10-Q 1 a12-20170_110q.htm 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 September 30, 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 November 13, 2012, there were 47,960,480 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 September 30, 2012 and March 31, 2012	3
	Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2012 and 2011	4
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended September 30, 2012 and 2011	5
	Condensed Consolidated Statement of Changes in Partners’ Equity for the six months ended September 30, 2012	6
	Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 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	35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 4.	Controls and Procedures	61

	PART II

Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	63
Item 3.	Defaults Upon Senior Securities	63
Item 4.	Mine Safety Disclosures	63
Item 5.	Other Information	63
Item 6.	Exhibits	64

Signatures		65

Exhibit Index		66

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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;

· 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;

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· 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 “Part II Item 1A — Risk Factors” of this quarterly report and “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 report on Form 10-Q for the quarter ended June 30, 2012.

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PART I

Item 1. Financial Statements (Unaudited)

NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Balance Sheets

As of September 30, 2012 and March 31, 2012

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

	September 30,			March 31,
	2012			2012
				(Note 3)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	26,009		$	7,832
Accounts receivable - trade, net of allowance for doubtful accounts of $1,356 and $818, respectively	385,494			84,004
Receivables from affiliates	3,238			2,282
Inventories	264,556			94,504
Prepaid expenses and other current assets	57,000			10,002
Total current assets	736,297			198,624

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $25,326 and $12,843, respectively	425,641			237,652
GOODWILL	515,881			170,647
INTANGIBLE ASSETS, net of accumulated amortization of $17,646 and $8,174, respectively	345,942			139,780
OTHER NONCURRENT ASSETS	5,658			2,766
Total assets	$	2,029,419		$	749,469

LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Trade accounts payable	$	419,750		$	81,369
Accrued expenses and other payables	68,724			14,143
Advance payments received from customers	74,814			20,293
Payables to affiliates	11,780			9,462
Current maturities of long-term debt	78,033			19,484
Total current liabilities	653,101			144,751

LONG-TERM DEBT, net of current maturities	569,903			199,177
OTHER NONCURRENT LIABILITIES	2,599			212

COMMITMENTS AND CONTINGENCIES

PARTNERS’ EQUITY, per accompanying statement:
General Partner — 0.1% interest; 50,821 and 29,245 notional units outstanding, respectively	(51,052		)	442
Limited Partners — 99.9% interest —
Common units — 44,850,439 and 23,296,253 units outstanding, respectively	839,977			384,604
Subordinated units — 5,919,346 units outstanding at September 30, 2012 and March 31, 2012	11,784			19,824
Accumulated other comprehensive income —
Foreign currency translation	28			31
Noncontrolling interests	3,079			428
Total partners’ equity	803,816			405,329
Total liabilities and partners’ equity	$	2,029,419		$	749,469

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 Six Months Ended September 30, 2012 and 2011

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

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
REVENUES:
Retail propane	$	57,003		$	19,225		$	116,211		$	32,077
Natural gas liquids logistics	350,368			190,816			541,985			368,809
Crude oil logistics	711,021			—			784,538			—
Water services	15,810			—			17,751			—
Other	1,308			—			1,461			—
Total Revenues	1,135,510			210,041			1,461,946			400,886

COST OF SALES:
Retail propane	29,666			13,208			67,107			21,314
Natural gas liquids logistics	328,283			188,246			512,328			366,113
Crude oil logistics	693,687			—			770,570			—
Water services	2,054			—			2,670			—
Total Cost of Sales	1,053,690			201,454			1,352,675			387,427

OPERATING COSTS AND EXPENSES:
Operating	39,431			7,250			62,769			14,392
General and administrative	10,443			4,164			20,403			6,200
Depreciation and amortization	13,361			1,701			22,588			3,078
Operating Income (Loss)	18,585			(4,528		)	3,511			(10,211		)

OTHER INCOME (EXPENSE):
Interest income	263			99			629			225
Interest expense	(8,692		)	(1,012		)	(12,492		)	(2,313		)
Loss on early extinguishment of debt	—			—			(5,769		)	—
Other, net	3			46			29			131
Income (Loss) Before Income Taxes	10,159			(5,395		)	(14,092		)	(12,168		)

INCOME TAX PROVISION	(77		)	—			(536		)	—

Net Income (Loss)	10,082			(5,395		)	(14,628		)	(12,168		)

Net (Income) Loss Allocated to General Partner	(694		)	5			(789		)	12

Net (Income) Loss Attributable to Noncontrolling Interests	(9		)	—			51			—

Net Income (Loss) Attributable to Parent Equity Allocated to Limited Partners	$	9,379		$	(5,390	)	$	(15,366	)	$	(12,156	)

Basic and Diluted Earnings (Loss) Per Common Unit	$	0.18		$	(0.36	)	$	(0.37	)	$	(0.88	)

Basic and Diluted Earnings (Loss) per Subordinated Unit	$	0.18		$	(0.36	)	$	(0.38	)	$	(0.88	)

Basic and Diluted Weighted average units outstanding:
Common	44,831,836			8,864,222			35,730,492			9,370,997
Subordinated	5,919,346			5,919,346			5,919,346			4,431,423

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 Six Months Ended September 30, 2012 and 2011

(U.S. Dollars in Thousands)

	Three Months Ended					Six Months Ended
	September 30,					September 30,
	2012		2011			2012			2011

Net income (loss)	$	10,082	$	(5,395	)	$	(14,628	)	$	(12,168	)
Other comprehensive income (loss), net of tax:
Change in foreign currency translation adjustment	10		(61		)	(3		)	(56		)
Comprehensive income (loss)	$	10,092	$	(5,456	)	$	(14,631	)	$	(12,224	)

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

Six Months Ended September 30, 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	(144		)	—	(18,151		)	—	(4,588		)	—			—			(22,883		)
Contributions	449			—	—			—	—			—			302			751
Business combinations (Note 3)	(52,588		)	21,554,186	486,256			—	—			—			2,400			436,068
Equity issuance costs	—			—	(818		)	—	—			—			—			(818		)
Net income (loss)	789			—	(11,914		)	—	(3,452		)	—			(51		)	(14,628		)
Foreign currency translation adjustment	—			—	—			—	—			(3		)	—			(3		)
BALANCES, SEPTEMBER 30, 2012	$	(51,052	)	44,850,439	$	839,977		5,919,346	$	11,784		$	28		$	3,079		$	803,816

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

Six Months Ended September 30, 2012 and 2011

(U.S. Dollars in Thousands)

	Six Months Ended
	September 30,
	2012			2011
OPERATING ACTIVITIES:
Net loss	$	(14,628	)	$	(12,168	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization, including debt issuance cost amortization	31,245			4,133
Gain on sale of assets	(23		)	(46		)
Provision for doubtful accounts	356			109
Commodity derivative gain	(5,019		)	(465		)
Other	72			79
Changes in operating assets and liabilities, exclusive of acquisitions —
Accounts receivable	101,739			(10,821		)
Receivables from affiliates	6,768			—
Inventories	(121,981		)	(94,588		)
Product exchanges, net	12,663			8,856
Prepaid expenses and other assets	4,097			209
Trade accounts payable	(77,965		)	25,492
Accrued expenses and other liabilities	(25,674		)	1,001
Accounts payable to affiliates	(6,698		)	—
Advance payments received from customers	42,242			25,417
Net cash used in operating activities	(52,806		)	(52,792		)

INVESTING ACTIVITIES:
Purchases of long-lived assets	(14,595		)	(2,094		)
Cash paid for acquisitions of businesses, including acquired working capital, net of cash acquired	(307,082		)	(2,190		)
Cash flows from commodity derivatives	10,692			1,327
Proceeds from sales of assets	581			182
Other	427			(92		)
Net cash used in investing activities	(309,977		)	(2,867		)

FINANCING ACTIVITIES:
Proceeds from sale of common units, net of offering costs	(818		)	75,289
Repurchase of common units	—			(3,418		)
Proceeds from borrowings under revolving credit facilities	594,675			98,000
Payments on revolving credit facilities	(422,675		)	(113,000		)
Issuance of senior notes	250,000			—
Payments on other long-term debt	(251		)	(979		)
Debt issuance costs	(17,839		)	(1,932		)
Contributions	751			85
Distributions to partners	(22,883		)	(6,320		)
Net cash provided by financing activities	380,960			47,725
Net increase (decrease) in cash and cash equivalents	18,177			(7,934		)
Cash and cash equivalents, beginning of period	7,832			16,337
Cash and cash equivalents, end of period	$	26,009		$	8,403

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 September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

Note 1 - Organization and Operations

NGL Energy Partners LP (“we” 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, 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 and paid $32.2 million 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 in exchange for the assets and operations of North American, including working capital.

· During April, May, and July 2012, we completed four separate business combination transactions to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. The largest of these was with Downeast Energy Corp. (“Downeast”). On a combined basis, we paid $60.5 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 $0.4 million will be payable as deferred payments on the purchase price. We also assumed $5.9 million of long-term debt in the form of non-compete agreements.

· 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 assets include water treatment and disposal facilities, two crude oil terminals, a fleet of rail cars, and a fleet of trucks. We paid $96.8 million of cash 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 million of cash and issued 2,685,042 common units to our general partner.

As of September 30, 2012, our businesses include:

· Retail propane and distillate operations in over 20 states;

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

· Propane and natural gas liquids transportation and terminalling operations, conducted through 18 owned terminals and a fleet of owned and predominantly leased rail cars;

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

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

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

Note 2 - Significant Accounting Policies

Basis of Presentation

The condensed consolidated financial statements as of September 30, 2012 and March 31, 2012 and for the three months and six months ended September 30, 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.

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 a business combination.

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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

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.

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 September 30, 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 September 30, 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:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

	Three Months Ended				Six Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(in thousands)

Interest paid, exclusive of debt issuance costs	$	6,594	$	183	$	9,831	$	860
Income taxes paid	$	—	$	—	$	176	$	—

Value of common units issued in retail propane combinations (Note 3)	$	2,224	$	—	$	18,874	$	—

Value of common units issued in High Sierra combination (Note 3)	$	—	$	—	$	414,794	$	—

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:

	September 30,		March 31,
	2012		2012
	(in thousands)
Propane	$	154,104	$	78,993
Other natural gas liquids	66,425		9,259
Crude oil	33,501		—
Other	10,526		6,252
	$	264,556	$	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

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 $96.8 million of cash 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 units on the New York Stock Exchange 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 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 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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

partner at $7.6 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 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 $7.6 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 stock exchange, is reported as a reduction to equity. We incurred and charged to general and administrative expense during the six months ended September 30, 2012 approximately $3.7 million of costs related to the High Sierra transaction. We also incurred or accrued costs of approximately $653,000 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 six months ended September 30, 2012, our consolidated statement of operations includes operating income of approximately $16.8 million generated by the operations of High Sierra. The following table summarizes the revenues and cost of sales generated from High Sierra’s operations that are included in our consolidated statement of operations for the six months ended September 30, 2012 (in thousands):

	Revenues		Cost of Sales
Crude oil logistics	$	784,538	$	770,570
Natural gas liquids logistics	218,973		204,030
Water services	17,751		2,670
Other	1,461		—
Total	$	1,022,723	$	977,270

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 September 30, 2012 are subject to change and such changes could be material. We currently expect to complete this process prior to filing our Form 10-K for the 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 September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

Accounts receivable	$	395,223
Inventory	43,365
Receivables from affiliates	7,724
Derivative assets	10,646
Forward purchase and sale contracts	34,717
Other current assets	11,175
Property, plant and equipment:
Land	5,900
Transportation vehicles and equipment (5 years)	12,160
Facilities and equipment (20 years)	70,409
Buildings and improvements (20 years)	29,800
Software (5 years)	2,700
Construction in progress	9,600
Intangible assets:
Customer relationships (15 years)	174,100
Lease contracts (1-6 years)	10,500
Trade names (indefinite)	3,000
Goodwill	329,227

Assumed liabilities:
Accounts payable	(417,057		)
Accrued expenses and other current liabilities	(35,260		)
Payables to affiliates	(9,016		)
Advance payments received from customers	(1,237		)
Derivative liabilities	(5,726		)
Forward purchase and sale contracts	(22,448		)
Noncurrent liabilities	(3,057		)
Noncontrolling interest in consolidated subsidiary	(2,400		)
Consideration paid, net of cash acquired	$	654,045

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.

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

Terminal Acquisition

On August 31, 2012, we completed the acquisition of a crude oil terminalling facility in Catoosa, Oklahoma for a cash payment of $7.3 million (net of cash acquired). The results of operations of this facility have been included in our consolidated results of operations beginning with the acquisition date. We are in the process of estimating the fair value of the assets and liabilities acquired. These estimates of fair value are subject to change, although we do not expect such changes to be material to our consolidated financial statements. We have preliminarily estimated the fair values 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 September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

Accounts receivable	$	39
Property, plant and equipment (5-20 years)	1,545
Customer relationships (5 years)	1,300
Goodwill	4,516
Current liabilities	(87		)
Consideration paid, net of cash acquired	$	7,313

Retail combinations during the six months ended September 30, 2012

During April, May, and July 2012, we entered into four 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 $60.5 million and issued 850,676 common units, valued at $18.9 million, in exchange for the receipt of these assets. In addition, a combined amount of approximately $0.4 million will be payable as deferred payments on the purchase price. We also assumed $5.9 million of long-term debt in the form of non-compete agreements. We incurred and charged to general and administrative expense during the six months ended September 30, 2012 approximately $225,000 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 September 30, 2012 are subject to change and changes could be material. Our preliminary estimates of the fair value of the assets acquired and liabilities assumed in these three combinations are as follows (in thousands):

Accounts receivable	$	8,323
Inventory	4,707
Other current assets	1,188
Property, plant and equipment:
Land	4,299
Tanks and other retail propane equipment (5-20 years)	29,782
Vehicles (5 years)	9,307
Buildings (30 years)	9,505
Other equipment	1,117
Intangible assets:
Customer relationships (10-15 years)	15,350
Tradenames (indefinite)	600
Non-compete agreements (5 years)	950
Goodwill	11,491
Other non-current assets	784
Long-term debt, including current portion	(5,922		)
Other assumed liabilities	(11,666		)
Fair value of net assets acquired	$	79,815

Consideration paid consists of the following (in thousands):

Cash consideration paid through September 30, 2012	$	60,518
Deferred payments on purchase price	423
Value of common units issued	18,874
Total consideration	$	79,815

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

The retail combinations completed during the six months ended September 30, 2012 contributed approximately $25.1 million of revenue and approximately $16.0 million of cost of sales to our consolidated statement of operations for the six months ended September 30, 2012.

Business Combination During Fiscal 2012 for which Acquisition Accounting was Completed During Fiscal 2013

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. 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):

				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 (expected to be 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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

Business Combinations During Fiscal 2012 for which Acquisition Accounting is Not Yet Complete

During the year ended March 31, 2012, we completed two other business combinations for which we have not yet completed the process of identifying the fair values of the assets and liabilities acquired. These include the Pacer and North American combinations. The estimates of fair value reflected as of March 31, 2012 and September 30, 2012 are subject to change and changes could be material. Our preliminary estimates of the fair values of the assets acquired and liabilities assumed in these two combinations are as follows (in thousands):

	Pacer			North American
Accounts receivable	$	4,389		$	10,338
Inventory	965			3,437
Other current assets	43			282
Property, plant and equipment:
Land	1,400			2,600
Tanks and other retail propane equipment (15 years)	11,200			27,100
Vehicles (5 years)	5,000			9,000
Buildings (30 years)	2,300			2,200
Other equipment (3-5 years)	200			500
Intangible assets:
Customer relationships (15 years)	21,980			9,800
Tradenames (indefinite life)	1,000			1,000
Goodwill	18,460			14,702
Assumed liabilities	(4,349		)	(11,129		)
Consideration paid	$	62,588		$	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 following unaudited pro forma consolidated data below are presented as if the High Sierra acquisition had been completed on April 1, 2011. The pro forma earnings per unit are based on the common and subordinated units outstanding as of September 30, 2012.

	Three Months Ended		Six Months Ended
	September 30,		September 30,
	2011		2012			2011
	(in thousands, except per unit amounts)
Revenues	$	958,704	$	2,177,885		$	1,914,082
Net income (loss) from continuing operations	6,593		(21,757		)	12,315
Limited partners’ interest in net income (loss) from continuing operations	6,697		(21,720		)	12,775
Basic and diluted earnings (loss) from continuing operations per Common Unit	0.13		(0.43		)	0.25
Basic and diluted earnings (loss) from continuing operations per Subordinated Unit	0.13		(0.43		)	0.25

The pro forma consolidated data in the table above was prepared by adding the historical results of operations of High Sierra to our historical results of operations and making certain pro forma adjustments. The pro forma adjustments included: (i) replacing High Sierra’s historical depreciation and amortization expense with pro forma depreciation and amortization expense, calculated using the estimated fair values of long-lived assets recorded in the acquisition accounting; (ii) replacing High Sierra’s historical interest expense with pro forma interest expense, calculated using the cash consideration paid by us in the merger multiplied by the 6.65% interest rate on the senior notes we issued at the time of the merger; and (iii) excluding approximately $12.3 million of professional fees and other expenses incurred by us and by High Sierra that were directly related to the merger. 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 September 30, 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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

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 merger 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:

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	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	$	10,073		$	(5,395	)	$	(14,577	)	$	(12,168	)
Loss (income) allocated to general partner (*)	(694		)	5			(789		)	12
Net income (loss) allocated to limited partners	$	9,379		$	(5,390	)	$	(15,366	)	$	(12,156	)

Net income (loss) allocated to:
Common unitholders	$	8,286		$	(3,232	)	$	(13,112	)	$	(8,253	)
Subordinated unitholders	$	1,093		$	(2,158	)	$	(2,254	)	$	(3,903	)

Weighted average common units outstanding - Basic and Diluted	44,831,836			8,864,222			35,730,492			9,370,997

Weighted average subordinated units outstanding - Basic and Diluted	5,919,346			5,919,346			5,919,346			4,431,423

Earnings (loss) per common unit - Basic and Diluted	$	0.18		$	(0.36	)	$	(0.37	)	$	(0.88	)

Earnings (loss) per subordinated unit - Basic and Diluted	$	0.18		$	(0.36	)	$	(0.38	)	$	(0.88	)

(*) The income allocated to the general partner for the three months and six months ended September 30, 2012 includes distributions to which it is entitled as the holder of incentive distribution rights (described in Note 10).

The 761,000 restricted units described in Note 10 were antidilutive for all periods presented subsequent to the grant date.

Note 5 - Property, Plant and Equipment

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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

	September 30,			March 31,
Description and Useful Life	2012			2012
				(Note 3)
Terminal assets (30 years)	$	61,229		$	60,980
Retail propane equipment (5-20 years)	152,410			120,689
Vehicles (5 years)	53,803			31,463
Water treatment equipment (20 years)	51,640			—
Crude oil tanks and related equipment (20 years)	14,332			—
Information technology equipment (3-5 years)	8,025			2,381
Buildings (30 years)	56,528			16,356
Land	23,231			12,616
Other (3-7 years)	14,198			5,331
Construction in progress	15,571			679
	450,967			250,495
Less: Accumulated depreciation	(25,326		)	(12,843		)
Net property, plant and equipment	$	425,641		$	237,652

Depreciation expense was $7.7 million and $1.4 million for the three months ended September 30, 2012 and 2011, respectively, and $13.8 million and $2.6 million for the six months ended September 30, 2012 and 2011, respectively.

Note 6 — Goodwill and Intangible Assets

The changes in the balance of goodwill during the six months ended September 30, 2012 were as follows (in thousands):

Balance at March 31, 2012, as previously reported	$	148,785
Revision to allocation of Osterman combination	21,862
Balance at March 31, 2012, as retrospectively adjusted (Note 3)	170,647
Acquisitions	345,234
Balance at September 30, 2012	$	515,881

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

	September 30,		March 31,
	2012		2012
			(Note 3)
Retail propane	$	105,180	$	93,689
Natural gas liquids logistics	162,861		76,958
Crude oil logistics	125,049		—
Water services	122,791		—
	$	515,881	$	170,647

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

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

		September 30, 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	$	3,531	$	2,810	$	1,545
Customer relationships	5-20 years	314,442		11,767		123,691		3,868
Non-compete agreements	2-7 years	3,762		1,406		2,813		919
Debt issuance costs	5-10 years	17,144		942		7,310		1,842
Total amortizable		348,658		17,646		136,624		8,174

Non-Amortizable —
Trade names	Indefinite	14,930		—		11,330		—
Total		$	363,588	$	17,646	$	147,954	$	8,174

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

Year Ending March 31,
2013 (six months)	$	15,470
2014	28,180
2015	26,959
2016	26,022
2017	25,309
Thereafter	209,072
	$	331,012

Amortization expense was as follows:

	Three Months Ended				Six Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(in thousands)
Recorded in
Cost of sales	$	1,352	$	200	$	1,552	$	400
Depreciation and amortization	5,654		267		8,820		449
Interest expense	835		303		1,336		655
Loss on early extinguishment of debt	—		—		5,769		—
	$	7,841	$	770	$	17,477	$	1,504

Note 7 - Long-Term Debt

Our long-term debt consists of the following:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

	September 30,		March 31,
	2012		2012
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	262,000	$	—
Working capital loans	124,000		—

Senior notes	250,000		—

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

Other notes payable	11,936		4,661
	647,936		218,661
Less - current maturities	78,033		19,484
Long-term debt	$	569,903	$	199,177

On June 19, 2012, we entered into a new revolving 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 whereby we issued $250 million of notes payable 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.

Credit Agreement

The Working Capital Facility had a total capacity of $197.5 million for cash borrowings and letters of credit at September 30, 2012, which we increased to $217.5 million in November 2012. At September 30, 2012, we had outstanding cash borrowings of $124.0 million and outstanding letters of credit of $58.2 million on the Working Capital Facility, leaving a remaining capacity of $15.3 million at September 30, 2012. The Expansion Capital Facility had a total capacity of $447.5 million for cash borrowings at September 30, 2012, which we increased to $477.5 million in November 2012. At September 30, 2012, we had outstanding cash borrowings of $262.0 million on the Expansion Capital Facility, leaving a remaining capacity of $185.5 million at September 30, 2012. The commitments under the Credit Agreement expire on June 19, 2017. We generally have the right to make early principal payments without incurring any penalties, and earlier principal payments may be required if we enter into certain transactions to sell assets or obtain new borrowings. Once during each fiscal year, we are required to prepay loans under the Working Capital Facility in order to reduce the outstanding Working Capital Facility loans to an aggregate amount of $50 million or less for 30 consecutive days.

All borrowings under the Credit Agreement bear interest, at NGL’s 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 the consolidated leverage ratio of NGL, as defined in the Credit Agreement. At September 30, 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 September 30, 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 September 30, 2012, our outstanding borrowings and interest rates under our revolving credit facility were as follows (dollars in thousands):

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	262,000	3.22	%
Base rate borrowings	—		—
Working capital facility —
LIBOR borrowings	97,000		3.23	%
Base rate borrowings	27,000		5.25	%

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 September 30, 2012, our leverage ratio was approximately 3 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 September 30, 2012, our interest coverage ratio was approximately 8 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 NGL 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 September 30, 2012, we were in compliance with all covenants under our credit facility.

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 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 make early principal payments, although we will be required to pay a penalty if we make an early principal payment. 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 specifies that our “leverage ratio”, as defined in the Note Purchase Agreement, cannot exceed 4.25 to 1.0 at any quarter end. At September 30, 2012, our leverage ratio was approximately 3 to 1. The Note Purchase Agreement also specifies that our “interest coverage ratio”, as defined in the Note Purchase Agreement, cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At September 30, 2012, our interest coverage ratio was approximately 8 to 1.

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.

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 September 30, 2012, we were in compliance with all covenants under the Note Purchase Agreement.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

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 six months ended September 30, 2012.

Other Notes Payable

The other notes payable of approximately $11.9 million mature as follows (in thousands):

Year Ending March 31,
2013 (six months)	$	2,190
2014	2,862
2015	2,351
2016	1,933
2017	1,795
2018	805
	$	11,936

Note 8 - Income Taxes

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 their share of our income or loss on their individual tax returns. 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.

As a publicly-traded partnership, we are allowed to have non-qualifying income up to 10% of our gross income and not be subject to taxation as a corporation. We have two taxable corporate subsidiaries that hold certain assets and operations that represent “non-qualifying income” for a partnership. Our taxable subsidiaries are subject to income taxes related to the taxable income generated by their operations.

We also have two Canadian subsidiaries, one of which we acquired in the June 2012 merger with High Sierra, that are subject to income tax in Canada. Our income tax provision for the six months ended September 30, 2012 related to these subsidiaries was not significant.

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 September 30, 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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

In February 2012, High Sierra, several of its subsidiaries and other unaffiliated parties, were notified of a claim for wrongful death and failure to maintain adequate safety precautions. At this time, we are not able to determine what amount, if any, for which we might ultimately be held liable. In March 2012, a vehicle collided with a truck owned and operated by High Sierra, which resulted in a fatality. At this time, we are not able to determine whether we will be held liable for this incident. We believe that the amount of our liability for these incidents, if any, would be covered under existing insurance coverage.

In September 2010, Pemex Exploracion y Produccion (“Pemex”) filed a lawsuit 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 an early 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. We intend to continue to defend this matter.

In early 2011, IC-CO, Inc. (“IC-CO”) and W.E.O.C., Inc. filed an action in the United States District Court for the Eastern District of Oklahoma against J. Aron & Company claiming they are entitled to enforce lien rights on crude oil purchased by the defendants. IC-CO and W.E.O.C., Inc. sought recovery of sums they were owed for crude oil they had sold and not been paid for. The amount of their claims is approximately $80,000. However, their complaint also seeks class action certification status on behalf of all other producers located in the State of Oklahoma. In December 2011, IC-CO filed a motion seeking to amend its complaint to add additional defendants, including High Sierra. The court has not yet ruled on the motion to amend the complaint. We believe we have meritorious defenses to the claims, including those raised in a substantially similar action that High Sierra previously settled for an immaterial amount, and that the IC-CO claims are now barred by applicable statute of limitations.

One of our facilities acquired in the High Sierra merger is operating with all but one of the required permits. High Sierra has applied for the permit, which is necessary for ongoing operations. We have been informed by the State of Wyoming that we have fulfilled all of the obligations necessary to receive the permit; however, we believe that denial of the permit application could adversely affect operations. We have continued to communicate with the State of Wyoming about the status of the permit. We believe that the permit will be granted, but are unable to determine the timing of any action by the State of Wyoming.

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, 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 have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

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 September 30	$	12,486	$	89
Six months ended September 30	17,246		177

Future minimum lease payments at September 30, 2012 are as follows for the next five years, including expected renewals (in thousands):

Year Ending March 31,
2013 (six months)	$	22,932
2014	45,743
2015	38,948
2016	34,568
2017	32,471

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 September 30, 2012, we had the following such commitments outstanding:

	Gallons	Value
	(in thousands)	(in $ thousands)
Natural gas liquids fixed-price purchase commitments	61,127	$	59,523
Natural gas liquids floating-price purchase commitments	431,379	432,266
Natural gas liquids fixed-price sale commitments	179,150	198,903
Natural gas liquids floating-price sale commitments	250,421	348,427

Crude oil fixed-price purchase commitments	234,278	501,597
Crude oil fixed-price sale commitments	247,624	542,898

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 September 30, 2012, the unamortized balances included $23.7 million recorded within other current assets, $0.3 million recorded within other noncurrent assets, $12.6 million recorded within other current liabilities, and $0.7 million recorded within other noncurrent liabilities. During the three and six months ended September 30, 2012, we recorded $1.6 million to cost of sales related to the amortization of these contract assets and liabilities. As described in Note 3, we

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

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 September 30, 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 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 six months ended September 30, 2012. The following table summarizes the changes in common units outstanding during the six months ended September 30, 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 outstanding at September 30, 2012		44,850,439

In connection with the completion of these transactions, we amended our Registration Rights Agreement. The Registration Rights Agreement, as amended, provides for certain registration rights for certain holders of our common units.

On October 1, 2012, we issued 516,978 common units as partial consideration for the acquisition of certain entities operating salt water disposal wells and related assets. As described in Note 14, on November 12, 2012, we issued 1,834,414 common units to the former owners of Pecos Gathering & Marketing, L.L.C and its affiliated companies.

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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

· 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.”

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

Declared

Date

Paid

Per Unit

to Limited Partners

to General Partner

(in thousands)

July 25, 2011

August 3, 2011

August 12, 2011

0.1669

2,467

October 21, 2011

October 31, 2011

November 14, 2011

0.3375

4,990

January 24, 2012

February 3, 2012

February 14, 2012

0.3500

7,735

April 18, 2012

April 30, 2012

May 15, 2012

0.3625

9,165

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

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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

Equity-Based Incentive Compensation

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

On June 15, 2012, the Board of Directors of our general partner granted 761,000 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		215,500
July 1, 2013		197,500
July 1, 2014		175,000
July 1, 2015		86,500
July 1, 2016		86,500

The weighted-average fair value of the awards was $21.40 at September 30, 2012, which was calculated as the closing price of the common units on September 30, 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 $2.3 million of expense related to these awards during the three months ended September 30, 2012 and $3.0 million of expense related to these awards during the six months ended September 30, 2012. We estimate that the expense we will record on the awards granted as of September 30, 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 September 30, 2012.

Year ending March 31,
2013 (six months)	$	4,535
2014	5,038
2015	2,272
2016	1,690
2017	416
Total	$	13,951

As of September 30, 2012, 4,314,743 units remain available for issuance under the Long-Term Incentive Plan.

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 September 30, 2012, as most of our debt is subject to terms that were recently negotiated.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

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 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 September 30, 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 September 30, 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 September 30, 2012:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	2,047		$	(3,568	)
Level 2 measurements	30,244			(18,733		)
	32,291			(22,301		)
Netting of counterparty contracts	(11,258		)	11,258
Cash collateral provided or held	(9,289		)	2,565
Commodity contracts reported on consolidated balance sheet	$	11,744		$	(8,478	)

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:

	September 30,			March 31,
	2012			2012
	(in thousands)
Other current assets	$	11,143		$	—
Other noncurrent assets	601			—
Other current liabilities	(8,003		)	(36		)
Other noncurrent liabilities	(475		)	—
Net asset (liability)	$	3,266		$	(36	)

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

The following table sets forth our open commodity derivative contract positions at September 30, 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 September 30, 2012 -
Propane swaps (1)	May 2011 - March 2014	(394	)	$	11,354
Heating oil calls and futures (2)	May 2012 - June 2013	188		2,400
Crude swaps (3)	September 2012 - December 2013	(429	)	1,411
Crude - butane spreads (4)	September 2012 - March 2013	(34	)	(1,778		)
Crude forwards (5)	September 2012 - December 2013	(300	)	3,245
Butane forwards (6)	September 2012 - October 2013	34		(6,642		)
				9,990
Less: Margin deposits				(6,724		)
Net fair value of commodity derivatives on consolidated balance sheet				3,266

As of March 31, 2012 -
Propane swaps	April 2012 - March 2013	(3,702	)	$	(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.

(4) Crude-butane spreads — Our crude oil 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:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(in thousands)
Commodity contracts -
Unrealized gain (loss)	$	9,476		$	1,384		$	11,405		$	(862	)
Realized gain (loss)	(8,685		)	(890		)	(6,386		)	1,327
Interest rate swaps	(4		)	(9		)	(5		)	(287		)
Total	$	787		$	485		$	5,014		$	178

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 major 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 14, we completed a business combination in November 2012 whereby we acquired Pecos Gathering & Marketing L.L.C. and certain of its affiliated entities (collectively, “Pecos”) that conduct 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 are 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.

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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers and refiners. These operations were acquired in our June 2012 merger with High Sierra.

Our water services segment provides services for the transportation, treatment, and disposal of waste-water generated from oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. These operations were acquired in 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 September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(in thousands)
Revenues:
Retail propane -
Propane sales	$	37,939		$	16,062		$	77,791		$	26,256
Distillate sales	10,859			—			22,623			—
Sales of equipment, water softener, and other	4,311			1,680			8,101			3,120
Service and rental revenues	3,894			1,483			7,696			2,701
Natural gas liquids logistics -
Propane sales	116,980			164,942			222,824			311,241
Other natural gas liquids sales	244,346			38,169			339,762			76,706
Storage and transportation revenues	5,495			443			8,321			760
Crude oil logistics	714,333			—			788,211			—
Water services	15,810			—			17,751			—
Other	1,308			—			1,461			—
Elimination of intersegment sales	(19,765		)	(12,738		)	(32,595		)	(19,898		)
Total revenues	$	1,135,510		$	210,041		$	1,461,946		$	400,886

Depreciation and Amortization:
Retail propane	$	5,187		$	1,388		$	11,928		$	2,455
Natural gas liquids logistics	3,553			313			5,450			623
Crude oil logistics	1,680			—			1,940			—
Water services	2,768			—			3,050			—
Corporate and other	173			—			220			—
Total depreciation and amortization	$	13,361		$	1,701		$	22,588		$	3,078

Operating Income (Loss):
Retail propane	$	(469	)	$	(3,098	)	$	(6,640	)	$	(6,292	)
Natural gas liquids logistics	10,217			272			11,402			(1,393		)
Crude oil logistics	10,129			—			5,819			—
Water services	4,377			—			4,547			—
Corporate and other	(5,669		)	(1,702		)	(11,617		)	(2,526		)
Total operating income (loss)	$	18,585		$	(4,528	)	$	3,511		$	(10,211	)

Other items not allocated by segment:
Interest income	263			99			629			225
Interest expense	(8,692		)	(1,012		)	(12,492		)	(2,313		)
Loss on early extinguishment of debt	—			—			(5,769		)	—
Other income, net	3			46			29			131
Income tax expense	(77		)	—			(536		)	—
Net income (loss)	$	10,082		$	(5,395	)	$	(14,628	)	$	(12,168	)

Geographic Information:
Revenues:
United States	$	1,090,276		$	210,041		$	1,410,084		$	400,886
Canada	45,234			—			51,862			—
Operating income (loss):
United States	20,243			(4,528		)	3,703			(10,211		)
Canada	(1,658		)	—			(192		)	—

Additions to property, plant and equipment, including acquisitions (accrual basis):
Retail propane	$	2,536		$	2,340		$	57,247		$	3,056
Natural gas liquids logistics	3,333			34			5,444			228
Crude oil logistics	2,836			—			28,314			—
Water services	4,579			—			96,357			—
Corporate and other	1,213			—			13,357			—
Total	$	14,497		$	2,374		$	200,719		$	3,284

	September 30, 2012		March 31, 2012 (Note 3)
	(in thousands)
Total assets:
Retail propane	$	496,265	$	417,589
Natural gas liquids logistics	668,545		325,173
Crude oil logistics	514,598		—
Water services	309,096		—
Corporate and other	40,915		6,707
Total	$	2,029,419	$	749,469

Long-lived assets, net:
Retail propane	$	440,763	$	366,192
Natural gas liquids logistics	307,111		176,419
Crude oil logistics	213,173		—
Water services	297,078		—
Corporate and other	29,339		5,468
Total	$	1,287,464	$	548,079

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 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. 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. These transactions are summarized in the table below (in thousands):

	Three Months Ended		Six Months Ended
	September 30,		September 30,
	2012		2012

Sales to SemGroup	$	11,598	$	24,280
Purchases from SemGroup	14,529		27,077
Sales to entities affiliated with High Sierra management	1,137		1,326
Purchases from entities affiliated with High Sierra management	13,895		15,651

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

	September 30,		March 31,
	2012		2012
Receivables from entities affiliated with High Sierra management	$	609	$	—
Receivables from SemGroup	1,750		1,878
Other	879		404
	$	3,238	$	2,282

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

	September 30,		March 31,
	2012		2012
			(Note 3)
Payables to entities affiliated with High Sierra management	$	371	$	—
Working capital settlement on Osterman acquisition	4,763		4,763
Payables to SemGroup	6,480		4,699
Other	166		—
	$	11,780	$	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 $96.8 million of cash 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 million of cash and issued 2,685,042 common units to our general partner.

As described above, 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. On August 31, 2012, our crude oil logistics segment

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

As of September 30, 2012 and March 31, 2012, and for the

Three Months and Six Months Ended September 30, 2012 and 2011

acquired a petroleum products terminal from one of these entities. The purchase price was $7.3 million (net of cash acquired) including working capital, which is subject to customary post-closing adjustments.

Note 14 — Subsequent Events

During October 2012, we completed a business combination whereby we acquired certain entities that operate salt water disposal wells and related assets. During October and November 2012, we acquired two retail propane businesses. On a combined basis, we paid cash of $42.2 million and issued 516,978 common units (valued at $12.4 million) as consideration for these acquisitions. An additional $1.1 million will be payable under non-compete agreements. The agreements contemplate post-closing adjustments to the purchase prices for certain specified working capital items.

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 $134.8 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 an agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45 million or a maximum of $60 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 agreement.

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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 six months ended September 30, 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 $96.8 million of cash 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 million of cash and issued 2,685,042 common units to our general partner.

As of September 30, 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 over 20 states and to certain re-sellers;

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· 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 18 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, and a fleet of leased rail cars; and

· A water services business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and fractionation 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 18 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.

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 waste-water 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 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.”

Propane Price Fluctuations

Fluctuations in the price of propane 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 retail propane and wholesale supply and marketing customers. 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:

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	Conway, Kansas
	Spot Price				Spot Price
	Per Gallon				Per Gallon
	Low		High		At Period End
For the Three Months Ended September 30:
2012	$	0.5069	$	0.8838	$	0.7919
2011	1.3663		1.4750		1.4269
For the Six Months Ended September 30:
2012	$	0.5038	$	0.9625	$	0.7919
2011	1.2763		1.4900		1.4269

	Mt. Belvieu, Texas
	Spot Price				Spot Price
	Per Gallon				Per Gallon
	Low		High		At Period End
For the Three Months Ended September 30:
2012	$	0.7925	$	0.9888	$	0.9150
2011	1.4438		1.6275		1.5119
For the Six Months Ended September 30:
2012	$	0.7063	$	1.2175	$	0.9150
2011	1.3800		1.6275		1.5119

Historically, we have been successful in passing on 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. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

Recent Developments

On November 1, 2012, we completed a business combination agreement 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 $134.8 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 an agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45 million or a maximum of $60 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 agreement.

Summary Discussion of Operating Results for the Three Months ended September 30, 2012

Our retail propane segment generated an operating loss of $0.5 million during the three months ended September 30, 2012, which was lower than the operating loss of $3.1 million during the three months ended September 30, 2011. Our retail propane segment generated $0.6 million of operating income during the three months ended September 30, 2012 from businesses acquired during the last twelve months, including Osterman, Pacer, North American, and Downeast. The operations that we owned during the corresponding quarter in the prior year experienced more favorable operating results during the three months ended September 30, 2012 than during the three months ended September 30, 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.

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Our natural gas liquids logistics segment generated operating income of $10.2 million during the three months ended September 30, 2012. This was due to $12.7 million of operating income related to the operations acquired in the merger with High Sierra. Our legacy wholesale operations generated an operating loss during the three months ended September 30, 2012.

Weather conditions were unusually warm during the recent winter heating season, 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 three months ended September 30, 2012 than during the corresponding period in the prior year.

The operations of our crude oil logistics segment were acquired in our merger with High Sierra. This segment generated operating income of $10.1 million during the three months ended September 30, 2012, which included unrealized gains of $6.7 million on derivatives.

The operations of our water services segment were acquired in our merger with High Sierra. This segment generated operating income of $4.4 million during the three months ended September 30, 2012.

Analysis of our operating results by segment for the three months and six months ended September 30, 2012 is provided below.

Consolidated Results of Operations

The following table summarizes our historical consolidated statements of operations for the three and six months ended September 30, 2012 and 2011.

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(in thousands)
Revenues	$	1,135,510		$	210,041		$	1,461,946		$	400,886
Cost of sales	1,053,690			201,454			1,352,675			387,427
Operating and general and administrative expenses	49,874			11,414			83,172			20,592
Depreciation and amortization	13,361			1,701			22,588			3,078
Operating income (loss)	18,585			(4,528		)	3,511			(10,211		)
Interest expense	(8,692		)	(1,012		)	(12,492		)	(2,313		)
Loss on early estinguishment of debt	—			—			(5,769		)	—
Interest and other income	266			145			658			356
Income (loss) before income taxes	10,159			(5,395		)	(14,092		)	(12,168		)
Income tax provision	(77		)	—			(536		)	—
Net income (loss)	10,082			(5,395		)	(14,628		)	(12,168		)
Net (income) loss allocated to general partner	(694		)	5			(789		)	12
Net (income) loss attributable to noncontrolling interests	(9		)				51
Net income (loss) attributable to parent equity allocated to limited partners	$	9,379		$	(5,390	)	$	(15,366	)	$	(12,156	)

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.

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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 September 30,
2012	$	310	$	835	$	366,283	3.46	%	$	250,000	6.65	%
2011	134		303		25,250		5.23	%	—		—
Six Months Ended September 30,
2012	$	416	$	1,336	$	320,272	3.61	%	$	142,077	6.65	%
2011	242		655		34,810		5.13	%	—		—

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 six months ended September 30, 2012.

The increased levels of debt outstanding during the six months ended September 30, 2012 are due primarily to borrowings to finance acquisitions and to finance working capital for our natural gas liquids logistics operations.

Interest and Other Income

Our non-operating income consists of the following:

	Three Months Ended				Six Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(in thousands)
Interest income	$	263	$	99	$	629	$	225
Other	3		46		29		131
	$	266	$	145	$	658	$	356

Income Tax Provision

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 their share of our income or loss on their individual tax returns. 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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Noncontrolling Interests

In March 2012, we formed Atlantic Propane LLC (“Atlantic Propane”), in which we own a 60% member interest. In our June 2012 business combination with High Sierra, we acquired an 80% interest in High Sierra Sertco LLC (“Sertco”). The noncontrolling interest shown in our consolidated statements of operations for the three months and six months ended September 30, 2012 represents the other owners’ interests in the income of Atlantic Propane and Sertco.

Non-GAAP Financial Measures

The following tables reconcile net income (loss) or 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:

	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(in thousands)
EBITDA:
Net income (loss) attributable to parent equity	$	10,073		$	(5,395	)	$	(14,577	)	$	(12,168	)
Provision for income taxes	77			—			536			—
Interest expense	8,692			1,012			12,492			2,313
Loss on early extinguishment of debt	—			—			5,769			—
Depreciation and amortization	14,699			1,901			24,113			3,478
EBITDA	$	33,541		$	(2,482	)	$	28,333		$	(6,377	)
Unrealized (gain) loss on derivative contracts	(9,476		)	(1,384		)	(11,405		)	862
Loss (gain) on sale of assets	(30		)	(46		)	(23		)	(46		)
Share-based compensation expense	2,302			—			2,957			—
Adjusted EBITDA	$	26,337		$	(3,912	)	$	19,862		$	(5,561	)

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 September 30, 2012 and 2011

Items Impacting the Comparability of Our Financial Results

Our results of operations for the three months ended September 30, 2012 may not be comparable to our results of operations for the three months ended September 30, 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

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have a significant impact on our sales volumes. For these and other reasons, our results of operations for the three months ended September 30, 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 September 30, 2012, and 2011, respectively. Gallons sold by our natural gas liquids logistics segment shown in the table below include sales to our retail segment.

	Three Months Ended		Change Resulting From
	September 30,		Retail	SemStream		High Sierra
Segment	2012	2011	Combinations	Combination		Combination	Other
				(in thousands)
Retail propane
Propane gallons sold	20,057	7,961	12,069	—		—	27
Distillate gallons sold	3,024	—	3,024	—		—	—

Natural gas liquids logistics
Propane gallons sold	137,840	109,468	—		(*)	20,238	8,134
Other natural gas liquids gallons sold	186,795	19,654	—		(*)	143,432	23,709

Crude oil logistics
Crude oil barrels sold	7,479	—	—	—		7,479	—

Water services
Barrels of water processed	6,036	—	—	—		6,036	—

(*) 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 September 30, 2012 increased approximately 15.1 million gallons over the 8.0 million gallons sold during the three months ended September 30, 2011. The principal factor driving the increase was our business combinations. The acquired businesses generated approximately 15.1 million gallons of propane and distillate sales during the three months ended September 30, 2012.

Sales of our natural gas liquids logistics segment increased approximately 195.5 million gallons during the three months ended September 30, 2012 as compared to sales of 129.1 million gallons during the three months ended September 30, 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. This 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 wholesale 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

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

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	Three Months Ended
	September 30,
Segment	2012			2011			Change
	(in thousands)
Retail propane	$	(469	)	$	(3,098	)	$	2,629
Natural gas liquids logistics	10,217			273			9,944
Crude oil logistics	10,129			—			10,129
Water services	4,377			—			4,377
Corporate and other	(5,669		)	(1,703		)	(3,966		)
Operating income (loss)	$	18,585		$	(4,528	)	$	23,113

The operating loss within “corporate and other” increased approximately $4.0 million during the three months ended September 30, 2012 as compared to $1.7 million during the three months ended September 30, 2011. This increase is due in part to $2.2 million of incremental expenses associated with the corporate activities of High Sierra. In addition, corporate general and administrative expenses for the three months ended September 30, 2012 include $2.3 million of compensation expense related to certain restricted units granted in June 2012 pursuant to employee and director compensation programs. 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
	September 30,						Retail
	2012			2011			Combinations		Other
	(in thousands)
Revenues:
Propane sales	$	37,939		$	16,062		$	25,825	$	(3,948	)
Distillate sales	10,859			—			10,859		—
Equipment, water softener, and other sales	4,311			1,680			2,929		(298		)
Service and rental revenues	3,894			1,483			2,772		(361		)
Total revenues	57,003			19,225			42,385		(4,607		)
Expenses:
Cost of sales - propane	19,296			11,912			13,209		(5,825		)
Cost of sales - distillates	7,276			—			7,276		—
Cost of sales - other	3,094			1,296			2,009		(211		)
Operating expenses	20,626			6,230			14,342		54
General and administrative expenses	1,993			1,497			1,374		(878		)
Depreciation and amortization expense	5,187			1,388			3,625		174
Total expenses	57,472			22,323			41,835		(6,686		)

Segment operating loss	$	(469	)	$	(3,098	)	$	550	$	2,079

Revenues. Propane sales for the three months ended September 30, 2012 increased approximately $21.9 million as compared to propane sales of $16.1 million during the three months ended September 30, 2011. The principal reason for the increase in propane sales is the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane sales were lower during the three months ended September 30, 2012 than during the three months ended September 30, 2011, due primarily to a decline in the average price per gallon sold of $0.50 during the three months ended September 30, 2012, as compared to an average price per gallon sold of $2.02 during the three months ended September 30, 2011. Also excluding the effect of these acquisitions, volumes sold during the three months ended September 30, 2012 were similar to volumes sold during the three months ended September 30, 2011.

Our acquired Osterman, Pacer, North American, and Downeast operations generated propane sales of $25.8 million during the three months ended September 30, 2012, consisting of approximately 12.1 million gallons sold at an average price of $2.14 per

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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 areas of propane supply than are the markets served by our historical operations.

Our acquired operations generated $10.9 million of revenue from the sales of distillates during the three months ended September 30, 2012, consisting of 3.0 million gallons sold at an average selling price of $3.59 per gallon.

Cost of Sales. Propane cost of sales for the three months ended September 30, 2012 increased approximately $7.4 million as compared to propane cost of sales of $11.9 million during the three months ended September 30, 2011. This increase in propane cost of sales is due primarily to the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane cost of sales was lower during the three months ended September 30, 2012 than during the three months ended September 30, 2011, due primarily to a decline in the average cost per gallon sold of $0.73 during the three months ended September 30, 2012, as compared to an average price per gallon sold of $1.50 during the three months ended September 30, 2011. Also excluding the effect of these acquisitions, volumes sold during the three months ended September 30, 2012 were similar to volumes sold during the three months ended September 30, 2011.

Our acquired Osterman, Pacer, North American, and Downeast operations generated propane cost of sales of $13.2 million during the three months ended September 30, 2012, consisting of approximately 12.1 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 areas of propane supply than are the markets served by our historical operations.

Our acquired operations generated $7.3 million of cost of sales for distillates during the three months ended September 30, 2012, consisting of 3.0 million gallons sold at an average cost of $2.41 per gallon. Cost of distillate sales during the three months ended September 30, 2012 was reduced by approximately $1.8 million of unrealized gains and $0.1 million of realized gains on derivatives.

Operating Expenses. Operating expenses of our retail propane segment increased approximately $14.4 million during the three months ended September 30, 2012 as compared to operating expenses of $6.2 million during the three months ended September 30, 2011. This increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $14.3 million of operating expense during the three months ended September 30, 2012.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $0.5 million during the three months ended September 30, 2012 as compared to general and administrative expenses of $1.5 million during the three months ended September 30, 2011. The principal factor causing the increase is the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $1.4 million of general and administrative expense during the three months ended September 30, 2012.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased approximately $3.8 million during the three months ended September 30, 2012 as compared to depreciation and amortization expense of $1.4 million during the three months ended September 30, 2011. The increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $3.6 million of depreciation and amortization expense during the three months ended September 30, 2012.

Operating Loss. Our retail propane segment had an operating loss of approximately $0.5 million during the three months ended September 30, 2012 compared to an operating loss of $3.1 million during the three months ended September 30, 2011. The reduced operating loss is due primarily to improved margins on propane sales. Sales volumes in our retail propane segment are typically lower during the warmer months of the year, and, as a result, it is not unusual for this segment to experience operating losses during the first and second quarters of our fiscal year.

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
	September 30,				High Sierra
	2012		2011		Combination		Other
	(in thousands)
Revenues:
Propane sales	$	116,980	$	164,942	$	15,374	$	(63,336	)
Other natural gas liquids sales	244,346		38,169		176,514		29,663
Transportation and other revenues	5,495		443		2,269		2,783
Total revenues	366,821		203,554		194,157		(30,890		)

Expenses:
Cost of sales - propane	111,870		163,128		12,743		(64,001		)
Cost of sales - other NGLs	230,098		37,755		163,197		29,146
Cost of sales - storage and other	2,768		102		—		2,666
Operating expenses	7,128		1,020		4,373		1,735
General and administrative expenses	1,187		964		476		(253		)
Depreciation and amortization expense	3,553		313		647		2,593
Total expenses	356,604		203,282		181,436		(28,114		)

Segment operating income	$	10,217	$	272	$	12,721	$	(2,776	)

Revenues. Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale propane sales decreased approximately $63.3 million during the three months ended September 30, 2012, as compared to $164.9 million during the three months ended September 30, 2011. This resulted from a decrease in the average selling price of $0.64 per gallon, as compared to an average selling price per gallon of $1.51 in the prior year. This decrease in revenue was partially offset by an increase in volume sold of approximately 8.1 million gallons, as compared to 109.5 million gallons sold in the prior year.

During the three months ended September 30, 2012, the operations of High Sierra contributed revenues of $15.4 million from propane sales. This consisted of sales of 20.2 million gallons of propane at an average price of $0.76 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 $29.7 million during the three months ended September 30, 2012, as compared to $38.2 million during the three months ended September 30, 2011. This resulted from an increase in volume sold of approximately 23.7 million gallons as compared to 19.7 million gallons in the prior year, partially offset by a decrease in the average selling price of $0.38 per gallon, as compared to $1.94 per gallon in the prior year.

During the three months ended September 30, 2012, the operations of High Sierra contributed revenues of $176.5 million from sales of other natural gas liquids (primarily butane). This resulted from sales of 143.4 million gallons of other natural gas liquids at an average price of $1.23 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 during the recent winter heating season as a result of mild weather.

Transportation and other revenues for the three months ended September 30, 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 $64.0 million during the three months ended September 30, 2012, as compared to $163.1 million during the three months ended September 30, 2011. This resulted from a decrease in the average cost of $0.65 per gallon, as compared to an average cost per gallon of $1.49 in the prior year. This decrease in cost was partially offset by an increase in volume sold of approximately 8.1 million gallons, as compared to 109.5 million gallons sold in the prior year. Cost of propane sales were increased by $0.9 million during the three months ended September 30, 2012 due to $1.9 million of unrealized losses on derivatives, partially offset by $1.0 million of realized gains on derivatives. These derivatives consisted primarily of propane swaps that we

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entered into as economic hedges against the potential decline in the market value of our propane inventories.

During the three months ended September 30, 2012, the cost of propane sales of the High Sierra operations were $12.7 million. This consisted of sales of 20.2 million gallons of propane at an average price of $0.63 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 $29.1 million during the three months ended September 30, 2012, as compared to $37.8 million during the three months ended September 30, 2011. This resulted from an increase in volume sold of approximately 23.7 million gallons as compared to 19.7 million gallons in the prior year, partially offset by a decrease in the average cost of $0.38 per gallon, as compared to $1.92 per gallon in the prior year.

During the three months ended September 30, 2012, the cost of other natural gas liquids sales of the High Sierra operations was $163.2 million. This consisted of sales of 143.4 million gallons of other natural gas liquids (primarily butane) at an average price of $1.14 per gallon. Cost of sales associated with the operations acquired from High Sierra during the three months ended September 30, 2012 were reduced by $4.1 million due to $3.7 million of unrealized gains and $0.4 million of realized gains on derivatives.

Other cost of sales for the three months ended September 30, 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 six months ended September 30, 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 $1.7 million during the three months ended September 30, 2012 as compared to operating expenses of $1.0 million during the three months ended September 30, 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 September 30, 2012, our natural gas liquids logistics segment incurred $4.4 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 September 30, 2012 were similar to the expense during the three months ended September 30, 2011. During the three months ended September 30, 2012, our natural gas liquids logistics segment incurred $0.5 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 $2.6 million during the three months ended September 30, 2012, as compared to depreciation and amortization expense of approximately $0.3 million during the three months ended September 30, 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 September 30, 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 $10.2 million during the three months ended September 30, 2012 as compared to operating income of $0.3 million during the three months ended September 30, 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 September 30, 2012 (amounts in thousands). The operations of our crude oil logistics segment began with our June 19, 2012 combination with High Sierra.

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Revenues:
Crude oil sales	$	712,119
Crude oil transportation	2,214
Total revenues	714,333
Expenses:
Cost of sales	696,999
Operating expenses	4,816
General and administrative expenses	709
Depreciation and amortization expense	1,680
Total expenses	704,204
Segment operating income	$	10,129

Revenues. We generated revenue of $712.1 million from crude oil sales during the three months ended September 30, 2012, selling 7.5 million barrels at an average price of $95.22 per barrel. We also generated $2.2 million of revenue from the transportation of crude oil owned by other parties.

Cost of sales. Our cost of crude oil sold was $697.0 million during the three months ended September 30, 2012. We sold 7.5 million barrels at an average cost of $93.19 per barrel. Our cost of sales during the three months ended September 30, 2012 included $9.9 million of realized losses on derivatives, partially offset by $6.7 million of unrealized gains on derivatives.

Other operating expenses. Our crude oil operations generated $5.5 million of operating and general and administrative expenses during the three months ended September 30, 2012. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $1.7 million during the three months ended September 30, 2012.

Water Services

The following table summarizes the operating results of our water services segment for the three months ended September 30, 2012 (amounts in thousands). The operations of our water services segment began with our June 19, 2012 combination with High Sierra.

Revenues:
Water treatment and disposal	$	12,724
Water transportation	3,086
Total revenues	15,810
Expenses:
Cost of sales	2,054
Operating expenses	6,154
General and administrative expenses	457
Depreciation and amortization expense	2,768
Total expenses	11,433
Segment operating income	$	4,377

Revenues. Our water services segment generated $12.7 million of processing revenue during the three months ended September 30, 2012, processing 6.0 million gallons of wastewater at an average revenue of $2.11 per barrel. Our water transportation business generated $3.1 million of revenues.

Cost of sales. The cost of sales for our water services segment was $2.1 million for the three months ended September 30, 2012, an average cost of $0.34 per barrel processed. Cost of sales included unrealized losses of $0.8 million and realized losses of $0.4 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.

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Other operating expenses. Our water services segment generated $6.6 million of operating and general and administrative expenses during the three months ended September 30, 2012. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $2.8 million during the three months ended September 30, 2012.

Segment Operating Results for the Six Months Ended September 30, 2012 and 2011

Items Impacting the Comparability of Our Financial Results

Our results of operations for the six months ended September 30, 2012 may not be comparable to our results of operations for the six months ended September 30, 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 six months ended September 30, 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 September 30, 2012 and 2011, respectively. Gallons sold by our natural gas liquids logistics segment shown in the table below include sales to our retail segment.

	Six Months Ended		Change Resulting From
	September 30,		Retail	SemStream		High Sierra
Segment	2012	2011	Combinations	Combination		Combination	Other
				(in thousands)
Retail propane
Propane gallons sold	39,327	12,964	26,143	—		—	220
Distillate gallons sold	6,273	—	6,273	—		—	—

Natural gas liquids logistics
Propane gallons sold	256,755	212,166	—		(*)	22,535	22,054
Other natural gas liquids gallons sold	251,750	38,100	—		(*)	160,241	53,409

Crude oil logistics
Crude oil barrels sold	8,461	—	—	—		8,461	—

Water services
Barrels of water processed	6,775	—	—	—		6,775	—

Our retail propane segment’s sales volumes for the six months ended September 30, 2012 increased approximately 32.6 million gallons over the 13.0 million gallons sold during the six months ended September 30, 2011. The principal factor driving the increase was our business combinations. The acquired businesses generated approximately 32.4 million gallons of propane and distillate sales during the six months ended September 30, 2012.

Sales of our natural gas liquids logistics segment increased approximately 258.2 million gallons during the six months ended September 30, 2012 as compared to sales of 250.3 million gallons during the six months ended September 30, 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.

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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

	Six Months Ended
	September 30,
Segment	2012			2011			Change
	(in thousands)
Retail propane	$	(6,640	)	$	(6,292	)	$	(348	)
Natural gas liquids logistics	11,402			(1,393		)	12,795
Crude oil logistics	5,819			—			5,819
Water services	4,547			—			4,547
Corporate and other	(11,617		)	(2,526		)	(9,091		)
Operating income (loss)	$	3,511		$	(10,211	)	$	13,722

The operating loss within “corporate and other” increased approximately $9.1 million during the six months ended September 30, 2012 as compared to the six months ended September 30, 2011. This increase is due in part to $2.8 million of incremental expenses associated with the corporate activities of High Sierra. In addition, corporate general and administrative expenses for the six months ended September 30, 2012 include $3.0 million of compensation expense related to employee and director compensation programs and $3.7 million of expenses related to the acquisition of High Sierra. 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:

	Six Months Ended						Change Resulting From
	September 30,						Retail
	2012			2011			Combinations			Other
	(in thousands)
Revenues:
Propane sales	$	77,791		$	26,256		$	56,438		$	(4,903	)
Distillate sales	22,623			—			22,623			—
Equipment, water softener, and other sales	8,101			3,120			5,285			(304		)
Service and rental revenues	7,696			2,701			5,254			(259		)
Total revenues	116,211			32,077			89,600			(5,466		)
Expenses:
Cost of sales - propane	42,489			18,892			31,244			(7,647		)
Cost of sales - distillates	18,897			—			18,897			—
Cost of sales - other	5,721			2,422			3,543			(244		)
Operating expenses	39,068			12,294			26,650			124
General and administrative expenses	4,748			2,306			3,507			(1,065		)
Depreciation and amortization expense	11,928			2,455			8,857			616
Total expenses	122,851			38,369			92,698			(8,216		)

Segment operating loss	$	(6,640	)	$	(6,292	)	$	(3,098	)	$	2,750

Revenues. Propane sales for the six months ended September 30, 2012 increased approximately $51.5 million as compared to propane sales of $26.3 million during the six months ended September 30, 2011. The principal reason for the increase in propane sales is the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane sales were lower during the six months ended September 30, 2012 than during the six months ended September 30, 2011, due primarily to a decline in the average price per gallon sold of $0.41 during the six months ended September 30, 2012, as compared to an average price

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per gallon sold of $2.03 during the six months ended September 30, 2011. Excluding the effect of these acquisitions, volumes sold during the six months ended September 30, 2012 were similar to volumes sold during the six months ended September 30, 2011.

Our acquired Osterman, Pacer, North American, and Downeast operations generated propane sales of $56.4 million during the six months ended September 30, 2012, consisting of approximately 26.1 million gallons sold at an average price of $2.16 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 areas of propane supply than are the markets served by our historical operations.

Our acquired operations generated $22.6 million of revenue from the sales of distillates during the six months ended September 30, 2012, consisting of 6.3 million gallons sold at an average selling price of $3.61 per gallon.

Cost of Sales. Propane cost of sales for the six months ended September 30, 2012 increased approximately $23.6 million as compared to propane cost of sales of $18.9 million during the six months ended September 30, 2011. This increase in propane cost of sales is due primarily to the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane cost of sales were lower during the six months ended September 30, 2012 than during the six months ended September 30, 2011, due primarily to a decline in the average cost per gallon sold of $0.60 during the six months ended September 30, 2012, as compared to an average price per gallon sold of $1.46 during the six months ended September 30, 2011. Excluding the effect of these acquisitions, volumes sold during the six months ended September 30, 2012 were similar to volumes sold during the six months ended September 30, 2011.

Our acquired Osterman, Pacer, North American, and Downeast operations generated propane cost of sales of $31.2 million during the six months ended September 30, 2012, consisting of approximately 26.1 million gallons sold at an average cost of $1.20 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 areas of propane supply than are the markets served by our historical operations.

Our acquired operations generated $18.9 million of cost of sales for distillates during the six months ended September 30, 2012, consisting of 6.3 million gallons sold at an average cost of $3.01 per gallon. Cost of distillate sales during the six months ended September 30, 2012 was reduced by approximately $0.9 million of unrealized gains on derivatives.

Operating Expenses. Operating expenses of our retail propane segment increased approximately $26.8 million during the six months ended September 30, 2012 as compared to operating expenses of $12.3 million during the six months ended September 30, 2011. This increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $26.7 million of operating expense during the six months ended September 30, 2012.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $2.4 million during the six months ended September 30, 2012 as compared to general and administrative expenses of $2.3 million during the six months ended September 30, 2011. The principal factor causing the increase is the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $3.5 million of general and administrative expense during the six months ended September 30, 2012.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased approximately $9.5 million during the six months ended September 30, 2012 as compared to depreciation and amortization expense of $2.5 million during the six months ended September 30, 2011. The increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $8.9 million of depreciation and amortization expense during the six months ended September 30, 2012.

Operating Loss. Our retail propane segment had an operating loss of approximately $6.6 million during the six months ended September 30, 2012 compared to an operating loss of $6.3 million during the six months ended September 30, 2011. The increased operating loss is due primarily to the acquired operations of Osterman, Pacer, North American, and Downeast. Excluding these acquired operations, our retail segment’s operating losses were lower during the six months ended September 30, 2012 than during the six months ended September 30, 2011, due primarily to improved margins on propane sales. Sales volumes in our retail propane segment are typically lower during the warmer months of the year, as a result of which it is not unusual for this segment to experience operating losses during the first and second quarters of our fiscal year.

Natural Gas Liquids Logistics

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

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	Six Months Ended					Change Resulting From
	September 30,					High Sierra
	2012		2011			Combination		Other
	(in thousands)
Revenues:
Propane sales	$	222,824	$	311,241		$	17,092	$	(105,509	)
Other natural gas liquids sales	339,762		76,706			199,373		63,683
Transportation and other revenues	8,321		760			2,508		5,053
Total revenues	570,907		388,707			218,973		(36,773		)

Expenses:
Cost of sales - propane	208,161		309,502			14,318		(115,659		)
Cost of sales - other NGLs	327,951		76,309			189,712		61,930
Costs of sales - other	5,138		200			—		4,938
Operating expenses	10,506		2,098			4,782		3,626
General and administrative expenses	2,299		1,368			551		380
Depreciation and amortization expense	5,450		623			845		3,982
Total expenses	559,505		390,100			210,208		(40,803		)

Segment operating income (loss)	$	11,402	$	(1,393	)	$	8,765	$	4,030

Revenues. Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale propane sales decreased approximately $105.5 million during the six months ended September 30, 2012, as compared to $311.2 million during the six months ended September 30, 2011. This resulted from a decrease in the average selling price of $0.59 per gallon, as compared to an average selling price per gallon of $1.47 in the prior year. This decrease in revenue was partially offset by an increase in volume sold of approximately 22.1 million gallons, as compared to 212.2 million gallons sold in the prior year.

During the six months ended September 30, 2012, the operations of High Sierra contributed revenues of $17.1 million from propane sales. These operations sold 22.5 million gallons of propane at an average price of $0.76 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 $63.7 million during the six months ended September 30, 2012, as compared to $76.7 million during the six months ended September 30, 2011. This resulted from an increase in volume sold of approximately 53.4 million gallons as compared to 38.1 million gallons in the prior year, partially offset by a decrease in the average selling price of $0.48 per gallon, as compared to $2.01 per gallon in the prior year.

During the six months ended September 30, 2012, the operations of High Sierra contributed revenues of $199.4 million from sales of other natural gas liquids (primarily butane). These operations sold 160.2 million gallons of other natural gas liquids at an average price of $1.24 per gallon.

Transportation and other revenues for the three months ended September 30, 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 $115.7 million during the six months ended September 30, 2012, as compared to $309.5 million during the six months ended September 30, 2011. This resulted from a decrease in the average cost of $0.63 per gallon, as compared to an average cost per gallon of $1.46 in the prior year. This decrease in cost was partially offset by an increase in volume sold of approximately 22.1 million gallons, as compared to 212.2 million gallons sold in the prior year. Cost of propane sales were reduced

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by $13.3 million during the six months ended September 30, 2012 due to $2.2 million of realized gains and $11.1 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 six months ended September 30, 2012 was $0.88 cents per gallon, which approximated the average selling price. Our wholesale segment utilizes a weighted-average inventory costing method to calculate cost of sales. Propane prices decreased steadily during April and May 2012, as a result of which the replacement cost of propane was at times lower than the weighted-average cost, which had an adverse effect on margins. One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of falling prices, such as we experienced during the three months ended June 30, 2012, this can result in negative margins on these sales, which we expect to recover when delivering future volumes .

During the six months ended September 30, 2012, the cost of propane sales of the High Sierra operations were $14.3 million. These operations sold 22.5 million gallons of propane at an average price of $0.64 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 $61.9 million during the six months ended September 30, 2012, as compared to $76.3 million during the six months ended September 30, 2011. This resulted from an increase in volume sold of approximately 53.4 million gallons as compared to 38.1 million gallons in the prior year, partially offset by a decrease in the average cost of $0.49 per gallon, as compared to $2.00 per gallon in the prior year.

During the six months ended September 30, 2012, the cost of other natural gas liquids sales of the High Sierra operations was $189.7 million. These operations sold 160.2 million gallons of other natural gas liquids (primarily butane) at an average price of $1.18 per gallon. Costs of sales of other natural gas liquids during the six months ended September 30, 2012 were increased by $1.3 million of unrealized losses and $0.1 million of realized losses on derivatives.

Exclusive of the operations acquired from High Sierra, other cost of sales of for the three months ended September 30, 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 $3.6 million during the six months ended September 30, 2012 as compared to operating expenses of $2.1 million during the six months ended September 30, 2011. The increase in operating expenses is due primarily to increased compensation and terminal operating expenses resulting from our SemStream combination. During the six months ended September 30, 2012, our natural gas liquids logistics segment incurred $4.8 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 increased approximately $0.4 million during the six months ended September 30, 2012 as compared to general and administrative expenses of $1.4 million during the six months ended September 30, 2011. This increase is due primarily to increased compensation and related expenses resulting from our SemStream combination. During the six months ended September 30, 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 $4.0 million during the six months ended September 30, 2012, as compared to depreciation and amortization expense of approximately $0.6 million during the six months ended September 30, 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 six months ended September 30, 2012, our natural gas liquids logistics segment recorded $0.8 million of depreciation and amortization expense related to assets acquired in our merger with High Sierra.

Operating Income (Loss). Our natural gas liquids logistics segment had operating income of approximately $11.4 million during the six months ended September 30, 2012 as compared to an operating loss of $1.4 million during the six months ended September 30, 2011. The increased operating income is due in part to $8.8 million of operating income contributed by the operations acquired in the merger with High Sierra. Exclusive of these operations, operating income improved by $4.0 million, which was due to increased product margins, which included $11.1 million of unrealized gains on derivatives, partially offset by increased expenses.

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Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the six months ended September 30, 2012 (amounts in thousands). The operations of our crude oil logistics segment began with our June 19, 2012 combination with High Sierra.

Revenues:
Crude oil sales	$	785,677
Crude oil transportation	2,534
Total revenues	788,211
Expenses:
Cost of sales	774,243
Operating expenses	5,426
General and administrative expenses	783
Depreciation and amortization expense	1,940
Total expenses	782,392
Segment operating income	$	5,819

Revenues. We generated revenue of $785.7 million from crude oil sales during the six months ended September 30, 2012, selling 8.5 million barrels at an average price of $92.86 per barrel. We also generated $2.5 million of revenue from the transportation of crude oil owned by other parties.

Cost of sales. Our cost of crude oil sold was $774.2 million during the six months ended September 30, 2012. We sold 8.5 million barrels at an average cost of $91.51 per barrel. Our cost of sales during the six months ended September 30, 2012 were increased by $8.2 million of realized losses on derivatives, partially offset by $2.0 million of realized gains on derivatives.

Other operating expenses. Our crude oil operations generated $6.2 million of operating and general and administrative expenses during the six months ended September 30, 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 six months ended September 30, 2012.

Water Services

The following table summarizes the operating results of our water services segment for the six months ended September 30, 2012 (amounts in thousands). The operations of our water services segment began with our June 19, 2012 combination with High Sierra.

Revenues:
Water treatment and disposal	$	14,236
Water transportation	3,515
Total revenues	17,751
Expenses:
Cost of sales	2,670
Operating expenses	6,958
General and administrative expenses	526
Depreciation and amortization expense	3,050
Total expenses	13,204
Segment operating income	$	4,547

Revenues. Our water services segment generated $14.2 million of processing revenue during the six months ended September 30, 2012, processing 6.8 million gallons of wastewater at an average revenue of $2.10 per barrel. Our water transportation business generated $3.5 million of revenues.

Cost of sales. The cost of sales for our water services segment was $2.7 million for the six months ended September 30, 2012, an average cost of $0.39 per barrel processed. Cost of sales was increased by unrealized losses of $1.3 million

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and realized losses of $0.4 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 $7.5 million of operating and general and administrative expenses during the six months ended September 30, 2012. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $3.1 million during the six months ended September 30, 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 to the seasonal nature of our 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 propane operations are reduced. Our needs also increase during those periods when we are building our physical propane inventories in anticipation of the heating season and to help us establish a fixed margin for a percentage of our wholesale and retail sales under fixed price sales agreements. Our working capital borrowing needs decline during the period of October through March when the cash flows from our retail and wholesale propane 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.

Revolving Credit Agreement

Credit Agreement

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September 30, 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 NGL 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 September 30, 2012, we were in compliance with all covenants under our credit facility.

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 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 make early principal payments, although we will be required to pay a penalty if we make an early principal payment. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

At September 30, 2012, we were in compliance with all covenants under the Note Purchase Agreement.

Previous Credit Facilities

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Balances Outstanding and Rates

At September 30, 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	$	262,000	3.22	%
Base rate borrowings	—		—
Working capital facility —
LIBOR borrowings	97,000		3.23	%
Base rate borrowings	27,000		5.25	%

The following table provides certain information on borrowings during the six months ended September 30, 2012 (dollars in thousands):

							Average
	Daily Average		Lowest		Highest		Interest
	Balance		Balance		Balance		Rate
New credit facility (June 19 - September 30) —
Expansion loans	$	256,385	$	254,000	$	262,000	3.49	%
Working capital loans	106,322		70,000		139,000		3.73	%
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):

	Six Months Ended
	September 30,
Cash Flows Provided by (Used In):	2012			2011

Operating activities, before changes in operating assets and liabilities	$	12,003		$	(8,358	)
Changes in operating assets and liabilities	(64,809		)	(44,434		)

Operating activities	$	(52,806	)	$	(52,792	)

Investing activities	(309,977		)	(2,867		)

Financing activities	380,960			47,725

Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. The changes in our operating assets and liabilities caused by the seasonality of our retail and wholesale propane businesses also have a significant impact on our net cash flows from operating activities, as is demonstrated in the table above. Increases in propane prices will tend to result in reduced operating cash flows due to the need to use more cash to fund increases in propane inventories, and propane price decreases tend to increase our operating cash flow due to lower cash requirements to fund increases in propane inventories.

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 propane sales and when we are building our inventory levels for the upcoming heating season. Our operating cash flows are generally greatest

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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 propane consumed during the heating 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. The table above reflects this general trend.

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, depending on our cash flows from operating activities, may require us to increase the borrowings under our acquisition or working capital facilities. During the six months ended September 30, 2012, we completed our merger with High Sierra, for which we paid $239.3 million, net of cash acquired, and issued 20,703,510 common units. Also, during the six months ended September 30, 2012, we completed four business combinations to acquire retail propane and distillate operations, for which we paid $60.5 million and issued 850,676 common units.

Financing Activities. Our cash flows from financing activities are impacted by distributions to our partners. In periods where our cash flows from operating activities are reduced (such as during our first and second quarters), we fund the cash flow deficits through our credit facility. Cash flows required by our investing activities in excess of cash available through our operating activities are funded primarily by our acquisition credit facility, although our merger with High Sierra was funded by the issuance of $250 million of Senior Notes.

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 September 30, 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 $17.2 million per quarter ($68.6 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.

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 acquisition facility.

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

Date

Record

Date

Amount

Amount Paid

Declared

Date

Paid

Per Unit

to Limited Partners

to General Partner

(in thousands)

July 25, 2011

August 3, 2011

August 12, 2011

0.1669

2,467

October 21, 2011

October 31, 2011

November 14, 2011

0.3375

4,990

January 24, 2012

February 3, 2012

February 14, 2012

0.3500

7,735

April 18, 2012

April 30, 2012

May 15, 2012

0.3625

9,165

July 24, 2012

August 3, 2012

August 14, 2012

0.4125

13,571

134

October 17, 2012

October 29, 2012

November 14, 2012

0.4500

22,846

707

During June 2012, we entered into a new credit agreement and issued $250 million of notes in a private placement, and retired our previous credit facility. Cash inflows from financing activities for the six months ended September 30, 2012 include additional borrowings of $844.7 million on long-term debt, to finance working capital needs and acquisitions. Cash outflows from financing activities for the six months ended September 30, 2012 include $423.0 million of payments on long-term debt.

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 businesses.

As described in Note 14 to our consolidated financial statements, we completed a business combination in November 2012 whereby we acquired certain entities (collectively, “Pecos”) that conduct 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.

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We entered into an agreement with the sellers of Pecos to provide some protection against the risk that we are 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 September 30, 2012 for our fiscal years ending thereafter (amounts in thousands):

			For the
			Six 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	$	262,000	$	—	$	—	$	—	$	—	$	262,000
Working capital borrowings	124,000		74,000		—		—		—		50,000
Senior notes	250,000		—		—		—		—		250,000
Other long-term debt	11,936		2,190		2,862		2,351		1,933		2,600
Scheduled interest payments on revolving credit facility (1)	50,764		7,936		13,304		13,304		13,304		2,916
Scheduled interest payments on senior notes	124,688		8,313		16,625		16,625		16,625		66,500
Standby letters of credit	58,177		—		—		—		—		58,177
Future estimated payments under terminal operating agreements	1,966		188		370		376		382		650
Future minimum payments under storage leases, including expected renewals (2)	48,972		5,456		10,879		10,879		10,879		10,879
Future minimum lease payments under noncancelable operating leases, including expected renewals (2)	125,690		17,476		34,864		28,069		23,689		21,592
Fixed price commodity purchase commitments (3)	561,120		533,450		27,670		—		—		—
Index priced commodity purchase commitments (3) (4)	432,266		315,057		117,209		—		—		—
Capital commitment (5)	88		88		—		—		—		—
Total contractual obligations	$	2,051,667	$	964,154	$	223,783	$	71,604	$	66,812	$	725,314

Gallons under fixed-price purchase commitments (thousands)	295,405		281,936		13,469		—		—		—
Gallons under index-price purchase commitments (thousands)	431,379		300,166		131,213		—		—		—

(1) The estimated interest payments on our revolving credit facility are based on principal and letters of credit outstanding at March 31, 2012. See Note 7 to our consolidated financial statements as of September 30, 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. Once each year, we are required to prepay borrowings under our working capital facility to reduce the outstanding working capital borrowings to $50.0 million or less for 30 consecutive days.

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

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(3) At September 30, 2012, we had fixed priced and index priced sales contracts for approximately 179.2 million and 250.4 million gallons of natural gas liquids, respectively. At September 30, 2012, we had fixed-price sales contracts for approximately 247.6 million gallons of crude oil.

(4) Index prices are based on a forward price curve as of September 30, 2012. A theoretical change of $0.10 per gallon in the underlying commodity prices at September 30, 2012 would result in a change of approximately $43.1 million in the value of our index-based purchase commitments.

(5) We own a 60% member interest in Atlantic Propane LLC. Upon formation of this entity, we made a commitment to contribute up to $1.2 million of capital prior to February 2014. As of September 30, 2012, we had made capital contributions of $1.1 million.

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.

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 as relates to future operations. When evaluating operating performance, various factors are considered such as current and changing economic conditions and the

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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 impairment 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 with 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 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 held in storage facilities or in various common carrier pipelines. 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

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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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

As of September 30, 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 September 30, 2012, we had $386.0 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 $0.5 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 September 30, 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 September 30, 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 propane 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 September 30, 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.

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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):

Propane (Natural gas liquids logistics segment)	$	(1,737	)
Heating oil (Retail segment)	669
Natural gas liquids (Natural gas liquids logistics segment)	(21,554		)
Crude oil (Crude oil logistics segment)	(6,440		)
Crude oil (Water services segment)	(1,892		)

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 businesses. As described in Note 14 to our consolidated financial statements, we completed a business combination in November 2012 whereby we acquired certain entities (collectively, “Pecos”) that conduct 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 September 30, 2012 was a net asset of $3.3 million and a net liability of $0.1 million, respectively. See Note 11 to our condensed consolidated financial statements as of September 30, 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.

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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 September 30, 2012. Based on this evaluation, our principal executive officer and principal financial officer have concluded that as of September 30, 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 with High Sierra and Downeast, as discussed below, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)—15(f) or Rule 15(d)—15(f) of the Exchange Act) during the three months ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We closed our business combination with High Sierra on June 19, 2012 and our business combination with Downeast on May 1, 2012. At this time, we are in the process of implementing our internal control structure over the operations of High Sierra and Downeast. We expect that our evaluation and integration efforts related to these operations 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

Except as set forth below, 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 Report on Form 10-Q for the quarter ended June 30, 2012.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

The risk of nonpayment by customers is a concern in all of our operating segments, and our procedures may not fully eliminate this risk. We manage our credit risk exposure through credit analysis, credit approvals, establishing credit limits, requiring prepayments (partially or wholly), requiring propane deliveries over defined time periods and credit monitoring. While we believe our procedures are effective, we can provide no assurance that bad debt write-offs in the future may not be significant and any such non-payment problems could impact our results of operations and potentially limit our ability to make distributions to our unitholders.

In particular, in our November 2012 acquisition of Pecos, we acquired operations that sell a substantial amount of crude oil each month to one customer on certain credit terms. To provide some protection against the risk of nonpayment by this significant customer, we have entered into a credit enhancement agreement with the sellers of Pecos whereby they placed certain of our common units that they own into escrow, and if the customer defaults on its obligation to us within the six months of the acquisition, we will be entitled to take back the escrowed common units as partial compensation for the loss sustained on the uncollectable receivable. Although this guarantee from the sellers of Pecos may partially mitigate the economic loss associated with a default by the customer, such a default would be adverse to our operations, 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 depend on several significant customers, and a loss of one or more significant customers could materially or adversely affect our results of operations.

We are dependent on a few customers for the majority of the revenue of the High Sierra businesses. During the twelve months ended December 31, 2011, two of High Sierra’s customers each represented more than 10% of High Sierra’s consolidated total revenues. Additionally, in our water business, significant volumes are contracted across a few customers, and in November 2012, we acquired crude oil logistics operations that supply a substantial amount of crude oil to one customer. We expect to continue to depend on these customers to support our revenues for the foreseeable future. The loss of any one of these customers, failure to renew contracts upon expiration or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material and adverse effect on our results of operations.

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

On July 18, 2012, pursuant to a Contribution and Purchase Agreement, we issued 100,676 common units in a private transaction exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2). The common units were issued as partial consideration for the acquisition of a retail propane business.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number		Exhibit
4.1		Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 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 September 30, 2012 and March 31, 2012, (ii) Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2012 and 2011, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended September 30, 2012 and 2011, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the six months ended September 30, 2012, (v) Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 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: November 14, 2012		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer and
			Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number		Exhibit
4.1		Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 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 September 30, 2012 and March 31, 2012, (ii) Condensed Consolidated Statements of Operations for the three months and six months ended September 30, 2012 and 2011, (iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months and six months ended September 30, 2012 and 2011, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the six months ended September 30, 2012, (v) Condensed Consolidated Statements of Cash Flows for the six months ended September 30, 2012 and 2011, and (vi) Notes to Condensed Consolidated Financial Statements.