Edgar Filing: NGL Energy Partners LP

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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 June 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 August 7, 2012, there were 45,611,439 common units and 5,919,346 subordinated units issued and outstanding.

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	PART I

Item 1.	Financial Statements (Unaudited)	2

	Condensed Consolidated Balance Sheets as of June 30, 2012 and March 31, 2012	2
	Condensed Consolidated Statements of Operations for the three months ended June 30, 2012 and 2011	3
	Condensed Consolidated Statements of Comprehensive Loss for the three months ended June 30, 2012 and 2011	4
	Condensed Consolidated Statement of Changes in Partners’ Equity for the three months ended June 30, 2012	5
	Condensed Consolidated Statements of Cash Flows for the three months ended June 30, 2012 and 2011	6
	Notes to Condensed Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	48

	PART II

Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	58
Item 3.	Defaults Upon Senior Securities	58
Item 4.	Mine Safety Disclosures	58
Item 5.	Other Information	58
Item 6.	Exhibits	59

Signatures		60

Exhibit Index		61

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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;

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

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

· the nonpayment or nonperformance by our customers;

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

· a deterioration of the credit and capital markets;

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

· the ability to successfully integrate acquired assets and businesses;

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

· the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this quarterly report. Except as required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks described under “Item 1A — Risk Factors” 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.

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PART I

Item 1. Financial Statements (Unaudited)

NGL ENERGY PARTNERS LP

Unaudited Condensed Consolidated Balance Sheets

As of June 30, 2012 and March 31, 2012

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

	June 30,			March 31,
	2012			2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	21,467		$	7,832
Accounts receivable - trade, net of allowance for doubtful accounts of $1,111 and $818, respectively	347,709			84,004
Receivables from affiliates	4,599			2,282
Inventories	192,066			94,504
Prepaid expenses and other current assets	62,617			10,002
Total current assets	628,458			198,624

PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $18,819 and $12,843, respectively	435,369			255,403
GOODWILL	476,894			148,785
INTANGIBLE ASSETS, net of accumulated amortization of $9,805 and $8,174, respectively	355,673			143,559
Other	3,816			2,766
Total assets	$	1,900,210		$	749,137

LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Trade accounts payable	$	360,941		$	81,369
Accrued expenses and other payables	51,068			10,023
Product exchanges	15,372			4,764
Advance payments received from customers	47,042			20,293
Payables to affiliates	14,778			8,486
Current maturities of long-term debt	92,412			19,484
Total current liabilities	581,613			144,419

LONG-TERM DEBT, net of current maturities	510,437			199,177
OTHER NONCURRENT LIABILITIES	2,978			212

COMMITMENTS AND CONTINGENCIES

PARTNERS’ EQUITY, per accompanying statement:
General Partner — 0.1% interest; 50,720 and 29,245 notional units outstanding, respectively	(51,601		)	442
Limited Partners — 99.9% interest —
Common units — 44,749,763 and 23,296,253 units outstanding, respectively	840,744			384,604
Subordinated units — 5,919,346 units outstanding at June 30, 2012 and March 31, 2012	13,133			19,824
Accumulated other comprehensive income —
Foreign currency translation	18			31
Noncontrolling interests	2,888			428
Total partners’ equity	805,182			405,329
Total liabilities and partners’ equity	$	1,900,210		$	749,137

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 Ended June 30, 2012 and 2011

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

	Three Months			Three Months
	Ended			Ended
	June 30,			June 30,
	2012			2011
REVENUES:
Retail propane	$	59,184		$	12,852
Wholesale supply and marketing	164,675			177,497
Midstream	2,151			497
High Sierra operations	100,426			—
Total Revenues	326,436			190,846

COST OF SALES:
Retail propane	37,417			8,106
Wholesale supply and marketing	155,176			177,769
Midstream	803			98
High Sierra operations	105,589			—
Total Cost of Sales	298,985			185,973

OPERATING COSTS AND EXPENSES:
Operating	23,338			7,142
General and administrative	9,960			2,036
Depreciation and amortization	9,227			1,377
Operating Loss	(15,074		)	(5,682		)

OTHER INCOME (EXPENSE):
Interest income	366			126
Interest expense	(3,800		)	(1,301		)
Loss on early extinguishment of debt	(5,769		)	—
Other, net	26			85
Loss Before Income Taxes	(24,251		)	(6,772		)

INCOME TAX PROVISION	(459		)	—

Net Loss	(24,710		)	(6,772		)

Net (Income) Loss Allocated to General Partner	(95		)	7

Net Loss Attributable to Noncontrolling Interests	60

Net Loss Attributable to Parent Equity Allocated to Limited Partners	$	(24,745	)	$	(6,765	)

Basic and Diluted Earnings Per Common Unit	$	(0.76	)	$	(0.53	)

Basic and Diluted Earnings per Subordinated Unit	$	(0.77	)	$	(0.53	)

Basic and Diluted Weighted average units outstanding:
Common	26,529,133			9,883,342
Subordinated	5,919,346			2,927,149

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 Loss

Three Months Ended June 30, 2012 and 2011

(U.S. Dollars in Thousands)

	Three Months			Three Months
	Ended			Ended
	June 30,			June 30,
	2012			2011

Net loss	$	(24,710	)	$	(6,772	)
Other comprehensive income (loss), net of tax:
Change in foreign currency translation adjustment	(13		)	5
Comprehensive loss	$	(24,723	)	$	(6,767	)

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

Three Months Ended June 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
Distribution to partners	(10		)	—	(7,019		)	—	(2,146		)	—			—			(9,175		)
Contributions	460			—	—			—	—			—			120			580
Business combinations (Note 3)	(52,588		)	21,453,510	483,359			—	—			—			2,400			433,171
Net income (loss)	95			—	(20,200		)	—	(4,545		)	—			(60		)	(24,710		)
Foreign currency translation adjustment	—			—	—			—	—			(13		)	—			(13		)
BALANCES, June 30, 2012	$	(51,601	)	44,749,763	$	840,744		5,919,346	$	13,133		$	18		$	2,888		$	805,182

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

Three Months Ended June 30, 2012 and 2011

(U.S. Dollars in Thousands)

	Three Months			Three Months
	Ended			Ended
	June 30,			June 30,
	2012			2011
OPERATING ACTIVITIES:
Net loss	$	(24,710	)	$	(6,772	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization, including debt issuance cost amortization	15,697			1,930
Loss on sale of assets	7			—
Provision for doubtful accounts	293			46
Commodity derivative (gain) loss	(4,228		)	29
Other	62			(7		)
Changes in operating assets and liabilities, exclusive of acquisitions —
Accounts receivable	139,458			(3,783		)
Receivables from affiliates	5,407			—
Inventories	(49,519		)	(40,424		)
Product exchanges, net	10,698			6,389
Prepaid expenses and other current assets	(1,019		)	408
Trade accounts payable	(140,417		)	12,071
Accrued expenses and other payables	(18,804		)	(61		)
Accounts payable to affiliates	(2,724		)	—
Advance payments received from customers	14,890			7,831
Net cash used in operating activities	(54,909		)	(22,343		)

INVESTING ACTIVITIES:
Purchases of long-lived assets	(2,684		)	(840		)
Cash paid for acquisitions of businesses, including acquired working capital	(295,341		)	(70		)
Cash flows from commodity derivatives	15,514			2,217
Proceeds from sales of assets	361			39
Other	212			(204		)
Net cash provided by (used in) investing activities	(281,938		)	1,142

FINANCING ACTIVITIES:
Proceeds from sale of common units, net of offering costs	(673		)	75,289
Repurchase of common units	—			(3,418		)
Proceeds from borrowings under revolving credit facilities	462,175			22,500
Payments on revolving credit facilities	(333,675		)	(76,500		)
Issuance of senior notes	250,000			—
Payments on other long-term debt	(300		)	(189		)
Debt issuance costs	(18,450		)	(251		)
Contributions	580			—
Distributions to partners	(9,175		)	(3,846		)
Net cash provided by financing activities	350,482			13,585
Net increase (decrease) in cash and cash equivalents	13,635			(7,616		)
Cash and cash equivalents, beginning of period	7,832			16,337
Cash and cash equivalents, end of period	$	21,467		$	8,721

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

Three Months Ended June 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 to own and operate retail and wholesale propane and other natural gas liquids businesses. NGL Energy Holdings LLC serves as our general partner. We completed an initial public offering in May 2011. Subsequent to our initial public offering, we significantly expanded our businesses 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 $96 million in exchange for the assets and operations of Osterman. The agreement also contemplates a working capital payment post-closing for certain specified working capital items, currently estimated as a liability of $4.0 million.

· 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 and May 2012, we completed three separate business combination transactions to acquire retail propane and distillate operations in Georgia, Kansas, Maine, and New Hampshire. The largest of these was with Downeast Energy Corp. (“Downeast”). On a combined basis, we paid $56.1 million of cash and issued 750,000 common units in exchange for these assets and operations, including working capital. In addition, a combined amount of approximately $8.9 million will be payable either as deferred payments on the purchase price or under non-compete agreements.

· On June 19, 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy, GP (collectively, “High Sierra”). High Sierra’s assets include water discharge, recycling, 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 June 30, 2012, our businesses include:

· Retail propane and distillate operations in 24 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 2,868 owned and leased rail cars;

· A crude oil transportation and marketing business, the assets of which include two crude oil terminals, 96 trucks, and 461 leased rail cars; and

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

· A water treatment business, the assets of which include a water discharge and recycling facility, a water recycling facility, eight water disposal facilities, a fleet of 50 water trucks, and 65 fractionation tanks.

Note 2 - Significant Accounting Policies

Basis of Presentation

The condensed consolidated financial statements as of and for the three months ended June 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, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

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

Three Months Ended June 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. GAAP defines fair value as 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 should be 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. GAAP requires fair value measurements to 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 and our product exchange assets and liabilities were categorized as Level 2 at June 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 or other assets or liabilities categorized as Level 3 at June 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 June 30, 2012 and March 31, 2012, and for the

Three Months Ended June 30, 2012 and 2011

	Three Months Ended June 30,
	2012		2011
	(in thousands)

Interest paid, exclusive of debt issuance costs	$	3,237	$	677
Income taxes paid	$	176	$	—

Value of common units issued in Downeast combination (Note 3)	$	16,650	—

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:

	June 30, 2012		March 31, 2012
	(in thousands)
Propane and other natural gas liquids	$	161,492	$	89,224
Crude oil	21,320		—
Other	9,254		5,280
	$	192,066	$	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 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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

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 three months ended June 30, 2012 approximately $3.5 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 three months ended June 30, 2012, our consolidated statement of operations includes an operating loss of approximately $8.7 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 three months ended June 30, 2012 (in thousands):

	Revenues		Cost of Sales
Crude oil transportation and marketing	$	73,914	$	76.883
Natural gas liquids transportation and marketing	24,779		28,090
Water treatment and disposal	1,580		616
Other	153		—
Total	$	100,426	$	105,589

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 June 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-Q for the quarter ending December 31, 2012. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	395,204
Inventory	43,365
Receivables from affiliates	7,724
Derivative assets	10,646
Forward purchase and sale contracts	34,717
Other current assets	11,965
Property, plant and equipment:
Land	5,900
Transportation vehicles and equipment (5 years)	12,160
Facilities and equipment (20 years)	70,500
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	318,652
Other noncurrent assets	120
Assumed liabilities:
Accounts payable	(416,765		)
Accrued expenses and other current liabilities	(26,460		)
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	(2,556		)
Noncontrolling interest in consolidated subsidiary	(2,400		)
Consideration paid, net of cash acquired	$	654,045

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

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.

Retail combinations during the three months ended June 30, 2012

During April and May 2012, we entered into three separate business combination agreements to acquire retail propane and distillate operations in Georgia, Kansas, Maine, and New Hampshire. On a combined basis, we paid cash of $56.1 million and issued 750,000 common units, valued at $16.7 million, in exchange for the receipt of these assets. In addition, a combined amount of approximately $4.4 million will be payable either as working capital adjustments or as deferred payments on the purchase price, and a combined amount of $4.5 million will be payable under non-compete agreements. 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 June 30, 2012 are subject to change and changes could be material. We expect to complete this process prior to filing our Form 10-Q for the quarter ending December 31, 2012. 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	$	8,252
Inventory	4,679
Other current assets	1,193
Property, plant and equipment
Land	4,219
Tanks and other retail propane equipment (5-20 years)	28,917
Vehicles (5 years)	9,122
Buildings (30 years)	9,505
Other equipment	1,116
Intangible assets
Customer relationships (10-15 years)	14,350
Tradenames (indefinite)	500
Non-compete agreements (5 years)	850
Goodwill	9,424
Other non-current assets	784
Working capital settlement payable	(3,818		)
Deferred payments	(614		)
Long-term debt, including current portion	(4,491		)
Other assumed liabilities	(11,248		)
Consideration paid through June 30, 2012	$	72,740

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

Business combinations for which acquisition accounting is not yet complete

During the year ended March 31, 2012, we completed three 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 Osterman, Pacer, and North American combinations. The estimates of fair value reflected as of March 31, 2012 and June 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 three combinations are as follows (in thousands):

	Osterman			Pacer			North American
Accounts receivable	$	5,584		$	4,389		$	10,338
Inventory	4,048			965			3,437
Other current assets	212			43			282
Property, plant and equipment
Land	4,500			1,400			2,600
Tanks and other retail propane equipment	55,000			11,200			27,100
Vehicles	12,000			5,000			9,000
Buildings	6,500			2,300			2,200
Other equipment	1,520			200			500
Intangible assets
Customer relationships	62,479			21,980			9,800
Tradenames	5,000			1,000			1,000
Goodwill	30,405			18,460			14,702
Assumed liabilities	(5,431		)	(4,349		)	(11,129		)
Consideration paid	$	181,817		$	62,588		$	69,830

Pro Forma Results of Operations

The operations of High Sierra have been included in our statement of operations since High Sierra was acquired on June 19, 2012. The following unaudited pro forma consolidated data for the three months ended June 30, 2012 and 2011 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 June 30, 2012.

	Three Months Ended			Three Months Ended
	June 30,			June 30,
	2012			2011
	(in thousands)
Revenues	$	1,042,375		$	955,379
Net loss from continuing operations	(8,976		)	(5,995		)
Limited partners' interest in net loss from continuing operations	(8,967		)	(5,989		)
Basic and diluted earnings from continuing operations per Common Unit	(0.18		)	(0.12		)
Basic and diluted earnings from continuing operations per Subordinated Unit	(0.18		)	(0.12		)

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 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 certain 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 June 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 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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

Note 4 — Earnings per Unit

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

	Three Months Ended June 30,
	2012			2011
	(in thousands, except unit and per unit amounts)
Earnings per common or subordinated Limited Partner Unit
Net loss attributable to parent equity	$	(24,650	)	$	(6,772	)
Loss (income) allocated to general partner(*)	(95		)	7
Net loss allocated to limited partners	$	(24,745	)	$	(6,765	)

Net loss allocated to:
Common unitholders	$	(20,200	)	$	(5,220	)
Subordinated unitholders	$	(4,545	)	$	(1,545	)

Weighted average common units outstanding - Basic and Diluted	26,529,133			9,883,342

Weighted average subordinated units outstanding - Basic and Diluted	5,919,346			2,927,149

Earnings per common unit - Basic and Diluted	$	(0.76	)	$	(0.53	)

Earnings per subordinated unit - Basic and Diluted	$	(0.77	)	$	(0.53	)

(*) The income allocated to the general partner for the three months ended June 30, 2012 includes $134,000 of distributions to which it is entitled as the holder of incentive distribution rights, which are described in Note 10.

Since we experienced a net loss during the three months ended June 30, 2012, the 761,000 restricted units described in Note 10 did not cause any dilution.

Note 5 - Property, Plant and Equipment

Our property, plant and equipment consists of the following as of the dates indicated:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

	June 30,			March 31,
Description and Useful Life	2012			2012
	(in thousands)
Terminal assets (30 years)	$	60,923		$	60,980
Retail propane equipment (5-20 years)	158,399			128,529
Vehicles (5 years)	57,491			35,764
Water treatment equipment (20 years)	48,400			—
Crude oil tanks and related equipment (20 years)	13,500			—
Information technology equipment (3 years)	6,754			1,973
Buildings (30 years)	58,362			19,027
Land	25,232			14,767
Other (3-7 years)	14,040			6,527
Construction in progress	11,087			679
	454,188			268,246
Less: Accumulated depreciation	(18,819		)	(12,843		)
Net property, plant and equipment	$	435,369		$	255,403

Depreciation expense was $6.1 million and $1.2 million for the three months ended June 30, 2012 and 2011, respectively.

Note 6 — Goodwill and Intangible Assets

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

Balance, March 31, 2012	$	148,785
Acquisitions	328,076
Other	33
Balance, June 30, 2012	$	476,894

Goodwill by reportable segment is as follows:

	June 30,		March 31,
	2012		2012
	(in thousands)
Retail propane	$	81,284	$	71,827
Wholesale supply and marketing	58,128		58,128
Midstream	18,830		18,830
High Sierra operations	318,652		—
	$	476,894	$	148,785

Our intangible assets consist of the following as of the dates indicated:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

		June 30, 2012				March 31, 2012
		Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Useful Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable —
Lease and other agreements	5-8 years	$	13,310	$	2,053	$	2,810	$	1,545
Customer relationships	7-20 years	320,120		6,565		131,670		3,868
Non-compete agreements	2-6 years	2,963		1,080		2,113		919
Debt issuance costs	5-10 years	17,755		107		7,310		1,842
Total amortizable		354,148		9,805		143,903		8,174

Non-Amortizable —
Trade names	Indefinite	11,330		—		7,830		—
Total		$	365,478	$	9,805	$	151,733	$	8,174

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

Year Ending March 31,
2013 (nine months)	$	23,940
2014	28,235
2015	27,017
2016	26,077
2017	25,259
Thereafter	213,815
	$	344,343

Amortization expense was as follows:

	Three Months Ended June 30,
	2012		2011
	(in thousands)
Recorded in
Cost of sales	$	200	$	200
Depreciation and amortization	3,166		182
Interest expense	501		352
Loss on early extinguishment of debt	5,769		—
	$	9,636	$	734

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

Three Months Ended June 30, 2012 and 2011

	June 30,		March 31,
	2012		2012
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	254,000	$	—
Working capital loans	88,500		—

Senior notes	250,000		—

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

Other notes payable	10,349		4,661
	602,849		218,661
Less - current maturities	92,412		19,484
Long-term debt	$	510,437	$	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 has a capacity of $197.5 million for cash borrowings and letters of credit. At June 30, 2012, we had outstanding cash borrowings of $88.5 million and outstanding letters of credit of $60.5 million on the Working Capital Facility. The Expansion Capital Facility has a capacity of $447.5 million for cash borrowings. At June 30, 2012, we had outstanding cash borrowings of $254.0 million on the Expansion Capital Facility. In addition, upon satisfaction of certain conditions, we will have the right to increase the amount available under our revolving credit facilities from the current amount of $645 million up to an aggregate amount of $700 million. 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 and/or cash collateralize outstanding letters of credit in order to reduce the outstanding Working Capital Facility loans and letters of credit 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 June 30, 2012, the interest rate in effect on outstanding LIBOR borrowings was 3.25%, calculated as the LIBOR rate of 0.25% plus a margin of 3.0%. At June 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 June 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 June 30, 2012 and March 31, 2012, and for the

Three Months Ended June 30, 2012 and 2011

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	254,000	3.25	%
Base rate borrowings	—		—
Working capital facility —
LIBOR borrowings	65,000		3.25	%
Base rate borrowings	23,500		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 June 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 June 30, 2012, our interest coverage ratio was greater than 9 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 June 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 June 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 June 30, 2012, our interest coverage ratio was greater than 9 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 June 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 June 30, 2012 and March 31, 2012, and for the

Three Months Ended June 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.

Other Notes Payable

The other notes payable of approximately $10.3 million mature as follows (in thousands):

Year Ending March 31,
2013 (nine months)	$	2,739
2014	2,207
2015	1,665
2016	1,549
2017	1,424
2018	765
	$	10,349

Note 8 - Income Taxes

We qualify as a partnership for income taxes. As a result, we generally do not pay any 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 three months ended June 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 June 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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our consolidated liabilities may change materially as circumstances develop.

In 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 would later be alleged to have been sold illegally. The proceedings are in an early stage, and as a result, we cannot reliably predict the outcome of this litigation. We believe that we have good defenses and also believe that, in the event of an adverse outcome, our total exposure is not expected to 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. 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 in excess of $72 million and assert that our allocated share of that is in excess of $2.1 million. The parties are in the discovery phase of the cases and no trial date has been set.

In August 2009, a number of lawsuits were filed entitled “Samson Resource Company vs. Valero Marketing and Supply, et al.” (“Samson”) under which Samson claimed it was entitled to enforce lien rights on crude oil purchased by High Sierra. In December 2011, High Sierra and Samson settled this matter for a payment by High Sierra of $50,000. 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. The claims asserted in the IC-CO action are identical to those asserted in the Samson and Associated Producers actions. 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 the Associated Producers action, 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.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

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 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, real estate, equipment and bulk propane storage tanks. Rental expense relating to operating leases was as follows (in thousands):

	2012		2011
Three months ended June 30	$	4,760	$	681

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

Year Ending March 31,
2013 (nine months)	$	42,575
2014	50,658
2015	41,870
2016	37,099
2017	32,683

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

	Gallons	Value
	(in thousands)	(in $ thousands)
Natural gas liquids fixed-price purchase commitments	62,119	$	68,807
Natural gas liquids floating-price purchase commitments	438,425	354,171
Natural gas liquids fixed-price sale commitments	170,857	161,290
Natural gas liquids floating-price sale commitments	322,250	405,681

Crude oil fixed-price purchase commitments	223,509	405,675
Crude oil fixed-price sale commitments	190,294	366,537

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

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 June 30, 2012, the unamortized balances included $34.7 million recorded within other current assets and $22.4 million recorded within other current liabilities. As described in Note 3, we are still in the process of identifying the fair values of the assets and liabilities acquired in the combination with High Sierra. The estimates of fair value reflected as of June 30, 2012 are subject to change and such changes could be material.

Note 10 — Equity

Partnership Equity

The Partnership’s equity consists of 0.1% general partner equity and a 99.9% limited partner equity. 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 three months ended June 30, 2012. The following table summarizes the changes in common units outstanding during the quarter ended June 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 Downeast combination		750,000
Common units outstanding at June 30, 2012		44,749,763

As a result of provisions in agreements reached at the time of certain common unit issuances in connection with business combinations, 3,932,031 of the common units will not be eligible to receive the distribution declared in July 2012 and 20,703,510 of the common units will only be eligible to receive one-third of the distribution declared in July 2012.

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.

During July 2012, we issued 100,676 common units as partial consideration for the acquisition of a retail propane business.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

Distributions

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

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

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

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

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

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	%

During the three months ended June 30, 2012, we distributed a total of $9.2 million ($0.3625 per common and subordinated limited partner units and per general partner notional unit) to our unitholders of record as of April 30, 2012. On July 24, 2012, we declared a distribution of $0.4125 per common unit, to be paid on August 14, 2012 to unitholders of record on August 3, 2012. This distribution amounts to $13.7 million, including amounts paid on common, subordinated, and general partner notional units and the amount paid on incentive distribution rights.

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

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

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 $19.10 at June 30, 2012, which was calculated as the closing price of the common units on June 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 expense of $0.7 million related to these awards during the three months ended June 30, 2012. We estimate that the expense we will record on the awards granted as of June 30, 2012 will be as follows (in thousands), after taking into consideration an estimate of forfeitures:

Year ending March 31,
2013 (nine months)	$	6,252
2014	4,639
2015	2,094
2016	1,557
2017	383
Total	$	14,925

As of June 30, 2012, 4,305,910 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 June 30, 2012, as most of our debt is subject to terms that were recently negotiated.

The following table presents the estimated fair value measurements of our assets and liabilities carried at fair value in our condensed consolidated financial statements at the dates indicated:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

		June 30, 2012				March 31, 2012
Item	Recorded As	Level 1		Level 2		Level 1		Level 2
		(in thousands)
Assets:
Commodity derivatives	Other current assets	$	35	$	8,347	$	—	$	—
Product exchanges	Other current assets	—		41		—		131

Liabilities:
Product exchanges	Product exchanges	—		15,372		—		4,764
Interest rate derivative	Accrued expenses and other payables	—		120		—		157
Commodity derivatives	Accrued expenses and other payables	2,406		8,293		—		36

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 June 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.

The following table sets forth our open commodity derivative contract positions at June 30, 2012 and March 31, 2012. We do not account for these derivatives as hedges.

Underlying Contracts	Period	Total Notional Units (Barrels)	Fair Value
		(in thousands)
As of June 30, 2012 -
Propane swaps	July 2012 - December 2013	3,976	$	12,994
Heating oil calls and futures	August 2012 - June 2013	204	663
Crude swaps	July 2012 - June 2013	2,585	1,456
Crude - butane spreads	July 2012 - March 2014	581	(16,290		)
Crude forwards	July 2012 - December 2013	27,388	2,961
Butane forwards	September 2012 - December 2012	116	(571		)
Propane forwards	October 2012 - March 2013	71	117
			1,330
Less: Margin Deposits			(3,647		)
Net fair value of commodity derivatives on consolidated balance sheet			$	(2,317	)

As of March 31, 2012 -
Propane swaps	April 2012 - March 2013	3,702	$	(36	)

At June 30, 2012, the propane swaps include 134 instruments that have a combined unfavorable fair value of $21.9 million (liability) and 159 instruments that have a combined favorable fair value of $34.0 million (asset). We have reported these amounts on a net basis on the consolidated balance sheet, as all of these instruments are settled through the Intercontinental Exchange or the New York Mercantile Exchange.

At June 30, 2012, we have reported $16.7 million of derivative liabilities associated with the natural gas liquids operations of High Sierra net of derivative assets, as the master netting agreements with the counterparties give us the right to settle these amounts net. At June 30, 2012, we have reported $4.4 million of derivative assets associated with crude oil operations of High Sierra net of derivative liabilities, as the master netting agreements with the counterparties give us the right to settle these amounts net.

At March 31, 2012, the propane swaps include 77 instruments that have a combined unfavorable fair value of $6.5 million (liability) and 97 instruments that have a combined favorable fair value of $6.4 million (asset). We have reported these amounts on a net basis on the consolidated balance sheet, as all of these instruments are settled through the Intercontinental Exchange or the New York Mercantile Exchange.

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

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

	Three Months Ended June 30,
	2012			2011
	(in thousands)
Commodity contracts -
Unrealized gain (loss)	$	1,929		$	(2,246	)
Realized gain	2,299			2,217
Interest rate swaps	(1		)	(278		)
Total	$	4,227		$	(307	)

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. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty performance.

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 have historically included retail propane, wholesale marketing and supply, and midstream. On June 19, 2012, we completed a merger with High Sierra, the operations of which are reflected as a separate segment in the table below. We evaluate our operating segments’ performance based on operating income and EBITDA. Certain financial data related to our segments is shown below:

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

	Three Months Ended June 30,
	2012			2011
	(in thousands)
Revenues:
Retail propane -
Propane sales	$	39,852		$	10,194
Distillate sales	11,764			—
Sales of equipment, water softener, and other	3,790			1,440
Service and rental revenues	3,802			1,218
Wholesale supply and marketing -
Propane sales	104,126			146,299
Other natural gas liquids sales	72,557			38,537
Storage revenues	437			317
Midstream	3,718			497
High Sierra operations	100,426			—
Elimination of intersegment sales	(14,036		)	(7,656		)
Total revenues	$	326,436		$	190,846

Depreciation and Amortization:
Retail propane	$	6,741		$	1,067
Wholesale supply and marketing	785			98
Midstream	914			212
High Sierra operations	787			—
Total depreciation and amortization	$	9,227		$	1,377

Operating Income (Loss):
Retail propane	$	(6,171	)	$	(3,194	)
Wholesale supply and marketing	6,168			(1,693		)
Midstream	(1,026		)	28
High Sierra operations	(8,698		)	—
General and administrative expenses not allocated to segments	(5,347		)	(823		)
Total operating loss	$	(15,074	)	$	(5,682	)

Other items not allocated by segment:
Interest income	366			126
Interest expense	(3,800		)	(1,301		)
Loss on early extinguishment of debt	(5,769		)	—
Other income, net	26			85
Income tax expense	(459		)	—
Net loss	$	(24,710	)	$	(6,772	)

Geographic Information:
Revenues:
United States	$	319,808		$	190,803
Canada	6,628			43
Operating income (loss):
United States	(16,540		)	(5,613		)
Canada	1,466			(69		)

Additions to property, plant and equipment, including acquisitions (accrual basis):
Retail propane	$	54,711		$	716
Wholesale supply and marketing	185			194
Midstream	526			—
High Sierra operations	130,800			—
Total	$	186,222		$	910

	June 30,		March 31,
	2012		2012
	(in thousands)
Total assets:
Retail propane	$	494,395	$	417,257
Wholesale supply and marketing	256,648		225,396
Midstream	99,584		99,777
High Sierra operations	1,029,621		—
Corporate	19,962		6,707
Total	$	1,900,210	$	749,137

Long-lived assets, net:
Retail propane	$	438,825	$	365,860
Wholesale supply and marketing	82,159		82,959
Midstream	93,040		93,460
High Sierra operations	636,264		—
Corporate	17,648		5,468
Total	$	1,267,936	$	547,747

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NGL ENERGY PARTNERS LP

Notes to Unaudited Condensed Consolidated Financial Statements - Continued

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

Three Months Ended June 30, 2012 and 2011

Note 13 — Transactions with Affiliates

SemGroup Corporation (“SemGroup”) holds ownership interests in us and in our general partner, and has the right to appoint two members to the Board of Directors of our general partner. During the three months ended June 30, 2012, our wholesale marketing and supply segment sold $12.7 million of natural gas liquids to SemGroup and purchased $12.5 million of natural gas liquids from SemGroup. In addition, we paid $0.1 million to SemGroup during the three months ended June 30, 2012 for certain transition services related to our acquisition of the operations of SemStream.

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 with which we purchase and sell products and services. Subsequent to the merger with High Sierra, through June 30, 2012, we purchased products and services in the amount of $1.8 million and we sold product in the amount of $0.2 million to these entities.

Receivables from affiliates at June 30, 2012 consist of the following (in thousands):

Receivables from entities affiliated with High Sierra management	$	737
Receivables from SemGroup	1,291
Receivables from employees	1,725
Other	846
	$	4,599

Payables to affiliates at June 30, 2012 consist of the following (in thousands):

Payables to entities affiliated with High Sierra management	$	4,878
Estimated working capital settlement on Osterman acquisition	4,663
Payables to SemGroup	5,237
	$	14,778

As described in Note 1, we completed a merger with High Sierra Energy, LP and High Sierra Energy, GP 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.

At June 30, 2012, we had a receivable of approximately $1.7 million from certain employees for reimbursement of withholding taxes paid on behalf of the employees. The full balance of this receivable was collected during July 2012.

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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 ended June 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 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 $96 million, in exchange for the assets and operations of Osterman. The agreement also contemplates a working capital payment post-closing for certain specified working capital items, currently estimated as a liability of $4.0 million.

· During April and May 2012, we completed three separate business combination agreements to acquire retail propane and distillate operations in Georgia, Kansas, Maine, and New Hampshire. The largest of these was with Downeast Energy Corp (“Downeast”). On a combined basis, we paid cash of $56.1 million and issued 750,000 common units in exchange for these assets and operations, including working capital. In addition, a combined amount of approximately $8.9 million will be payable either as deferred payments on the purchase price or under 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”), 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, recycling, and transportation; and natural gas liquids transportation and marketing. High Sierra’s assets include water discharge, recycling, 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 June 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 24 states;

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· Our wholesale natural gas liquids supply and marketing business, which supplies propane and other natural gas liquids to retailers, wholesalers, and refiners throughout the United States and in Canada;

· Our midstream business, which provides natural gas liquids terminalling services through its 18 terminals throughout the United States and rail car transportation services through its fleet of 2,868 owned and leased rail cars;

· A crude oil transportation and marketing business, the assets of which include two crude oil terminals, 96 trucks, and 461 leased rail cars; and

Our businesses represent a combination of “margin-based,” “cost-plus” and “fee-based” revenue generating operations. Our retail propane business generates margin-based revenues, meaning our gross margin depends on the difference between our propane sales price and our total propane supply cost.

Our wholesale supply and marketing business generates cost-plus revenues. Cost-plus represents our aggregate total propane supply cost plus a margin to cover our replacement cost consisting of cost of capital, storage, transportation, fuel surcharges and an appropriate competitive margin. The margins we realize in our wholesale business are substantially less as a percentage of revenues or on a per gallon basis than our retail propane business. We attempt to reduce our exposure to the impact of price fluctuations by using “back-to-back” contractual agreements and “pre-sale” agreements which 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 propane swap agreements, whereby we agree to pay a floating rate and receive a fixed rate on a specified notional amount. We enter into these agreements as an economic hedge against the potential decline in the value of a portion of our propane inventory.

Our midstream business generates fee-based revenues derived from a cents-per-gallon charge for the transfer of product volumes, or throughput, at our natural gas liquids terminals. Our midstream business is impacted primarily by throughput volumes at our propane terminals. Throughput volumes are impacted by weather, agricultural uses of propane and general economic conditions, all of which are beyond our control. We are able to somewhat mitigate the potential decline in throughput volumes by preselling volumes to customers at our terminals in advance of the demand period through our wholesale supply and marketing segment. Our midstream business also leases rail cars for the transportation of natural gas liquids and crude oil, and charges a transportation fee for these services.

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.

Our water services business generates fee-based revenues from the transportation, treatment, and disposal of waste-water generated from oil and natural gas production operations, and generates revenues from the re-sale of recycled water and recovered hydrocarbons. Our revenues are dependent on continued production of oil and natural gas in the markets we serve.

Historically, the principal factors affecting each of our businesses have been propane demand and our cost of supply, as well as our ability to maintain or expand our realized margin from our margin-based and cost-plus operations.

Seasonality and Weather

Seasonality and weather have a significant impact on propane demand which impacts several of our segments, but the most significant impact 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 supply and marketing and midstream segments. Consequently, our sales, operating profits and positive operating cash flows are generated mostly 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.”

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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 of 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:

	Conway, Kansas
	Spot Price				Spot Price
	Per Gallon				Per Gallon
	Low		High		At Period End
For the Three Months Ended June 30:
2012	$	0.5038	$	0.9625	$	0.5413
2011	1.2763		1.4900		1.4163

	Mt. Belvieu, Texas
	Spot Price				Spot Price
	Per Gallon				Per Gallon
	Low		High		At Period End
For the Three Months Ended June 30:
2012	$	0.7063	$	1.2175	$	0.8238
2011	1.3800		1.6175		1.4838

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

The business combinations described above had a significant impact on the comparability of our results of operations for the three months ended June 30, 2012 and 2011.

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

Sales and throughput volumes in all of our segments increased during the three months ended June 30, 2012 as compared to the same period in 2011, due to our business combinations with Osterman, SemStream, Pacer, North American, and Downeast. We also completed a merger with High Sierra in June 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 of propane declined steadily during the three months ended June 30, 2012. This decline in the market price had an adverse effect on the revenues of our wholesale propane business. We use a weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory. During periods of declining prices, such as we experienced during the three months ended June 30, 2012, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

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.

Margins for our Wholesale segment during the three months ended June 30, 2012 benefitted from $13.0 million of unrealized gains on derivatives, which were recorded as a reduction to cost of sales.

Although the reduced demand for propane had an adverse effect on the volumes sold by our retail segment, the margin per gallon sold was higher for our retail segment during the three months ended June 30, 2012 than during the corresponding period in the prior year.

Our Midstream segment generated an operating loss of $1.0 million during the three months ended June 30, 2012, as reduced demand for propane had an adverse effect on throughput volumes.

We have included within our consolidated results of operations the activity of High Sierra from the June 19, 2012 merger

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date through June 30, 2012. The operations of High Sierra during this period generated an operating loss of $8.7 million, which included $10.1 million of unrealized losses on derivatives, which were recorded as an increase to cost of sales.

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

Consolidated Results of Operations

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

	Three Months Ended June 30,
	2012			2011
	(in thousands)
Revenues	$	326,436		$	190,846
Cost of sales	298,985			185,973
Operating and general and administrative expenses	33,298			9,178
Depreciation and amortization	9,227			1,377
Operating loss	(15,074		)	(5,682		)
Interest expense	(3,800		)	(1,301		)
Loss on early extinguishment of debt	(5,769		)	—
Interest and other income	392			211
Loss before income taxes	(24,251		)	(6,772		)
Income tax provision	(459		)	—
Net loss	(24,710		)	(6,772		)
Net (income) loss allocated to general partner	(95		)	7
Net loss attributable to noncontrolling interests	60			—
Net loss attributable to parent equity allocated to limited partners	$	(24,745	)	$	(6,765	)

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

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

Interest Expense

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

					Average Debt				Average Debt
	Letter of		Amortization		Balance		Average		Balance
	Credit		of Debt Issuance		Outstanding -		Interest Rate -		Outstanding -		Interest Rate -
	Fees		Costs		Revolving Facilities		Revolving Facilities		Senior Notes		Senior Notes
Three Months Ended June 30,
2012	$	106	$	501	$	274,114	3.81	%	$	32,967	6.65	%
2011	108		352		36,824		4.97	%	—		—

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.

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The increased levels of debt outstanding during the three months ended June 30, 2012 are due to borrowings to finance acquisitions and to finance working capital for our wholesale operations.

Interest and Other Income

Our non-operating income consists of the following:

	Three Months Ended June 30,
	2012		2011
	(in thousands)
Interest income	$	366	$	126
Other	26		85
	$	392	$	211

Income Tax Provision

We qualify as a partnership for income taxes. As such, we generally do not pay any 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.

Noncontrolling Interests

In March 2012, we formed Atlantic Propane LLC, or 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, or Sertco. The noncontrolling interest shown in our consolidated statement of operations for the three months ended June 30, 2012 represents the other owners’ interests in the income of Atlantic Propane and Sertco.

Non-GAAP Financial Measures

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

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	Three Months Ended June 30,
	2012			2011
	(in thousands)
EBITDA:
Net loss attributable to parent equity	$	(24,650	)	$	(6,772	)
Provision for income taxes	459			—
Interest expense	3,800			1,301
Loss on early extinguishment of debt	5,769			—
Depreciation and amortization	9,414			1,577
EBITDA	$	(5,208	)	$	(3,894	)
Unrealized (gain) loss on derivative contracts	(1,929		)	2,246
Loss on sale of assets	7			—
Share-based compensation expense	655			—
Adjusted EBITDA	$	(6,475	)	$	(1,648	)

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 June 30, 2012 and 2011

Items Impacting the Comparability of Our Financial Results

Our results of operations for the three months ended June 30, 2012 may not be comparable to our results of operations for the three months ended June 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, as well as the increase in terminal throughput volumes during the heating season. In addition, propane price fluctuations can have a significant impact on our sales volumes. For these and other reasons, our results of operations for the three months ended June 30, 2012 are not necessarily indicative of the results to be expected for the full fiscal year.

Volumes Sold or Throughput

The following table summarizes the volume of gallons sold by our retail propane and wholesale supply and marketing segments and the throughput volume for our midstream segment for the three months ended June 30, 2012, and 2011, respectively. Gallons sold by our wholesale supply and marketing segment shown in the table below include sales to our retail segment.

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			Change Resulting From
	Three Months Ended June 30,		Retail	SemStream		Other
Segment	2012	2011	Combinations	Combination		Volume		Percentage
	(gallons in thousands)
Retail propane
Propane	19,270	5,003	14,074	—		193		3.9	%
Distillates	3,249	—	3,249	—		—		—

Wholesale supply and marketing
Propane	116,618	102,698	—		(*)	13,920		13.6	%
Other NGLs	48,146	18,446	—		(*)	29,700		161.0	%

Midstream	36,300	21,004	—	17,167		(1,871	)	(8.9	)%

(*) 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 combinations and which were attributable to our historical wholesale business.

In addition to the volumes shown in the table above, subsequent to our June 19, 2012 merger with High Sierra, our crude oil logistics operations sold 982,000 barrels of crude oil through June 30, 2012. During this same time period, our water services business disposed of 739,000 barrels of water. Also during this time, High Sierra’s natural gas liquids operations sold 19.1 million gallons of natural gas liquids.

Our retail propane sales volumes for the three months ended June 30, 2012 increased approximately 14.3 million gallons over the 5.0 million gallons sold during the three months ended June 30, 2011. The principal factor driving the increase was our business combinations. The acquired businesses had approximately 14.1 million gallons of propane sales during the three months ended June 30, 2012.

Sales of our wholesale supply and marketing segment increased approximately 43.6 million gallons during the three months ended June 30, 2012 as compared to sales of 121.1 million gallons during the three months ended June 30, 2011. The principal reason for the increase in wholesale volumes is 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.

Terminal throughput of our midstream segment increased approximately 15.3 million gallons during the three months ended June 30, 2012 as compared to throughput of 21.0 million gallons during the three months ended June 30, 2011. This increase is due primarily to the addition of 12 terminals in the SemStream combination and one terminal in the North American combination. Excluding the activity of the terminals acquired in these combinations, throughput volumes were lower during the three months ended June 30, 2012 than in the corresponding period in the prior year, due to lower demand for natural gas liquids. The weather during the past winter was unusually mild, which reduced propane usage, and has resulted in a greater supply of propane in the market than would normally be available during this time of year.

Operating Income (Loss) by Segment

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

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	Three Months Ended June 30,
Segment	2012			2011			Change
	(in thousands)
Retail propane	$	(6,171	)	$	(3,194	)	$	(2,977	)
Wholesale supply and marketing	6,168			(1,693		)	7,861
Midstream	(1,026		)	28			(1,054		)
High Sierra operations	(8,698		)	—			(8,698		)
Corporate general and administrative expenses	(5,347		)	(823		)	(4,524		)
Operating loss	$	(15,074	)	$	(5,682	)	$	(9,392	)

Corporate general and administrative expense increased approximately $4.5 million during the three months ended June 30, 2012 as compared to the corporate general and administrative expenses of $0.8 million during the three months ended June 30, 2011. This increase is due primarily to $3.5 million of acquisition costs during the three months ended June 30, 2012 related to the merger with High Sierra. In addition, corporate general and administrative expenses for the three months ended June 30, 2012 include $0.7 million of compensation expense related to certain restricted units granted in June 2012 pursuant to employee and director compensation programs.

Retail Propane

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

							Change Resulting From
	Three Months Ended June 30,						Retail
	2012			2011			Combinations			Other
	(in thousands)
Revenues:
Propane sales	$	39,852		$	10,194		$	30,613		$	(955	)
Distillate sales	11,764			—			11,764			—
Equipment, water softener, and other sales	3,790			1,440			2,356			(6		)
Service and rental revenues	3,802			1,218			2,482			102
Total revenues	59,208			12,852			47,215			(859		)
Expenses:
Cost of sales - propane	23,193			6,980			18,035			(1,822		)
Cost of sales - distillates	11,621			—			11,621			—
Cost of sales - other	2,627			1,126			1,534			(33		)
Operating expenses	18,442			6,064			12,308			70
General and administrative expenses	2,755			809			2,133			(187		)
Depreciation and amortization expense	6,741			1,067			5,232			442
Total expenses	65,379			16,046			50,863			(1,530		)

Segment operating loss	$	(6,171	)	$	(3,194	)	$	(3,648	)	$	671

Revenues. Propane sales for the three months ended June 30, 2012 increased approximately $29.7 million as compared to propane sales of $10.2 million during the three months ended June 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 June 30, 2012 than during the three months ended June 30, 2011, due primarily to a decline in the average price per gallon sold of $0.26 during the three months ended June 30, 2012, as compared to an average price per gallon sold of $2.04 during the three months ended June 30, 2011. Also excluding the effect of these acquisitions, volumes sold during the three months ended June 30, 2012 were similar to volumes sold during the three months ended June 30, 2011.

Our acquired Osterman, Pacer, North American, and Downeast operations generated propane sales of $30.6 million during the three months ended June 30, 2012, consisting of approximately 14.1 million gallons sold at an average price of $2.18 per gallon. The average selling price per gallon for the acquired operations was higher than the average selling price for our historical operations,

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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 $11.8 million of revenue from the sales of distillates during the three months ended June 30, 2012, consisting of 3.2 million gallons sold at an average selling price of $3.62 per gallon.

Cost of Sales. Propane cost of sales for the three months ended June 30, 2012 increased approximately $16.2 million as compared to propane cost of sales of $7.0 million during the three months ended June 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 three months ended June 30, 2012 than during the three months ended June 30, 2011, due primarily to a decline in the average cost per gallon sold of $0.40 during the three months ended June 30, 2012, as compared to an average price per gallon sold of $1.40 during the three months ended June 30, 2011. Also excluding the effect of these acquisitions, volumes sold during the three months ended June 30, 2012 were similar to volumes sold during the three months ended June 30, 2011.

Our acquired Osterman, Pacer, North American, and Downeast operations generated propane cost of sales of $18.0 million during the three months ended June 30, 2012, consisting of approximately 14.1 million gallons sold at an average cost of $1.28 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 $11.6 million of cost of sales for distillates during the three months ended June 30, 2012, consisting of 3.2 million gallons sold at an average cost of $3.58 per gallon. Cost of distillate sales during the three months ended June 30, 2012 includes approximately $1.0 million of realized and unrealized losses on derivatives.

Operating Expenses. Operating expenses of our retail propane segment increased approximately $12.4 million during the three months ended June 30, 2012 as compared to operating expenses of $6.1 million during the three months ended June 30, 2011. This increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $12.3 million of operating expense during the three months ended June 30, 2012.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $1.9 million during the three months ended June 30, 2012 as compared to general and administrative expenses of $0.8 million during the three months ended June 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 $2.1 million of general and administrative expense during the three months ended June 30, 2012.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased approximately $5.7 million during the three months ended June 30, 2012 as compared to depreciation and amortization expense of $1.1 million during the three months ended June 30, 2011. The increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $5.2 million of depreciation and amortization expense during the three months ended June 30, 2012.

Operating Loss. Our retail propane segment had an operating loss of approximately $6.2 million during the three months ended June 30, 2012 compared to an operating loss of $3.2 million during the three months ended June 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 three months ended June 30, 2012 than during the three months ended June 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.

Wholesale Supply and Marketing

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

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	Three Months Ended June 30,
	2012		2011			Change
	(in thousands)
Revenues:
Propane sales	$	104,126	$	146,299		$	(42,173	)
Other natural gas liquids sales	72,557		38,537			34,020
Storage and other revenues	437		317			120
Total revenues	177,120		185,153			(8,033		)

Expenses:
Cost of sales - propane	91,959		145,645			(53,686		)
Cost of sales - other NGLs	70,994		38,532			32,462
Cost of sales - storage	4,668		1,248			3,420
Operating expenses	1,876		1,046			830
General and administrative expenses	670		277			393
Depreciation and amortization expense	785		98			687
Total expenses	170,952		186,846			(15,894		)

Segment operating income (loss)	$	6,168	$	(1,693	)	$	7,861

Revenues. Revenues from wholesale propane sales decreased approximately $42.2 million during the three months ended June 30, 2012, as compared to $146.3 million during the three months ended June 30, 2011. This resulted from a decrease in the average selling price of $0.53 per gallon, as compared to an average selling price per gallon of $1.42 in the prior year. This decrease in revenue was partially offset by an increase in volume sold of approximately 13.9 million gallons, as compared to 102.7 million gallons sold in the prior year.

Revenues from wholesale sales of other natural gas liquids increased approximately $34.0 million during the three months ended June 30, 2012, as compared to $38.5 million during the three months ended June 30, 2011. This resulted from an increase in volume sold of approximately 29.7 million gallons as compared to 18.4 million gallons in the prior year, partially offset by a decrease in the average selling price of $0.58 per gallon, as compared to $2.09 per gallon in the prior year.

In both cases, 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.

Cost of Sales. Costs of wholesale propane sales increased approximately $53.7 million during the three months ended June 30, 2012, as compared to $145.6 million during the three months ended June 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 $1.42 in the prior year. This decrease in cost was partially offset by an increase in volume sold of approximately 13.9 million gallons, as compared to 102.7 million gallons sold in the prior year. Cost of propane sales were reduced by $14.1 million during the three months ended June 30, 2012 due to $1.1 million of realized gains and $13.0 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 three months ended June 30, 2012 was $0.91 cents per gallon, which is lower than 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 often lower than the historical average cost, which had an adverse effect on margins.

Cost of wholesale sales of other natural gas liquids increased approximately $32.5 million during the three months ended June 30, 2012, as compared to $38.5 million during the three months ended June 30, 2011. This resulted from an increase in volume of approximately 29.7 million gallons as compared to 18.4 million gallons in the prior year, partially offset by a decrease in the average cost of $0.61 per gallon, as compared to $2.09 per gallon in the prior year.

Storage costs increased approximately $3.4 million during the three months ended June 30, 2012, as compared to storage costs of approximately $1.2 million during the three months ended June 30, 2011.

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The increase in volume of propane and other natural gas liquids 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 was due primarily to a greater than normal supply in the marketplace, which was due in part to low demand during the recent winter heating season as a result of mild weather.

Operating Expenses. Operating expenses of our wholesale supply and marketing segment increased approximately $0.8 million during the three months ended June 30, 2012 as compared to operating expenses of $1.0 million during the three months ended June 30, 2011. The increase in operating expenses is due primarily to increased compensation and related expenses resulting from our SemStream combination.

General and Administrative Expenses. General and administrative expenses of our wholesale supply and marketing segment increased approximately $0.4 million during the three months ended June 30, 2012 as compared to general and administrative expenses of $0.3 million during the three months ended June 30, 2011. This increase is due primarily to increased compensation and related expenses resulting from our SemStream combination.

Depreciation and amortization expense. Depreciation and amortization expense of our wholesale supply and marketing segment increased approximately $0.7 million during the three months ended June 30, 2012, as compared to depreciation and amortization expense of approximately $0.1 million during the three months ended June 30, 2011. This increase is due primarily to depreciation and amortization expense related to assets acquired in the SemStream combination.

Operating Income (Loss). Our wholesale supply and marketing segment had operating income of approximately $6.2 million during the three months ended June 30, 2012 as compared to an operating loss of $1.7 million during the three months ended June 30, 2011. The increased operating income is due primarily to increased product margins, partially offset by increased operating and general and administrative expenses. Product margins during the three months ended June 30, 2012 benefitted from approximately $14.1 million of realized and unrealized gains on derivatives.

Midstream

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

						Change Resulting From
	Three Months Ended June 30,					Business
	2012			2011		Combinations			Other
	(in thousands)
Revenues:
Rail car	$	2,515		$	—	$	739		$	1,776
Terminalling and other	1,203			497		745			(39		)
Total revenues	3,718			497		1,484			1,737

Expenses:
Cost of sales - rail car	2,270			—		999			1,271
Cost of sales - other	100			98		21			(19		)
Operating expenses	1,093			32		958			103
General and administrative expenses	367			127		158			82
Depreciation and amortization expense	914			212		682			20
Total expenses	4,744			469		2,818			1,457

Segment operating income (loss)	$	(1,026	)	$	28	$	(1,334	)	$	280

Revenues. Terminalling and other revenues of our midstream segment increased approximately $0.7 million during the three months ended June 30, 2012, as compared to $0.5 million during the three months ended June 30, 2011, partially as a result of the increased throughput volume resulting from the operations of the twelve terminals acquired in the SemStream combination and the terminal acquired in the North American combination. We also acquired certain owned and leased rail cars in the SemStream combination; our midstream segment operates these rail cars, to transport natural gas liquids primarily in the service of our wholesale

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supply and marketing segment. In addition, during the three months ended June 30, 2012, we began leasing rail cars to transport crude oil for third parties.

Cost of sales. Cost of sales for our midstream segment increased approximately $2.3 million during the three months ended June 30, 2012, as compared to $0.1 million during the three months ended June 30, 2011. This was due to the natural gas liquids and crude oil rail car operations.

Operating and general and administrative expenses. Expenses of our midstream segment increased approximately $1.3 million during the three months ended June 30, 2012, as compared to $0.2 million during the three months ended June 30, 2011, primarily as a result of the operations of the twelve terminals acquired in the SemStream combination and the terminal acquired in the North American combination.

High Sierra Operations

We completed a merger with High Sierra on June 19, 2012. The results of operations of the businesses of High Sierra for the period of time between the merger date and June 30, 2012 are summarized below (in thousands):

Revenues	$	100,426
Expenses:
Cost of sales	105,589
Operating expenses	1,927
General and administrative expenses	821
Depreciation and amortization expense	787
Total expenses	109,124
Operating loss	$	(8,698	)

Cost of sales for the High Sierra operations includes $10.1 million of unrealized losses on derivatives, partially offset by $1.2 million of realized gains on derivatives.

We entered into certain derivatives as an economic hedge against the risk of a decline in the value of crude oil inventory. Crude oil prices increased from June 19, 2012 to June 30, 2012, which resulted in unrealized losses on the derivatives.

We have certain commitments to sell butane at future dates at prices that are calculated as a percentage of a crude oil index price on the delivery date. We entered into certain derivatives as an economic hedge against the risk of a decline in the value of crude oil relative to the value of butane. During the period from June 19, 2012 to June 30, 2012, crude oil prices increased and butane prices decreased, which resulted in unrealized losses on the derivatives.

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, the periods 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.

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Revolving Credit Agreement

Credit Agreement

The Working Capital Facility has a capacity of $197.5 million for cash borrowings and letters of credit. At June 30, 2012, we had outstanding cash borrowings of $88.5 million and outstanding letters of credit of $60.5 million on the Working Capital Facility. The Expansion Capital Facility has a capacity of $447.5 million for cash borrowings. At June 30, 2012, we had outstanding cash borrowings of $254.0 million on the Expansion Capital Facility. In addition, upon satisfaction of certain conditions, we will have the right to increase the amount available under our revolving credit facilities from the aggregate amount of $645 million up to an aggregate amount of $700 million. 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 and/or cash collateralize outstanding letters of credit in order to reduce the outstanding Working Capital Facility loans and letters of credit 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 June 30, 2012, the interest rate in effect on outstanding LIBOR borrowings was 3.25%, calculated as the LIBOR rate of 0.25% plus a margin of 3.0%. At June 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 June 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 $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.

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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.

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

Previous Credit Facilities

Balances outstanding and rates

At June 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	$	254,000	3.25	%
Base rate borrowings	—		—
Working capital facility —
LIBOR borrowings	65,000		3.25	%
Base rate borrowings	23,500		5.25	%

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

	Daily Average		Lowest		Highest		Average
	Balance		Balance		Balance		Interest
	During Quarter		During Quarter		During Quarter		Rate
New credit facility (June 19 - June 30) —
Expansion loans	$	254,000	$	254,000	$	254,000	4.03	%
Working capital loans	81,292		70,000		88,500		4.04	%
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:

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	Three Months Ended
	June 30,			June 30,
Cash Flows Provided by (Used In):	2012			2011

Operating activities, before changes in operating assets and liabilities	$	(12,879	)	$	(4,774	)
Changes in operating assets and liabilities	(42,030		)	(17,569		)

Operating activities	$	(54,909	)	$	(22,343	)

Investing activities	(281,938		)	1,142

Financing activities	350,482			13,585

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.

In general, 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 less operating income as a result of lower volumes of propane sales and terminal throughput and when we are building our inventory levels for the upcoming heating season. Our operating cash flows are greatest during our third and fourth fiscal quarters, or the six months ending March 31, when our operating income levels are highest and customers pay for 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 three months ended June 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. During the three months ended June 30, 2012, we completed three business combinations to acquire retail propane and distillate operations, for which we paid $56.1 million and issued 750,000 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 in part 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 June 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 $17.1 million per quarter ($68.5 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.

On May 15, 2012, we paid a distribution of $0.3625 per unit to unitholders of record as of April 30, 2012. The total amount of this distribution was approximately $9.2 million.

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On July 24, 2012, we declared a distribution of $0.4125 per unit to unitholders of record as of August 3, 2012. This distribution amounted to approximately $13.7 million, including amounts paid on common, subordinated, and general partner notional units and amounts paid on incentive distribution rights.

During the three months ended June 30, 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 three months ended June 30, 2012 include additional borrowings of $462.2 million on long-term debt, to finance working capital needs and acquisitions. Cash outflows from financing activities for the three months ended June 30, 2012 include $333.7 million of payments on long-term debt.

Contractual Obligations

The following table updates our contractual obligations summary as of June 30, 2012 for our fiscal years ending thereafter (amounts in thousands):

			For the
			Nine Months
			Ending		For the Years Ending March 31,						After March 31,
	Total		2013		2014		2015		2016		2016
	(in thousands)
Debt principal payments –
Expansion capital borrowings	$	254,000	$	—	$	—	$	—	$	—	$	254,000
Working capital borrowings	88,500		50,000		—		—		—		38,500
Senior notes	250,000		—		—		—		—		250,000
Other long-term debt	10,349		2,739		2,207		1,665		1,549		2,189
Scheduled interest payments on revolving credit facility (1)	48,377		11,083		11,585		11,585		11,585		2,539
Scheduled interest payments on senior notes	128,844		12,469		16,625		16,625		16,625		66,500
Standby letters of credit	60,535		60,535		—		—		—		—
Future estimated payments under terminal operating agreements	2,057		278		370		376		382		651
Future minimum payments under storage leases, including expected renewals (2)	47,411		7,160		11,745		9,502		9,502		9,502
Future minimum lease payments under noncancelable operating leases, including expected renewals (2)	157,474		35,415		38,913		32,368		27,597		23,181
Fixed price commodity purchase commitments (3)	474,482		425,707		27,933		20,842		—		—
Index priced commodity purchase commitments (3) (4)	354,171		343,643		10,528		—		—		—
Capital commitment (5)	360		360		—		—		—		—
Total contractual obligations	$	1,876,560	$	949,389	$	119,906	$	92,963	$	67,240	$	647,062

Gallons under fixed-price purchase commitments (thousands)	285,628		258,670		15,475		11,483		—		—
Gallons under index-price purchase commitments (thousands)	438,425		428,115		10,310		—		—		—

(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 June 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 and/or cash collateralize letters of credit 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 June 30, 2012, we had fixed priced and index priced sales contracts for approximately 170.9 million and 322.3 million gallons of propane, respectively. At June 30, 2012, we had fixed-price sales contracts for approximately 190.3 million gallons of crude oil.

(4) Index prices are based on a forward price curve as of June 30, 2012. A theoretical change of $0.10 per gallon in the underlying commodity price at June 30, 2012 would result in a change of approximately $43.8 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 June 30, 2012, we had made capital contributions of $0.8 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.

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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 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 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.

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.

The net book value of our property, plant and equipment was $435.4 million at June 30, 2012. We recorded depreciation expense of $6.1 million and $1.2 million for the three months ended June 30, 2012 and 2011, respectively.

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 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

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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 propane inventory we hold 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 propane on a per gallon basis would be less than our average cost. However, the accounting guidelines do not require us to record a writedown of our inventory at an interim period if we believe that the market values will recover by our year end of March 31. Propane prices fluctuate year to year, and during the interim periods within a year. We are unable to control changes in the market value of propane 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 wholesale supply and marketing 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 June 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 June 30, 2012, we had $342.5 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 $0.4 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 June 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 June 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 propane and other natural gas liquids 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 June 30, 2012 were propane retailers, resellers, energy marketers, producers, refiners and dealers.

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

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

Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accounted for such derivative commodity instruments as hedges. In addition, we do not use such derivative commodity instruments for speculative or trading purposes. As of June 30, 2012, the net fair value of our unsettled commodity derivative instruments was a net liability of approximately $2.3 million. 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 a change of 10% in the value of the underlying commodity:

Propane (Wholesale segment)		$2.0 million

Heating oil (Retail segment)		0.5 million

Natural gas liquids (High Sierra operations)		28.4 million

Crude oil (High Sierra operations)		7.6 million

Fair Value

The net value of our open derivative commodity instruments and interest rate swap contracts at June 30, 2012 was a net liability of $2.4 million and $0.1 million, respectively. See Note 11 to our condensed consolidated financial statements as of June 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.

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 June 30, 2012. Based on this evaluation, our principal executive officer and principal financial officer have concluded that as of June 30, 2012, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

Other than changes that have 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 June 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

Set forth below are risk factors that are relevant to the operations of High Sierra, which we acquired on June 19, 2012. Except as set forth below, there have been no material changes from 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.

Our business depends on spending by the oil and natural gas industries in the United States and Canada, and this spending and our business have been, and may continue to be, adversely affected by industry and financial market conditions that are beyond our control including, without limitation, (1) prices for crude oil, condensate, NGLs, recycled water and services, (2) oil and natural gas producers, midstream companies, refiners, wholesalers, end users and other customers and potential customers (collectively, “customers”) having success in their operations, (3) continued commercially viable areas in which to explore and produce oil and natural gas, and (4) the availability of liquids-rich natural gas needed to produce NGLs.

Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business have been, and may continue to be, adversely affected by industry and financial market conditions and existing or new regulations, such as those related to environmental matters, that are beyond our control.

We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas in the United States and Canada and to sell to and purchase from us, or contract with us to transport, water, crude oil, condensate, NGLs and asphalt in the United States and Canada. Customers’ expectations of lower market prices for oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing business opportunities and demand for our services and equipment. Actual market conditions and customers’ expectations of market conditions for crude oil, condensate and NGLs may also cause our customers to curtail spending, thereby reducing business opportunities and demand for our services.

Industry conditions are influenced by numerous factors over which we have no control, such as the availability of commercially viable geographic areas in which to explore and produce oil and natural gas, the availability of liquids-rich natural gas needed to produce NGLs, the supply of and demand for oil and natural gas, environmental restrictions on the exploration and production of oil and natural gas, such as existing and proposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in oil and natural gas producing countries and merger and divestiture activity among our current or potential customers. The volatility of the oil and natural gas industry and the consequent impact on exploration and production activity could adversely impact the level of drilling activity by our customers. This reduction may cause a decline in business opportunities or the demand for our services, or adversely affect the price of our services. Reduced discovery rates of new oil and natural gas reserves in our market areas also may have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced and the number of producing wells for us to service declines.

The oilfield midstream and services industry tends to run in cycles and may, at any time, cycle into a downturn and, if that again occurs, the rate at which it slows or returns to former levels, if ever, will be uncertain. Prior adverse changes in the global economic environment and capital markets and declines in prices for oil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for oil and natural gas. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customers to make additional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending may curtail drilling programs and other discretionary spending, which could result in a reduction in business opportunities and demand for our services, the rates we can charge and our utilization. In addition, certain of our customers could become unable to pay their suppliers, including

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us. As a result of these conditions, customers’ spending patterns have become increasingly unpredictable, making it difficult for us to predict our future operating results. Any of these conditions or events could materially and adversely affect our operating results.

We depend on our producer customers for the crude oil, condensate, NGLs, waste-water and recycled water that we gather, treat, purchase, sell or transport, as applicable, and any failure to increase or reduction in these quantities could affect our profitability.

We depend on our producer customers for the crude oil, condensate, and NGLs that we gather, transport, and sell and for the produced waste-water we treat and recycle or dispose. If a significant number of these customers were to materially decrease their operations or supplies for any reason, we could experience difficulty in replacing those lost volumes.

Additionally, to maintain the volumes of waste-water, crude oil, condensate, and NGLs we require for our operations and capacity, and to increase such volumes to meet our expanding capacity, we must continue to contract for new supplies of such products to keep pace with our expanding capacity and to offset volumes lost because of natural declines in production from depleting wells or decreased activity or volumes lost to competitors. Furthermore, at our DJ Basin facilities, where we are in the process of installing our waste-water recycling technology, we will need to contract for new supplies of waste-water to ensure that our expanded facility operations are profitable. Generally, because producers experience inconveniences in switching midstream service providers or product purchasers, such as delays in receipt of proceeds while awaiting the preparation of new division orders or from changing equipment, producers typically do not change midstream service providers or product purchasers on the basis of minor variations in price for products and services. Thus, we may experience difficulty in obtaining the volumes of waste-water, crude oil, condensate, or NGLs in areas where relationships already exist between producers and other water disposers and recyclers, and gatherers and purchasers of crude oil, condensate, and NGLs.

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. 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.

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The fees charged to customers under our agreements with them for the transportation and marketing of crude oil, condensate, and NGLs may not escalate sufficiently to cover increases in costs and the agreements may be suspended in some circumstances, which would affect our profitability.

Our costs may increase at a rate greater than the rate that the fees that we charge to customers increase pursuant to our contracts with them. Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of crude oil, condensate, and/or NGLs are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities of our customers. If the escalation of fees is insufficient to cover increased costs or if any customer suspends or terminates its contracts with us, our profitability could be materially and adversely affected.

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Our sales of crude oil, condensate and NGLs and related transportation and hedging activities expose us to potential regulatory risks.

The Federal Trade Commission (“FTC”), the Federal Energy Regulatory Commission (“FERC”), and the Commodity Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of energy commodities, and any related transportation and/or hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Additionally, to the extent that we enter into transportation contracts with pipelines that are subject to FERC regulation or we become subject to FERC regulation ourselves (see Risk Factor entitled “Some of our transportation services could become subject to the jurisdiction of the FERC,” below), we will be obligated to comply with FERC’s regulations and policies. Any failure on our part to comply with the FERC’s regulations and policies at that time, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material and adverse effect on our business, results of operations and financial condition.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provides for new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on exchanges and cash collateral will have to be posted. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. Since the Dodd-Frank Act mandates the CFTC to promulgate rules to define these terms, we do not know the definitions the CFTC will actually adopt or how these definitions will apply to us. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalent. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict if and when the CFTC will finalize these regulations.

Depending on the rules and definitions ultimately adopted by the CFTC, we might in the future be required to post cash collateral for our commodities derivative transactions. Posting of cash collateral could cause liquidity issues for us by reducing our ability to use our cash for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flows. Although the CFTC has issued proposed rules under the Dodd-Frank Act, we are at risk unless and until the CFTC adopts rules and definitions that confirm that companies such as us are not required to post cash collateral for our derivative hedging contracts. In addition, even if we are not required to post cash collateral for our derivative contracts, the banks and other derivatives dealers who are our contractual counterparties will be required to comply with the Dodd-Frank Act’s new requirements, and the costs of their compliance will likely be passed on to customers, including us, thus decreasing the benefits to us of hedging transactions and reducing the profitability of our cash flows.

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We are subject to the trucking safety regulations, which are likely to be amended, and made stricter, as part of the initiative known as Comprehensive, Safety, Analysis, or “CSA.” If our current USDOT safety ratings are downgraded to “Unsatisfactory” or the equivalent in connection with this initiative, our business and results of our operations may be adversely affected.

As part of the CSA initiative, the Federal Motor Carrier Safety Administration (“FMCSA”) is expected to open a rulemaking docket later in 2011 for purposes of changing its safety rating methodology. Any new methodology adopted in the rulemaking is likely to link safety ratings more closely to roadside inspection and driver violation data gathered and analyzed from month to month under the agency’s new Safety Measurement System or “SMS.” This linkage could result in greater variability in safety ratings than the current system, in which a safety rating is based on relatively infrequent on-site compliance audits at a carrier’s place(s) of business. Preliminary studies by transportation consulting firms indicate that “Satisfactory” ratings (or any equivalent under a new SMS-based system) may become more difficult to achieve and maintain under such a system. If we ever receive an “Unsatisfactory” or equivalent rating, we may lose some of our customer contracts that require such a rating, which may materially and adversely affect our business prospects and results of operations.

Difficulty in attracting and retaining qualified drivers could adversely affect our growth and profitability.

Maintaining a staff of qualified truck drivers is critical to the success of our operations. We have in the past experienced difficulty in attracting and retaining sufficient numbers of qualified drivers. In addition, due in part to current economic conditions, including the cost of fuel, insurance, and tractors and the U.S. Department of Transportation’s (“DOT”) regulatory requirements, the available pool of qualified truck drivers has been declining. Regulatory requirements, including the new CSA initiative, and an improvement in the economy could reduce the number of eligible drivers or require us to pay more to attract and retain drivers. A shortage of qualified drivers and intense competition for drivers from other companies will create difficulties in increasing the number of our drivers for our anticipated expansion in our fleet of trucks. If we are unable to continue to attract and retain a sufficient number of qualified drivers, we could have difficulty meeting customer demands, any of which could materially and adversely affect our growth and profitability.

Volumes of crude oil recovered during the waste-water treatment process can vary. Any significant reduction in residual crude oil content in waste-water we treat will affect our recovery of crude oil and, hence, our profitability.

A significant portion of revenues in our water business is derived from sales of crude oil recovered during the waste-water treatment process. Our ability to recover sufficient volumes of crude oil is dependent upon the residual crude oil content in the waste-water we treat, which is, among other things, a function of water temperature. Generally, where water temperature is higher, residual crude oil content is lower. Thus, our crude oil recovery during the winter season is substantially higher than our recovery during the summer season. Additionally, residual crude oil content will decrease if, among other things, producers begin recovering higher levels of crude oil in produced waste-water prior to distributing such water to us for treatment. Any reduction in residual crude oil content in the waste-water we treat could materially and adversely affect our profitability.

Our business is subject to federal, state, provincial and local laws and regulations with respect to environmental, safety and other regulatory matters and the cost of compliance with, violation of or liabilities under, such laws and regulations could adversely affect our profitability.

Our operations, including those involving crude oil, condensate, NGLs, and oil and gas produced waste-water, are subject to stringent federal, state, provincial and local laws and regulations relating to the protection of natural resources and the environment, health and safety, waste management, and transportation and disposal of such products and materials. We face inherent risks of incurring significant environmental costs and liabilities in the performance of our operations due to handling of waste-water and hydrocarbons, such as crude oil, condensate and NGLs. For instance, our waste-water treatment and transportation business carries with it environmental risks, including leakage from the treatment plants to surface or subsurface soils, surface water or groundwater, or accidental spills or releases during the transport of waste-water. Our crude oil, condensate, and NGL businesses carry similar risks of leakage and sudden or accidental spills of crude oil, condensate, NGLs, and hydrocarbons. Liability under, or violation of, environmental laws and regulations could result in, among other things, the impairment or cancellation of operations, injunctions,

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fines and penalties, reputational damage, expenditures for remediation and liability for natural resource damages, property damage and personal injuries.

In addition, under certain environmental laws, we could be subject to strict and/or joint and several liability for the investigation, removal or remediation of previously released materials. As a result, these laws could cause us to become liable for the conduct of others, such as prior owners or operators of our facilities, or for consequences of our or our predecessor’s actions, regardless of whether we were responsible for the release or if such actions were in compliance with all applicable laws at the time of those actions. Also, upon closure of certain facilities, such as at the end of their useful life, we have been and may be required to undertake environmental evaluations or cleanups.

Additionally, in order to conduct our operations, we must obtain and maintain numerous permits, approvals and other authorizations from various federal, state, provincial and local governmental authorities relating to waste-water handling, discharge and disposal, air emissions and other environmental matters. These authorizations subject us to terms and conditions which may be onerous or costly to comply with, and that may require costly operational modifications to attain and maintain compliance. The renewal, amendment or modification of these permits, approvals and other authorizations may involve the imposition of even more stringent and burdensome terms and conditions with attendant higher costs and more significant effects upon our operations.

Changes in environmental laws and regulations occur frequently. New laws or regulations, changes to existing laws or regulations, such as more stringent pollution control requirements or additional safety requirements, or more stringent interpretation or enforcement of existing laws and regulations, may unfavorably impact us, and could result in increased operating costs and have a material and adverse effect on our activities and profitability. For example, new or proposed laws or regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our costs for treatment of frac flow-back water (or affect our hydraulic fracturing customers’ ability to operate) and cause delays, interruption or termination of our water treatment operations, all of which could have a material and adverse affect on our operations and financial performance.

Furthermore, our customers in the oil and gas production industry are subject to certain environmental laws and regulations that may impose significant costs and liabilities on them, including as a result of changes in such laws and regulations causing them to become more stringent over time. For example, in July 2011, the U.S. Environmental Protection Agency (“EPA”) proposed standards for oil and gas drilling operations to reduce emissions of volatile organic compounds (“VOCs”) (which contribute to smog) and methane (a greenhouse gas that is the primary constituent of natural gas). This proposal would require a 95% reduction in VOCs emitted during the completion of new and modified hydraulically fractured wells. Any significant increased costs or restrictions placed on our customers to comply with environmental laws and regulations could affect their production output significantly. Such an effect could materially and adversely affect our utilization and profitability.

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which they are accustomed, thus reducing demand for our midstream services. Such an effect on our customers could materially and adversely affect our utilization and profitability. The adoption or implementation of any new regulations imposing additional reporting obligations on GHG emissions, or limiting GHG emissions from our equipment and operations, could require us to incur significant costs.

Federal and state legislation and regulatory initiatives relating to our hydraulic fracturing customers could result in increased costs and additional operating restrictions or delays and could harm our business.

Hydraulic fracturing is a frequent practice in the oil and gas fields in which the Water Segment operates. Hydraulic fracturing is an important and common process used to facilitate production of natural gas and other hydrocarbon condensates in shale formations, as well as tight conventional formations. The hydraulic fracturing process is typically regulated by state oil and gas authorities. This process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the fracturing process could adversely affect drinking water supplies. New laws or regulations, or changes to existing laws or regulations in response to this perceived threat may unfavorably impact the oil and gas drilling industry. For instance, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing practices involving the use of diesel fuel. At the same time, the EPA has commenced a study of the potential environmental impact of hydraulic fracturing activities, with initial results of the study anticipated to be available by late 2012 and final results by 2014. Also, for the second consecutive session, legislation has been introduced, but not adopted, in Congress to provide for federal regulation of hydraulic fracturing. In addition, some states have adopted and other states are considering adopting regulations that could restrict or regulate hydraulic fracturing in certain circumstances. For example, Texas, Wyoming and other states have adopted legislation requiring the disclosure of hydraulic fracturing chemicals, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. We cannot predict whether any proposed federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. However, any restrictions on hydraulic fracturing could lead to operational delays or increased operating costs and regulatory burdens that could make it more difficult or costly to perform hydraulic fracturing which would negatively impact our customer base resulting in an adverse effect on our profitability.

Seasonal weather conditions and natural or man-made disasters could severely disrupt normal operations and harm our business.

Among other locations, we operate in Colorado, Wyoming, Kansas, Texas, Oklahoma and Canada. These areas are adversely affected by seasonal weather conditions. In addition, the predicated effects of climate change could also increase the severity and frequency of extreme weather patterns. During periods of heavy snow, ice, rain or extreme weather conditions such as high winds, tornados and hurricanes or after other natural disasters such as earthquakes, we may be unable to move our trucks between locations and our facilities may be damaged, thereby reducing our ability to provide services and generate revenues. These same conditions may cause the field operations of our customers to be shut down.

Some of our operations cross the United States/Canada border and are subject to cross-border regulation.

Our cross border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Such regulations include the “Short Supply Controls” of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties.

Some of our transportation services could become subject to the jurisdiction of the FERC.

Any of our transportation services could in the future become subject to the jurisdiction of FERC, which could adversely affect the terms of service, rates and revenues of such transportation services. Currently, FERC regulates oil and natural gas pipelines, among other things. As of the date of this offering memorandum, our facilities do not fall under FERC’s jurisdiction. However, if FERC’s regulatory reach was expanded to our water pipelines or other facilities, or if we expand our operations into areas that are subject to FERC’s regulation, we may have to commit substantial capital to comply with such regulations and such expenditures could have a material and adverse effect on our results of operations and cash flows.

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We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, and we are subject to the possibility of increased costs to retain necessary land and equipment use which could disrupt our operations.

We do not own all of the land on which our pipelines and facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if our facilities are not properly located within the boundaries of such rights-of-way. Additionally, our loss of rights, through our inability to renew right-of-way contracts or otherwise, could materially and adversely affect on our business, results of operations and financial condition.

Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods. Our inability to renew facility or equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material and adverse effect on our results of operations and cash flow.

We also must operate within the terms and conditions of permits and various rules and regulations from the U.S. Bureau of Land Management for the rights of way on which our pipelines are constructed and the Wyoming State Engineer’s Office for water well, disposal well and containment pits.

Our risk policy cannot eliminate all commodity risk, basis risk, or risk of adverse market conditions which can adversely affect our financial condition and results of operations. In addition, any non-compliance with our risk policy could result in significant financial losses.

Pursuant to the requirements of our risk management policy, we attempt to lock in a margin for a portion of the commodities we purchase by selling such commodities for physical delivery to our customers, such as independent refiners or major oil companies, or by entering into future delivery obligations under contracts for forward sale. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other hand. These policies and practices cannot, however, eliminate all risks. For example, any event that disrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to cover obligations required under contracts for forward sale. Additionally, we can provide no assurance, however, that our monitoring processes and procedures will detect and/or prevent all violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In these instances, physical inventory generally loses value as price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our financial condition and results of operations.

Growing our business by constructing new transportation systems and facilities subjects us to construction risks and risks that supplies for such systems and facilities will not be available upon completion thereof.

One of the ways we intend to grow our business is through the construction of additions to our systems and/or the construction of new gathering, transportation, and waste-water treatment facilities. The construction of such facilities requires the expenditure of significant amounts of capital, which may exceed our resources, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase upon the expenditure of funds on a particular project. For instance, if we build a new waste-water treatment facility, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until at least after completion of the project, if at all. Moreover, we may construct facilities to capture

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anticipated future growth in production in a region in which anticipated production growth does not materialize or for which we are unable to acquire new customers. We may also rely on estimates of proved, probable or possible reserves in our decision to build new transportation systems and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved, probable or possible reserves. As a result, new facilities may not be able to attract enough product to achieve our expected investment return, which could materially and adversely affect our results of operations and financial condition.

We may incur product liability losses and other litigation liability.

In the ordinary course of business, we are subject to product liability claims and lawsuits, including potential class actions, alleging that our assets or the products we transfer or wellhead compressors we lease have resulted or could result in an unsafe condition or injury. Any product liability claim brought against us, with or without merit, could be costly to defend and could result in an increase of our insurance premiums. Some claims brought against us might not be covered by our insurance policies. In addition, we have significant self-insured retention amounts which we would have to pay in full before obtaining any insurance proceeds to satisfy a judgment or settlement and we may have insufficient reserves on our balance sheet to satisfy such self-retention obligations. Furthermore, even where the claim is covered by our insurance, our insurance coverage might be inadequate and we would have to pay the amount of any settlement or judgment that is in excess of our policy limits. We may not be able to obtain insurance on terms acceptable to us or at all since insurance varies in cost and can be difficult to obtain. Our failure to maintain adequate insurance coverage or successfully defend against product liability claims could materially and adversely effect on our business, results of operations, financial condition and cash flows.

We have only a limited ability to protect our intellectual property rights relating to our water business, which are important to our success in such business. Our failure to protect our intellectual property rights could adversely affect our competitive position.

Our success depends, in part, upon our ability to protect our proprietary information and other intellectual property we have developed. We primarily rely upon patent, trademark, and trade secret laws, and non-disclosure, confidentiality and other types of agreements with our employees, customers, suppliers and other parties, to establish, maintain and enforce our intellectual property rights. Despite these measures, our intellectual property rights may be difficult to protect and any of our intellectual property rights could be challenged, invalidated, circumvented, infringed or misappropriated, or such intellectual property rights may not be sufficient to permit us to take advantage of current market trends or otherwise to provide competitive advantages, which could result in costly redesign efforts, discontinuance of certain services or other competitive harm. Further, the laws of certain countries do not protect proprietary rights to the same extent as the laws of the United States. Therefore, in certain jurisdictions, we may be unable to protect our proprietary technology adequately against unauthorized third-party copying, infringement or use, which could adversely affect our competitive position. In addition, although our employees, customers, suppliers and other parties are generally subject to confidentiality and non-disclosure agreements, these agreements may be inadequate to deter or prevent unauthorized disclosure or misappropriation of our intellectual property and we may not have adequate remedies for any breach of these agreements. In addition, we may be unable to detect unauthorized use of our intellectual property or otherwise take appropriate steps to enforce our intellectual property rights. Our trade secrets may be disclosed to or otherwise become known or be independently developed by our competitors. To the extent that our employees, consultants or contractors use intellectual property owned by others in their work for us, disputes may arise as to the rights in related or resulting know-how and inventions.

In order to protect or enforce and protect our intellectual property rights, we may initiate litigation against third parties, such as patent infringement suits or interference proceedings. Any lawsuits that we initiate could be expensive, take significant time and divert management’s attention from other business concerns. Litigation also puts our patents at risk of being invalidated or interpreted narrowly and our patent applications at risk of not issuing. Additionally, we may provoke third parties to assert claims against us. We may not prevail in any lawsuits that we initiate and the damages or other remedies awarded, if any, may not be commercially valuable. Failure to obtain or maintain intellectual property protection, adequately enforce our intellectual property against third parties, or prevent the disclosure or misappropriation of our trade secrets, would adversely affect our competitive business position.

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Third parties may assert that we violate their intellectual property rights, resulting in costly litigation.

Third parties may allege that we, our customers, licensees or other parties indemnified by us infringe upon their intellectual property rights. Even if we believe that such claims are without merit, defending such intellectual property litigation can be costly, distract management’s attention and resources, and the outcome of intellectual property related litigation is typically uncertain. Claims of intellectual property infringement also might require us to redesign affected services, enter into costly settlement or license agreements, pay costly damage awards, or face a temporary or permanent injunction prohibiting us from marketing or selling certain of our services. Any of these results may adversely affect our financial condition.

High Sierra has in the past identified material weaknesses in its internal control over financial reporting, and the identification of any material weaknesses in the future could affect our ability to ensure timely and accurate financial statements.

At the end of several periods during the last five years, High Sierra’s management identified material weaknesses in its internal control over financial reporting. The Public Company Accounting Oversight Board has defined a material weakness as a control deficiency, or combination of control deficiencies, that results in a reasonable possibility that a material misstatement of the annual or interim statements will not be prevented or detected on a timely basis. Accordingly, a material weakness increases the risk that reported financial information contains material errors. High Sierra has implemented procedures and controls to address these issues.

Although action has been taken to remediate the past material weaknesses in internal controls, these measures may not be sufficient to ensure that our internal controls are effective in the future. Any future material weaknesses, or any failure to effectively address a material weakness or other control deficiency or implement required new or improved controls, or difficulties encountered in their implementation, could limit our ability to obtain financing, harm our reputation or disrupt our ability to process key components of our results of operations and financial condition timely and accurately.

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

See our current reports on Form 8-K filed with the SEC on May 4, 2012 and June 25, 2012.

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
2.1		Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Partners LP, NGL Energy Holdings LLC, HSELP LLC, High Sierra Energy, LP and the High Sierra Energy GP, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012).
2.2		Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Holdings LLC, HSEGP LLC and High Sierra Energy GP, LLC (incorporated by reference to Exhibit 2.2 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012).
4.1		Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGL Energy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 4, 2012).
4.2		Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012).
4.3		Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and between NGL Energy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012).
10.1		Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders party thereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012).
10.2*+		Form of Restricted Unit Award Agreement
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
32.2*		Certification of 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 June 30, 2012 and March 31, 2012, (ii) Condensed Consolidated Statement of Operations for the three months ended June 30, 2012 and 2011, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months ended June 30, 2012 and 2011, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the three months ended June 30, 2012, (v) Condensed Consolidated Statement of Cash Flows for the three months ended June 30, 2012 and 2011, and (vi) Notes to Condensed Consolidated Financial Statements.
	+		Management contracts or compensatory plans or arrangements.

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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: August 14, 2012		By:	/s/ H. Michael Krimbill
			H. Michael Krimbill
			Chief Executive Officer


Date: August 14, 2012		By:	/s/ Craig S. Jones
			Craig S. Jones
			Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number		Exhibit
2.1		Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Partners LP, NGL Energy Holdings LLC, HSELP LLC, High Sierra Energy, LP and the High Sierra Energy GP, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012).
2.2		Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Holdings LLC, HSEGP LLC and High Sierra Energy GP, LLC (incorporated by reference to Exhibit 2.2 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012).
4.1		Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGL Energy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 4, 2012).
4.2		Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012).
4.3		Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and between NGL Energy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012).
10.1		Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders party thereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012).
10.2*+		Form of Restricted Unit Award Agreement
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
32.2*		Certification of 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 June 30, 2012 and March 31, 2012, (ii) Condensed Consolidated Statement of Operations for the three months ended June 30, 2012 and 2011, (iii) Condensed Consolidated Statements of Comprehensive Loss for the three months ended June 30, 2012 and 2011, (iv) Condensed Consolidated Statement of Changes in Partners’ Equity for the three months ended June 30, 2012, (v) Condensed Consolidated Statement of Cash Flows for the three months ended June 30, 2012 and 2011, and (vi) Notes to Condensed Consolidated Financial Statements.
	+		Management contracts or compensatory plans or arrangements.