NGL Energy Partners LP - Quarter Report: 2012 December (Form 10-Q)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended December 31, 2012

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

For the transition period from to

Commission File Number: 001-35172

NGL Energy Partners LP

(Exact Name of Registrant as Specified in Its Charter)

Delaware		27-3427920
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

6120 South Yale Avenue Suite 805 Tulsa, Oklahoma		74136
(Address of Principal Executive Offices)		(Zip code)

(918) 481-1119

(Registrant’s Telephone Number, Including Area Code)

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

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

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

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x		Smaller reporting company o

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

As of February 7, 2013, there were 49,136,700 common units and 5,919,346 subordinated units issued and outstanding.

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	PART I

Item 1.	Financial Statements (Unaudited)	3

	Condensed Consolidated Balance Sheets as of December 31, 2012 and March 31, 2012	3
	Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2012 and 2011	4
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2012 and 2011	5
	Condensed Consolidated Statement of Changes in Partners’ Equity for the nine months ended December 31, 2012	6
	Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2012 and 2011	7
	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	66
Item 4.	Controls and Procedures	67

	PART II

Item 1.	Legal Proceedings	69
Item 1A.	Risk Factors	69
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	69
Item 3.	Defaults Upon Senior Securities	69
Item 4.	Mine Safety Disclosures	69
Item 5.	Other Information	69
Item 6.	Exhibits	69

Signatures		71

Exhibit Index		72

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Forward-Looking Statements

This quarterly report on Form 10-Q contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this quarterly report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

· the prices and market demand for petroleum products;

· energy prices generally;

· the price of propane compared to the price of alternative and competing fuels;

· the general level of petroleum product demand and the availability of propane supplies;

· the level of domestic oil, propane and natural gas production;

· the availability of imported oil and natural gas;

· the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;

· actions taken by foreign oil and gas producing nations;

· the political and economic stability of petroleum producing nations;

· the effect of weather conditions on demand for oil, natural gas and propane;

· the effect of natural disasters or other significant weather events;

· availability of local, intrastate and interstate transportation infrastructure;

· availability and marketing of competitive fuels;

· the impact of energy conservation efforts;

· energy efficiencies and technological trends;

· governmental regulation and taxation;

· the impact of legislative and regulatory actions on hydraulic fracturing;

· hazards or operating risks incidental to the transporting and distributing of petroleum products that may not be fully covered by insurance;

· the maturity of the propane industry and competition from other propane distributors;

· loss of key personnel;

· the ability to renew contracts with key customers;

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· the ability of our customers to perform on their contracts with us;

· the fees we charge and the margins we realize for our terminal services;

· the ability to renew leases for general purpose and high pressure rail cars;

· the ability to renew leases for underground storage;

· the nonpayment or nonperformance by our customers;

· the availability and cost of capital and our ability to access certain capital sources;

· a deterioration of the credit and capital markets;

· the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results;

· the ability to successfully integrate acquired assets and businesses;

· changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

· the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this quarterly report. Except as required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks described under “Item 1A — Risk Factors” in our annual report on Form 10-K for the fiscal year ended March 31, 2012, as supplemented and updated by Part II, Item 1A, “Risk Factors” in our quarterly reports on Form 10-Q for the quarters ended June 30, 2012 and September 30, 2012.

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PART I

Item 1. Financial Statements (Unaudited)

NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Balance Sheets

As of December 31, 2012 and March 31, 2012

(U.S. Dollars in Thousands, except unit amounts)

	December 31,			March 31,
	2012			2012
				(Note 3)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	23,903		$	7,832
Accounts receivable - trade, net of allowance for doubtful accounts of $1,962 and $818, respectively	595,274			84,004
Receivables from affiliates	1,334			2,282
Inventories	234,025			94,504
Prepaid expenses and other current assets	58,004			10,002
Total current assets	912,540			198,624

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $34,072 and $12,843, respectively	520,084			231,394
GOODWILL	510,072			167,245
INTANGIBLE ASSETS, net of accumulated amortization of $29,807 and $8,174, respectively	487,206			149,490
OTHER NONCURRENT ASSETS	7,567			2,766
Total assets	$	2,437,469		$	749,519

LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Trade accounts payable	$	579,371		$	81,369
Accrued expenses and other payables	74,064			14,143
Advance payments received from customers	59,237			20,293
Payables to affiliates	6,527			9,462
Current maturities of long-term debt	8,635			19,534
Total current liabilities	727,834			144,801

LONG-TERM DEBT, net of current maturities	827,570			199,177
OTHER NONCURRENT LIABILITIES	1,428			212

COMMITMENTS AND CONTINGENCIES

PARTNERS’ EQUITY, per accompanying statement:
General Partner — 0.1% interest; 53,174 and 29,245 notional units outstanding, respectively	(50,752		)	442
Limited Partners — 99.9% interest —
Common units — 47,201,831 and 23,296,253 units outstanding, respectively	912,028			384,604
Subordinated units — 5,919,346 units outstanding at December 31, 2012 and March 31, 2012	13,556			19,824
Accumulated other comprehensive income —
Foreign currency translation	32			31
Noncontrolling interests	5,773			428
Total partners’ equity	880,637			405,329
Total liabilities and partners’ equity	$	2,437,469		$	749,519

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statements of Operations

Three Months and Nine Months Ended December 31, 2012 and 2011

(U.S. Dollars in Thousands, except unit and per unit amounts)

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
REVENUES:
Retail propane	$	127,905		$	62,701		$	244,116		$	94,787
Natural gas liquids logistics	508,131			407,948			1,050,116			776,757
Crude oil logistics	677,985			—			1,462,523			—
Water services	22,806			—			40,557			—
Other	1,381			—			2,842			—
Total Revenues	1,338,208			470,649			2,800,154			871,544

COST OF SALES:
Retail propane	77,449			40,502			144,556			61,825
Natural gas liquids logistics	470,621			399,288			982,949			765,400
Crude oil logistics	654,976			—			1,425,546			—
Water services	1,499			—			4,169			—
Total Cost of Sales	1,204,545			439,790			2,557,220			827,225

OPERATING COSTS AND EXPENSES:
Operating	50,518			12,653			113,287			27,045
General and administrative	14,175			4,163			34,578			10,363
Depreciation and amortization	18,747			5,402			41,335			8,480
Operating Income (Loss)	50,223			8,641			53,734			(1,569		)

OTHER INCOME (EXPENSE):
Interest income	241			197			870			422
Interest expense	(9,762		)	(2,676		)	(22,254		)	(4,989		)
Loss on early extinguishment of debt	—			—			(5,769		)	—
Other, net	20			86			49			215
Income (Loss) Before Income Taxes	40,722			6,248			26,630			(5,921		)

INCOME TAX PROVISION	(245		)	(158		)	(781		)	(158		)

Net Income (Loss)	40,477			6,090			25,849			(6,079		)

Net (Income) Loss Allocated to General Partner	(942		)	(6		)	(1,731		)	6

Net (Income) Loss Attributable to Noncontrolling Interests	(301		)	—			(250		)	—

Net Income (Loss) Attributable to Parent Equity Allocated to Limited Partners	$	39,234		$	6,084		$	23,868		$	(6,073	)

Basic and Diluted Earnings (Loss) Per Common Unit	$	0.75		$	0.24		$	0.53		$	(0.41	)

Basic and Diluted Earnings (Loss) per Subordinated Unit	$	0.75		$	0.28		$	0.51		$	(0.20	)

Basic and Diluted Weighted average units outstanding:
Common	46,364,381			18,699,590			39,288,012			12,491,836
Subordinated	5,919,346			5,919,346			5,919,346			4,929,201

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)

Three Months and Nine Months Ended December 31, 2012 and 2011

(U.S. Dollars in Thousands)

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2012		2011		2012		2011

Net income (loss)	$	40,477	$	6,090	$	25,849	$	(6,079	)
Other comprehensive income (loss), net of tax:
Change in foreign currency translation adjustment	4		18		1		(38		)
Comprehensive income (loss)	$	40,481	$	6,108	$	25,850	$	(6,117	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statement of Changes in Partners’ Equity

Nine Months Ended December 31, 2012

(U.S. Dollars in Thousands, except unit amounts)

												Accumulated
				Limited Partners								Other				Total
	General			Common				Subordinated				Comprehensive		Noncontrolling		Partners’
	Partner			Units	Amount			Units	Amount			Income		Interests		Equity
BALANCES, MARCH 31, 2012	$	442		23,296,253	$	384,604		5,919,346	$	19,824		$	31	$	428	$	405,329
Distributions to partners	(851		)	—	(38,334		)	—	(7,251		)	—		—		(46,436		)
Contributions	514			—	—			—	—			—		362		876
Business combinations (Note 3)	(52,588		)	23,905,578	543,515			—	—			—		4,733		495,660
Equity issuance costs	—			—	(642		)	—	—			—		—		(642		)
Net income	1,731			—	22,885			—	983			—		250		25,849
Foreign currency translation adjustment	—			—	—			—	—			1		—		1
BALANCES, DECEMBER 31, 2012	$	(50,752	)	47,201,831	$	912,028		5,919,346	$	13,556		$	32	$	5,773	$	880,637

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Statements of Cash Flows

Nine Months Ended December 31, 2012 and 2011

(U.S. Dollars in Thousands)

	Nine Months Ended
	December 31,
	2012			2011
OPERATING ACTIVITIES:
Net income (loss)	$	25,849		$	(6,079	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization, including debt issuance cost amortization	52,680			10,026
Loss (gain) on sale of assets	(34		)	(84		)
Provision for doubtful accounts	909			405
Commodity derivative (gain) loss	(12,024		)	(2,179		)
Other	(13		)	43
Changes in operating assets and liabilities, exclusive of acquisitions —
Accounts receivable	(29,287		)	(66,459		)
Receivables from affiliates	8,672			—
Inventories	(88,631		)	(64,458		)
Product exchanges, net	13,678			15,873
Prepaid expenses and other assets	6,961			5,487
Trade accounts payable	26,437			68,583
Accrued expenses and other liabilities	(20,985		)	514
Accounts payable to affiliates	(11,951		)	5,738
Advance payments received from customers	25,813			18,926
Net cash used in operating activities	(1,926		)	(13,664		)

INVESTING ACTIVITIES:
Purchases of long-lived assets	(37,369		)	(4,131		)
Cash paid for acquisitions of businesses, including acquired working capital, net of cash acquired	(493,296		)	(192,588		)
Cash flows from commodity derivatives	14,478			2,097
Proceeds from sales of assets	700			309
Other	645			138
Net cash used in investing activities	(514,842		)	(194,175		)

FINANCING ACTIVITIES:
Proceeds from sale of common units, net of offering costs	(642		)	74,805
Repurchase of common units	—			(3,418		)
Proceeds from borrowings under revolving credit facilities	977,975			350,500
Payments on revolving credit facilities	(628,975		)	(205,500		)
Issuance of senior notes	250,000			—
Payments on other long-term debt	(1,346		)	(1,158		)
Debt issuance costs	(18,613		)	(2,044		)
Contributions	876			—
Distributions to partners	(46,436		)	(11,315		)
Net cash provided by financing activities	532,839			201,870
Net increase (decrease) in cash and cash equivalents	16,071			(5,969		)
Cash and cash equivalents, beginning of period	7,832			16,337
Cash and cash equivalents, end of period	$	23,903		$	10,368

The accompanying notes are an integral part of these condensed consolidated financial statements.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Note 1 - Organization and Operations

NGL Energy Partners LP (“we”, “our”, “us”, or the “Partnership”) is a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. We completed an initial public offering in May 2011. At the time of our initial public offering, we owned and operated retail propane and wholesale natural gas liquids businesses. Subsequent to our initial public offering, we significantly expanded our operations through a number of business combinations, including the following:

· On October 3, 2011, we completed a business combination transaction with E. Osterman Propane, Inc., its affiliated companies and members of the Osterman family (collectively, “Osterman”), whereby we acquired retail propane operations in the northeastern United States. We issued 4,000,000 common units and paid $94.9 million of cash, net of cash acquired, in exchange for the assets and operations of Osterman. The agreement also contemplated a post-closing payment of $4.8 million for certain specified working capital items, which was paid in November 2012.

· On November 1, 2011, we completed a business combination transaction with SemStream, L.P. (“SemStream”), whereby we acquired SemStream’s wholesale natural gas liquids supply and marketing operations and its 12 natural gas liquids terminals. We issued 8,932,031 common units and paid $91 million in exchange for the assets and operations of SemStream, including working capital.

· On January 3, 2012, we completed a business combination transaction with seven companies associated with Pacer Propane Holding, L.P. (collectively, “Pacer”), whereby we acquired retail propane operations, primarily in the western United States. We issued 1,500,000 common units, valued at $30.4 million, and paid $32.2 million of cash in exchange for the assets and operations of Pacer, including working capital. We also assumed $2.7 million of long-term debt in the form of non-compete agreements.

· On February 3, 2012, we completed a business combination transaction with North American Propane, Inc. (“North American”), whereby we acquired retail propane and distillate operations in the northeastern United States. We paid $69.8 million of cash in exchange for the assets and operations of North American, including working capital.

· On June 19, 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively, “High Sierra”). High Sierra’s businesses include crude oil gathering, transportation and marketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing. We paid $91.8 million of cash (net of $5.0 million of cash acquired) and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

equipment financing facilities. Also on November 1, 2012, we entered into a call agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners of Pecos purchased 1,834,414 common units from us for $45.0 million pursuant to this agreement.

· On December 31, 2012, we completed a business combination transaction whereby we acquired all of the limited liability company membership interests in Third Coast Towing, LLC (“Third Coast”) for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. The agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. Also on December 31, 2012, we entered into a call agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed to purchase a minimum of $8.0 million or a maximum of $10.0 million of common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to this call agreement.

· During the nine months ended December 31, 2012, we completed six separate business combination transactions to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. On a combined basis, we paid $71.1 million of cash and issued 850,676 common units in exchange for these assets and operations, including working capital. In addition, a combined amount of approximately $0.3 million will be payable as deferred payments on the purchase prices. We also assumed $6.6 million of long-term debt in the form of non-compete agreements.

· During the nine months ended December 31, 2012, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics and water services businesses. On a combined basis, we paid $53.3 million of cash and assumed $1.3 million of long-term debt in the form of non-compete agreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions. Certain of the acquisition agreements contemplate post-closing adjustment to the purchase price for certain specified working capital items.

As of December 31, 2012, our businesses include:

· Retail propane and distillate operations in more than 20 states;

· Wholesale natural gas liquids operations throughout the United States and in Canada;

· Propane and natural gas liquids transportation and terminalling operations, conducted through 17 owned terminals and a fleet of owned and predominantly leased rail cars;

· A crude oil transportation and marketing business, the assets of which include crude oil terminals, a fleet of trucks, a fleet of leased rail cars, and several barges; and

· A water treatment business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks.

Note 2 - Significant Accounting Policies

Basis of Presentation

The condensed consolidated financial statements as of December 31, 2012 and March 31, 2012 and for the three months and nine months ended December 31, 2012 and 2011 include our accounts and those of our controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). The condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of the financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the condensed consolidated financial statements do not include all the information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements for the fiscal year ended March 31, 2012, included in our Annual Report on Form 10-K. Due to the seasonal nature of our natural gas liquids operations and other factors, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

The condensed consolidated balance sheet as of March 31, 2012 is derived from audited financial statements. Certain amounts previously reported have been reclassified to conform to the current presentation. In addition, as described in Note 3, certain balances as of March 31, 2012 were adjusted to reflect the final acquisition accounting for certain business combinations.

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates.

Significant Accounting Policies

Our significant accounting policies are consistent with those disclosed in Note 2 of our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended March 31, 2012. We have included information below on certain new accounting policies relevant to the businesses acquired in the June 2012 merger with High Sierra, and on certain other accounting policies that are significant to an understanding of the accompanying financial statements.

Revenue Recognition

Revenues from sales of products are recognized on a gross basis at the time title to the product sold transfers to the purchaser and collection of those amounts is reasonably assured. Sales or purchases with the same counterparty that are entered into in contemplation of one another are reported on a net basis as one transaction. Revenue from wastewater disposal trucking services is recognized when the wastewater is picked up from the customer’s location or upon delivery of the wastewater to a specific delivery location, depending upon the terms of the contractual agreements. Revenue from other transportation services is recognized upon completion of the services as defined in the customer agreement. Revenue on equipment leased under operating leases is billed and recognized monthly according to the terms of the related lease agreement with the customer over the term of the lease. Net gains and losses resulting from commodity derivative instruments are recognized within cost of sales.

Revenues for the wastewater disposal business are recognized upon delivery of the wastewater to the disposal facilities. Certain agreements require customers to deliver minimum quantities of wastewater for an agreed upon period. Revenue is recognized when the wastewater is delivered, with an adjustment for the minimum volume delivery in the event that actual delivered wastewater is less than the committed minimum. Revenues from hydrocarbons recovered from wastewater are recognized upon sale.

Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations. Shipping and handling costs associated with product sales are included in operating expenses in the consolidated statements of operations. Taxes collected from customers and remitted to the appropriate taxing authority are excluded from revenues in the consolidated statements of operations.

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity and interest rate derivative instruments and assets and liabilities acquired in business combinations. Fair value represents the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

· Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

· Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts and interest rate protection agreements. The majority of our derivative financial instruments were categorized as Level 2 at December 31, 2012 and March 31, 2012 (see Note 11). We determine the fair value of all our derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

· Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at December 31, 2012 or March 31, 2012.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Supplemental Cash Flow Information

Supplemental cash flow information is as follows for the periods indicated:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2012		2011		2012		2011
	(in thousands)

Interest paid, exclusive of debt issuance costs	$	9,426	$	1,121	$	19,257	$	1,980
Income taxes paid	$	560	$	—	$	736	$	—

Value of common units issued in business combinations (Note 3)	$	57,259	$	266,655	$	490,927	$	266,655

Cash flows from commodity derivative instruments are classified as cash flows from investing activities in the consolidated statements of cash flows.

Inventories

Inventories consist of the following:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

	December 31,		March 31,
	2012		2012
	(in thousands)
Propane	$	144,949	$	78,993
Other natural gas liquids	37,507		9,259
Crude oil	40,521		—
Other	11,048		6,252
	$	234,025	$	94,504

Asset Retirement Obligations

An asset retirement obligation (“ARO”) is a legal obligation associated with the retirement of a tangible long-lived asset that generally results from the acquisition, construction, development or normal operation of the asset. Significant inputs used to estimate an ARO include: (i) the expected retirement date; (ii) the estimated costs of retirement, including adjustments for cost inflation and the time value of money; and (iii) the appropriate method for allocation of estimated asset retirement costs to expense. The cost for asset retirement is capitalized as part of the cost of the related long-lived assets and subsequently allocated to expense over the remaining useful lives of the assets associated with the obligation. The ARO liability is accreted to the estimated total retirement obligation over the period the related assets are used through the expected retirement date.

Note 3 — Acquisitions

Third Coast Combination

On December 31, 2012, we completed a business combination transaction whereby we acquired all of the limited liability company membership interests in Third Coast for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. The agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. Also on December 31, 2012, we entered into a call agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed to purchase a minimum of $8.0 million or a maximum of $10.0 million of common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to this agreement. We incurred and charged to general and administrative expense during the three months ended December 31, 2012 approximately $0.4 million of costs related to the Third Coast combination.

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the combination with Third Coast. The estimates of fair value reflected as of December 31, 2012 are subject to change. We currently expect to complete this process prior to filing our Form 10-Q for the quarter ended December 31, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Cash	$	2
Accounts receivable	2,248
Other noncurrent assets	2,733
Property, plant and equipment:
Marine vessels (20 years)	12,883
Other	30
Customer relationships (15 years)	8,000
Trade names (indefinite life)	500
Goodwill	18,689
Assumed liabilities	(2,202		)
Equity (fair value of call agreement)	117
Cash paid	$	43,000

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Pecos Combination

On November 1, 2012, we completed a business combination whereby we acquired Pecos. The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and New Mexico. We paid cash of $134.6 million at closing, subject to customary post-closing adjustments, and assumed certain obligations with a value of $10.4 million under certain vehicle and related equipment financing facilities. Also on November 1, 2012, we entered into a call agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement. We incurred and charged to general and administrative expense during the nine months ended December 31, 2012 approximately $0.5 million of costs related to the Pecos combination.

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the combination with Pecos. The estimates of fair value reflected as of December 31, 2012 are subject to change, and such changes could be material. We expect to complete this process prior to filing our Form 10-Q for the quarter ended September 30, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Cash	$	2,180
Accounts receivable	73,704
Inventory	1,903
Other current assets	1,475
Property, plant and equipment:
Vehicles and related equipment (5 years)	19,193
Other	2,562
Customer relationships (15 years)	37,754
Trade names (indefinite life)	1,000
Goodwill	56,830
Accounts payable and accrued liabilities	(51,669		)
Long-term debt	(10,365		)
Total consideration paid	$	134,567

The consideration paid consists of the following (in thousands):

Cash paid, net of cash received pursuant to Call Agreement	$	89,624
Value of common units issued pursuant to Call Agreement	44,943
Total consideration paid	$	134,567

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Other Crude Oil Logistics and Water Services Business Combinations

During the nine months ended December 31, 2012, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics and water services businesses. On a combined basis, we paid $53.3 million in cash and assumed $1.3 million of long-term debt in the form of non-compete agreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions. Certain of the agreements contemplate post-closing adjustments to the purchase price for certain specified working capital items. We incurred and charged to general and administrative expense during the nine months ended December 31, 2012 approximately $0.3 million of costs related to these acquisitions.

We are currently in the process of identifying and determining the fair value of the assets and liabilities acquired in this combination. The estimates of fair value reflected as of December 31, 2012 are subject to change. We currently expect to complete this process prior to filing our Form 10-Q for the quarter ended September 30, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Cash	$	743
Accounts receivable	2,782
Inventory	169
Other current assets	759
Property, plant and equipment:
Disposal wells and related equipment (10-30 years)	13,322
Other (5-30 years)	5,672
Customer relationships (15 years)	12,900
Trade names (indefinite life)	500
Goodwill	37,527
Current liabilities	(4,972		)
Notes payable	(1,340		)
Noncontrolling interest	(2,333		)
Consideration paid	$	65,729

The consideration paid consists of the following (in thousands):

Cash paid	$	53,296
Value of common units issued	12,433
Total consideration paid	$	65,729

High Sierra Combination

On June 19, 2012, we completed a business combination with High Sierra, whereby we acquired all of the ownership interests in High Sierra. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. These common units were valued at $406.8 million using the closing price of our common units on the New York Stock Exchange (the “NYSE”) on the merger date. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner. We recorded the value of the 2,685,042 common units issued to our general partner at $8.0 million, which represents an initial estimate, in accordance with GAAP, of the fair value of the equity issued by our general partner to the former owners of High Sierra’s general partner. In accordance with the fair value model specified in the accounting standards, this fair value was estimated based on assumptions of future distributions and a discount rate

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

that a hypothetical buyer might use. Under this model, the potential for distribution growth resulting from the prospect of future acquisitions and capital expansion projects would not be considered in the fair value calculation. We have not yet completed the accounting for the business combination, and this estimate of fair value is subject to change. The difference between the estimated fair value of the general partner interests issued by our general partner of $8.0 million, calculated as described above, and the fair value of the common units issued to our general partner of $60.6 million, as calculated using the closing price of the common units on the NYSE, is reported as a reduction to equity. We incurred and charged to general and administrative expense during the nine months ended December 31, 2012 approximately $3.6 million of costs related to the High Sierra transaction. We also incurred or accrued costs of approximately $0.6 million related to the equity issuance that we charged to equity.

We have included the results of High Sierra’s operations in our consolidated financial statements beginning on June 19, 2012. During the nine months ended December 31, 2012, our consolidated statement of operations includes operating income of approximately $47.8 million generated by the operations of High Sierra and by the operations of the subsequent acquisitions of crude oil logistics and water services businesses. The following table summarizes the revenues and cost of sales generated from High Sierra’s operations and by the operations of the subsequent acquisitions of crude oil logistics and water services businesses (in thousands):

	Revenues		Cost of Sales
Crude oil logistics	$	1,472,439	$	1,435,462
Natural gas liquids logistics	463,814		424,567
Water services	40,557		4,169
Other	2,842		—
Total	$	1,979,652	$	1,864,198

We are in the process of identifying, and obtaining an independent appraisal of the fair value of, the assets and liabilities acquired in the combination with High Sierra. The estimates of fair value reflected as of December 31, 2012 are subject to change and such changes could be material. We expect to complete this process prior to filing our Form 10-K for the fiscal year ending March 31, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Accounts receivable	$	395,351
Inventory	43,663
Receivables from affiliates	7,724
Derivative assets	10,646
Forward purchase and sale contracts	34,717
Other current assets	11,174
Property, plant and equipment:
Land	5,825
Transportation vehicles and equipment (5 years)	22,746
Facilities and equipment (20 years)	105,065
Buildings and improvements (20 years)	10,549
Software (5 years)	4,203
Construction in progress	11,213
Intangible assets:
Customer relationships (15 years)	242,000
Lease contracts (1-6 years)	10,500
Trade names (indefinite)	16,000
Goodwill	216,193

Assumed liabilities:
Accounts payable	(417,369		)
Accrued expenses and other current liabilities	(36,039		)
Payables to affiliates	(9,016		)
Advance payments received from customers	(1,237		)
Derivative liabilities	(5,726		)
Forward purchase and sale contracts	(18,680		)
Noncurrent liabilities	(3,057		)
Noncontrolling interest in consolidated subsidiary	(2,400		)
Consideration paid, net of cash acquired	$	654,045

The fair value of accounts receivable is approximately $0.6 million lower than the contract value, to give effect to estimated uncollectable accounts.

Retail Combinations During the Nine Months Ended December 31, 2012

During the nine months ended December 31, 2012, we entered into six separate business combination agreements to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. On a combined basis, we paid cash of $71.1 million and issued 850,676 common units, valued at $18.9 million, in exchange for these assets. In addition, a combined amount of approximately $0.3 million will be payable as deferred payments on the purchase prices. We also assumed $6.6 million of long-term debt in the form of non-compete agreements. We incurred and charged to general and administrative expense during the nine months ended December 31, 2012 approximately $0.3 million related to these acquisitions. We are in the process of identifying the fair value of the assets and liabilities acquired in the combinations. The estimates of fair value reflected as of December 31, 2012 are subject to change, and such changes could be material. Our preliminary estimates of the fair value of the assets acquired and liabilities assumed in these six combinations are as follows (in thousands):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Accounts receivable	$	8,711
Inventory	5,155
Other current assets	1,227
Property, plant and equipment:
Land	4,474
Tanks and other retail propane equipment (5-20 years)	33,770
Vehicles (5 years)	10,742
Buildings (30 years)	10,175
Other equipment	1,132
Intangible assets:
Customer relationships (10-15 years)	17,590
Tradenames (indefinite)	824
Non-compete agreements (5 years)	1,174
Goodwill	13,589
Other non-current assets	784
Long-term debt, including current portion	(6,585		)
Other assumed liabilities	(12,514		)
Fair value of net assets acquired	$	90,248

Consideration paid consists of the following (in thousands):

Cash consideration paid through December 31, 2012	$	71,085
Deferred payments on purchase price	289
Value of common units issued	18,874
Total consideration	$	90,248

The retail combinations completed during the nine months ended December 31, 2012 contributed approximately $65.0 million of revenue and approximately $44.2 million of cost of sales to our consolidated statement of operations for the nine months ended December 31, 2012.

Osterman Combination

As described in Note 1, we acquired the operations of Osterman in October 2011. During the three months ended September 30, 2012 we completed the acquisition accounting for this transaction. The following table presents the final allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision
Accounts receivable	$	9,350		$	5,584		$	3,766
Inventory	3,869			3,898			(29		)
Other current assets	215			212			3

Property, plant and equipment:
Land	2,349			4,500			(2,151		)
Tanks and other retail propane equipment (15-20 years)	47,160			55,000			(7,840		)
Vehicles (5-20 years)	7,699			12,000			(4,301		)
Buildings (30 years)	3,829			6,500			(2,671		)
Other equipment (3-5 years)	732			1,520			(788		)

Intangible assets:
Customer relationships (20 years)	54,500			62,479			(7,979		)
Tradenames (indefinite life)	8,500			5,000			3,500
Non-compete agreements (7 years)	700			—			700

Goodwill	52,267			30,405			21,862
Assumed liabilities	(9,654		)	(5,431		)	(4,223		)
Consideration paid, net of cash acquired	$	181,516		$	181,667		$	(151	)

Consideration paid consists of the following (in thousands):

			Estimated
			Allocation
			as of
	Final		March 31,
	Allocation		2012		Revision
Cash paid at closing, net of cash acquired	$	94,873	$	96,000	$	(1,127	)
Fair value of common units issued at closing	81,880		81,880		—
Working capital payment (paid in November 2012)	4,763		3,787		976
Consideration paid, net of cash acquired	$	181,516	$	181,667	$	(151	)

We have adjusted the March 31, 2012 balances reported in these condensed consolidated financial statements to reflect the final acquisition accounting. The impact of these revisions was not material to the condensed consolidated statements of operations.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Pacer Combination

As described in Note 1, we acquired the operations of Pacer in January 2012. During the three months ended December 31, 2012, we completed the acquisition accounting for this transaction. The following table presents the final allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision

Accounts receivable	$	4,389		$	4,389		$	—
Inventory	965			965			—
Other current assets	43			43			—
Property, plant and equipment:
Land	1,967			1,400			567
Tanks and other retail propane equipment (15-20 years)	12,793			11,200			1,593
Vehicles (5 years)	3,090			5,000			(1,910		)
Buildings (30 years)	409			2,300			(1,891		)
Other equipment	59			200			(141		)
Intangible assets:
Customer relationships (15 years)	23,560			21,980			1,580
Tradenames (indefinite life)	2,410			1,000			1,410
Noncompete agreements	1,520			—			1,520
Goodwill	15,782			18,460			(2,678		)
Assumed liabilities	(4,399		)	(4,349		)	(50		)
Consideration paid	$	62,588		$	62,588		$	—

The consideration paid consists of the following (in thousands):

Cash paid	$	32,213
Fair value of common units issued	30,375
Total consideration paid	$	62,588

North American Combination

As described in Note 1, we acquired the operations of North American in February 2012. During the three months ended December 31, 2012, we completed the acquisition accounting for this transaction. The following table presents the final allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision

Accounts receivable	$	10,338		$	10,338		$	—
Inventory	3,437			3,437			—
Other current assets	282			282			—
Property, plant and equipment:
Land	2,251			2,600			(349		)
Tanks and other retail propane equipment (15-20 years)	24,790			27,100			(2,310		)
Terminal assets (15-20 years)	1,044			—			1,044
Vehicles (5-15 years)	5,819			9,000			(3,181		)
Buildings (30 years)	2,386			2,200			186
Other equipment (3-5 years)	634			500			134
Intangible assets:
Customer relationships (10 years)	12,600			9,800			2,800
Tradenames (10 years)	2,700			1,000			1,700
Noncompete agreements (3 years)	700			—			700
Goodwill	13,978			14,702			(724		)
Assumed liabilities	(11,129		)	(11,129		)	—
Consideration paid	$	69,830		$	69,830		$	—

Pro Forma Results of Operations

The operations of High Sierra have been included in our statements of operations since High Sierra was acquired on June 19, 2012. The operations of Pecos have been included in our statements of operations since Pecos was acquired on November 1, 2012. The Third Coast acquisition was completed on December 31, 2012. The following unaudited pro forma consolidated data below are presented as if the High Sierra, Pecos, and Third Coast acquisitions had been completed on April 1, 2011. The pro forma earnings per unit are based on the common and subordinated units outstanding as of December 31, 2012.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

	Three Months				Nine Months
	Ended				Ended
	December 31,				December 31,
	2012		2011		2012		2011
			(in thousands, except per unit amounts)
Revenues	$	1,342,315	$	1,430,836	$	3,812,836	$	3,543,423
Net income (loss) from continuing operations	39,982		9,113		37,796		17,061
Limited partners’ interest in net income (loss) from continuing operations	39,942		9,104		37,758		17,044
Basic and diluted earnings (loss) from continuing operations per common unit	0.75		0.17		0.71		0.32
Basic and diluted earnings (loss) from continuing operations per subordinated unit	0.75		0.17		0.71		0.32

The pro forma consolidated data in the table above was prepared by adding the historical results of operations of High Sierra, Pecos, and Third Coast to our historical results of operations and making certain pro forma adjustments. The pro forma adjustments include: (i) replacing the historical depreciation and amortization expense of High Sierra, Pecos, and Third Coast with pro forma depreciation and amortization expense, calculated using the estimated fair values of long-lived assets recorded in the acquisition accounting; (ii) replacing the historical interest expense of High Sierra, Pecos, and Third Coast with pro forma interest expense; and (iii) excluding approximately $8.4 million of professional fees and other expenses incurred by us and by the acquirees that were directly related to the acquisitions. In order to calculate pro forma earnings per unit in the table above, we assumed that: (i) the same number of limited partner units outstanding at December 31, 2012 had been outstanding throughout the periods shown in the table, (ii) no incentive distributions (described in Note 10) were paid to the general partner related to the periods shown in the table, and (iii) all of the common units were eligible for a distribution related to the periods shown in the table. The pro forma information is not necessarily indicative of the results of operations that would have occurred if the acquisitions had been completed on April 1, 2011, nor is it necessarily indicative of the future results of the combined operations.

Note 4 — Earnings per Unit

Our earnings per common and subordinated unit for the periods indicated below were computed as follows:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
	(in thousands, except unit and per unit amounts)
Earnings (loss) per common or subordinated limited partner unit:
Net income (loss) attributable to parent equity	$	40,176		$	6,090		$	25,599		$	(6,079	)
Loss (income) allocated to general partner (*)	(942		)	(6		)	(1,731		)	6
Net income (loss) allocated to limited partners	$	39,234		$	6,084		$	23,868		$	(6,073	)

Net income (loss) allocated to:
Common unitholders	$	34,799		$	4,412		$	20,843		$	(5,111	)
Subordinated unitholders	$	4,435		$	1,672		$	3,025		$	(962	)

Weighted average common units outstanding - Basic and Diluted	46,364,381			18,699,590			39,288,012			12,491,836

Weighted average subordinated units outstanding - Basic and Diluted	5,919,346			5,919,346			5,919,346			4,929,201

Earnings (loss) per common unit - Basic and Diluted	$	0.75		$	0.24		$	0.53		$	(0.41	)

Earnings (loss) per subordinated unit - Basic and Diluted	$	0.75		$	0.28		$	0.51		$	(0.20	)

(*) The income allocated to the general partner for the three months and nine months ended December 31, 2012 includes distributions to which it is entitled as the holder of incentive distribution rights (described in Note 10).

The 1,651,400 restricted units described in Note 10 were antidilutive for all periods presented subsequent to the initial grant date.

Note 5 - Property, Plant and Equipment

Our property, plant and equipment consists of the following as of the dates indicated (in thousands):

	December 31,			March 31,
Description and Useful Life	2012			2012
				(Note 3)
Terminal assets (30 years)	$	62,252		$	62,024
Retail propane equipment (5-20 years)	157,261			119,972
Vehicles (5 years)	82,868			26,372
Water treatment equipment (20 years)	91,123			—
Crude oil tanks and related equipment (20 years)	34,542			—
Information technology equipment (3-5 years)	9,698			2,381
Buildings (30 years)	37,560			14,651
Land	24,014			12,834
Other (3-7 years)	17,800			5,324
Construction in progress	37,038			679
	554,156			244,237
Less: Accumulated depreciation	(34,072		)	(12,843		)
Net property, plant and equipment	$	520,084		$	231,394

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Depreciation expense was $9.2 million and $3.9 million for the three months ended December 31, 2012 and 2011, respectively, and $23.0 million and $6.5 million for the nine months ended December 31, 2012 and 2011, respectively.

Note 6 — Goodwill and Intangible Assets

The changes in the balance of goodwill during the nine months ended December 31, 2012 were as follows (in thousands):

Balance at March 31, 2012, as previously reported	$	148,785
Revision to allocation of Osterman, Pacer, and North American combinations	18,460
Balance at March 31, 2012, as retrospectively adjusted (Note 3)	167,245
Acquisitions	342,827
Balance at December 31, 2012	$	510,072

Goodwill by reportable segment is as follows in (in thousands):

	December 31,		March 31,
	2012		2012
			(Note 3)
Retail propane	$	103,860	$	90,287
Natural gas liquids logistics	95,238		76,958
Crude oil logistics	209,669		—
Water services	101,305		—
	$	510,072	$	167,245

Our intangible assets consist of the following as of the dates indicated (in thousands):

		December 31, 2012				March 31, 2012
		Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Useful Lives	Amount		Amortization		Amount		Amortization
						(Note 3)
Amortizable —
Lease and other agreements	1-8 years	$	13,310	$	5,048	$	2,810	$	1,545
Customer relationships	5-20 years	449,376		20,580		128,071		3,868
Non-compete agreements	2-7 years	6,145		2,064		5,033		919
Debt issuance costs	5-10 years	17,918		1,867		7,310		1,842
Trade names	10 years	2,700		248		2,700		—
Total amortizable		489,449		29,807		145,924		8,174

Non-Amortizable —
Trade names	Indefinite	27,564		—		11,740		—
Total		$	517,013	$	29,807	$	157,664	$	8,174

Expected amortization of our amortizable intangible assets is as follows (in thousands):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Year Ending March 31,
2013 (three months)	$	10,393
2014	38,971
2015	37,712
2016	36,587
2017	35,550
Thereafter	300,429
	$	459,642

Amortization expense was as follows:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2012		2011		2012		2011
	(in thousands)
Recorded in
Cost of sales	$	1,763	$	200	$	3,315	$	600
Depreciation and amortization	9,474		1,482		18,294		1,931
Interest expense	925		291		2,261		946
Loss on early extinguishment of debt	—		—		5,769		—
	$	12,162	$	1,973	$	29,639	$	3,477

Note 7 - Long-Term Debt

Our long-term debt consists of the following:

			March 31,
	December 31, 2012		2012 (Note 3)

	(in thousands)
Revolving credit facility —
Expansion capital loans	$	436,000	$	—
Working capital loans	127,000		—

Senior notes	250,000		—

Previous revolving credit facility —
Acquisition loans	—		186,000
Working capital loans	—		28,000

Other notes payable	23,205		4,711
	836,205		218,711
Less - current maturities	8,635		19,534
Long-term debt	$	827,570	$	199,177

On June 19, 2012, we entered into a credit agreement (the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility”). Also on June 19, 2012, we entered into a note purchase agreement (the “Note Purchase Agreement”) whereby we issued $250 million of Senior Notes in a private placement (the “Senior Notes”). We used the proceeds from the issuance of the Senior Notes and borrowings under the Credit Agreement to repay existing debt and to fund the acquisition of High Sierra.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Credit Agreement

The Working Capital Facility had a total capacity of $217.5 million for cash borrowings and letters of credit at December 31, 2012. At December 31, 2012, we had outstanding cash borrowings of $127.0 million and outstanding letters of credit of $66.3 million on the Working Capital Facility, leaving a remaining capacity of $24.2 million at December 31, 2012. The Expansion Capital Facility had a total capacity of $477.5 million for cash borrowings at December 31, 2012. At December 31, 2012, we had outstanding cash borrowings of $436.0 million on the Expansion Capital Facility, leaving a remaining capacity of $41.5 million at December 31, 2012. The commitments under the Credit Agreement expire on June 19, 2017. We generally have the right to pre-pay outstanding borrowings under the Credit Agreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

During January 2013 we entered into an amendment to the Credit Agreement that increased the total capacity on the Working Capital Facility from $217.5 million to $242.5 million and the total capacity on the Expansion Capital Facility from $477.5 million to $527.5 million. This amendment also removed a provision from the Credit Agreement that required us to reduce the balance of the Working Capital Facility to $50.0 million or less for 30 consecutive days once per year.

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 1.75% to 2.75% per annum or (ii) an adjusted LIBOR rate plus a margin of 2.75% to 3.75% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At December 31, 2012, the interest rate in effect on outstanding LIBOR borrowings was 3.22%, calculated as the LIBOR rate of 0.22% plus a margin of 3.0%. At December 31, 2012, the interest rate in effect on outstanding base rate borrowings was 5.25%, calculated as the base rate of 3.25% plus a margin of 2.0%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. The Credit Agreement is secured by substantially all of our assets.

At December 31, 2012, our outstanding borrowings and interest rates under our revolving credit facility were as follows (dollars in thousands):

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	392,000	3.22	%
Base rate borrowings (*)	44,000		5.25	%
Working capital facility —
LIBOR borrowings	127,000		3.22	%
Base rate borrowings	—		—

(*) We are generally required to pay the base rate on new borrowings for a few days, until the administrative agent is able to process our election to covert the base rate borrowing to the LIBOR rate. The base rate borrowings shown in this table were converted to LIBOR rate borrowings in early January.

The Credit Agreement specifies that our “leverage ratio,” as defined in the Credit Agreement, cannot exceed 4.25 to 1.0 at any quarter end. At December 31, 2012, our leverage ratio was approximately 3.0 to 1. The Credit Agreement also specifies that our “interest coverage ratio,” as defined in the Credit Agreement, cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At December 31, 2012, our interest coverage ratio was greater than 8.0 to 1.

The Credit Agreement contains various customary representations, warranties and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement or (iii) certain events of bankruptcy or insolvency.

At December 31, 2012, we were in compliance with all covenants under the Credit Agreement.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Senior Notes

The Senior Notes have an aggregate principal amount of $250 million and bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25 million beginning on December 19, 2017 and ending on June 19, 2022. We have the option to pre-pay outstanding principal, although we would be required to pay a pre-payment penalty. The Senior Notes are secured by substantially all of our assets, and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are described above.

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10 million, (iv) the rendering of a judgment for the payment of money in excess of $10 million, (v) the failure of the Note Purchase Agreement, the Senior Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

At December 31, 2012, we were in compliance with all covenants under the Note Purchase Agreement.

Previous Credit Facilities

On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations for the nine months ended December 31, 2012.

Other Notes Payable

The other notes payable of approximately $23.2 million mature as follows (in thousands):

Year Ending March 31,
2013 (three months)	$	2,372
2014	8,551
2015	6,164
2016	2,782
2017	2,133
2018	1,075
Thereafter	128
	$	23,205

Note 8 - Income Taxes

We believe that we qualify as a partnership for income tax purposes. As a result, we generally do not pay U.S. Federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner’s basis in the Partnership.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

We have two taxable corporate subsidiaries in the United States and two taxable corporate subsidiaries in Canada. The income tax provision reported in our consolidated statements of operations relates primarily to these subsidiaries.

A publicly-traded partnership is required to generate at least 90% of its revenues (net of cost of sales) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of the income of our non-taxable subsidiaries has been qualifying income for both of the calendar years since our initial public offering.

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. We had no uncertain tax positions that required recognition in the consolidated financial statements at December 31, 2012 or March 31, 2012. Any interest or penalties would be recognized as a component of income tax expense.

Note 9 - Commitments and Contingencies

Legal Contingencies

We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our consolidated liabilities may change materially as circumstances develop.

In September 2010, Pemex Exploracion y Produccion (“Pemex”) filed a lawsuit in the United States District Court for the Southern District of Texas against a number of defendants, including High Sierra. Pemex alleges that High Sierra and the other defendants purchased condensate from a source that had acquired the condensate illegally from Pemex. We do not believe that High Sierra had knowledge at the time of the purchases of the condensate that such condensate was allegedly sold illegally to High Sierra and others. The proceedings are in the discovery stage, and as a result, we cannot reliably predict the outcome of this litigation. We continue to defend this matter and believe that, in the event of an adverse outcome, our total exposure would not be material to the Partnership. However, future adverse rulings by the court could result in material increases to our maximum potential exposure. We have recorded an accrued liability in the High Sierra business combination accounting, based on our best estimate of the low end of the range of probable loss.

In May 2010, two lawsuits were filed in Kansas and Oklahoma by numerous oil and gas producers (the “Associated Producers”), asserting that they were entitled to enforce lien rights on crude oil purchased by High Sierra and other defendants. These cases were subsequently transferred to the United States Bankruptcy Court for the District of Delaware, where they are pending. These claims relate to the bankruptcy of SemCrude, L.P. The Associated Producers are claiming damages against all defendants, including High Sierra, in excess of $72 million and assert that our allocated share of that claim is in excess of $2.1 million. The parties are in the discovery phase of the cases and no trial date has been set. The Court has ordered the parties to mediation, which began in February 2013. We intend to continue to defend this matter.

One of our facilities acquired in the High Sierra merger is operating with all but one of the required permits. We are currently working with the State of Wyoming to obtain the permit. We believe that the permit will ultimately be granted, but we are unable to determine the timing of any action by the State of Wyoming.

Canadian Fuel and Sales Taxes

During January 2013, the taxing authority of a province of in Canada completed an audit of fuel and sales tax payments, and concluded that High Sierra should have collected from customers and remitted to the taxing authority approximately $13.4 million of fuel taxes and sales taxes on certain historical sales. High Sierra had not collected and remitted fuel and sales taxes on these transactions, as High Sierra believed the transactions were exempt from these taxes. We are in the process of gathering information to support High Sierra’s position that the transactions were exempt from the taxes, which we believe could substantially reduce or eliminate the amount of the tax assessed. If we are unsuccessful in demonstrating that these transactions were exempt, we would be required to remit payment to the taxing authority, and we would attempt to recover these payments from the customers. Although the outcome of this matter is not certain at this time, we do not believe the ultimate resolution of this matter will have a material adverse effect on our consolidated financial position or results of operations.

Environmental Matters

Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that significant costs will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use,

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

We recorded an asset retirement obligation liability of $1.1 million upon completion of our business combination with High Sierra. This asset retirement obligation liability is related to the wastewater disposal assets and crude oil lease automatic custody units, for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. As described in Note 3, the valuation of the liabilities acquired in this merger is subject to change, once we complete the process of identifying and valuing the assumed liabilities.

In addition to the obligations described above, we may be obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain other assets. However, we do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our financial position or results of operations.

Operating Leases

We have executed various noncancelable operating lease agreements for office space, product storage, trucks, rail cars, real estate, equipment and bulk propane storage tanks. Rental expense relating to operating leases was as follows (in thousands):

	2012		2011
Three months ended December 31,	$	15,938	$	1,559
Nine months ended December 31,	38,097		3,513

Future minimum lease payments at December 31, 2012 are as follows for the next five years, including expected renewals (in thousands):

Year Ending March 31,
2013 (three months)	$	14,376
2014	51,697
2015	44,908
2016	43,648
2017	42,684

Sales and Purchase Contracts

We have entered into sales and purchase contracts for natural gas liquids and crude oil to be delivered in future periods. These contracts require that the parties physically settle the transactions with inventory. At December 31, 2012, we had the following such commitments outstanding:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

	Volume	Value
	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)	47,998	$	40,017
Natural gas liquids floating-price purchase commitments (gallons)	285,401	296,059
Natural gas liquids fixed-price sale commitments (gallons)	118,820	119,815
Natural gas liquids floating-price sale commitments (gallons)	182,312	270,238

Crude oil fixed-price purchase commitments (barrels)	4,711	414,632
Crude oil fixed-price sale commitments (barrels)	5,524	497,023

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs.

Certain of the forward purchase and sale contracts shown in the table above were acquired in the June 2012 merger with High Sierra. We recorded these contracts at their estimated fair values at the merger date, and we are amortizing these assets and liabilities to cost of sales over the remaining terms of the contracts. At December 31, 2012, the unamortized balances included in our consolidated balance sheet were as follows (in thousands):

Current assets	$	11,640
Noncurrent assets	202
Current liabilities	(4,902		)
Net asset	$	6,940

The following table summarizes the amortization expense (income) we have recorded, and the amortization expense (income) we expect to record, to cost of sales related to these contracts during each of the three-month periods shown below (in thousands):

	Natural Gas Liquids		Crude Oil
For the Three Months Ended:	Logistics Segment		Logistics Segment			Total

September 30, 2012	$	2,742	$	(464	)	$	2,278
December 31, 2012	7,221		(403		)	6,818
March 31, 2013 (estimated)	4,624		(222		)	4,402
June 30, 2013 (estimated)	1,412		(163		)	1,249
September 30, 2013 (estimated)	1,008		—			1,008
December 31, 2013 (estimated)	80		—			80
March 31, 2014 (estimated)	201		—			201
Total expense (income)	$	17,288	$	(1,252	)	$	16,036

As described in Note 3, we are still in the process of identifying the fair values of the assets and liabilities acquired in the combination with High Sierra. The estimates of fair value reflected as of December 31, 2012 are subject to change and such changes could be material.

Note 10 — Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest. Limited partner equity consists of common and subordinated units. The limited partner units share equally in the allocation of income or loss. The

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

primary difference between common and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

The subordination period will end on the first business day after we have earned and paid the minimum quarterly distribution on each outstanding common unit and subordinated unit, and the corresponding distribution on the general partner interest, for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2014. Also, if we have earned and paid at least 150% of the minimum quarterly distribution on each outstanding common unit and subordinated unit, the corresponding distribution on the general partner interest and the related distribution on the incentive distribution rights for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

Our general partner is not obligated to make any additional capital contributions or guarantee any of our debts or obligations.

Common Units Issued in Business Combinations

As described in Note 3, we issued common units as partial consideration for acquisitions during the nine months ended December 31, 2012. The following table summarizes the changes in common units outstanding during the nine months ended December 31, 2012, exclusive of unvested units granted pursuant to the Long-Term Incentive Plan (described elsewhere in Note 10):

Common units outstanding at March 31, 2012		23,296,253
Common units issued in High Sierra combination		20,703,510
Common units issued in retail propane combinations		850,676
Common units issued in water services combination		516,978
Common units issued in Pecos combination		1,834,414
Common units outstanding at December 31, 2012		47,201,831

As described in Note 3, we issued 344,680 common units on January 11, 2013 pursuant to a Call Agreement we entered into with the sellers of Third Coast.

In connection with the completion of certain of these transactions, we amended our Registration Rights Agreement. This Registration Rights Agreement, as amended, provides for certain registration rights for the holders of our common units that are party to the agreement.

Distributions

Our general partner has adopted a cash distribution policy that will require us to pay a quarterly distribution to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as “available cash,” in the following manner:

· First, 99.9% to the holders of common units and 0.1% to the general partner, until each common unit has received the specified minimum quarterly distribution, plus any arrearages from prior quarters.

· Second, 99.9% to the holders of subordinated units and 0.1% to the general partner, until each subordinated unit has received the specified minimum quarterly distribution.

· Third, 99.9% to all unitholders, pro rata, and 0.1% to the general partner.

The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions.”

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, assume our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its incentive distribution rights and there are no arrearages on common units.

							Marginal Percentage Interest In
	Total Quarterly						Distributions
	Distribution Per Unit						Unitholders		General Partner
Minimum quarterly distribution					$	0.337500	99.9	%	0.1	%
First target distribution	above	$	0.337500	up to	$	0.388125	99.9	%	0.1	%
Second target distribution	above	$	0.388125	up to	$	0.421875	86.9	%	13.1	%
Third target distribution	above	$	0.421875	up to	$	0.506250	76.9	%	23.1	%
Thereafter	above	$	0.506250				51.9	%	48.1	%

The following table summarizes the distributions declared since our initial public offering:

Date	Record	Date	Amount		Amount Paid to		Amount Paid to
Declared	Date	Paid	Per Unit		Limited Partners		General Partner
					(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011	0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012	0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012	0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012	0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012	0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013	0.4625		24,245		927

Several of our business combination agreements contain provisions that temporarily limit the distributions to which the newly-issued units were entitled. The following table summarizes the number of equivalent units that were not eligible to receive a distribution on each of the record dates:

		Equivalent
		Units Not
Record Date		Eligible
August 3, 2011		—
October 31, 2011		4,000,000
February 3, 2012		7,117,031
April 30, 2012		3,932,031
August 3, 2012		17,862,470
October 29, 2012		516,978
February 4, 2013		1,202,085

Equity-Based Incentive Compensation

Our general partner has adopted the NGL Energy Partners LP 2011 Long-Term Incentive Plan (the “Long-Term Incentive Plan”) for the employees and directors of our general partner and its affiliates who perform services for us. The Long-Term Incentive Plan allows for the

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

issuance of restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards, as discussed below. The number of common units that may be delivered pursuant to awards under the plan is limited to 10% of the issued and outstanding common and subordinated units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common and subordinated units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations will not be considered to be delivered under the Long-Term Incentive Plan. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award will again be available for new awards under the Long-Term Incentive Plan. Common units to be delivered pursuant to awards under the Long-Term Incentive Plan may be newly issued common units, common units acquired by us in the open market, common units acquired by us from any other person, or any combination of the foregoing. If we issue new common units with respect to an award under the Long-Term Incentive Plan, the total number of common units outstanding will increase.

During the nine months ended December 31, 2012, the Board of Directors of our general partner granted 1,651,400 restricted units to employees and directors. The restricted units will vest in tranches subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the Board of Directors. No distributions will accrue to or be paid on the restricted units during the vesting period. The expected vesting of the awards is summarized below:

Vesting Date		Number of Awards
January 1, 2013		218,500
July 1, 2013		381,300
July 1, 2014		357,800
July 1, 2015		269,300
July 1, 2016		259,500
July 1, 2017		165,000

For the awards that vested on January 1, 2013, we issued 156,802 common units to the recipients. We withheld 61,698 common units, in return for which we paid withholding taxes on behalf of the recipients.

The weighted-average fair value of the awards was $19.62 at December 31, 2012, which was calculated as the closing price of the common units on December 31, 2012, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. We record the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through the reporting date using the estimated fair value of the awards at the reporting date. We recorded $2.4 million of general and administrative expense related to these awards during the three months ended December 31, 2012 and $5.3 million of general and administrative expense related to these awards during the nine months ended December 31, 2012. We account for these as liability awards. The balance in other current liabilities on our consolidated balance sheet at December 31, 2012 includes $5.3 million related to these awards.

We estimate that the expense we will record on the awards granted as of December 31, 2012 will be as follows (in thousands), after taking into consideration an estimate of forfeitures. For purposes of this calculation, we have used the closing price of the common units on December 31, 2012.

Year ending March 31,
2013 (three months)	$	4,110
2014	9,742
2015	5,881
2016	4,965
2017	3,375
2018	722
Total	$	28,795

As of December 31, 2012, 3,659,556 units remain available for issuance under the Long-Term Incentive Plan.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Note 11 — Fair Value of Financial Instruments

Our cash and cash equivalents, accounts receivable, accounts payable and accrued expenses and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature. The carrying amounts of our debt obligations reasonably approximate their fair values at December 31, 2012, as most of our debt is subject to terms that were recently negotiated.

Interest Rate Swap Agreement

We have entered into an interest rate swap agreement to hedge the risk of interest rate fluctuations on our long term debt. This agreement effectively converts a portion of our floating rate debt into fixed rate debt on a notional amount of $8.5 million and ends on December 31, 2013. The notional amounts of derivative instruments do not represent actual amounts exchanged between the parties, but instead represent amounts on which the contracts are based. The floating interest rate payments under these swaps are based on three-month LIBOR rates. We do not account for this agreement as a hedge. We recorded a liability of $0.1 million at December 31, 2012 and a liability of $0.2 million at March 31, 2012 related to this agreement.

Commodity Derivatives

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at December 31, 2012:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	4,332		$	(2,615	)
Level 2 measurements	21,472			(12,700		)
	25,804			(15,315		)
Netting of counterparty contracts	(8,938		)	8,938
Cash collateral provided or held	(4,038		)	—
Commodity contracts reported on consolidated balance sheet	$	12,828		$	(6,377	)

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2012:

	Derivative		Derivative
	Assets		Liabilities
	(in thousands)
Level 1 measurements	$	—	$	—
Level 2 measurements	—		(36		)
	—		(36		)

Netting of counterparty contracts	—		—
Cash collateral provided or held	—		—
Commodity contracts reported on consolidated balance sheet	$	—	$	(36	)

The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

	December 31,			March 31,
	2012			2012
	(in thousands)
Other current assets	$	12,367		$	—
Other noncurrent assets	461			—
Other current liabilities	(6,268		)	(36		)
Other noncurrent liabilities	(109		)	—
Net asset (liability)	$	6,451		$	(36	)

The following table sets forth our open commodity derivative contract positions at December 31, 2012 and March 31, 2012. We do not account for these derivatives as hedges.

Contracts	Period	Total Notional Units (Barrels)		Fair Value
		(in thousands)
As of December 31, 2012 -
Propane swaps (1)	January 2013 - March 2014	(403	)	$	5,680
Heating oil calls and futures (2)	January 2013 - June 2013	103		852
Crude swaps (3)	January 2013 - December 2013	(92	)	(1,087		)
Crude - butane spreads (4)	January 2013 - March 2014	(25	)	(3,647		)
Crude forwards (5)	January 2013 - December 2013	224		214
Butane forwards (6)	January 2013 - March 2014	53		8,477
				10,489
Less: Margin deposits				(4,038		)
Net fair value of commodity derivatives on consolidated balance sheet				$	6,451

As of March 31, 2012 -
Propane swaps	April 2012 - March 2013	(460	)	$	(36	)

(1) Propane swaps — Our natural gas liquids business routinely purchases inventory during the warmer months and stores the inventory for sale in the colder months. The contracts listed in this table as “propane swaps” represent financial derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

(2) Heating oil calls and futures — Our retail operations routinely offer our customers the opportunity to purchase a specified volume of heating oil at a fixed price. The contracts listed in this table as “heating oil calls and futures” represent financial derivatives we have entered into as an economic hedge against the risk that heating oil prices will rise between the time we entered into the fixed price sale commitment with the customers and the time we will the purchase heating oil to sell to the customers.

(3) Crude swaps — Our crude oil logistics operations routinely enter into crude oil purchase and sale contracts that are priced based on a crude oil index. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as “crude swaps” represent hedges against the risk that changes in the different index prices would reduce the margins between the purchase and the sale transactions.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

(4) Crude-butane spreads — Our natural gas liquids logistics business has entered into certain forward contracts to sell butane at a price that will be calculated as a specified percentage of a crude oil index at the delivery date. The contracts listed in this table as “crude — butane spreads” represent financial derivatives we have entered into as economic hedges against the risk that the spread between butane prices and crude prices will narrow between the time we entered into the butane forward sale contracts and the expected delivery dates.

(5) Crude forwards — Our crude oil logistics business routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “crude forwards” represent financial derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding inventory.

(6) Butane forwards — Our natural gas liquids logistics business routinely purchases butane inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “butane forwards” represent financial derivatives we have entered into as an economic hedge against the risk that butane prices will decline while we are holding inventory.

We recorded the following net gains (losses) from our commodity and interest rate derivatives during the periods indicated:

	Three Months Ended					Nine Months Ended
	December 31,					December 31,
	2012			2011		2012			2011
	(in thousands)
Commodity contracts -
Unrealized gain (loss)	$	(159	)	$	938	$	11,246		$	76
Realized gain (loss)	7,164			711		778			2,103
Interest rate swaps	—			6		(5		)	(281		)
Total	$	7,005		$	1,655	$	12,019		$	1,898

The commodity contract gains and losses are included in cost of sales in the consolidated statements of operations. The gain or loss on the interest rate contracts is recorded in interest expense.

Credit Risk

We maintain credit policies with regard to our counterparties on the derivative financial instruments that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty.

Our counterparties consist primarily of financial institutions and energy companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

As described in Note 3, we completed a business combination in November 2012 whereby we acquired Pecos, which conducts crude oil logistics operations in Texas and New Mexico. The acquired operations sell a substantial amount of crude oil each month to one customer. The credit terms with this customer call for us to collect payment on a monthly basis. We entered into an agreement with the sellers of Pecos to provide some protection against the risk that we may be unable to collect our receivables from this significant customer. The sellers of Pecos agreed to place certain of our common units that they own into escrow; if the customer defaults on its obligation to us within the six months following the date of the business combination, the sellers of Pecos will return the common units to us as partial compensation for the loss we would sustain on the uncollectable accounts receivable. This agreement may terminate early if we obtain a new credit enhancement facility to replace this agreement. In addition, the number of common units we would be entitled to recover under this agreement could be reduced if there is a decline in our sales to the customer.

A customer we acquired in our acquisition of Pecos did not pay the full amount of our November billing for transportation services and is questioning whether our transportation rate schedule is correct. We have billed this customer consistent with Pecos’ past practice. We continue to discuss this matter with the customer, and at this time we are not able to reliably predict the outcome of these discussions, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated statements of financial position and recognized in our net income.

Note 12 - Segments

Our reportable segments are based on the way in which our management structure is organized. Certain financial data related to our segments is shown below.

Our retail propane segment sells propane and petroleum distillates to end users consisting of residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which are organized based on the location of the operations.

Our natural gas liquids logistics segment supplies propane and other natural gas liquids, and provides natural gas liquids transportation, terminalling, and storage services to retailers, wholesalers, and refiners. This segment includes our historical natural gas liquids operations and the natural gas liquids operations acquired in the June 2012 merger with High Sierra. We previously reported our natural gas liquids operations in two segments, referred to as our “wholesale marketing and supply” and “midstream” segments. The data in the table below has been presented under our new structure for all periods, with the amounts previously reported in the wholesale marketing and supply and midstream segments reported on a combined basis within the natural gas liquids logistics segment.

Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. These operations began with our June 2012 merger with High Sierra.

Our water services segment provides services for the transportation, treatment, and disposal of wastewater generated from oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. These operations began with our June 2012 merger with High Sierra.

Items labeled “corporate and other” in the table below include the operations of a compressor leasing business that we acquired in our June 2012 merger with High Sierra, and also include certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our consolidated financial statements.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
	(in thousands)
Revenues:
Retail propane -
Propane sales	$	84,258		$	56,946		$	162,049		$	83,212
Distillate sales	33,062			—			55,685			—
Other retail sales	10,585			5,755			26,382			11,575
Natural gas liquids logistics -
Propane sales	255,157			340,006			477,981			651,247
Other natural gas liquids sales	286,598			89,063			626,360			165,769
Storage and transportation revenues	8,822			996			17,143			1,756
Crude oil logistics	684,228			—			1,472,439			—
Water services	22,806			—			40,557			—
Other	1,381			—			2,842			—
Elimination of intersegment sales	(48,689		)	(22,117		)	(81,284		)	(42,015		)
Total revenues	$	1,338,208		$	470,649		$	2,800,154		$	871,544

Depreciation and amortization:
Retail propane	$	6,987		$	4,237		$	18,915		$	6,692
Natural gas liquids logistics	2,265			1,165			7,715			1,788
Crude oil logistics	1,904			—			3,844			—
Water services	7,235			—			10,285			—
Corporate and other	356			—			576			—
Total depreciation and amortization	$	18,747		$	5,402		$	41,335		$	8,480

Operating income (loss):
Retail propane	$	16,437		$	4,851		$	9,797		$	(1,441	)
Natural gas liquids logistics	25,090			4,710			36,492			3,318
Crude oil logistics	11,407			—			17,226			—
Water services	5,499			—			10,046			—
Corporate and other	(8,210		)	(920		)	(19,827		)	(3,446		)
Total operating income (loss)	$	50,223		$	8,641		$	53,734		$	(1,569	)

Other items not allocated by segment:
Interest income	241			197			870			422
Interest expense	(9,762		)	(2,676		)	(22,254		)	(4,989		)
Loss on early extinguishment of debt	—			—			(5,769		)	—
Other income, net	20			86			49			215
Income tax expense	(245		)	(158		)	(781		)	(158		)
Net income (loss)	$	40,477		$	6,090		$	25,849		$	(6,079	)

Additions to property, plant and equipment, including acquisitions (accrual basis):
Retail propane	$	9,816		$	100,095		$	67,063		$	103,151
Natural gas liquids logistics	8,452			65,355			13,896			65,583
Crude oil logistics	53,913			—			82,227			—
Water services	34,227			—			130,584			—
Corporate and other	3,799			—			17,156			—
Total	$	110,207		$	165,450		$	310,926		$	168,734

			March 31,
	December 31,		2012
	2012		(Note 3)
	(in thousands)
Total assets:
Retail propane	$	523,108	$	417,639
Natural gas liquids logistics	567,243		325,173
Crude oil logistics	684,979		—
Water services	621,997		—
Corporate and other	40,142		6,707
Total	$	2,437,469	$	749,519

Long-lived assets, net:
Retail propane	$	450,223	$	366,242
Natural gas liquids logistics	239,694		176,419
Crude oil logistics	349,085		—
Water services	445,781		—
Corporate and other	32,579		5,468
Total	$	1,517,362	$	548,129

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of December 31, 2012 and March 31, 2012, and for the

Three Months and Nine Months Ended December 31, 2012 and 2011

Note 13 — Transactions with Affiliates

Since our business combination with SemStream on November 1, 2011, SemGroup Corporation (“SemGroup”) has held ownership interests in us and in our general partner, and has had the right to appoint two members to the Board of Directors of our general partner. Subsequent to November 1, 2011, our natural gas liquids logistics segment has sold natural gas liquids to and purchased natural gas liquids from affiliates of SemGroup. These transactions are included within revenues and cost of sales of our natural gas liquids logistics business in our consolidated statements of operations.

Certain members of management of High Sierra who joined our management team upon completion of the June 19, 2012 merger with High Sierra own interests in several entities. Subsequent to this business combination with High Sierra, we have purchased products and services from and have sold products and services to these entities. The majority of these transactions are reported within cost of sales in our consolidated statements of operations, although approximately $1.3 million of these transactions during the three and nine months ended December 31, 2012 were accounted for as increases to property, plant and equipment.

These transactions are summarized in the table below (in thousands):

	Three Months Ended		Nine Months Ended
	December 31,		December 31,
	2012		2012

Sales to SemGroup	$	8,091	$	32,371
Purchases from SemGroup	16,744		43,821
Sales to entities affiliated with High Sierra management	—		1,316
Purchases from entities affiliated with High Sierra management	2,507		10,434

In addition to the amounts shown in the table above, we completed two business combinations during the nine months ended December 31, 2012 with entities in which members of our management owned interests. We paid $14.0 million of cash (net of cash acquired) on a combined basis for these two acquisitions.

Receivables from affiliates consist of the following (in thousands):

	December 31,		March 31,
	2012		2012
Receivables from SemGroup	$	835	$	1,878
Receivables from entities affiliated with High Sierra management	383		—
Other	116		404
	$	1,334	$	2,282

Payables to affiliates consist of the following (in thousands):

	December 31,		March 31,
	2012		2012
			(Note 3)
Payables to SemGroup	$	6,059	$	4,699
Payables to entities affiliated with High Sierra management	468		—
Working capital settlement on Osterman acquisition	—		4,763
	$	6,527	$	9,462

As described in Note 1, we completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012, which involved certain transactions with our general partner. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner.

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

The following is a discussion of our financial condition and results of operations as of and for the three months and nine months ended December 31, 2012. The discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the historical consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2012.

Overview

· On June 19, 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively, “High Sierra”), whereby we acquired all of the ownership interests in High Sierra. High Sierra’s businesses include crude oil gathering, transportation and marketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner.

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· On November 1, 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and New Mexico. We paid cash of $134.6 million at closing, subject to customary post-closing adjustments, and assumed certain obligations with a value of $10.4 million under certain equipment financing facilities. Also on November 1, 2012, we entered into a call agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners of Pecos purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement.

· On December 31, 2012, we completed a business combination transaction whereby we acquired all of the limited liability company membership interests in Third Coast Towing, LLC (“Third Coast”) for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. The agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. Also on December 31, 2012, we entered into an agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed to purchase a minimum of $8.0 million or a maximum of $10.0 million of common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to this agreement.

As of December 31, 2012, our businesses include:

· Our retail propane business, which sells propane and distillates to end users consisting of residential, agricultural, commercial, and industrial customers in more than 20 states and to certain re-sellers;

· Our natural gas liquids logistics business, which supplies propane and other natural gas liquids to retailers, wholesalers, and refiners throughout the United States and in Canada, and which provides natural gas liquids terminalling services through its 17 terminals throughout the United States and rail car transportation services through its fleet of owned and predominantly leased rail cars;

· A crude oil logistics business, the assets of which include crude oil terminals, a fleet of trucks, a fleet of leased rail cars, and several barges; and

· A water services business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks.

Our retail propane segment sells propane, petroleum distillates, and equipment and supplies to residential, agricultural, commercial, and industrial end-users. Our retail propane segment purchases a large portion of its propane from our natural gas liquids logistics segment. Our retail propane segment generates margins based on the difference between the wholesale cost of product and the selling price of the product in the retail markets. These margins fluctuate over time due to supply and demand conditions. Weather conditions have a significant impact on our sales volumes and prices, as a significant portion of our sales are to residential customers who purchase propane and distillates for home heating purposes.

Our natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets. Our natural gas liquids logistics segment owns 17 terminals and operates a fleet of leased rail cars and leases storage capacity. The margins we realize in our wholesale business are substantially lower on a per gallon basis than the margins we realize in our retail business. We attempt to reduce our exposure to the impact of price fluctuations by using “back-to-back” contractual agreements and “pre-sale” agreements that essentially allow us to lock in a margin on a percentage of our winter volumes. We also attempt to reduce our exposure to the impact of price fluctuations by entering into swap agreements whereby we agree to pay a floating rate and receive a fixed rate on a specified notional amount of product. We enter into these agreements as economic hedges against the potential decline in the value of a portion of our inventory. Our natural gas liquids logistics segment includes the operations that were previously reported in our wholesale marketing and supply and terminals segments. Our natural gas liquids logistics segment also includes the natural gas liquids operations we acquired in our June 2012 merger with High Sierra.

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Our crude oil transportation and marketing business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. We attempt to reduce our exposure to price fluctuations by using “back-to-back” contractual agreements whenever possible. In addition, we enter into forward contracts, financial swaps, and commodity spread trades as economic hedges of our physical forward sales and purchase contracts with our customers and suppliers. The operations of our crude oil logistics segment began with our June 2012 merger with High Sierra.

Our water services business generates revenues from the transportation, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the re-sale of recycled water and recovered hydrocarbons. The operations of our water services segment began with our June 2012 merger with High Sierra.

Seasonality and Weather

Seasonality and weather have a significant impact on the demand for propane and butane. The most significant impact of seasonality and weather is on our retail segment. A large portion of our retail operation is in the residential market where propane and distillates are used primarily for heating purposes. Approximately 70% of our retail volume is sold during the peak heating season from October through March. Seasonal volume variations also impact our wholesale natural gas liquids operations. Consequently, we expect our sales, operating profits and operating cash flows to be greater in the third and fourth quarters of each fiscal year. We have historically realized operating losses and negative operating cash flows during our first and second fiscal quarters. See “—Liquidity, Sources of Capital and Capital Resource Activities — Cash Flows.”

Commodity Price Fluctuations

Fluctuations in the price of commodities can have a direct impact on our reported revenues and sales volumes and may affect our gross margins depending on our success in passing cost increases on to our customers. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

The range of low and high spot propane prices per gallon at two key pricing hubs for the periods indicated and the prices as of period end were as follows:

	Conway, Kansas						Mt. Belvieu, Texas
	Spot Price						Spot Price
	Per Gallon						Per Gallon
	Low		High		At Period End		Low		High		At Period End
For the Three Months Ended December 31:
2012	$	0.6613	$	0.8769	$	0.8306	$	0.7263	$	1.0050	$	0.8994
2011	1.1394		1.4187		1.1394		1.3262		1.5412		1.3975
For the Nine Months Ended December 31,
2012	$	0.5038	$	0.9625	$	0.8306	$	0.7063	$	1.2175	$	0.8994
2011	1.1394		1.4900		1.1394		1.3262		1.6275		1.3975

Historically, we have been successful in passing on propane price increases to our customers. We monitor propane prices daily and adjust our retail prices to maintain expected margins by passing on the wholesale costs to our customers.

The range of high and low spot butane prices per gallon at the Mt. Belvieu, Texas pricing hub for the periods indicated and the prices as of period end are as follows:

	Mt. Belvieu, Texas
	Spot Price
	Per Gallon
	Low		High		At Period End

For the Three Months Ended December 31, 2012	$	1.4388	$	1.8800	$	1.7763
For the Nine Months Ended December 31, 2012	1.1438		1.9313		1.7763

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The range of high and low spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma for the periods indicated and the prices as of period end are as follows:

	Spot Price Per Barrel
	Low		High		At Period End

For the Three Months Ended December 31, 2012	$	84.44	$	92.39	$	91.82
For the Nine Months Ended December 31, 2012	77.69		108.84		91.82

Summary Discussion of Operating Results for the Three Months Ended December 31, 2012

Our retail propane segment generated operating income of $16.4 million during the three months ended December 31, 2012, which was higher than the operating income of $4.9 million during the three months ended December 31, 2011. Our retail propane segment generated $8.4 million of operating income during the three months ended December 31, 2012 from businesses acquired during the last twelve months, including Pacer, North American, and others. The operations that we owned during the corresponding quarter in the prior year experienced more favorable operating results during the three months ended December 31, 2012 than during the three months ended December 31, 2011, which was due primarily to improved margins on propane sales. Although the average selling price per gallon of propane was lower in the current year than in the prior year, the average cost per gallon decreased by a larger amount than the selling price, and volumes were similar over the two periods.

Our natural gas liquids logistics segment generated operating income of $25.1 million during the three months ended December 31, 2012. This was due to $17.5 million of operating income related to the operations acquired in the merger with High Sierra and to $2.9 million of operating income generated by our legacy operations.

Weather conditions were unusually warm during the winter season of late calendar 2011 through early calendar 2012, which significantly reduced the demand for propane. Because of this, and due to continued high levels of production of natural gas and limitations on export infrastructure, the market price for propane and other natural gas liquids was lower during the nine months ended December 31, 2012 than during the corresponding period in the prior year. Weather conditions continued to be warmer than usual during the beginning of the winter season in late calendar 2012.

The operations of our crude oil logistics segment began with our acquisition of High Sierra in June 2012. This segment generated operating income of $11.4 million during the three months ended December 31, 2012, which was reduced by losses of $4.0 million on derivatives.

The operations of our water services segment began with our acquisition of High Sierra in June 2012. This segment generated operating income of $5.5 million during the three months ended December 31, 2012.

Analysis of our operating results by segment for the three and nine months ended December 31, 2012 is provided below.

Consolidated Results of Operations

The following table summarizes our historical consolidated statements of operations for the three and nine months ended December 31, 2012 and 2011.

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	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
	(in thousands)
Revenues	$	1,338,208		$	470,649		$	2,800,154		$	871,544
Cost of sales	1,204,545			439,790			2,557,220			827,225
Operating and general and administrative expenses	64,693			16,816			147,865			37,408
Depreciation and amortization	18,747			5,402			41,335			8,480
Operating income (loss)	50,223			8,641			53,734			(1,569		)
Interest expense	(9,762		)	(2,676		)	(22,254		)	(4,989		)
Loss on early estinguishment of debt	—			—			(5,769		)	—
Interest and other income	261			283			919			637
Income (loss) before income taxes	40,722			6,248			26,630			(5,921		)
Income tax provision	(245		)	(158		)	(781		)	(158		)
Net income (loss)	40,477			6,090			25,849			(6,079		)
Net (income) loss allocated to general partner	(942		)	(6		)	(1,731		)	6
Net (income) loss attributable to noncontrolling interests	(301		)				(250		)
Net income (loss) attributable to parent equity allocated to limited partners	$	39,234		$	6,084		$	23,868		$	(6,073	)

See the detailed discussion of revenues, cost of sales, gross margin, operating expenses, general and administrative expenses, depreciation and amortization and operating income by segment below.

Set forth below is a discussion of significant changes in the non-segment related corporate other income and expenses during the respective periods.

Interest Expense

Our interest expense consists primarily of interest on borrowings under a revolving credit facility, letter of credit fees, and amortization of debt issuance costs. See Note 7 to our condensed consolidated financial statements included elsewhere in this report for additional information on our long-term debt. The increase in interest expense during the periods presented is due primarily to increases in the average outstanding total debt balance. The average interest rate, amortization of debt issuance costs, and letter of credit fees were as follows (dollars in thousands):

					Average Debt				Average Debt
	Letter of		Amortization		Balance		Average		Balance
	Credit		of Debt Issuance		Outstanding -		Interest Rate -		Outstanding -		Interest Rate -
	Fees		Costs		Revolving Facilities		Revolving Facilities		Senior Notes		Senior Notes
Three Months Ended December 31,
2012	$	538	$	925	$	491,847	3.11	%	$	250,000	6.65	%
2011	48		291		207,346		4.52	%	—		—
Nine Months Ended December 31,
2012	$	954	$	2,261	$	377,671	3.39	%	$	178,182	6.65	%
2011	291		946		89,999		5.12	%	—		—

On June 19, 2012, we retired our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations for the nine months ended December 31, 2012.

The increased levels of debt outstanding during the nine months ended December 31, 2012 are due primarily to borrowings to finance acquisitions and working capital.

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Interest and Other Income

Our non-operating income consists of the following:

	Three Months Ended				Nine Months Ended
	December 31,				December 31,
	2012		2011		2012		2011
	(in thousands)
Interest income	$	241	$	197	$	870	$	422
Other	20		86		49		215
	$	261	$	283	$	919	$	637

Income Tax Provision

We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay U.S. Federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner’s basis in the Partnership.

Noncontrolling Interests

As of December 31, 2012, we have three consolidated subsidiaries in which outside parties own interests. Our ownership interests in these subsidiaries range from 60% to 80%. One of these subsidiaries was formed in March 2012, and the other two were acquired in June 2012 and October 2012, respectively. The noncontrolling interest shown in our consolidated statements of operations for the three months and nine months ended December 31, 2012 represents the other owners’ interests in these entities.

Non-GAAP Financial Measures

The following tables reconcile net income (loss) attributable to parent equity to our EBITDA and Adjusted EBITDA, each of which are non-GAAP financial measures, for the periods indicated:

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	Three Months Ended						Nine Months Ended
	December 31,						December 31,
	2012			2011			2012			2011
	(in thousands)
EBITDA:
Net income (loss) attributable to parent equity	$	40,176		$	6,090		$	25,599		$	(6,079	)
Provision for income taxes	245			158			781			158
Interest expense	9,762			2,676			22,254			4,989
Loss on early extinguishment of debt	—			—			5,769			—
Depreciation and amortization	20,494			5,602			44,607			9,080
EBITDA	$	70,677		$	14,526		$	99,010		$	8,148
Unrealized (gain) loss on derivative contracts	159			(938		)	(11,246		)	(76		)
Loss (gain) on sale of assets	(11		)	(38		)	(34		)	(84		)
Share-based compensation expense	2,365			—			5,322			—
Adjusted EBITDA	$	73,190		$	13,550		$	93,052		$	7,988

We define EBITDA as net income (loss) attributable to parent equity, plus income taxes, interest expense and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding the unrealized gain or loss on derivative contracts, the gain or loss on the disposal of assets, and share-based compensation expenses. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other entities.

Segment Operating Results for the Three Months Ended December 31, 2012 and 2011

Items Impacting the Comparability of Our Financial Results

Our results of operations for the three months ended December 31, 2012 may not be comparable to our results of operations for the three months ended December 31, 2011, due to the business combinations described above. The results of operations of our natural gas liquids businesses are impacted by seasonality, primarily due to the increase in volumes sold by our retail and wholesale natural gas liquids businesses during the peak heating season of October through March. In addition, propane price fluctuations can have a significant impact on our sales volumes. For these and other reasons, our results of operations for the three months ended December 31, 2012 are not necessarily indicative of the results to be expected for the full fiscal year.

Volumes Sold or Processed

The following table summarizes the volume of product sold and wastewater processed for the three months ended December 31, 2012, and 2011, respectively. Gallons sold by our natural gas liquids logistics segment shown in the table below include sales to our retail segment.

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	Three Months Ended		Change Resulting From
	December 31,		Retail	SemStream		High Sierra
Segment	2012	2011	Combinations (1)	Combination		Combinations (2)	Other
			(in thousands)
Retail propane
Propane gallons sold	42,122	24,694	17,171	—		—	257
Distillate gallons sold	8,818	—	8,818	—		—	—

Natural gas liquids logistics
Propane gallons sold	275,598	237,490	—	(3	)	52,925	(14,817	)
Other natural gas liquids gallons sold	205,498	50,456	—	(3	)	154,061	981

Crude oil logistics
Crude oil barrels sold	7,461	—	—	—		7,461	—

Water services
Barrels of water processed	9,818	—	—	—		9,818	—

(1) This data includes the operations of Pacer (acquired in January 2012), North American (acquired in February 2012), and certain of the retail acquisitions during the current fiscal year.

(2) This data includes the operations of High Sierra (acquired in June 2012), Pecos (acquired in November 2012), and other smaller acquisitions of crude oil logistics and water services businesses.

(3) Although the SemStream combination enabled us to significantly expand our wholesale supply and marketing operations, it is not possible to determine which of the volumes sold subsequent to the combination were specifically attributable to the SemStream combination and which were attributable to our historical wholesale business.

Our retail propane segment’s sales volumes for the three months ended December 31, 2012 increased approximately 26.2 million gallons over the 24.7 million gallons sold during the three months ended December 31, 2011. The principal factor driving the increase was our business combinations. The acquired businesses generated approximately 26.0 million gallons of propane and distillate sales during the three months ended December 31, 2012.

Sales of our natural gas liquids logistics segment increased approximately 193.2 million gallons during the three months ended December 31, 2012 as compared to sales of 287.9 million gallons during the three months ended December 31, 2011. The primary reason for this increase in volumes was the acquisition of the operations of High Sierra in June 2012.

The operations of our crude oil logistics and water services segments began with our June 2012 merger with High Sierra.

Operating Income (Loss) by Segment

Our operating income (loss) by segment is as follows:

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	Three Months Ended
	December 31,
Segment	2012			2011			Change
				(in thousands)
Retail propane	$	16,437		$	4,851		$	11,586
Natural gas liquids logistics	25,090			4,710			20,380
Crude oil logistics	11,407			—			11,407
Water services	5,499			—			5,499
Corporate and other	(8,210		)	(920		)	(7,290		)
Operating income	$	50,223		$	8,641		$	41,582

The operating loss within “corporate and other” increased approximately $7.3 million during the three months ended December 31, 2012 as compared to $0.9 million during the three months ended December 31, 2011. This increase is due in part to $3.5 million of incremental expenses associated with the corporate activities of High Sierra. In addition, corporate general and administrative expenses for the three months ended December 31, 2012 include $2.4 million of compensation expense related to certain restricted units granted pursuant to employee and director compensation programs. Corporate general and administrative expenses for the three months ended December 31, 2012 also include $0.8 million of costs related to acquisitions. The operations of our compressor leasing business are also included within “corporate and other.”

Retail Propane

The following table compares the operating results of our retail propane segment for the periods indicated:

	Three Months Ended				Change Resulting From
	December 31,				Retail
	2012		2011		*Combinations()**		Other
			(in thousands)
Revenues:
Propane sales	$	84,258	$	56,956	$	35,630	$	(8,328	)
Distillate sales	33,062		—		33,062		—
Other sales	10,585		5,754		6,454		(1,623		)
Total revenues	127,905		62,710		75,146		(9,951		)
Expenses:
Cost of sales - propane	44,961		38,644		18,713		(12,396		)
Cost of sales - distillates	28,986		—		28,986		—
Cost of sales - other	3,502		1,867		1,889		(254		)
Operating expenses	24,125		10,599		12,500		1,026
General and administrative expenses	2,907		2,512		1,347		(952		)
Depreciation and amortization expense	6,987		4,237		3,328		(578		)
Total expenses	111,468		57,859		66,763		(13,154		)

Segment operating income	$	16,437	$	4,851	$	8,383	$	3,203

(*) This data includes the operations of Pacer (acquired in January 2012), North American (acquired in February 2012), and certain of the retail acquisitions during the current fiscal year.

Revenues. Propane sales for the three months ended December 31, 2012 increased approximately $27.3 million as compared to propane sales of $57.0 million during the three months ended December 31, 2011. The principal reason for the increase in propane sales is the acquisitions of Pacer, North American, and other retail operations. Excluding the impact of these acquisitions, propane sales were lower during the three months ended December 31, 2012 than during the three months ended December 31, 2011, due primarily to a decline in the average price per gallon sold of $0.36 during the three months ended December 31, 2012, as compared to an average price per gallon sold of $2.31 during the three months ended December 31, 2011. Also excluding the effect of these acquisitions, volumes sold during the three months ended December 31, 2012 were similar to volumes sold during the three months ended December 31, 2011.

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Our acquired operations generated propane sales of $35.6 million during the three months ended December 31, 2012, consisting of approximately 17.2 million gallons sold at an average price of $2.08 per gallon. The average selling price per gallon for the acquired operations was higher than the average selling price for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary sources of propane supply than are the markets served by our historical operations.

Our acquired operations generated $33.1 million of revenue from the sales of distillates during the three months ended December 31, 2012, consisting of 8.8 million gallons sold at an average selling price of $3.75 per gallon.

Cost of Sales. Propane cost of sales for the three months ended December 31, 2012 increased approximately $6.3 million as compared to propane cost of sales of $38.6 million during the three months ended December 31, 2011. This increase in propane cost of sales is due primarily to the acquisitions of Pacer, North American, and other retail acquisitions. Excluding the impact of these acquisitions, propane cost of sales was lower during the three months ended December 31, 2012 than during the three months ended December 31, 2011, due primarily to a decline in the average cost per gallon sold of $0.51 during the three months ended December 31, 2012, as compared to an average price per gallon sold of $1.56 during the three months ended December 31, 2011. Also excluding the effect of these acquisitions, volumes sold during the three months ended December 31, 2012 were similar to volumes sold during the three months ended December 31, 2011.

Our acquired Pacer, North American, and other retail operations generated propane cost of sales of $18.7 million during the three months ended December 31, 2012, consisting of approximately 17.2 million gallons sold at an average cost of $1.09 per gallon. The average cost per gallon for the acquired operations was higher than the average cost for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary sources of propane supply than are the markets served by our historical operations.

Our acquired operations generated $28.9 million of cost of sales for distillates during the three months ended December 31, 2012, consisting of 8.8 million gallons sold at an average cost of $3.29 per gallon. Cost of distillate sales during the three months ended December 31, 2012 was increased by approximately $1.0 million of realized and unrealized losses on derivatives.

Operating Expenses. Operating expenses of our retail propane segment increased approximately $13.5 million during the three months ended December 31, 2012 as compared to operating expenses of $10.6 million during the three months ended December 31, 2011. This increase is due primarily to the impact of our Pacer, North American, and other retail acquisitions, the operations of which generated $12.5 million of operating expenses during the three months ended December 31, 2012.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $0.4 million during the three months ended December 31, 2012 as compared to general and administrative expenses of $2.5 million during the three months ended December 31, 2011. The principal factor causing the increase is the impact of our Pacer, North American, and other retail acquisitions, the operations of which generated $1.3 million of general and administrative expense during the three months ended December 31, 2012.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased approximately $2.8 million during the three months ended December 31, 2012 as compared to depreciation and amortization expense of $4.2 million during the three months ended December 31, 2011. The increase is due primarily to the impact of our Pacer, North American, and other retail acquisitions, the operations of which generated $3.3 million of depreciation and amortization expense during the three months ended December 31, 2012.

Operating Income. Our retail propane segment had operating income of approximately $16.4 million during the three months ended December 31, 2012 compared to operating income of $4.9 million during the three months ended December 31, 2011. The increased operating income is due primarily to $8.4 million of operating income from our acquired operations and improved margins on propane sales.

Natural Gas Liquids Logistics

The following table compares the operating results of our natural gas liquids logistics segment for the periods indicated:

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	Three Months Ended				Change Resulting From
	December 31,				High Sierra
	2012		2011		Combination		Other
			(in thousands)
Revenues:
Propane sales	$	255,157	$	340,006	$	41,576	$	(126,425	)
Other natural gas liquids sales	286,598		89,063		199,150		(1,615		)
Transportation and other revenues	8,822		996		4,115		3,711
Total revenues (1)	550,577		430,065		244,841		(124,329		)

Expenses:
Cost of sales - propane	242,642		334,635		38,333		(130,326		)
Cost of sales - other NGLs	266,665		86,614		182,204		(2,153		)
Cost of sales - storage and other	3,760		156		—		3,604
Operating expenses	8,758		2,054		5,691		1,013
General and administrative expenses	1,397		731		566		100
Depreciation and amortization expense	2,265		1,165		595		505
Total expenses	525,487		425,355		227,389		(127,257		)

Segment operating income	$	25,090	$	4,710	$	17,452	$	2,928

(1) The revenues in this table include $42.4 million of sales to our retail propane segment during the three months ended December 31, 2012 and $22.1 million of sales to our retail propane segment during the three months ended December 31, 2011. These intercompany sales, along with a corresponding amount of cost of sales, are eliminated in our consolidated statement of operations.

Revenues. Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale propane sales decreased approximately $126.4 million during the three months ended December 31, 2012, as compared to $340.0 million during the three months ended December 31, 2011. This resulted from a decrease in the average selling price of $0.47 per gallon, as compared to an average selling price per gallon of $1.43 in the prior year. Volume sold decreased by approximately 14.8 million gallons, as compared to 237.5 million gallons sold in the prior year.

During the three months ended December 31, 2012, the operations of High Sierra contributed revenues of $41.6 million from propane sales. This consisted of sales of 52.9 million gallons of propane at an average price of $0.79 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale sales of other natural gas liquids decreased approximately $1.6 million during the three months ended December 31, 2012, as compared to revenues of $89.1 million during the three months ended December 31, 2011. This resulted from an increase in volume sold of approximately 1.0 million gallons as compared to 50.5 million gallons sold in the prior year, which was offset by a decrease in the average selling price of $0.07 per gallon, as compared to $1.77 per gallon in the prior year.

During the three months ended December 31, 2012, the operations of High Sierra contributed revenues of $199.2 million from sales of other natural gas liquids (primarily butane). This resulted from sales of 154.1 million gallons of other natural gas liquids at an average price of $1.29 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, the increase in volume sold is due primarily to the SemStream acquisition, which expanded the markets we are able to serve. We believe the decline in average selling prices is due primarily to a greater than normal supply in the marketplace, due in part to low demand as a result of mild weather.

Transportation and other revenues for the three months ended December 31, 2012 relate primarily to fees charged for transporting customer-owned product by rail car.

Cost of Sales. Exclusive of the operations acquired in our June 2012 merger with High Sierra, costs of wholesale propane sales decreased approximately $130.3 million during the three months ended December 31, 2012, as compared to $334.6 million during the three months ended December 31, 2011. This resulted from a decrease in the average cost of $0.49 per gallon, as compared to an average cost per gallon of $1.41 in the prior year. Volume sold decreased by approximately 14.8 million gallons, as compared to 237.5 million gallons sold in the prior year. Cost of propane sales were reduced by $1.2 million during the three months ended December 31, 2012 due to $6.4 million of realized gains on derivatives, partially offset by $5.2 million of unrealized losses on

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derivatives. These derivatives consisted primarily of propane swaps that we entered into as economic hedges against the potential decline in the market value of our propane inventories.

During the three months ended December 31, 2012, the cost of propane sales of the High Sierra operations was $38.3 million. This consisted of sales of 52.9 million gallons of propane at an average cost of $0.72 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, cost of wholesale sales of other natural gas liquids decreased approximately $2.2 million during the three months ended December 31, 2012, as compared to $86.6 million during the three months ended December 31, 2011. This resulted from an increase in volume sold of approximately 1.0 million gallons as compared to 50.5 million gallons in the prior year that was offset by a decrease in the average cost of $0.07 per gallon, as compared to $1.72 per gallon in the prior year.

During the three months ended December 31, 2012, the cost of other natural gas liquids sales of the High Sierra operations was $182.2 million. This consisted of sales of 154.1 million gallons of other natural gas liquids (primarily butane) at an average cost of $1.18 per gallon. Cost of sales associated with the operations acquired from High Sierra during the three months ended December 31, 2012 was reduced by $10.5 million due to $10.6 million of unrealized gains on derivatives, partially offset by $0.1 million of realized losses on derivatives. These derivatives consisted primarily of instruments that we entered into as economic hedges against the potential decline in the market value of our butane inventories.

Other cost of sales for the three months ended December 31, 2012 relates primarily to the cost of leasing rail cars used in the transportation of customer-owned crude oil. We began these operations during the nine months ended December 31, 2012.

Operating Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, operating expenses of our wholesale supply and marketing segment increased approximately $1.0 million during the three months ended December 31, 2012 as compared to operating expenses of $2.1 million during the three months ended December 31, 2011. The increase in operating expenses is due primarily to increased compensation and terminal operating expenses resulting from our SemStream combination. During the three months ended December 31, 2012, our natural gas liquids logistics segment incurred $5.7 million of operating expenses related to the operations of High Sierra.

General and Administrative Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, general and administrative expenses of our wholesale supply and marketing segment during the three months ended December 31, 2012 were similar to the expenses during the three months ended December 31, 2011. During the three months ended December 31, 2012, our natural gas liquids logistics segment incurred $0.6 million of general and administrative expenses related to the operations of High Sierra.

Depreciation and Amortization Expense. Exclusive of the operations acquired in our June 2012 merger with High Sierra, depreciation and amortization expense of our wholesale supply and marketing segment increased approximately $0.5 million during the three months ended December 31, 2012, as compared to depreciation and amortization expense of approximately $1.2 million during the three months ended December 31, 2011. This increase is due primarily to depreciation and amortization expense related to assets acquired in the SemStream combination, including depreciation of terminal assets and amortization on customer relationship intangible assets. During the three months ended December 31, 2012, our natural gas liquids logistics segment recorded $0.6 million of depreciation and amortization expense related to assets acquired in our merger with High Sierra.

Operating Income. Our natural gas liquids logistics segment had operating income of approximately $25.1 million during the three months ended December 31, 2012 as compared to operating income of $4.7 million during the three months ended December 31, 2011. The increased operating income is due primarily to the acquisition of the natural gas liquids operations in our June 2012 merger with High Sierra.

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the three months ended December 31, 2012 (amounts in thousands). The operations of our crude oil logistics segment began with our June 2012 merger with High Sierra.

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Revenues:
Crude oil sales (1)	$	683,054
Crude oil transportation	1,174
Total revenues	684,228
Expenses:
Cost of sales	661,219
Operating expenses	8,631
General and administrative expenses	1,067
Depreciation and amortization expense	1,904
Total expenses	672,821
Segment operating income	$	11,407

(1) The revenues in this table include $6.2 million of sales between our crude logistics and water services segments during the three months ended December 31, 2012. These intercompany sales, along with a corresponding amount of cost of sales, are eliminated in our consolidated statement of operations.

Revenues. We generated revenue of $683.1 million from crude oil sales during the three months ended December 31, 2012, selling 7.5 million barrels at an average price of $91.55 per barrel. We also generated $1.2 million of revenue from the transportation of crude oil owned by other parties.

Cost of Sales. Our cost of crude oil sold was $661.2 million during the three months ended December 31, 2012. We sold 7.5 million barrels at an average cost of $88.62 per barrel. Our cost of sales during the three months ended December 31, 2012 included $4.9 million of unrealized losses on derivatives, partially offset by $1.0 million of realized gains on derivatives.

Other Operating Expenses. Our crude oil operations generated $9.7 million of operating and general and administrative expenses during the three months ended December 31, 2012. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $1.9 million during the three months ended December 31, 2012.

Water Services

The following table summarizes the operating results of our water services segment for the three months ended December 31, 2012 (amounts in thousands). The operations of our water services segment began with our June 2012 merger with High Sierra.

Revenues:
Water treatment and disposal	$	20,563
Water transportation	2,243
Total revenues	22,806
Expenses:
Cost of sales	1,499
Operating expenses	8,035
General and administrative expenses	538
Depreciation and amortization expense	7,235
Total expenses	17,307
Segment operating income	$	5,499

Revenues. Our water services segment generated $20.6 million of processing revenue during the three months ended December 31, 2012, processing 9.8 million barrels of wastewater at an average revenue of $2.09 per barrel. Our water transportation business generated $2.2 million of revenues.

Cost of Sales. The cost of sales for our water services segment was $1.5 million for the three months ended December 31, 2012, an average cost of $0.15 per barrel processed. Cost of sales was reduced by $0.3 million of unrealized gains on derivatives, which was partially offset by $0.1 million of realized losses on derivatives. A portion of our processing revenue is generated from the sale of recovered hydrocarbons; we enter into derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover.

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Other Operating Expenses. Our water services segment generated $8.6 million of operating and general and administrative expenses during the three months ended December 31, 2012. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $7.2 million during the three months ended December 31, 2012.

Segment Operating Results for the Nine Months Ended December 31, 2012 and 2011

Items Impacting the Comparability of Our Financial Results

Our results of operations for the nine months ended December 31, 2012 may not be comparable to our results of operations for the nine months ended December 31, 2011, due to the business combinations described above. The results of operations of our natural gas liquids businesses are impacted by seasonality, primarily due to the increase in volumes sold by our retail and wholesale natural gas liquids businesses during the peak heating season of October through March. In addition, propane price fluctuations can have a significant impact on our sales volumes. For these and other reasons, our results of operations for the nine months ended December 31, 2012 are not necessarily indicative of the results to be expected for the full fiscal year.

Volumes Sold or Processed

The following table summarizes the volume of product sold and wastewater processed for the nine months ended December 31, 2012 and 2011, respectively. Gallons sold by our natural gas liquids logistics segment shown in the table below include sales to our retail segment.

	Nine Months Ended		Change Resulting From
	December 31,		Retail	SemStream		High Sierra
Segment	2012	2011	Combinations (1)	Combination		Combinations (2)	Other
				(in thousands)
Retail propane
Propane gallons sold	81,449	37,658	43,314	—		—	477
Distillate gallons sold	15,091	—	15,091	—		—	—

Natural gas liquids logistics
Propane gallons sold	532,353	449,656	—	(3	)	75,460	7,237
Other natural gas liquids gallons sold	457,248	88,556	—	(3	)	314,302	54,390

Crude oil logistics
Crude oil barrels sold	15,922	—	—	—		15,922	—

Water services
Barrels of water processed	16,593	—	—	—		16,593	—

(1) This data includes the operations of Pacer (acquired in January 2012), North American (acquired in February 2012), and certain of the retail acquisitions during the current fiscal year. This data also includes the operations of Osterman (acquired in October 2012) from April 1, 2012 through September 30, 2012.

(2) This data includes the operations of High Sierra (acquired in June 2012), Pecos (acquired in November 2012), and other smaller acquisitions of crude oil logistics and water services businesses.

Our retail propane segment’s sales volumes for the nine months ended December 31, 2012 increased approximately 58.9 million gallons over the 37.7 million gallons sold during the nine months ended December 31, 2011. The principal factor driving the

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increase was our business combinations. The acquired businesses generated approximately 58.4 million gallons of propane and distillate sales during the nine months ended December 31, 2012.

Sales of our natural gas liquids logistics segment increased approximately 451.4 million gallons during the nine months ended December 31, 2012 as compared to sales of 538.2 million gallons during the nine months ended December 31, 2011. The primary reason for this increase in volumes was the acquisition of the operations of High Sierra in a June 2012 merger. An additional reason for the increase in wholesale volumes was the business combination with SemStream in November 2011. The combination facilitated an increase in our wholesale supply and marketing activities, as the acquisition of terminals and leased rail cars gave us more flexibility in the markets we can serve.

The operations of our crude oil logistics and water services segments began with our June 2012 merger with High Sierra.

Operating Income (Loss) by Segment

	Nine Months Ended
	December 31,
Segment	2012			2011			Change
				(in thousands)
Retail propane	$	9,797		$	(1,441	)	$	11,238
Natural gas liquids logistics	36,492			3,318			33,174
Crude oil logistics	17,226			—			17,226
Water services	10,046			—			10,046
Corporate and other	(19,827		)	(3,446		)	(16,381		)
Operating income (loss)	$	53,734		$	(1,569	)	$	55,303

The operating loss within “corporate and other” increased approximately $16.4 million during the nine months ended December 31, 2012 as compared to the nine months ended December 31, 2011. This increase is due in part to $6.2 million of incremental expenses associated with the corporate activities of High Sierra. In addition, corporate general and administrative expenses for the nine months ended December 31, 2012 include $5.3 million of compensation expense related to employee and director compensation programs and $5.2 million of expenses related acquisitions. The operations of our compressor leasing business are also included within “corporate and other.”

Retail Propane

The following table compares the operating results of our retail propane segment for the periods indicated:

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	Nine Months Ended					Change Resulting From
	December 31,					Retail
	2012		2011			*Combinations()**		Other
	(in thousands)
Revenues:
Propane sales	$	162,049	$	83,212		$	92,068	$	(13,231	)
Distillate sales	55,685		—			55,685		—
Other sales	26,382		11,575			16,993		(2,186		)
Total revenues	244,116		94,787			164,746		(15,417		)
Expenses:
Cost of sales - propane	87,450		57,536			49,957		(20,043		)
Cost of sales - distillates	47,883		—			47,883		—
Cost of sales - other	9,223		4,289			5,432		(498		)
Operating expenses	63,193		22,893			39,150		1,150
General and administrative expenses	7,655		4,818			4,854		(2,017		)
Depreciation and amortization expense	18,915		6,692			12,185		38
Total expenses	234,319		96,228			159,461		(21,370		)

Segment operating income (loss)	$	9,797	$	(1,441	)	$	5,285	$	5,953

(*) This data includes the operations of Pacer (acquired in January 2012), North American (acquired in February 2012), and certain of the retail acquisitions during the current fiscal year. This data also includes the operations of Osterman (acquired in October 2012) from April 1, 2012 through September 30, 2012.

Revenues. Propane sales for the nine months ended December 31, 2012 increased approximately $78.8 million as compared to propane sales of $83.2 million during the nine months ended December 31, 2011. The principal reason for the increase in propane sales is the acquisitions of Osterman, Pacer, North American, and other retail operations. Excluding the impact of these acquisitions, propane sales were lower during the nine months ended December 31, 2012 than during the nine months ended December 31, 2011, due primarily to a decline in the average price per gallon sold of $0.37 during the nine months ended December 31, 2012, as compared to an average price per gallon sold of $2.21 during the nine months ended December 31, 2011. Excluding the effect of these acquisitions, volumes sold during the nine months ended December 31, 2012 were similar to volumes sold during the nine months ended December 31, 2011.

Our acquired Osterman, Pacer, North American, and other retail operations generated propane sales of $92.1 million during the nine months ended December 31, 2012, consisting of approximately 43.3 million gallons sold at an average price of $2.13 per gallon. The average selling price per gallon for the acquired operations was higher than the average selling price for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary sources of propane supply than are the markets served by our historical operations.

Our acquired operations generated $55.7 million of revenue from the sales of distillates during the nine months ended December 31, 2012, consisting of 15.1 million gallons sold at an average selling price of $3.69 per gallon.

Cost of Sales. Propane cost of sales for the nine months ended December 31, 2012 increased approximately $29.9 million as compared to propane cost of sales of $57.5 million during the nine months ended December 31, 2011. This increase in propane cost of sales is due primarily to the acquisitions of Osterman, Pacer, North American, and other retail operations. Excluding the impact of these acquisitions, propane cost of sales was lower during the nine months ended December 31, 2012 than during the nine months ended December 31, 2011, due primarily to a decline in the average cost per gallon sold of $0.54 during the nine months ended December 31, 2012, as compared to an average price per gallon sold of $1.53 during the nine months ended December 31, 2011. Excluding the effect of these acquisitions, volumes sold during the nine months ended December 31, 2012 were similar to volumes sold during the nine months ended December 31, 2011.

Our acquired Osterman, Pacer, North American, and other retail operations generated propane cost of sales of $50.0 million during the nine months ended December 31, 2012, consisting of approximately 43.3 million gallons sold at an average cost of $1.15 per gallon. The average cost per gallon for the acquired operations was higher than the average cost for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary sources of propane supply than are the markets served by our historical operations.

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Our acquired operations generated $47.9 million of cost of sales for distillates during the nine months ended December 31, 2012, consisting of 15.1 million gallons sold at an average cost of $3.17 per gallon.

Operating Expenses. Operating expenses of our retail propane segment increased approximately $40.3 million during the nine months ended December 31, 2012 as compared to operating expenses of $22.9 million during the nine months ended December 31, 2011. This increase is due primarily to the impact of our Osterman, Pacer, North American, and other retail acquisitions, the operations of which generated $39.2 million of operating expense during the nine months ended December 31, 2012.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $2.8 million during the nine months ended December 31, 2012 as compared to general and administrative expenses of $4.8 million during the nine months ended December 31, 2011. The principal factor causing the increase is the impact of our Osterman, Pacer, North American, and other retail acquisitions, the operations of which generated $4.9 million of general and administrative expense during the nine months ended December 31, 2012.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased approximately $12.2 million during the nine months ended December 31, 2012 as compared to depreciation and amortization expense of $6.7 million during the nine months ended December 31, 2011. The increase is due primarily to the impact of our Osterman, Pacer, North American, and other retail acquisitions, the operations of which generated $12.2 million of depreciation and amortization expense during the nine months ended December 31, 2012.

Operating Income. Our retail propane segment had operating income of approximately $9.8 million during the nine months ended December 31, 2012 compared to an operating loss of $1.4 million during the nine months ended December 31, 2011. The increased operating income is due in part to the acquired operations. Excluding these acquired operations, our retail segment’s operating income was higher during the nine months ended December 31, 2012 than during the nine months ended December 31, 2011, due primarily to improved margins on propane sales.

Natural Gas Liquids Logistics

The following table compares the operating results of our wholesale supply and marketing segment for the periods indicated:

	Nine Months Ended				Change Resulting From
	December 31,				High Sierra
	2012		2011		Combination		Other
	(in thousands)

Revenues:
Propane sales	$	477,981	$	651,247	$	58,668	$	(231,934	)
Other natural gas liquids sales	626,360		165,769		398,523		62,068
Transportation and other revenues	17,143		1,756		6,623		8,764
Total revenues (1)	1,121,484		818,772		463,814		(161,102		)

Expenses:
Cost of sales - propane	450,803		644,137		52,651		(245,985		)
Cost of sales - other NGLs	594,616		162,923		371,916		59,777
Costs of sales - other	8,898		355		—		8,543
Operating expenses	19,264		4,152		10,473		4,639
General and administrative expenses	3,696		2,099		1,117		480
Depreciation and amortization expense	7,715		1,788		1,440		4,487
Total expenses	1,084,992		815,454		437,597		(168,059		)

Segment operating income	$	36,492	$	3,318	$	26,217	$	6,957

(1) The revenues in this table include $71.4 million of sales to our retail propane segment during the nine months ended December 31, 2012 and $42.0 million of sales to our retail propane segment during the nine months ended December 31, 2011. These intercompany sales, along with a corresponding amount of cost of sales, are eliminated in our consolidated statements of operations.

Revenues. Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale propane sales decreased approximately $231.9 million during the nine months ended December 31, 2012, as compared to $651.2 million during the nine months ended December 31, 2011. This resulted from a decrease in the average selling price of $0.53 per gallon, as

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compared to an average selling price per gallon of $1.45 in the prior year. This decrease in revenue was partially offset by an increase in volume sold of approximately 7.2 million gallons, as compared to 449.7 million gallons sold in the prior year.

During the nine months ended December 31, 2012, the operations of High Sierra contributed revenues of $58.7 million from propane sales. These operations sold 75.5 million gallons of propane at an average price of $0.78 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale sales of other natural gas liquids increased approximately $62.1 million during the nine months ended December 31, 2012, as compared to $165.8 million during the nine months ended December 31, 2011. This resulted from an increase in volume sold of approximately 54.4 million gallons as compared to 88.6 million gallons in the prior year, partially offset by a decrease in the average selling price of $0.28 per gallon, as compared to $1.87 per gallon in the prior year.

During the nine months ended December 31, 2012, the operations of High Sierra contributed revenues of $398.5 million from sales of other natural gas liquids (primarily butane). These operations sold 314.3 million gallons of other natural gas liquids at an average price of $1.27 per gallon.

Transportation and other revenues for the nine months ended December 31, 2012 relate primarily to fees charged for transporting customer-owned product by rail car.

Cost of Sales. Exclusive of the operations acquired in our June 2012 merger with High Sierra, costs of wholesale propane sales decreased approximately $246.0 million during the nine months ended December 31, 2012, as compared to $644.1 million during the nine months ended December 31, 2011. This resulted from a decrease in the average cost of $0.56 per gallon, as compared to an average cost per gallon of $1.43 in the prior year. This decrease in cost was partially offset by an increase in volume sold of approximately 7.2 million gallons, as compared to 449.7 million gallons sold in the prior year. Cost of propane sales were reduced by $14.5 million during the nine months ended December 31, 2012 due to $8.6 million of realized gains and $5.9 million of unrealized gains on derivatives. These derivatives consisted primarily of propane swaps that we entered into as economic hedges against the potential decline in the market value of our propane inventories. Excluding gains on derivatives, our average cost of propane sold during the nine months ended December 31, 2012 was $0.90 cents per gallon.

During the nine months ended December 31, 2012, the cost of propane sales of the High Sierra operations was $52.7 million. These operations sold 75.5 million gallons of propane at an average cost of $0.70 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, cost of wholesale sales of other natural gas liquids increased approximately $59.8 million during the nine months ended December 31, 2012, as compared to $162.9 million during the nine months ended December 31, 2011. This resulted from an increase in volume sold of approximately 54.4 million gallons as compared to 88.6 million gallons in the prior year, partially offset by a decrease in the average cost of $0.28 per gallon, as compared to $1.84 per gallon in the prior year.

During the nine months ended December 31, 2012, the cost of other natural gas liquids sales of the High Sierra operations was $371.9 million. These operations sold 314.3 million gallons of other natural gas liquids (primarily butane) at an average cost of $1.18 per gallon. Costs of sales of other natural gas liquids during the nine months ended December 31, 2012 were reduced by $9.3 million of unrealized gains on derivatives, partially offset by $0.2 million of realized losses on derivatives. These derivatives consisted primarily of instruments that we entered into as economic hedges against the potential decline in the market value of our butane inventories.

Exclusive of the operations acquired from High Sierra, other cost of sales for the nine months ended December 31, 2012 relate primarily to the cost of leasing rail cars used in the transportation of customer-owned crude oil.

Operating Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, operating expenses of our wholesale supply and marketing segment increased approximately $4.6 million during the nine months ended December 31, 2012 as compared to operating expenses of $4.2 million during the nine months ended December 31, 2011. The increase in operating expenses is due primarily to increased compensation and terminal operating expenses resulting from our SemStream combination. During the nine months ended December 31, 2012, our natural gas liquids logistics segment incurred $10.5 million of operating expenses related to the operations of High Sierra.

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nine months ended December 31, 2012 as compared to general and administrative expenses of $2.1 million during the nine months ended December 31, 2011. This increase is due primarily to increased compensation and related expenses resulting from our SemStream combination. During the nine months ended December 31, 2012, our natural gas liquids logistics segment incurred $1.1 million of general and administrative expenses related to the operations of High Sierra.

Depreciation and Amortization Expense. Exclusive of the operations acquired in our June 2012 merger with High Sierra, depreciation and amortization expense of our wholesale supply and marketing segment increased approximately $4.5 million during the nine months ended December 31, 2012, as compared to depreciation and amortization expense of approximately $1.8 million during the nine months ended December 31, 2011. This increase is due primarily to depreciation and amortization expense related to assets acquired in the SemStream combination, including depreciation of terminal assets and amortization on customer relationship intangible assets. During the nine months ended December 31, 2012, our natural gas liquids logistics segment recorded $1.4 million of depreciation and amortization expense related to assets acquired in our merger with High Sierra.

Operating Income. Our natural gas liquids logistics segment had operating income of approximately $36.5 million during the nine months ended December 31, 2012 as compared to operating income of $3.3 million during the nine months ended December 31, 2011. The increased operating income is due in part to $26.2 million of operating income contributed by the operations acquired in the merger with High Sierra. Exclusive of these operations, operating income improved by $7.0 million, which was due to increased product margins, which included $14.5 million of realized and unrealized gains on derivatives, partially offset by increased expenses.

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the nine months ended December 31, 2012 (amounts in thousands). The operations of our crude oil logistics segment began with our June 2012 merger with High Sierra.

Revenues:
Crude oil sales (1)	$	1,468,731
Crude oil transportation	3,708
Total revenues	1,472,439
Expenses:
Cost of sales	1,435,462
Operating expenses	14,057
General and administrative expenses	1,850
Depreciation and amortization expense	3,844
Total expenses	1,455,213
Segment operating income	$	17,226

(1) The revenues in this table include $9.9 million of sales between our crude logistics and water services segments during the nine months ended December 31, 2012. These intercompany sales, along with a corresponding amount of cost of sales, are eliminated in our consolidated statement of operations.

Revenues. We generated revenue of $1.5 billion from crude oil sales during the nine months ended December 31, 2012, selling 15.9 million barrels at an average price of $92.25 per barrel. We also generated $3.7 million of revenue from the transportation of crude oil owned by other parties.

Cost of Sales. Our cost of crude oil sold was $1.4 billion during the nine months ended December 31, 2012. We sold 15.9 million barrels at an average cost of $90.12 per barrel. Our cost of sales during the nine months ended December 31, 2012 was increased by $7.2 million of realized losses and $2.9 million of unrealized losses on derivatives.

Other Operating Expenses. Our crude oil operations generated $15.9 million of operating and general and administrative expenses during the nine months ended December 31, 2012. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $3.8 million during the nine months ended December 31, 2012.

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Water Services

The following table summarizes the operating results of our water services segment for the nine months ended December 31, 2012 (amounts in thousands). The operations of our water services segment began with our June 2012 merger with High Sierra.

Revenues:
Water treatment and disposal	$	34,799
Water transportation	5,758
Total revenues	40,557
Expenses:
Cost of sales	4,169
Operating expenses	14,993
General and administrative expenses	1,064
Depreciation and amortization expense	10,285
Total expenses	30,511
Segment operating income	$	10,046

Revenues. Our water services segment generated $34.8 million of processing revenue during the nine months ended December 31, 2012, processing 16.6 million barrels of wastewater at an average revenue of $2.09 per barrel. Our water transportation business generated $5.8 million of revenues.

Cost of Sales. The cost of sales for our water services segment was $4.2 million for the nine months ended December 31, 2012, an average cost of $0.25 per barrel processed. Cost of sales was increased by unrealized losses of $1.0 million and realized losses of $0.5 million on derivatives. A portion of our processing revenue is generated from the sale of recovered hydrocarbons; we enter into derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover.

Other Operating Expenses. Our water services segment generated $16.1 million of operating and general and administrative expenses during the nine months ended December 31, 2012. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $10.3 million during the nine months ended December 31, 2012.

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our revolving credit facility. Our cash flows from operations are discussed below.

Our borrowing needs vary significantly during the year due in part to the seasonal nature of our natural gas liquids business. Our greatest working capital borrowing needs generally occur during the period of April through September, when the cash flows from our retail and wholesale natural gas liquids operations are reduced. Our needs also increase during those periods when we are building our physical natural gas liquids inventories in anticipation of the winter heating and gasoline blending season, which helps us to establish a fixed margin for a percentage of our wholesale and retail sales under fixed price sales agreements. Our working capital borrowing needs typically decline during the period of October through March when the cash flows from our retail and wholesale natural gas liquids operations are the greatest.

Under our partnership agreement, we are required to make distributions in an amount equal to all of our available cash, if any, no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available cash generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by our general partner in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business, debt principal and interest payments and for distributions to our unitholders during the next four quarters. Our general partner reviews the level of available cash on a quarterly basis based upon information provided by management.

We believe that our anticipated cash flows from operations and the borrowing capacity under our revolving credit facility will be sufficient to meet our liquidity needs for the next 12 months. If our plans or assumptions change or are inaccurate, or if we complete acquisitions, we may need to raise additional capital. However, we cannot give any assurances that we can raise additional capital to meet these needs. Commitments or expenditures, if any, we may make toward any acquisition projects are at our discretion.

We continue to pursue a strategy of growth through acquisitions. We expect to consider financing future acquisitions through a variety of sources, including the use of available capacity on our revolving credit facility, the issuance of equity to sellers of the businesses we acquire, private placements of common units or debt securities, and public offerings of common units or debt securities. Our ability to raise additional capital through the issuance of debt or equity securities will have a significant impact on our ability to continue to pursue our growth strategy.

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Revolving Credit Agreement

Credit Agreement

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 1.75% to 2.75% per annum or (ii) an adjusted LIBOR rate plus a margin of 2.75% to 3.75% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At December 31, 2012, the interest rate in effect on outstanding LIBOR borrowings was 3.22%, calculated as the LIBOR rate of 0.22% plus a margin of 3.0%. At December 31, 2012, interest rate in effect on outstanding base rate borrowings was 5.25%, calculated as the base rate of 3.25% plus a margin of 2.0%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. The Credit Agreement is secured by substantially all of our assets.

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At December 31, 2012, we were in compliance with all covenants under the Credit Agreement.

Senior Notes

The Senior Notes have an aggregate principal amount of $250 million and bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25 million beginning on December 19, 2017 and ending on June 19, 2022. We have the option to pre-pay outstanding principal, although we would be required to pay a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

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(vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are described above.

At December 31, 2012, we were in compliance with all covenants under the Note Purchase Agreement.

Previous Credit Facilities

Balances Outstanding and Rates

At December 31, 2012, our outstanding borrowings and interest rates under our revolving credit facility were as follows (dollars in thousands):

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	392,000	3.22	%
Base rate borrowings (*)	44,000		5.25	%
Working capital facility —
LIBOR borrowings	127,000		3.22	%
Base rate borrowings	—		—

The following table provides certain information on borrowings during the nine months ended December 31, 2012 (dollars in thousands):

							Average
	Daily Average		Lowest		Highest		Interest
	Balance		Balance		Balance		Rate
New credit facility (June 19 - December 31) —
Expansion loans	$	310,702	$	254,000	$	451,000	3.23	%
Working capital loans	112,622		70,000		153,500		3.56	%
Previous credit facility (April 1 — June 19) —
Acquisition loans	222,238		186,000		239,275		3.65	%
Working capital loans	42,700		22,000		67,500		4.07	%

Cash Flows

The following summarizes the sources (uses) of our cash flows for the periods indicated (in thousands):

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	Nine Months Ended
	December 31,
Cash Flows Provided by (Used In):	2012			2011
Operating activities, before changes in operating assets and liabilities	$	67,367		$	2,132
Changes in operating assets and liabilities	(69,293		)	(15,796		)

Operating activities	$	(1,926	)	$	(13,664	)

Investing activities	(514,842		)	(194,175		)

Financing activities	532,839			201,870

Operating Activities. Our operating cash flows are generally at their lowest levels during our first and second fiscal quarters, or the six months ending September 30, when we experience operating losses or lower operating income as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming winter heating and gasoline blending season. Our operating cash flows are generally greatest during our third and fourth fiscal quarters, or the six months ending March 31, when our operating income levels are highest and customers pay for natural gas liquids consumed during the winter season months. We will generally borrow under our Working Capital Facility to supplement our operating cash flows as necessary during our first and second quarters.

Operating cash flows during the nine months ended December 31, 2012 included $69.3 million of cash outflows related to changes in operating assets and liabilities. Operating cash flows during the nine months ended December 31, 2011 included $15.8 million of cash outflows related to changes in operating assets and liabilities.

Investing Activities. Our cash flows from investing activities are primarily impacted by our capital expenditures. In periods where we are engaged in significant acquisitions, we will generally realize negative cash flows in investing activities, which generally require us to increase the borrowings under our revolving credit facilities. During the nine months ended December 31, 2012, we completed thirteen acquisitions, for which we paid $493.3 million in cash in total and issued 23.9 million common units in total. During the nine months ended December 31, 2011, we completed two acquisitions, for which we paid $192.6 million in total and issued 12.9 million common units in total.

Financing Activities. Our cash inflows from financing activities consist primarily of borrowings to fund acquisitions and working capital needs. Our cash outflows from financing activities consist primarily of repayments of debt and distributions to our partners. During the nine months ended December 31, 2012, we had net borrowings of $349.0 million on our revolving credit facilities and $250.0 million from the issuance of senior notes. We also paid $18.6 million of debt issuance costs during the nine months ended December 31, 2012. During the nine months ended December 31, 2011, we had net borrowings of $145.0 million on our revolving credit facilities and we paid $2.0 million of debt issuance costs.

Our cash flows from financing activities during the nine months ended December 31, 2012 included the payment of $46.4 million of distributions, We expect our distributions to owners to increase in future periods under the terms of our partnership agreement. Based on the number of common and subordinated units outstanding as of December 31, 2012 (exclusive of unvested restricted units issued pursuant to employee and director compensation programs), if we made distributions equal to our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $17.9 million per quarter ($71.8 million per year). To the extent our cash flows from operating activities are not sufficient to finance distributions to our partners, we may be required to increase the borrowings under our Working Capital Facility.

The following table summarizes the distributions declared since our initial public offering:

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Date	Record	Date	Amount		Amount Paid to		Amount Paid to
Declared	Date	Paid	Per Unit		Limited Partners		General Partner
					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011	0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012	0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012	0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012	0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012	0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013	0.4625		24,245		927

On May 5, 2011, we made a distribution of $3.85 million from available cash to our general partner and common unitholders as of March 31, 2012. Also in May 2011, we used approximately $65.0 million of the proceeds from our initial public offering to repay advances under our previous credit facility.

Credit Risk

We acquired a crude oil logistics business in our June 2012 merger with High Sierra. As is customary in the crude oil industry, we generally receive payment for a given month’s crude oil sales on the 20th day of the following month. As a result, receivables from individual customers in our crude business are generally higher than the receivables from customers in our other segments.

As described in Note 3 to our consolidated financial statements, we completed a business combination in November 2012 whereby we acquired Pecos, which conducts crude oil logistics operations in Texas and New Mexico. The acquired operations sell a substantial amount of crude oil each month to one customer. The credit terms with this customer call for us to collect payment on a monthly basis. We entered into an agreement with the sellers of Pecos to provide some protection against the risk that we may be unable to collect our receivables from this significant customer. The sellers of Pecos agreed to place certain of our common units that they own into escrow; if the customer defaults on its obligation to us within the six months following the date of the business combination, the sellers of Pecos will return the common units to us as partial compensation for the loss we would sustain on the uncollectable receivable. This agreement may terminate early if we obtain a new credit enhancement facility to replace this agreement. In addition, the number of common units we would be entitled to recover under this agreement could be reduced if there is a decline in our sales to the customer. Although the guarantee from the sellers of Pecos would partially mitigate the economic loss associated with a default by the customer, such a default would be adverse, as we would be required to borrow funds on our revolving credit facility or to sell inventory to replace the cash we were entitled to receive from the customer. We are currently seeking other alternatives to mitigate the credit risk associated with this customer.

Contractual Obligations

The following table updates our contractual obligations summary as of December 31, 2012 for our fiscal years ending thereafter (amounts in thousands):

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			For the
			Three Months
			Ending								After
			March 31,		For the Years Ending March 31,						March 31,
	Total		2013		2014		2015		2016		2016
	(in thousands)
Debt principal payments —
Expansion capital borrowings	$	436,000	$	—	$	—	$	—	$	—	$	436,000
Working capital borrowings	127,000		—		—		—		—		127,000
Senior notes	250,000		—		—		—		—		250,000
Other long-term debt	23,205		2,372		8,551		6,164		2,782		3,336
Scheduled interest payments on revolving credit facility(1)	75,812		5,463		21,853		21,853		21,853		4,790
Scheduled interest payments on senior notes	120,531		4,156		16,625		16,625		16,625		66,500
Standby letters of credit	66,307		—		—		—		—		66,307
Future minimum payments under lease agreements, including expected renewals (2)	197,313		14,376		51,697		44,908		43,648		42,684
Fixed price commodity purchase commitments (3)	454,649		442,778		11,871		—		—		—
Index priced commodity purchase commitments (3) (4)	296,059		218,827		77,232		—		—		—
Total	$	2,046,876	$	687,972	$	187,829	$	89,550	$	84,908	$	996,617

Natural gas liquids gallons under fixed-price purchase commitments (thousands)	47,998		46,225		1,773		—		—		—
Natural gas liquids gallons under index-price purchase commitments (thousands)	285,401		206,438		78,963		—		—		—
Crude oil barrels under fixed-price purchase commitments (thousands)	4,711		4,600		111

(1) The estimated interest payments on our revolving credit facility are based on principal and letters of credit outstanding at December 31, 2012. See Note 7 to our consolidated financial statements as of December 31, 2012 included elsewhere herein for additional information on our credit agreement. We are required to pay a commitment fee ranging from 0.38% to 0.50% on the average unused commitment.

(2) For this caption, amounts shown in the “After March 31, 2016” column represent amounts for the fiscal year ending March 31, 2017.

(3) At December 31, 2012, we had fixed priced and index priced sales contracts for approximately 118.8 million and 182.3 million gallons of natural gas liquids, respectively. At December 31, 2012, we had fixed-price sales contracts for approximately 5.5 million barrels of crude oil.

(4) Index prices are based on a forward price curve as of December 31, 2012. A theoretical change of $0.10 per gallon in the underlying commodity prices at December 31, 2012 would result in a change of approximately $28.5 million in the value of our index-based purchase commitments.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that are expected to have an impact on our financial condition or results of operations other than the operating leases we have executed.

Environmental Legislation

Please see our Annual Report on Form 10-K for the year ended March 31, 2012 for a discussion of proposed environmental legislation and regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome of any future legislation or regulations or the eventual cost we could incur in compliance.

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Critical Accounting Policies

The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership’s operations and the use of estimates made by management. We have identified the following critical accounting policies that are most important to the portrayal of our financial condition and results of operations. Changes in these policies could have a material effect on the financial statements. The application of these accounting policies necessarily requires our most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements.

Revenue Recognition

Impairment of Goodwill and Long-Lived Assets

Goodwill is subject to at least an annual assessment for impairment by applying a fair-value-based test. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant. The valuation of our reporting units requires us to make certain assumptions related to future operations. When evaluating operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge. To date, we have not recognized any material impairment losses on assets we have acquired.

Asset Retirement Obligations

We are required to recognize the fair value of a liability for an asset retirement obligation when it is incurred (generally in the period in which we acquire, construct or install an asset) if a reasonable estimate of fair value can be made. If a reasonable estimate cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.

In order to determine fair value of such liability, we must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free interest rate and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time.

We recorded an asset retirement obligation liability of $1.1 million upon completion of our business combination with High Sierra. Our asset retirement obligation liability is related to the wastewater disposal assets and crude oil lease automatic custody units, for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and

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removal activities when the assets are abandoned. As described in Note 3, the valuation of the liabilities acquired in this merger is subject to change, once we complete the process of identifying and valuing the assumed liabilities.

In addition to the obligations described above, we may be obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain other assets. However, we do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, would be material to our financial position or results of operations.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

Depreciation expense represents the systematic and rational write-off of the cost of our property and equipment, net of residual or salvage value (if any), to the results of operations for the quarterly and annual periods the assets are used. We depreciate the majority of our property and equipment using the straight-line method, which results in our recording depreciation expense evenly over the estimated life of the individual asset. The estimate of depreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. At the time we acquire and place our property and equipment in service, we develop assumptions about such lives and residual values that we believe are reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation expense amounts prospectively. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset; changes in technology that render an asset obsolete; or changes in expected salvage values.

For additional information regarding our property and equipment, see Note 5 of our condensed consolidated financial statements included elsewhere in this interim report.

Business Combinations

We have made in the past, and expect to make in the future, acquisitions of other businesses. In accordance with generally accepted accounting principles for business combinations, we recorded business combinations using a method known as the “acquisition method” in which the various assets acquired and liabilities assumed are recorded at their estimated fair value. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all tangible and intangible assets acquired that meet certain criteria, including assets that were not previously recorded by the acquired entity, such as forward purchase and sale contracts. The estimates most commonly involve property and equipment and intangible assets, including those with indefinite lives. The excess of purchase price over the fair value of acquired assets is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Generally, we have, if necessary, up to one year from the acquisition date to finalize the purchase price allocation. The impact of subsequent changes to the identification of assets and liabilities may require a retroactive adjustment to previously reported financial position and results of operations.

Inventory

Our inventory consists primarily of natural gas liquids and crude oil. We value our inventory at the lower of cost or market, and our cost is determined based on the weighted average cost method. There may be periods during our fiscal year where the market price for inventory on a per gallon basis would be less than our average cost. However, the accounting guidelines do not require us to record a writedown of our inventory at an interim period if we believe that the market values will recover by our year end of March 31. Product prices fluctuate year to year, and during the interim periods within a year. We are unable to control changes in the market value of products and are unable to determine whether writedowns will be required in future periods. In addition, writedowns at interim periods could be required if we cannot conclude that market values will recover sufficiently by our year end.

Product Exchanges

In our natural gas liquids logistics business, we frequently have exchange transactions with suppliers or customers in which we will deliver product volumes to them, or receive product volumes from them to be delivered back to us or from us in future periods, generally in the short-term (referred to as “product exchanges”). The settlements of exchange volumes are generally done through in-kind arrangements whereby settlement volumes are delivered at no cost, with the exception of location differentials. Such in-kind deliveries are ongoing and can take place over several months. We estimate the value of our current product exchange assets and liabilities using period end spot market prices plus or minus location differentials, which we believe represents the value of the exchange volumes at such date. Changes in product prices could impact our estimates.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

As of December 31, 2012, the majority of our long-term debt, other than $250 million of 6.65% Senior Notes, is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt but generally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of the fixed-rate debt but do not impact its cash flows.

Our revolving credit facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. As of December 31, 2012, we had $563.0 million of outstanding borrowings under our revolving credit facility. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of approximately $0.7 million.

We have entered into an interest rate swap agreement to hedge the risk of interest rate fluctuations on our long-term debt. This agreement converts a portion of our revolving credit facility floating rate debt into fixed rate debt on a notional amount of $8.5 million and ends on December 31, 2013. The notional amounts of derivative instruments do not represent actual amounts exchanged between the parties, but instead represent amounts on which the contracts are based. The floating interest rate payments under this swap are based on three-month LIBOR rates. We do not account for this agreement as a hedge. At December 31, 2012, the fair value of this hedge was a liability of approximately $0.1 million and is recorded within accrued liabilities on our consolidated balance sheet.

Commodity Price and Credit Risk

Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of natural gas liquids and crude oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

We take an active role in managing and controlling commodity price and credit risks and have established control procedures, which we review on an ongoing basis. We monitor commodity price risk through a variety of techniques, including daily reporting of price changes to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, restrictions on product liftings, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The principal counterparties associated with our operations as of December 31, 2012 were retailers, resellers, energy marketers, producers, refiners and dealers.

The propane industry is a “margin-based” and “cost-plus” business in which gross profits depend on the differential of sales prices over supply costs. As a result, our profitability will be sensitive to changes in wholesale prices of propane caused by changes in supply or other market conditions. When there are sudden and sharp increases in the wholesale cost of propane, we may not be able to pass on these increases to our customers through retail or wholesale prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost increases can significantly affect our realized margins. Sudden and extended wholesale price increases could reduce our gross margins and could, if continued over an extended period of time, reduce demand by encouraging our retail customers to conserve or convert to alternative energy sources.

We have engaged in derivative financial and other risk management transactions in the past, including various types of forward contracts, options, swaps and future contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. We may experience net unbalanced positions from time to time which we believe to be immaterial in amount. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.

Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accounted for such derivative commodity instruments as hedges. In addition, we do not use such derivative commodity instruments for speculative or trading purposes. We record the changes in fair value of these derivative commodity instruments within cost of sales in our consolidated statements of operations.

The following table summarizes the hypothetical impact on the fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

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	Increase
	(Decrease)
	To Fair Value
Propane (Natural gas liquids logistics segment)	$	(5,272	)
Natural gas liquids (Natural gas liquids logistics segment)	(18,722		)
Heating oil (Retail segment)	277
Crude oil (Crude oil logistics segment)	(4,073		)
Crude oil (Water services segment)	(1,531		)

We acquired a crude oil logistics business in our June 2012 merger with High Sierra. As is customary in the crude oil industry, we generally receive payment from customers on a monthly basis. As a result, receivables from individual customers in our crude business are generally higher than the receivables from customers in our other segments. As described in Note 3 to our consolidated financial statements, we completed a business combination in November 2012 whereby we acquired Pecos, which conducts crude oil logistics operations in Texas and New Mexico. The acquired operations sell a substantial amount of crude oil each month to one customer. The credit terms with this customer call for us to collect payment on a monthly basis. We entered into an agreement with the sellers of Pecos to provide some protection against the risk that we may be unable to collect our receivables from this significant customer. The sellers of Pecos agreed to place certain of our common units that they own into escrow; if the customer defaults on its obligation to us within six months following the date of the business combination, the sellers of Pecos will return the common units to us as partial compensation for the loss we would sustain on the uncollectable receivable. This agreement may terminate early if we obtain a new credit enhancement facility to replace this agreement. In addition, the number of common units we would be entitled to recover under this agreement could be reduced if there is a decline in our sales to the customer. Although the guarantee from the sellers of Pecos would partially mitigate the economic loss associated with a default by the customer, such a default would be adverse, as we would be required to borrow funds on our revolving credit facility or to sell inventory to replace the cash we were entitled to receive from the customer. We are currently seeking other alternatives to mitigate the credit risk associated with this customer.

Fair Value

The net value of our open derivative commodity instruments and interest rate swap contracts at December 31, 2012 was a net asset of $6.5 million and a net liability of $0.1 million, respectively. See Note 11 to our condensed consolidated financial statements as of December 31, 2012 included elsewhere in this interim report for additional information.

We use observable market values for determining the fair value of our trading instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) of the Securities Exchange Act of 1934) that are designed to provide reasonable assurance that information required to be disclosed in our filings and submissions under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

We completed an evaluation under the supervision and with participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2012. Based on this evaluation, our principal executive officer and principal financial officer has concluded that as of December 31, 2012, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

Other than changes that have resulted or may result from our business combinations as discussed below, there have been no changes in our internal controls over financial reporting (as defined in Rules 13(a)—15(f) or Rule 15(d)—15(f) of the Exchange Act) during the three months ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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During the nine months ended December 31, 2012, we completed the following business combinations, among others, on the dates indicated:

· High Sierra – June 19, 2012

· Pecos – November 2, 2012

· Third Coast – December 31, 2012

At this time, we are in the process of implementing our internal control structure over the operations of the businesses acquired during the nine months ended December 31, 2012. We expect that our evaluation and integration efforts related to these acquisitions will continue into future fiscal quarters, due to the magnitude of the acquired operations.

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PART II

Item 1. Legal Proceedings

For information related to legal proceedings, please see the discussion under the caption “Legal matters” in Note 9 to our unaudited condensed consolidated financial statements in Part I, Item I of this Quarterly Report on Form 10-Q, which information is incorporated by reference into this Item 1.

Item 1A. Risk Factors

There have been no material changes in the risk factors previously disclosed in “Item 1A — Risk Factors” in our Annual report on Form 10-K for the fiscal year ended March 31, 2012, as supplemented and updated by Part II, Item 1A “Risk Factors” in our Quarterly Reports on Form 10-Q for the quarters ended June 30, 2012 and September 30, 2012.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

See our current reports on Form 8-K filed with the SEC on October 3, 2012 and November 7, 2012.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Number		Exhibit
2	.1	Equity Purchase Agreement, dated as of October 23, 2012, among Black Hawk Gathering, L.L.C. Midstream Operations L.L.C., Pecos Gathering & Marketing, L.L.C., Striker Oilfield Services, LLC, Transwest Leasing, LLC, the owners of the Pecos Entities, NGL Energy Partners LP and Gerald L. Jensen (incorporated by reference to Exhibit 2.1 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012).
2	.2	Sale Agreement, dated as of December 31, 2012, among Third Coast Towing, LLC, Jeff Kirby, Jane Helm, James Rudellat and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 7, 2012).
4	.1	Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and between NGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2012).
4	.2	Call Agreement, dated as of November 1, 2012, among Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust, Nitor Trust and NGL Energy Partners LP (incorporated by reference to Exhibit 4.1 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012).
4	.3	Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by and between NGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust and Nitor Trust (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 19, 2012).
4	.4	Call Agreement, dated as of December 31, 2012, among NGL Energy Partners LP, Jeff Kirby, Jane Helm and James Rudellat (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 7, 2012).
10	.1	Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012).
31	.1*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
32	.1*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002

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101	.INS**	XBRL Instance Document
101	.SCH**	XBRL Schema Document
101	.CAL**	XBRL Calculation Linkbase Document
101	.DEF**	XBRL Definition Linkbase Document
101	.LAB**	XBRL Label Linkbase Document
101	.PRE**	XBRL Presentation Linkbase Document

*		Exhibits filed with this report.
**		Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of December 31, 2012 and March 31, 2012, (ii) Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2012 and 2011, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2012 and 2011, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the nine months ended December 31, 2012, (v) Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2012 and 2011, and (vi) Notes to Condensed Consolidated Financial Statements.

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SIGNATURES

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

	NGL ENERGY PARTNERS LP

	By:	NGL Energy Holdings LLC, its general partner

Date: February 14, 2013		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer and
			Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number		Exhibit
2	.1	Equity Purchase Agreement, dated as of October 23, 2012, among Black Hawk Gathering, L.L.C. Midstream Operations L.L.C., Pecos Gathering & Marketing, L.L.C., Striker Oilfield Services, LLC, Transwest Leasing, LLC, the owners of the Pecos Entities, NGL Energy Partners LP and Gerald L. Jensen (incorporated by reference to Exhibit 2.1 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012).
2	.2	Sale Agreement, dated as of December 31, 2012, among Third Coast Towing, LLC, Jeff Kirby, Jane Helm, James Rudellat and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 7, 2012).
4	.1	Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and between NGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2012).
4	.2	Call Agreement, dated as of November 1, 2012, among Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust, Nitor Trust and NGL Energy Partners LP (incorporated by reference to Exhibit 4.1 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012).
4	.3	Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by and between NGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust and Nitor Trust (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 19, 2012).
4	.4	Call Agreement, dated as of December 31, 2012, among NGL Energy Partners LP, Jeff Kirby, Jane Helm and James Rudellat (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 7, 2012).
10	.1	Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012).
31	.1*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
32	.1*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
101	.INS**	XBRL Instance Document
101	.SCH**	XBRL Schema Document
101	.CAL**	XBRL Calculation Linkbase Document
101	.DEF**	XBRL Definition Linkbase Document
101	.LAB**	XBRL Label Linkbase Document
101	.PRE**	XBRL Presentation Linkbase Document

*		Exhibits filed with this report.
**		Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of December 31, 2012 and March 31, 2012, (ii) Condensed Consolidated Statements of Operations for the three months and nine months ended December 31, 2012 and 2011, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and nine months ended December 31, 2012 and 2011, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the nine months ended December 31, 2012, (v) Condensed Consolidated Statements of Cash Flows for the nine months ended December 31, 2012 and 2011, and (vi) Notes to Condensed Consolidated Financial Statements.