacity of 770,000 barrels from 10 tanks and is served by the Explorer Pipeline.

NGL distribution and sales. The NGL distribution and sales segment consists of three businesses: (i) portable cylinder tank exchange (ii) sales of NGLs through our retail, commercial and wholesale distribution business and (iii) NGL gathering and transportation business. Currently, the cylinder exchange network covers over 48 states through a network of over 17,700 locations, which includes grocery chains, pharmacies, convenience stores and hardware stores. Additionally, in five states in the southwest region of the U.S., the Partnership sells NGLs to retailers, wholesalers, industrial end-users and commercial and residential customers. The Partnership also owns a fleet of NGL gathering and transportation operations trucks operating in the Eagle Ford shale and the Permian Basin.

Corporate and other. Corporate and other includes general partnership expenses associated with managing all of the Partnership’s reportable segments.

The Partnership’s chief operating decision maker evaluates the segments’ operating performance based on Adjusted EBITDA, a financial measure that is not recognized under GAAP. Adjusted EBITDA is used as it is the primary measure of the Partnership’s performance. Adjusted EBITDA is defined as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period), and selected (gains) charges and transaction costs that are unusual or non-recurring.

The Partnership’s chief operating decision maker evaluates the segments’ operating performance based on Adjusted EBITDA, a financial measure that is not recognized under GAAP. Adjusted EBITDA is used as it is the primary measure of our performance. Adjusted EBITDA is defined as net income (loss), plus interest expense, income tax expense, depreciation and amortization expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts, selected charges and transaction costs that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts and selected gains that are unusual or non-recurring.

The following tables reflect certain financial data for each reportable segment for the three months ended March 31, 2012 and 2013. For the quarter ended March 31, 2012, the Partnership’s operations consisted of only one reportable segment, NGL distribution and sales.

	Three months ended March 31,
	2012		2013
	(Restated)		(Restated and Recast)
External Revenues:
Crude oil pipelines and storage	$	—	$	3,600
Crude oil supply and logistics	—		422,357
Refined products terminaling and storage	—		7,702
NGL distribution and sales	29,896		47,823
Total revenues	$	29,896	$	481,482

Cost of Sales, excluding depreciation and amortization:
Crude oil pipelines and storage	$	—	$	—
Crude oil supply and logistics	—		415,428
Refined products terminaling and storage	—		2,690
NGL distribution and sales	22,777		27,516
Total cost of sales, excluding depreciation and amortization	$	22,777	$	445,634

Operating Expenses:
Crude oil pipelines and storage	$	—	$	654
Crude oil supply and logistics	—		2,552
Refined products terminaling and storage	—		625
NGL distribution and sales	2,760		10,287
Total operating expenses	$	2,760	$	14,118

Adjusted EBITDA:
Crude oil pipelines and storage	$	—	$	3,007
Crude oil supply and logistics	—		2,743
Refined products terminaling and storage	—		4,295
NGL distribution and sales	3,798		7,119
Total adjusted EBITDA	$	3,798	$	17,164

A reconciliation of adjusted EBITDA to net income is included in the tables below.

	Three months ended March 31,
	2012			2013
	(Restated)			(Restated and Recast)
Total adjusted EBITDA from reportable segments	$	3,798		$	17,164
Other expenses not allocated to reportable segments	(1,709		)	(4,169		)
Depreciation and amortization	(1,112		)	(8,226		)
Interest expense	(330		)	(1,998		)
Income tax expense	(45		)	(160		)
Loss on disposal of assets	(6		)	(447		)
Unit-based compensation	(129		)	(128		)
Total gain on commodity derivatives	—			85
Net settlement loss for commodity derivatives during the period	—			241
Transaction costs	(142		)	(81		)
Other	(18		)	(75		)
Net income	$	307		$	2,206

Total assets from the Partnership’s reportable segments as of December 31, 2012 and March 31, 2013 were as follows:

	December 31 , 2012		March 31, 2013
	(Restated and Recast)		(Restated and Recast)
Crude oil pipelines and storage	$	89,862	$	88,429
Crude oil supply and logistics	174,312		166,664
Refined products terminaling and storage	135,051		135,246
NGL distribution and sales	153,418		153,802
Corporate and other	9,481		10,743
Total assets	$	562,124	$	554,884

11. Subsequent Events

Common Units. On July 18, 2013, the Partnership issued 45,860 Class C Common Units to JP Development for total net proceeds of $1,628,000. On August 13, 2013, the Partnership issued 42,254 Class C Common Units to JP Development for total net proceeds of $1,500,000.

Preferred Units. On August 1, 2013, the Partnership executed the Series A, Series B, and Series C Forced Conversion Notice (“Conversion Notice”) with Lonestar. Pursuant to the Conversion Notice, all 524,746 of the then-outstanding Series A Convertible Preferred Units, all 552,348 of the then-outstanding Series B Convertible Preferred Units, and all 59,270 of the then-outstanding Series C Convertible Preferred Units held by Lonestar were converted on a one-for-one basis into Class A Common Units.

ArcLight Capital Commitment. Pursuant to a Purchase Agreement dated June 27, 2011 (the “Purchase Agreement”) by and among the Partnership, JP Energy GP II LLC (the “General Partner”) and Lonestar Midstream Holdings, LLC (“Lonestar”), the board of directors of Lonestar committed to provide up to $100,000,000 to fund acquisitions or for other valid partnership purposes. On July 12, 2012, the Partnership, the General Partner, JP Energy GP LLC, CB Capital Holdings II, LLC and Lonestar entered into an Amended and Restated Purchase Agreement (the “Amended and Restated Purchase Agreement”) that increased Lonestar’s capital commitment in the aggregate to the Partnership and to JP Energy Development LP to $300,000,000. On

October 4, 2013, the parties to the Amended and Restated Purchase Agreement terminated the Amended and Restated Purchase Agreement and any obligations thereunder.

Related Party Note Payable. On November 5, 2013, The Partnership issued a $1,000,000 promissory note to JP Development for working capital requirements. The note will mature on November 5, 2016 and currently bears interest at 4.75%. The interest rate is subject to an adjustment each quarter equal to the weighted average rate of JP Development’s outstanding indebtedness during the most recently ended fiscal quarter. Accrued interest on the note is payable quarterly in arrears. On March 20, 2014, the Partnership repaid the promissory note in full.

Series D Preferred Units. On March 28, 2014 (the “Issue Date”), the Partnership authorized and issued to Lonestar 1,818,182 Series D Convertible Redeemable Preferred Units (the “Series D Preferred Units”) for a cash purchase price of $22.00 per unit pursuant to the terms of a Series D Subscription Agreement (the “Subscription Agreement”) by and among the Partnership, GP II and Lonestar. This transaction resulted in proceeds to the Partnership of $40 million.

The Series D Preferred Units are a new class of voting equity security that ranks senior to all of the Partnership’s other classes or series of equity securities with respect to distribution rights and rights upon liquidation. The Series D Preferred Units have voting rights identical to the voting rights of the Partnership’s Class A Common Units and will vote with the Partnership’s common units as a single class, such that each Series D Preferred Unit (including each Series D Preferred Unit issued as an in-kind distribution, discussed below) is entitled to one vote for each common unit into which such Series D Preferred Unit is convertible on each matter with respect to which each common unit is entitled to vote.

Each Series D Preferred Unit (including Series D Paid-in-kind (“PIK”) Units issued as in-kind distributions) earns a cumulative distribution that is payable in either cash or Series D PIK Units as described below. The distribution rate for any such unit is (A) with respect to any distribution for the four consecutive quarters commencing with the quarter ended June 30, 2014, an amount equal to the greater of (i) the amount of aggregate distributions in cash for such quarter that would be payable with respect to such unit if such unit had been converted into a common unit of the Partnership as of the date of determination and (ii) $0.66, and (B) with respect to any distribution for any quarterly period after the quarter ending March 31, 2015, (i) the amount of aggregate distributions in cash for such quarter that would be payable with respect to such unit if such unit had been converted into a common unit of the Partnership as of the date of determination and (ii) $0.825. If the Partnership does not have sufficient available cash to make cash distributions with respect to the common units, the Partnership may pay all or any portion of the Series D Distribution in-kind during each quarter commencing on the Issue Date and ending on March 31, 2015.

The Series D Preferred Units (including Series D PIK Units issued as in-kind distributions) are convertible into common units of the Partnership on a one-for-one basis by Lonestar at any time after December 31, 2014. The Partnership may redeem the Series D Preferred Units (A) at any time prior to the Partnership’s initial public offering of its common units or (B) during the period commencing on the Issue Date and ending on April 1, 2015, whichever is later, in each case at a price of $22.00 per Series D Preferred Unit, subject to adjustment pursuant to the provisions of the Partnership Agreement.

Location of
Gain/(Loss)
Recognized in
Income on
Derivatives

Amount of
Gain/(Loss)
Recognized in
Income on
Derivatives

Mark-to-Market derivatives

Commodity derivatives

Cost of sales

Interest rate swaps

Interest expense