Rose Rock Midstream 10-Q 2012 Q2 Quarterly report

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

OR

¨ 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: 1-35365

ROSE ROCK MIDSTREAM, L.P.

(Exact name of registrant as specified in its charter)

Delaware	45-2934823
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification Number)

Two Warren Place

6120 S. Yale Avenue, Suite 700

Tulsa, OK 74136-4216

(Address of principal executive offices and zip code)

(918) 524-7700

(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  ¨

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 (§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  ¨

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. (Check one):

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x	Smaller reporting company	¨

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

At August 1, 2012, there were 8,389,709 common units and 8,389,709 subordinated units outstanding.

Rose Rock Midstream, L.P.

TABLE OF CONTENTS

	PART I – FINANCIAL INFORMATION
Item 1	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets – June 30, 2012 and December 31, 2011	4
	Condensed Consolidated Statements of Income – Three Months and Six Months Ended June 30, 2012 and 2011	5
	Condensed Consolidated Statements of Cash Flows – Six 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	18
Item 3	Quantitative and Qualitative Disclosures about Market Risk	31
Item 4	Controls and Procedures	33
	PART II – OTHER INFORMATION
Item 1	Legal Proceedings	34
Item 1A	Risk Factors	34
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3	Defaults Upon Senior Securities	34
Item 4	Mine Safety Disclosures	34
Item 5	Other Information	34
Item 6	Exhibits	34
	SIGNATURE	35

Cautionary Note Regarding Forward-Looking Statements

Certain matters contained in this Form 10-Q include “forward-looking statements.” All statements, other than statements of historical fact, included in this Form 10-Q regarding the prospects of our industry, our anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters, may constitute forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking words such as “may,” “expect,” “intend,” “estimate,” “foresee,” “project,” “anticipate,” “believe,” “plans,” “forecasts,” “continue” or “could” or the negative of these terms or variations of them or similar terms. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that these expectations will prove to be correct. These forward-looking statements are subject to certain known and unknown risks, and uncertainties, as well as assumptions that could cause actual results to differ materially from those reflected in these forward-looking statements. Factors that might cause actual results to differ include, but are not limited to, those discussed in Part II, Item 1A of our most recent Annual Report on Form 10-K, entitled “Risk Factors,” risk factors discussed in other reports that we file with the Securities and Exchange Commission (the “SEC”), and the following:

• Our ability to generate sufficient cash flow from operations to enable us to pay the minimum quarterly distribution to holders of our common units, general partner units and subordinated units;

• Our profitability depends on the demand for crude oil in the markets we serve;

• Our ability to obtain new sources of crude oil;

• Restrictions in our revolving credit facility could adversely affect our business, results of operations, financial condition and ability to make cash distributions to our unitholders;

• Our future debt may limit our flexibility to obtain financing and pursue business opportunities;

• The credit profile of SemGroup Corporation could adversely affect our credit rating which could increase our borrowing costs;

• Our ability to renew or replace expiring storage contracts;

• The loss or nonpayment by one of our key customers could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders;

• Our ability to minimize risk exposure associated with the marketing of crude oil; and

• Our preparedness towards the many hazards and operational risks associated with our business, many of which may not be covered by insurance.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement.

Readers are cautioned not to place undue reliance on any forward-looking statements contained in this Form 10-Q, which reflect management’s opinions only as of the date hereof. Except as required by law, we undertake no obligation to revise or publicly release the results of any revision to any forward-looking statements.

As used in this Form 10-Q, and unless the context indicates otherwise, the terms (i) the “Partnership,” “Rose Rock,” “we,” “our,” “us” or like terms, refer to Rose Rock Midstream, L.P., its subsidiaries and its predecessor; (ii) “SemGroup” refers to SemGroup Corporation (NYSE: SEMG), SemGroup, L.P. (SemGroup Corporation’s predecessor), and their subsidiaries and affiliates, other than our general partner and us; (iii) “Rose Rock GP” or our “general partner” refers to Rose Rock Midstream GP, LLC; and (iv) “unitholders” refer to our common and subordinated unitholders, and not our general partner.

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

ROSE ROCK MIDSTREAM, L.P.

Condensed Consolidated Balance Sheets

(Dollars in thousands)

	(unaudited) June 30, 2012		December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	12,955	$	9,709
Accounts receivable (net of allowance of $184 at June 30, 2012 and December 31, 2011)		153,501		131,655
Receivable from affiliates		1,453		2,210
Inventories		12,022		21,803
Other current assets		1,025		1,205
Total current assets		180,956		166,582
Property, plant and equipment (net of accumulated depreciation of $28,479 at June 30, 2012 and $22,611 at December 31, 2011)		279,150		276,246
Other assets, net		2,567		2,666
Total assets	$	462,673	$	445,494
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	141,129	$	125,681
Payable to affiliates		3,712		7,991
Accrued liabilities		4,717		4,708
Other current liabilities		2,687		2,173
Total current liabilities		152,245		140,553
Long-term debt		75		87
Commitments and contingencies (Note 4)
Partners’ Capital:
Common units – public (7,000,000 units issued and outstanding at June 30, 2012 and December 31, 2011)		129,862		127,531
Common units – SemGroup (1,389,709 units issued and outstanding at June 30, 2012 and December 31, 2011)		38,173		37,739
Subordinated units – SemGroup (8,389,709 units issued and outstanding at June 30, 2012 and December 31, 2011)		136,114		133,487
General partner		6,204		6,097
Total Partners’ Capital		310,353		304,854
Total liabilities and partners’ capital	$	462,673	$	445,494

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

Page 4

ROSE ROCK MIDSTREAM, L.P.

Unaudited Condensed Consolidated Statements of Income

(In thousands, except per unit amounts)

	Three Months Ended June  30, 2012			Three Months Ended June  30, 2011			Six Months Ended June 30, 2012			Six Months Ended June 30, 2011
Revenues, including revenues from affiliates (Note 7):
Product	$	146,070		$	102,137		$	315,456		$	176,394
Service		11,402			8,512			21,736			17,935
Other		(54	)		65			(59	)		176
Total revenues		157,418			110,714			337,133			194,505
Expenses, including expenses from affiliates (Note 7):
Costs of products sold, exclusive of depreciation and amortization shown below		140,549			96,144			301,057			162,144
Operating		6,221			4,501			11,448			9,165
General and administrative		2,046			2,110			4,749			4,467
Depreciation and amortization		2,999			2,700			5,966			5,383
Total expenses		151,815			105,455			323,220			181,159
Operating income		5,603			5,259			13,913			13,346
Other expenses:
Interest expense		477			488			957			971
Other expense (income)		—			(202	)		72			(202	)
Total other expenses		477			286			1,029			769
Net income	$	5,126		$	4,973		$	12,884		$	12,577
General partner’s interest in net income	$	103					$	258
Common unitholders’ interest in net income	$	2,511.5					$	6,313.0
Subordinated unitholders’ interest in net income	$	2,511.5					$	6,313.0
Earnings per limited partner unit (Note 6):
Common unit (basic and diluted)	$	0.30					$	0.75
Subordinated unit (basic and diluted)	$	0.30					$	0.75
Basic weighted average number of limited partner units outstanding:
Common Units		8,390						8,390
Subordinated Units		8,390						8,390
Diluted weighted average number of limited partner units outstanding:
Common Units		8,402						8,398
Subordinated Units		8,390						8,390

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

Page 5

ROSE ROCK MIDSTREAM, L.P.

Unaudited Condensed Consolidated Statements of Cash Flows

(Dollars in thousands)

	Six Months Ended June 30, 2012			Six Months Ended June 30, 2011
Cash flows from operating activities:
Net income	$	12,884		$	12,577
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		5,966			5,383
Loss on disposal of long-lived assets, net		56			12
Amortization of debt issuance costs		171			—
Recovery of uncollectible accounts receivable		—			(600	)
Non-cash equity compensation		139			—
Net unrealized (gain) loss related to derivative instruments		122			(1,524	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(21,846	)		(34,830	)
Decrease (increase) in receivable from affiliates		757			(141	)
Decrease (increase) in inventories		9,602			7,270
Decrease (increase) in margin deposits		693			2,193
Decrease (increase) in other current assets		(635	)		(277	)
Decrease (increase) in other assets		(20	)		—
Increase (decrease) in accounts payable and accrued liabilities		16,467			36,658
Increase (decrease) in payable to affiliates		(4,277	)		3
Net cash provided by operating activities		20,079			26,724
Cash flows from investing activities:
Capital expenditures		(9,391	)		(15,879	)
Proceeds from sale of long-lived assets		145			3
Net cash used in investing activities		(9,246	)		(15,876	)
Cash flows from financing activities:
Change in book overdrafts		—			549
Debt issuance costs		(52	)		—
Borrowings on debt and other obligations		73,500			—
Principal payments on debt and other obligations		(73,500	)		—
Principal payments on capital lease obligations		(11	)		—
Net distributions to Partners		(7,524	)		(11,700	)
Net cash used in financing activities		(7,587	)		(11,151	)
Net increase (decrease) in cash and cash equivalents		3,246			(303	)
Cash and cash equivalents at beginning of period		9,709			303
Cash and cash equivalents at end of period	$	12,955		$	—

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

Page 6

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

1. OVERVIEW

Rose Rock Midstream, L.P., a Delaware limited partnership, was formed in August 2011. On November 29, 2011, SemGroup Corporation contributed a wholly-owned subsidiary, Rose Rock Midstream Crude, L.P. (formerly known as SemCrude, L.P.), to Rose Rock Midstream, L.P., in return for limited partner interests, general partner interests and certain incentive distribution rights in Rose Rock Midstream, L.P. On December 14, 2011, Rose Rock Midstream, L.P. completed an initial public offering in which it sold 7,000,000 common units representing limited partner interests.

The general partner of Rose Rock Midstream, L.P. is Rose Rock Midstream GP, LLC, which is a wholly-owned subsidiary of SemGroup Corporation. SemGroup Corporation is a Delaware corporation headquartered in Tulsa, Oklahoma that provides diversified midstream services to the energy industry. SemGroup Corporation is the successor entity of SemGroup, L.P., which was an Oklahoma limited partnership.

The terms “we,” “our,” “us,” “Rose Rock,” the “Partnership” and similar language used in these notes to the unaudited condensed consolidated financial statements refer to Rose Rock Midstream, L.P, its subsidiaries, and its predecessor. The term “SemGroup” refers to SemGroup Corporation, SemGroup, L.P., and their other controlled subsidiaries, including Rose Rock Midstream GP, LLC.

Basis of presentation

These condensed consolidated financial statements of Rose Rock Midstream, L.P. include the activity of its predecessor prior to November 29, 2011. The predecessor included Rose Rock Midstream Crude, L.P. (“Rose Rock Crude”), a wholly-owned subsidiary of SemGroup Corporation (exclusive of Rose Rock Crude’s ownership interest in SemCrude Pipeline, L.L.C., which holds a 51% ownership interest in the White Cliffs Pipeline). Subsequent to November 29, 2011, these condensed consolidated financial statements include the accounts of Rose Rock Midstream, L.P. and its controlled subsidiaries, which include Rose Rock Crude.

These condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States and the rules and regulations of the SEC. These condensed consolidated financial statements include all normal and recurring adjustments that, in the opinion of management, are necessary to present fairly the financial position of the Company and the results of its operations and its cash flows. All significant transactions between Rose Rock Midstream, L.P. and its consolidated subsidiaries have been eliminated.

These condensed consolidated financial statements are unaudited. The condensed consolidated balance sheet at December 31, 2011 is derived from audited financial statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures in the financial statements. Although management believes these estimates are reasonable, actual results could differ materially from these estimates. The results of operations for the three months and six months ended June 30, 2012 are not necessarily indicative of the results to be expected for the full year ending December 31, 2012.

Pursuant to the rules and regulations of the SEC, the accompanying condensed consolidated financial statements do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States. Certain reclassifications have been made to conform previously reported balances to the current presentation. These condensed consolidated financial statements should be read in conjunction with the audited condensed consolidated financial statements and notes thereto for the year ended December 31, 2011, which are included in our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC.

Our significant accounting policies are consistent with those described in our Annual Report on Form 10-K for the year ended December 31, 2011.

Page 7

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

1. OVERVIEW, Continued

SemGroup bankruptcy

On July 22, 2008 (the “Petition Date”), SemGroup, L.P., SemCrude, L.P. (“SemCrude”) and Eaglwing, L.P. (“Eaglwing”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. While in bankruptcy, SemGroup, L.P. filed a plan of reorganization with the court, which was confirmed on October 28, 2009 (the “Plan of Reorganization”). The Plan of Reorganization determined, among other things, how pre-Petition Date obligations would be settled, the equity structure of the reorganized company upon emergence, and the financing arrangements upon emergence. SemGroup Corporation, SemCrude, and Eaglwing emerged from bankruptcy protection on November 30, 2009 (the “Emergence Date”).

Recent accounting pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” which creates common fair value measurement and disclosure requirements in U.S. GAAP and IFRS. We adopted this guidance on January 1, 2012. The impact of adoption was not material.

2. FINANCIAL INSTRUMENTS

Commodity derivative contracts

Our results of operations and cash flows are impacted by changes in market prices for petroleum products. This exposure to commodity price risk is managed, in part, by entering into various commodity derivatives.

We seek to manage the price risk associated with our marketing operations by limiting our net open positions through (i) the concurrent purchase and sale of like quantities of crude oil to create back-to-back transactions that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered or (ii) derivative contracts. Our storage and transportation assets also can be used to mitigate location and time basis risk. All marketing activities are subject to our Comprehensive Risk Management Policy, which establishes limits in order to manage risk and mitigate financial exposure.

Our commodity derivatives were comprised of crude oil and natural gas liquids forward contracts and futures contracts. These are defined as follows:

Forward contracts – Over the counter contracts to buy or sell a commodity at an agreed upon future date. The buyer and seller agree on specific terms (price, quantity, delivery period, and location) and conditions at the inception of the contract.

Futures contracts – Exchange traded contracts to buy or sell a commodity. These contracts are standardized by the exchange in terms of quality, quantity, delivery period and location for each commodity.

We record certain commodity derivative assets and liabilities at fair value at each balance sheet date. The tables below summarize the balances of these assets and liabilities at June 30, 2012 and December 31, 2011 (in thousands):

	June 30, 2012
	Level 1		Netting*			Total
Assets	$	254	$	(214	)	$	40
Liabilities		214		(214	)		—
Net assets at fair value	$	40	$	—		$	40

Page 8

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

2. FINANCIAL INSTRUMENTS, Continued

	December 31, 2011
	Level 1		Netting*			Total
Assets	$	393	$	(231	)	$	162
Liabilities		231		(231	)		—
Net assets at fair value	$	162	$	—		$	162

* Relates primarily to exchange traded futures. Gain and loss positions on multiple contracts are settled net on a daily basis with the exchange.

“Level 1” measurements were obtained using unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. These include futures contracts that are traded on an exchange.

“Level 2” measurements use as inputs market observable and corroborated prices for similar derivative contracts. Assets and liabilities classified as Level 2 include over-the-counter (“OTC”) traded physical fixed priced purchases and sales forward contracts.

“Level 3” measurements were obtained using information from a pricing service and internal valuation models incorporating observable and unobservable market data. For 2011, these included physical fixed price purchases and sales forward contracts with an affiliate for which there was not a highly liquid OTC market, and therefore were not included in Level 1 or Level 2 above.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the measurement requires judgment, and may affect the valuation of assets and liabilities and their placement within the fair value levels. At June 30, 2012, all of our physical fixed price forward purchases and sales contracts were being accounted for as normal purchases and normal sales.

There were no financial assets or liabilities classified as Level 3 during the three months and six months ended June 30, 2012. The following tables reconcile changes in the fair value of commodity derivatives classified as Level 3 in the fair value hierarchy (in thousands):

	Three Months Ended June 30, 2012		Three Months Ended June 30, 2011
Beginning balance	$	—	$	2,450
Total loss (realized and unrealized) included in product revenues		—		(847	)
Settlements		—		(1,122	)
Ending balance	$	—	$	481
Amount of total gain (loss) included in earnings for the period attributable to the change in unrealized gain or loss relating to assets and liabilities still held at the reporting date	$	—	$	481

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

2. FINANCIAL INSTRUMENTS, Continued

	Six Months Ended June 30, 2012		Six Months Ended June 30, 2011
Beginning balance	$	—	$	1,619
Total gain (realized and unrealized) included in product revenues		—		411
Settlements		—		(1,549	)
Ending balance	$	—	$	481
Amount of total gain (loss) included in earnings for the period attributable to the change in unrealized gain or loss relating to assets and liabilities still held at the reporting date	$	—	$	481

The following table sets forth the notional quantities for commodity derivative instruments entered into during the periods indicated (amounts in thousands of barrels):

	Three Months Ended June 30, 2012		Three Months Ended June 30, 2011		Six Months Ended June 30, 2012		Six Months Ended June 30, 2011
Sales		300		1,207		683		4,620
Purchases		235		1,252		686		4,785

We have not designated any of our commodity derivative instruments as accounting hedges. We record the fair value of the derivative instruments on our condensed consolidated balance sheets in other current assets and other current liabilities. The fair value of our commodity derivative assets and liabilities recorded to other current assets and other current liabilities was as follows (in thousands):

	June 30, 2012				December 31, 2011
	Assets		Liabilities		Assets		Liabilities
Commodity contracts	$	40	$	—	$	162	$	—

Realized and unrealized gains from our commodity derivatives were recorded to product revenue in the following amounts (in thousands):

	Three Months Ended June 30, 2012		Three Months Ended June 30, 2011		Six Months Ended June 30, 2012		Six Months Ended June 30, 2011
Commodity contracts	$	1,415	$	609	$	289	$	1,419

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

3. LONG-TERM DEBT

At June 30, 2012, we did not have any outstanding borrowings on our $150 million revolving credit facility. There was $35.0 million in outstanding letters of credit, and the rate in effect was 2.25%. In addition, a fronting fee of 0.25% is charged on outstanding letters of credit. A commitment fee that ranges from 0.375% to 0.50%, depending on a leverage ratio specified in the credit agreement, is charged on any unused capacity of the revolving credit facility. We had $2.7 million of secured bilateral letters of credit outstanding and the interest rate in effect was 1.75%. Secured bilateral letters of credit are external to the facility and do not reduce revolver availability.

At June 30, 2012, $1.5 million in capitalized loan fees, net of accumulated amortization, was recorded in other noncurrent assets, which is being amortized over the life of the facility.

We recorded $0.5 million and $1.0 million of interest expense during the three months and six months ended June 30, 2012, respectively, including amortization of debt issuance costs.

At June 30, 2012, we had $75 thousand of capital lease obligations reported as long-term debt on the consolidated balance sheet.

4. COMMITMENTS AND CONTINGENCIES

Bankruptcy matters

(a) Confirmation order appeal

Luke Oil appeal.On October 21, 2009, Luke Oil Company, C&S Oil/Cross Properties, Inc., Wayne Thomas Oil and Gas and William R. Earnhardt Company (collectively, “Luke Oil”) filed an objection to the Plan of Reorganization “to the extent that the Plan of Reorganization may alter, impair, or otherwise adversely affect Luke Oil’s legal rights or other interests.” On October 28, 2009, the bankruptcy court overruled the Luke Oil objection and entered the confirmation order. On November 6, 2009, Luke Oil filed a notice of appeal. On December 23, 2009, Luke Oil’s appeal was docketed in the United States District Court for the District of Delaware. SemGroup filed a motion to dismiss the appeal as equitably moot. On May 21, 2012, the District Court entered an order granting our motion to dismiss Luke Oil’s appeal of the confirmation order. On June 18, 2012, Luke Oil filed its Notice of Appeal, notifying the District Court and the parties to the lawsuit that it was appealing the decision of the District Court to the United States Court of Appeals for the Third Circuit. While SemGroup believes that this action is without merit and is vigorously defending this matter on appeal, an adverse ruling on this account could have a material adverse impact on us. Rose Rock is indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement.

(b) Claims reconciliation process

A large number of parties have made claims against SemGroup for obligations alleged to have been incurred prior to the Petition Date. On September 15, 2010, the bankruptcy court entered an order estimating the contingent, unliquidated and disputed claims and authorizing distributions to holders of allowed claims. Pursuant to that order SemGroup has begun making distributions to the claimants. SemGroup continues to attempt to settle unresolved claims.

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

4. COMMITMENTS AND CONTINGENCIES, Continued

Pursuant to the Plan of Reorganization, SemGroup committed to settle all pre-petition claims by paying a specified amount of cash, issuing a specified number of warrants, and issuing a specified number of shares of SemGroup Corporation common stock. The resolution of most of the outstanding claims will not impact the total amount of consideration SemGroup will give to the claimants; instead, the resolution of the claims will impact the relative share of the total consideration that each claimant receives.

However, there is a specified group of claims for which SemGroup could be required to pay additional funds to settle. Pursuant to the Plan of Reorganization, SemGroup set aside a specified amount of restricted cash at the Emergence Date, which SemGroup expected to be sufficient to settle this group of claims. Since the Emergence Date, SemGroup has made significant progress in resolving these claims, and continues to believe that the cash set aside at the Emergence Date will be sufficient to pay these claims. However, SemGroup has not yet reached a resolution of all of these claims and, if the total settlement amount of these claims exceeds the specified amount, SemGroup will be required to pay additional funds to these claimants, and we could be required to share in this expense. Rose Rock is indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement.

Environmental

We may from time to time experience leaks of petroleum products from our facilities and, as a result of which, we may incur remediation obligations or property damage claims. In addition, we are subject to numerous environmental regulations. Failure to comply with these regulations could result in the assessment of fines or penalties by regulatory authorities.

The Kansas Department of Health and Environment (“KDHE”) initiated discussions during SemGroup’s bankruptcy proceeding regarding five of our sites in Kansas that KDHE believed, based on their historical use, may have soil or groundwater contamination in excess of state standards. KDHE sought our agreement to undertake assessments of these sites to determine whether they are contaminated. SemGroup entered into a Consent Agreement and Final Order with KDHE to conduct environmental assessments on the sites and to pay KDHE’s costs associated with their oversight of this matter. SemGroup has conducted Phase II investigations at all sites. Three of the five sites have limited amounts of soil contamination that will be excavated and/or remediated on site. Three of the five sites appear to have ground water contamination that may require further delineation and/or on-going monitoring. Work plans have been submitted to, and approved by, the KDHE. SemGroup does not anticipate any penalties or fines for these historical sites. Rose Rock is indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement.

Blueknight claim

Blueknight Energy Partners, L.P. (“Blueknight”), which was formerly a subsidiary of SemGroup, together with other entities related to Blueknight, entered into a Shared Services Agreement on April 7, 2009, with SemCrude and SemManagement, L.L.C. (which are currently subsidiaries of SemGroup). The services provided by SemCrude to Blueknight under this agreement included the coordination of movement of crude oil belonging to Blueknight’s customers and the operation of Blueknight’s Oklahoma pipeline system and its Cushing, Oklahoma terminal. Under the subsequent amendments to the agreements beginning in May 2010, certain of these services were phased out and Blueknight began to manage the movement of its crude oil and the operation of its Cushing terminal.

In a letter dated August 18, 2011, Blueknight claimed that SemCrude owes Blueknight approximately 141,000 barrels of crude oil. SemGroup responded to Blueknight’s letter denying their charges and requesting documentation from Blueknight of its claim. On February 14, 2012, after months of interaction between the parties through which SemGroup requested Blueknight to substantiate its claim, Blueknight filed suit against SemGroup in the District Court of Oklahoma County, Oklahoma. On May 1, 2012, the court approved SemGroup’s motion to transfer this case to Tulsa County, Oklahoma. On July 2, 2012, the Tulsa County District Court appointed a Special Master to conduct a review of whether Blueknight is missing 141,000 barrels of crude oil from operations occurring during the months of April through June, 2010. The Special Master will prepare an advisory report to the Court of her findings and conclusions. SemGroup believes this matter is without merit and will vigorously defend their position; however, they cannot predict the outcome. Rose Rock is indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement.

Page 12

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

4. COMMITMENTS AND CONTINGENCIES, Continued

Other matters

We are party to various other 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 effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our consolidated liabilities may change materially as circumstances develop.

Asset retirement obligations

We may be subject to removal and restoration costs upon retirement of our facilities. However, we are unable to predict when, or if, our pipelines, storage tanks and related facilities would become completely obsolete and require decommissioning. Accordingly, we have not recorded a liability or corresponding asset, as both the amount and timing of such potential future costs are indeterminable.

Purchase and sale commitments

We routinely enter into agreements to purchase and sell petroleum products at specified future dates. We create a margin for these purchases by entering into various types of physical and financial sales and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. We account for these commitments as normal purchases and sales and, therefore, we do not record assets or liabilities related to these agreements until the product is purchased or sold. At June 30, 2012, such commitments included the following (in thousands):

	Volume (Barrels)		Value
Fixed price purchases		76	$	5,907
Fixed price sales		75	$	6,260
Floating price purchases		28,277	$	2,508,059
Floating price sales		28,824	$	2,573,122

Certain of the commitments shown in the table above relate to agreements to purchase product from a counterparty and to sell a similar amount of product (in a different location) to the same counterparty. Many of the commitments shown in the table above are cancellable by either party, as long as notice is given within the time frame specified in the agreement, generally 30 to 120 days.

5. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Unaudited condensed consolidated statement of changes in partners’ capital

The following table shows the changes in our consolidated partners’ capital accounts from December 31, 2011 to June 30, 2012 (in thousands):

	Common Units - Public			Common Units - SemGroup			Subordinated Units			General Partner Interest			Total Partners’ Capital
Balance at December 31, 2011	$	127,531		$	37,739		$	133,487		$	6,097		$	304,854
Net income		5,269			1,044			6,313			258			12,884
Distributions		(3,077	)		(610	)		(3,686	)		(151	)		(7,524	)
Non-cash equity compensation		139			—			—			—			139
Balance at June 30, 2012	$	129,862		$	38,173		$	136,114		$	6,204		$	310,353

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

5. PARTNERS’ CAPITAL AND DISTRIBUTIONS, Continued

Distribution rights

We intend to pay a minimum quarterly distribution of $0.3625 per unit, to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors.

Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:

• first,98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.3625, plus any arrearages from prior quarters;

• second,98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.3625; and

• third,98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.416875.

If cash distributions to our unitholders exceed $0.416875 per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” The following table summarizes the incentive distribution levels:

			Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Per Unit Target Amount		Unitholders			General Partner Interest			Incentive Distribution Rights
Minimum Quarterly Distribution		$0.3625		98.0	%		2.0	%		—
First Target Distribution	above $0.3625	up to $0.416875		98.0	%		2.0	%		—
Second Target Distribution	above $0.416875	up to $0.453125		85.0	%		2.0	%		13.0	%
Third Target Distribution	above $0.453125	up to $0.54375		75.0	%		2.0	%		23.0	%
Thereafter		above $0.54375		50.0	%		2.0	%		48.0	%

Distribution declared in January 2012

On January 23, 2012, we declared a distribution of $0.0670 (calculated as the $0.3625 minimum quarterly distribution, prorated based on the length of time during the three months ended December 31, 2011, that was subsequent to our initial public offering). This distribution was paid on February 13, 2012, to unitholders of record as of February 3, 2012.

Distribution declared in April 2012

On April 24, 2012, we declared a distribution of $0.3725 per unit, or $1.49 per unit on an annualized basis. This was a 2.8% increase over the prior quarter on an annualized basis and marked the first increase in the distribution to our limit partner unitholders. This distribution was paid on May 15, 2012, to all unitholders of record as of May 7, 2012.

Distribution declared in July 2012

On July 24, 2012, we declared a distribution of $0.3825 per unit, or $1.53 per unit on an annualized basis. This is a 2.7% increase over the prior quarter on an annualized basis. This distribution will be paid on August 14, 2012, to all unitholders of record as of August 6, 2012.

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

5. PARTNERS’ CAPITAL AND DISTRIBUTIONS, Continued

Equity incentive plan

On December 8, 2011, the board of directors of our general partner adopted the Rose Rock Midstream Equity Incentive Plan (the “Incentive Plan”). We have reserved 840,000 limited partner common units for issuance to non-management directors and employees under the Incentive Plan. At June 30, 2012, there are 38,359 unvested restricted unit awards that have been granted pursuant to the Incentive Plan. Generally, the awards vest three years after the date of grant for employees and one year after the date of grant for non-managerial directors, contingent upon the continued service of the recipients and may be subject to accelerated vesting in the event of involuntary terminations.

The holders of these restricted units are entitled to equivalent distributions (“Unvested Unit Distributions” or “UUD’s”) to be received upon vesting of the restricted unit awards. The distributions will be settled in common units based on the market price of our limited partner common units as of the close of business on the vesting date. The UUD’s are subject to the same forfeiture and acceleration conditions as the associated restricted units. At June 30, 2012, the value of the UUD’s was approximately $17 thousand. This is equivalent to approximately 690 common units based on the quarter end close of business market price of our common units of $24.43 per unit.

6. EARNINGS PER LIMITED PARTNER UNIT

Net income is allocated to the general partner and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated to the general partner.

Basic and diluted earnings per limited partner unit is determined by dividing net income allocated to the limited partners by the weighted average number of limited partner units for such class outstanding during the period. Diluted earnings per limited partner unit reflects, where applicable, the potential dilution that could occur if securities or other agreements to issue additional units of a limited partner class, such as restricted unit awards, were exercised, settled or converted into such units. At June 30, 2012, the dilutive effect of our restricted stock awards was immaterial.

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months and six months ended June 30, 2012 (amounts in thousands, except per unit data):

	Three Months Ended June��30, 2012		Six Months Ended June 30, 2012
Net income	$	5,126	$	12,884
Less: General partner’s incentive distribution earned (*)		—		—
Less: General partner’s 2.0% ownership		103		258
Net income allocated to limited partners	$	5,023	$	12,626
Numerator for basic and diluted earnings per limited partner unit:
Allocation of net income among limited partner interests:
Net income allocable to common units	$	2,511.5	$	6,313.0
Net income allocable to subordinated units	$	2,511.5	$	6,313.0
Net income allocated to limited partners	$	5,023	$	12,626
Denominator for basic and diluted earnings per limited partner unit:
Basic weighted average number of limited partner common units outstanding		8,390		8,390
Effect of dilutive securities		12		8
Diluted weighted average number of limited partner common units outstanding		8,402		8,398
Basic and diluted weighted average number of subordinated units outstanding		8,390		8,390
Basic & diluted net income per limited partner unit:
Common units	$	0.30	$	0.75
Subordinated units	$	0.30	$	0.75

(*) Based on the amount of the distribution declared per common and subordinated unit related to earnings for the three and six months ended June 30, 2012, our general partner was not entitled to receive any incentive distribution for this period.

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

7. RELATED PARTY TRANSACTIONS

Direct employee expenses

We do not directly employ any persons to manage or operate our business. These functions are performed by employees of SemGroup. SemGroup charged us $3.1 million and $2.6 million during the three months ended June 30, 2012 and 2011, respectively, for direct employee costs. SemGroup charged us $6.0 million and $5.1 million during the six months ended June 30, 2012 and 2011, respectively, for direct employee costs. These expenses were recorded to operating expenses and general and administrative expenses in our condensed consolidated statements of income.

Allocated expenses

SemGroup incurs expenses to provide certain indirect corporate general and administrative services to its subsidiaries. Such expenses include employee compensation costs, professional fees and rental fees for office space, among other expenses. SemGroup charged us $0.8 million and $1.1 million during the three months ended June 30, 2012 and 2011, respectively, for such allocated costs. SemGroup charged us $2.0 million and $2.4 million during the six months ended June 30, 2012 and 2011, respectively, for such allocated costs. These expenses were recorded to general and administrative expenses in our condensed consolidated statements of income.

SemGroup credit facilities

SemGroup was a borrower under various credit agreements during the periods included in these financial statements. Prior to our initial public offering, SemCrude, along with other subsidiaries of SemGroup, served as subsidiary guarantors under certain of these agreements. SemGroup did not allocate this debt to its subsidiaries, and our condensed consolidated statements of income do not include any allocated interest expense prior to our initial public offering. SemGroup did not charge us interest expense on intercompany payables.

Prior to our initial public offering, we utilized letters of credit under SemGroup’s credit facilities. Our condensed consolidated statements of income include direct charges from SemGroup for letter of credit usage, which is reported within interest expense.

Subsequent to our initial public offering, which was completed on December 14, 2011, our assets no longer serve as collateral under SemGroup’s credit agreement.

Predecessor cash management

Prior to our initial public offering, we participated in SemGroup’s cash management program. Under this program, cash we received from customers was transferred to SemGroup on a regular basis; when we remitted payments to suppliers, SemGroup transferred cash to us to cover the payments. Such cash transfers were recorded to intercompany accounts.

NGL Energy

SemGroup acquired certain ownership interests in NGL Energy Partners LP (“NGL Energy”) and its general partner on November 1, 2011. During the three months and six months ended June 30, 2012, we made purchases of natural gasoline and condensate from NGL Energy in the amount of $11.7 million and $25.7 million, respectively.

SemStream

We purchased condensate from SemStream, L.P. (“SemStream”), which is also a wholly-owned subsidiary of SemGroup. Certain of these purchases were fixed price forward purchases, which we recorded at fair value at each balance sheet date, with the unrealized gains being recorded to revenue. Our transactions with SemStream consisted of the following (in thousands):

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

7. RELATED PARTY TRANSACTIONS, Continued

	Three Months Ended June 30, 2012		Three Months Ended June 30, 2011			Six Months Ended June 30, 2012		Six Months Ended June 30, 2011
Sales	$	—	$	(1,969	)	$	—	$	(1,138	)
Purchases	$	—	$	16,606		$	—	$	29,523

SemGas

We purchase condensate from SemGas, L.P. (“SemGas”), which is also a wholly-owned subsidiary of SemGroup. Our purchases from SemGas included the following (in thousands):

	Three Months Ended June 30, 2012		Three Months Ended June 30, 2011		Six Months Ended June 30, 2012		Six Months Ended June 30, 2011
Purchases	$	2,553	$	1,770	$	5,283	$	3,281

White Cliffs

SemGroup owns 51% of White Cliffs and exercises significant influence over it. We generated revenues from White Cliffs of $0.6 million and $0.5 million for the three months ended June 30, 2012 and June 30, 2011, respectively. We generated revenues from White Cliffs of $1.2 million and $0.9 million for the six months ended June 30, 2012 and June 30, 2011, respectively.

Legal Services

The law firm of Conner & Winters, LLP, of which Mark D. Berman is a partner, performs legal services for us. Mr. Berman is the spouse of Candice L. Cheeseman, General Counsel and Secretary. Mr. Berman does not perform any legal services for us. Rose Rock paid $0.1 million and $0.1 million in legal fees and related expenses to this law firm during the three months ended June 30, 2012 and 2011, respectively. Rose Rock paid $0.3 million and $0.2 million in legal fees and related expenses to this law firm during the six months ended June 30, 2012 and 2011, respectively.

Page 17

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated interim financial statements and the notes thereto included in Part I, Item 1 of this Quarterly Report on Form 10-Q, and our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC.

Overview of Business

We are a growth-oriented Delaware limited partnership formed in 2011 by SemGroup to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We are engaged in the business of crude oil gathering, transportation, storage and marketing in Colorado, Kansas, Montana, North Dakota, Oklahoma and Texas. We serve areas that are experiencing strong production growth and drilling activity through our exposure to the Bakken Shale in North Dakota and Montana, the DJ Basin and the Niobrara Shale in the Rocky Mountain region, and the Granite Wash and the Mississippian oil trend in the Mid-Continent region. The majority of our assets are strategically located in, or connected to, the Cushing, Oklahoma crude oil marketing hub. Cushing is the designated point of delivery specified in all NYMEX crude oil futures contracts and is one of the largest crude oil marketing hubs in the United States. We believe that our connectivity in Cushing and our numerous interconnections with third-party pipelines, refineries and storage terminals provide our customers with the flexibility to access multiple points for the receipt and delivery of crude oil.

We own and operate all of our assets, which include:

• 7.0 million barrels of crude oil storage capacity in Cushing, Oklahoma;

• a 640-mile crude oil gathering and transportation pipeline system with over 660,000 barrels of associated storage capacity in Kansas and northern Oklahoma that is connected to several third-party pipelines and refineries and our storage terminal in Cushing;

• a crude oil gathering, storage, transportation and marketing business in the Bakken Shale in North Dakota and Montana in which we marketed an average of 7,500 barrels of crude oil per day for the three months ended June 30, 2012; and

• a modern, ten-lane crude oil truck unloading facility with 220,000 barrels of associated storage capacity in Platteville, Colorado which connects to the origination point of SemGroup’s White Cliffs Pipeline, with an additional six truck unloading lanes and 10,000 barrels of storage expected to be completed by the end of 2012.

For the three months and six months ended June 30, 2012, approximately 85% and 77%, respectively, of our adjusted gross margin was generated from fee-based services or fixed-margin transactions. For a definition of adjusted gross margin and a reconciliation of adjusted gross margin to operating income, its most directly comparable financial measure calculated and presented in accordance with generally accepted accounting principles (“GAAP”), please see “Non-GAAP Financial Measures”.

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include financial measures, including adjusted gross margin, operating expenses and adjusted EBITDA, and operating data, including contracted storage capacity and transportation, marketing and unloading volumes.

Adjusted Gross Margin

We view adjusted gross margin as an important performance measure of the core profitability of our operations, as well as our operating performance as compared to that of other companies in our industry, without regard to financing methods, historical cost basis, capital structure or the impact of fluctuating commodity prices. We define adjusted gross margin as total revenues minus cost of products sold and unrealized gain (loss) on derivatives. Adjusted gross margin allows us to make a meaningful comparison of the operating results between our fee-based activities, which do not involve the purchase or sale of crude oil, and our fixed-margin and marketing operations, which do. In particular, adjusted gross margin provides a way to compare the actual transportation fee received under fixed-fee contracts with the effective transportation fee realized through a fixed-margin transaction. In addition, adjusted gross margin allows us to make a meaningful comparison of the results of our fixed-margin and marketing operations across different commodity price environments because it measures the spread between the product sales price and cost of products sold. See “Non-GAAP Financial Measures”.

Because adjusted gross margin may be defined differently by other companies in our industry, our definition may not be comparable to similarly titled measures of other companies.

Page 18

Operating Expenses

Our management seeks to maximize the profitability of our operations, in part, by minimizing operating expenses. These expenses are comprised of salary and wage expense, utility costs, insurance premiums, taxes and other operating costs, some of which are independent of the volumes we handle.

The current high levels of crude oil exploration, development and production activities are increasing competition for personnel and equipment. This increased competition is placing upward pressure on the prices we pay for labor, supplies and miscellaneous equipment. To the extent we are unable to procure necessary services or offset higher costs, our operating results will be negatively impacted.

Adjusted EBITDA

We define adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation and amortization and any non-cash adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities. We use adjusted EBITDA as a supplemental performance and liquidity measure to assess:

• our operating performance as compared to that of other companies in our industry, without regard to financing methods, historical cost basis, capital structure or the impact of fluctuating commodity prices;

• the ability of our assets to generate sufficient cash flow to make distributions to our partners;

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

Contracted Storage Capacity and Transportation, Marketing and Unloading Volumes

In our Cushing storage operations, we charge our customers a fee for storage capacity provided, regardless of actual usage. On our Kansas and Oklahoma system, we provide transportation services on a fee basis or pursuant to fixed-margin transactions, but in either case, the adjusted gross margin we generate is dependent on the volume of crude oil transported (if on a fee basis) or purchased and sold (if pursuant to a fixed-margin transaction). We refer to these volumes, in the aggregate, as transportation volumes. Similarly, on our Kansas and Oklahoma system, and through our Bakken Shale operations, we conduct marketing activities involving the purchase and sale of crude oil or related derivative contracts. We refer to the crude oil volumes purchased and sold in our marketing operations as marketing volumes. Finally, at our Platteville truck unloading facility, we charge our customers a fee based on the volumes unloaded. We refer to these as unloading volumes.

How We Generate Adjusted Gross Margin

We generate adjusted gross margin by providing fee-based services, by entering into fixed-margin transactions and through marketing activities. Revenues from our fee-based services are included in service revenue, and revenues from our fixed-margin and marketing activities are included in product revenue.

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Fee-Based Services

We charge a capacity or volume-based fee for the unloading, transportation and storage of crude oil and related ancillary services. Our fee-based services include substantially all of our operations in Cushing, Oklahoma and Platteville, Colorado and a portion of the transportation services we provide on our Kansas and Oklahoma pipeline system. Some of our fee-based contracts are take-or-pay contracts whereby the customer is required to pay us a fixed minimum monthly fee regardless of usage. For the three months ended June 30, 2012 and 2011, approximately 67% and 59%, respectively, of our adjusted gross margin was generated by providing fee-based services to customers. For the six months ended June 30, 2012 and 2011, approximately 60% and 59%, respectively, of our adjusted gross margin was generated by providing fee-based services to customers.

Fixed-Margin Transactions

We purchase crude oil from a producer or supplier at a designated receipt point at an index price (less a transportation fee) and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price, thereby locking in a fixed margin that is, in effect, economically equivalent to a transportation fee. We refer to these arrangements as “fixed-margin” or “buy/sell” transactions. These fixed-margin transactions account for a portion of the adjusted gross margin we generate on our Kansas and Oklahoma pipeline system and through our Bakken Shale operations. For the three months ended June 30, 2012 and 2011, approximately 18% and 14%, respectively, of our adjusted gross margin was generated through fixed-margin transactions. For the six months ended June 30, 2012 and 2011, approximately 17% and 15%, respectively, of our adjusted gross margin was generated through fixed-margin transactions.

Marketing Activities

We conduct marketing activities by purchasing crude oil for our own account from producers, aggregators and traders and selling crude oil to traders and refiners. Our marketing activities account for a portion of the adjusted gross margin we generate on our Kansas and Oklahoma pipeline system and through our Bakken Shale operations. For the three months ended June 30, 2012 and 2011, approximately 15% and 27%, respectively, of our adjusted gross margin was generated through marketing activities. For the six months ended June 30, 2012 and 2011, approximately 23% and 27%, respectively, of our adjusted gross margin was generated through marketing activities.

We mitigate the commodity price exposure of our crude oil marketing operations by limiting our net open positions through (i) the concurrent purchase and sale of like quantities of crude oil to create “back-to-back” transactions intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered or (ii) derivative contracts. All of our marketing activities are subject to our Comprehensive Risk Management Policy, which establishes limits to manage risk and mitigate financial exposure.

More specifically, we utilize futures and swap contracts to manage our exposure to market changes in commodity prices to protect our adjusted gross margin on our purchased crude oil. As we purchase inventory from suppliers, we may establish a fixed or variable margin with future sales by selling a like quantity of crude oil for future physical delivery to create an effective back-to-back transaction; or entering into futures and swaps contracts on the NYMEX or over-the-counter markets.

Adjusted Gross Margin

The following table shows adjusted gross margin generated by product revenue and service revenue for the three months and six months ended June 30, 2012 and 2011 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues:
Product	$	146,070		$	102,137		$	315,456		$	176,394
Service		11,402			8,512			21,736			17,935
Other		(54	)		65			(59	)		176
Total Revenues		157,418			110,714			337,133			194,505
Less: Costs of products sold, exclusive of depreciation and amortization		140,549			96,144			301,057			162,144
Less: Unrealized gain (loss) on derivatives		24			(65	)		(122	)		1,524
Adjusted gross margin	$	16,845		$	14,635		$	36,198		$	30,837

The following tables show the adjusted gross margin categorized by our storage, transportation and marketing activities for the three months ended June 30, 2012 and June 30, 2011 (in thousands):

Three months ended June 30, 2012	Storage		Transportation		Marketing Activities		Other (1)		Total
Revenues	$	8,429	$	4,106	$	143,139	$	1,744	$	157,418
Less: Costs of products sold, exclusive of depreciation and amortization		—		—		140,549		—		140,549
Less: Unrealized gain (loss) on derivatives		—		—		24		—		24
Adjusted gross margin	$	8,429	$	4,106	$	2,566	$	1,744	$	16,845

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Three months ended June 30, 2011	Storage		Transportation		Marketing Activities			Other (1)		Total
Revenues	$	5,613	$	3,437	$	100,037		$	1,627	$	110,714
Less: Costs of products sold, exclusive of depreciation and amortization		—		—		96,144			—		96,144
Less: Unrealized gain (loss) on derivatives		—		—		(65	)		—		(65	)
Adjusted gross margin	$	5,613	$	3,437	$	3,958		$	1,627	$	14,635

(1) This category includes fee-based services such as unloading and ancillary storage terminal services.

The following tables show the adjusted gross margin generated by our storage, transportation and marketing activities for the six months ended June 30, 2012 and June 30, 2011 (in thousands):

Six months ended June 30, 2012	Storage		Transportation		Marketing Activities			Other (1)		Total
Revenues	$	15,838	$	8,656	$	309,122		$	3,517	$	337,133
Less: Costs of products sold, exclusive of depreciation and amortization		—		—		301,057			—		301,057
Less: Unrealized gain (loss) on derivatives		—		—		(122	)		—		(122	)
Adjusted gross margin	$	15,838	$	8,656	$	8,187		$	3,517	$	36,198

Six months ended June 30, 2011	Storage		Transportation		Marketing Activities		Other (1)		Total
Revenues	$	12,015	$	7,816	$	171,859	$	2,815	$	194,505
Less: Costs of products sold, exclusive of depreciation and amortization		—		—		162,144		—		162,144
Less: Unrealized gain (loss) on derivatives		—		—		1,524		—		1,524
Adjusted gross margin	$	12,015	$	7,816	$	8,191	$	2,815	$	30,837

(1) This category includes fee-based services such as unloading and ancillary storage terminal services.

Selected Consolidated Financial and Operating Data

The following table provides selected historical condensed consolidated financial operating data as of and for the periods shown. The statement of income data for the three months and six months ended June 30, 2012 and 2011 have been derived from our unaudited financial statements for those periods. The selected financial data provided below should be read in conjunction with our condensed consolidated financial statements and related notes included in this Form 10-Q.

The following table presents the non-GAAP financial measures of adjusted gross margin and adjusted EBITDA, which we use in our business and view as important supplemental measures of our performance and, in the case of adjusted EBITDA, our liquidity. Adjusted gross margin and adjusted EBITDA are not calculated or presented in accordance with GAAP. For definitions of adjusted gross margin and adjusted EBITDA and a reconciliation of operating income to adjusted gross margin, of net income to adjusted EBITDA and of net cash provided by (used in) operating activities to adjusted EBITDA, their most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” below.

Page 21

	Three Months Ended June  30, 2012			Three Months Ended June  30, 2011			Six Months Ended June 30, 2012			Six Months Ended June 30, 2011
	(in thousands, except per unit and operating data)
Statement of income data:
Total revenues	$	157,418		$	110,714		$	337,133		$	194,505
Operating income	$	5,603		$	5,259		$	13,913		$	13,346
Net income	$	5,126		$	4,973		$	12,884		$	12,577
Net income per common unit (basic and diluted)	$	0.30			N/A		$	0.75			N/A
Net income per subordinated unit (basic and diluted)	$	0.30			N/A		$	0.75			N/A
Distributions paid per unit	$	0.3725			N/A		$	0.4395			N/A
Statement of cash flows data:
Net cash provided by (used in):
Operating activities	$	20,319		$	1,551		$	20,079		$	26,724
Investing activities	$	(6,202	)	$	(14,351	)	$	(9,246	)	$	(15,876	)
Financing activities	$	(6,393	)	$	12,800		$	(7,587	)	$	(11,151	)
Other financial data:
Adjusted gross margin	$	16,845		$	14,635		$	36,198		$	30,837
Adjusted EBITDA	$	8,712		$	7,936		$	20,124		$	16,819
Capital expenditures	$	6,347		$	14,351		$	9,391		$	15,879
Operating data:
Cushing storage capacity (MMBbls as of period end)		7.0			4.7			7.0			4.7
Percent of Cushing capacity contracted (as of end of period)		96	%		95	%		96	%		95	%
Transportation volumes (average Bpd)		49,000			30,900			46,900			29,000
Marketing volumes (average Bpd)		21,300			11,500			22,000			10,900
Unloading/Platteville volumes (average Bpd)		44,300			32,500			43,400			30,100

Non-GAAP Financial Measures

We define adjusted gross margin as total revenues minus cost of products sold and unrealized gain (loss) on derivatives. We define adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation and amortization and any non-cash adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities. Adjusted gross margin and adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.

Operating income (loss) is the GAAP measure most directly comparable to adjusted gross margin, and net income (loss) and cash provided by (used in) operating activities are the GAAP measures most directly comparable to adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measures. These non-GAAP financial measures have important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider adjusted gross margin and adjusted EBITDA in isolation or as substitutes for analysis of our results as reported under GAAP. Because adjusted gross margin and adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Management compensates for the limitation of adjusted gross margin and adjusted EBITDA as analytical tools by reviewing the comparable GAAP measures, understanding the differences between adjusted gross margin and adjusted EBITDA, on the one hand, and operating income (loss), net income (loss) and net cash provided by (used in) operating activities, on the other hand, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.

The following table presents a reconciliation of: (i) operating income to adjusted gross margin, (ii) net income to adjusted EBITDA, and (iii) net cash provided by operating activities to adjusted EBITDA, the most directly comparable GAAP financial measures, on a historical basis for each of the periods indicated.

Page 22

	Three Months Ended June 30, 2012		Three Months Ended June 30, 2011			Six Months Ended June 30, 2012			Six Months Ended June  30, 2011
	(Unaudited; in thousands)
Reconciliation of operating income to adjusted gross margin:
Operating income	$	5,603	$	5,259		$	13,913		$	13,346
Add:
Operating expense		6,221		4,501			11,448			9,165
General and administrative		2,046		2,110			4,749			4,467
Depreciation and amortization		2,999		2,700			5,966			5,383
Less:
Unrealized gain (loss) on derivatives, net		24		(65	)		(122	)		1,524
Adjusted gross margin	$	16,845	$	14,635		$	36,198		$	30,837
Reconciliation of net income to adjusted EBITDA:
Net income	$	5,126	$	4,973		$	12,884		$	12,577
Add:
Interest expense		477		488			957			971
Depreciation and amortization		2,999		2,700			5,966			5,383
Non-cash equity compensation		78		—			139			—
Loss on impairment or sale of assets		56		10			56			12
Provision for (recovery of) uncollectible accounts receivable		—		(300	)		—			(600	)
Less:
Unrealized gain (loss) on derivatives, net		24		(65	)		(122	)		1,524
Adjusted EBITDA	$	8,712	$	7,936		$	20,124		$	16,819
Reconciliation of net cash provided by operating activities to adjusted EBITDA:
Net cash provided by operating activities	$	20,319	$	1,551		$	20,079		$	26,724
Less:
Changes in assets and liabilities		11,998		(5,897	)		741			10,876
Add:
Interest expense, excluding amortization of debt issuance costs		391		488			786			971
Adjusted EBITDA	$	8,712	$	7,936		$	20,124		$	16,819

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Results of Operations

	Three Months Ended June  30, 2012			Three Months Ended June  30, 2011			Six Months Ended June 30, 2012			Six Months Ended June 30, 2011
	(Unaudited, in thousands except per unit data)
Statement of income data:
Revenues, including revenues from affiliates:
Product	$	146,070		$	102,137		$	315,456		$	176,394
Service		11,402			8,512			21,736			17,935
Other		(54	)		65			(59	)		176
Total revenues		157,418			110,714			337,133			194,505
Expenses, including expenses from affiliates:
Costs of products sold, exclusive of depreciation and amortization shown below		140,549			96,144			301,057			162,144
Operating		6,221			4,501			11,448			9,165
General and administrative		2,046			2,110			4,749			4,467
Depreciation and amortization		2,999			2,700			5,966			5,383
Total expenses		151,815			105,455			323,220			181,159
Operating income		5,603			5,259			13,913			13,346
Other expenses:
Interest expense		477			488			957			971
Other expense (income)		—			(202	)		72			(202	)
Total other expenses		477			286			1,029			769
Net income	$	5,126		$	4,973		$	12,884		$	12,577
Net income per common unit (basic and diluted)	$	0.30			N/A		$	0.75			N/A
Net income per subordinated unit (basic and diluted)	$	0.30			N/A		$	0.75			N/A
Distribution paid per unit	$	0.3725			N/A		$	0.4395			N/A
Adjusted gross margin (1)	$	16,845		$	14,635		$	36,198		$	30,837
Adjusted EBITDA (1)	$	8,712		$	7,936		$	20,124		$	16,819

(1) For a definition of adjusted gross margin, adjusted EBITDA and reconciliation to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Non-GAAP Financial Measures.”

ASC 845-10-15, “Nonmonetary Transactions,”requires certain transactions – those where inventory is purchased from a customer then resold to the same customer – to be presented in the income statement on a net basis, resulting in a reduction of revenue and costs of products sold by the same amount, but has no effect on operating income. However, changes in the level of such purchase and sale activity between periods can have an effect on the comparison between those periods.

Three months ended June 30, 2012 vs. three months ended June 30, 2011

Revenue

Revenue increased in the three months ended June 30, 2012, to $157 million from $111 million for the three months ended June 30, 2011, as shown in the following table:

Page 24

	Three Months Ended June  30, 2012			Three Months Ended June  30, 2011
	(in thousands)
Gross product revenue	$	471,733		$	271,612
Nonmonetary transaction adjustment		(325,687	)		(169,410	)
Unrealized gain (loss) on derivatives, net		24			(65	)
Product revenue		146,070			102,137
Service revenue		11,402			8,512
Other		(54	)		65
Total revenue	$	157,418		$	110,714

Gross product revenue increased in the three months ended June 30, 2012, to $472 million from $272 million in three months ended June 30, 2011. The increase was primarily due to 5.2 million barrels sold in the three months ended June 30, 2012, at an average sales price of $91 per barrel, compared to 2.7 million barrels sold during the three months ended June 30, 2011, at an average sales price of $102 per barrel.

Gross product revenue was reduced by $326 million and $169 million during the three months ended June 30, 2012 and June 30, 2011, respectively, in accordance with ASC 845-10-15.

Service revenue increased to $11 million in the three months ended June 30, 2012, from $9 million in the three months ended June 30, 2011, due to the completion of additional storage capacity in Cushing.

Costs of Products Sold

Costs of products sold increased in the three months ended June 30, 2012, to $141 million from $96 million in the three months ended June 30, 2011. Costs of products sold reflected reductions of $326 million and $169 million in the three months ended June 30, 2012 and June 30, 2011, respectively, in accordance with ASC 845-10-15. Costs of products sold increased due to the increase in the volume of barrels sold per month described above, combined with a decrease in the average per barrel cost of crude oil to $90 for the three months ended June 30, 2012, from $99 for the three months ended June 30, 2011.

Adjusted Gross Margin

We define adjusted gross margin as total revenues minus costs of products sold and unrealized gain (loss) on derivatives. (See “Non-GAAP Financial Measures” for adjusted gross margin tables.) Adjusted gross margin increased in the three months ended June 30, 2012, to $17 million from $15 million in the three months ended June 30, 2011, due to:

• an increase in marketing volume (which is a subset of the total volume sold as shown above) of approximately 0.9 million barrels in the three months ended June 30, 2012, over the same period in 2011, offset by a lower spread between the purchase and sale price for volumes of crude oil sold, as the excess of our average sales price per barrel over our average purchase cost per barrel decreased to approximately $1 for the three months ended June 30, 2012, from approximately $3 for the three months ended June 30, 2011. This lower realized spread resulted in a $(1.4) million reduction in adjusted gross margin during the three months ended June 30, 2012, compared to the same period in 2011;

• an increase in transportation volumes of approximately 1.7 million barrels, contributing an additional $0.7 million adjusted gross margin during the three months ended June 30, 2012, compared to the same period in 2011;

• an increase in unloading volumes from our Platteville operations of approximately 1 million barrels, contributing an additional $0.2 million adjusted gross margin, during the three months ended June 30, 2012, compared to the same period in 2011; and

• an increase from our storage operations of approximately 4.7 million barrels in contracted storage capacity at June 30 2011, to 7.0 million barrels at June 30, 2012, contributing an additional $2.8 million adjusted gross margin.

Operating Expense

Operating expense increased in the three months ended June 30, 2012, to $6 million from $4 million in the three months ended June 30, 2011. This increase is due primarily to increased compensation expense ($560,000), field expenses ($360,000) and maintenance ($320,000). In addition, a recovery in 2011 of a previously written off account receivable ($300,000) did not reoccur in 2012.

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General

All other expenses for the three months ended June 30, 2012 remained roughly consistent with like expenses for the three months ended June 30, 2011.

Six months ended June 30, 2012 vs. six months ended June 30, 2011

Revenue

Revenue increased in the six months ended June 30, 2012, to $337 million from $195 million for the six months ended June 30, 2011, as shown in the following table:

	Six Months Ended June 30, 2012			Six Months Ended June 30, 2011
	(in thousands)
Gross product revenue	$	973,212		$	481,988
Nonmonetary transaction adjustment		(657,634	)		(307,118	)
Unrealized gain (loss) on derivatives, net		(122	)		1,524
Product revenue		315,456			176,394
Service revenue		21,736			17,935
Other		(59	)		176
Total revenue	$	337,133		$	194,505

Gross product revenue increased in the six months ended June 30, 2012, to $973 million from $482 million in six months ended June 30, 2011. The increase was primarily due to 10.2 million barrels sold in the six months ended June 30, 2012, at an average sales price of $96 per barrel, compared to 4.9 million barrels sold during the six months ended June 30, 2011, at an average sales price of $97 per barrel.

Gross product revenue was reduced by $658 million and $307 million during the six months ended June 30, 2012 and June 30, 2011, respectively, in accordance with ASC 845-10-15.

Service revenue increased to $22 million in the six months ended June 30, 2012, from $18 million in the six months ended June 30, 2011, due to the completion of additional storage capacity in Cushing.

Costs of Products Sold

Costs of products sold increased in the six months ended June 30, 2012, to $301 million from $162 million in the six months ended June 30, 2011. Costs of products sold reflected reductions of $658 million and $307 million in the six months ended June 30, 2012 and June 30, 2011, respectively, in accordance with ASC 845-10-15. Costs of products sold increased due to the increase in the volume of barrels sold per month described above with the average per barrel cost of crude oil remaining flat at $94.

Adjusted Gross Margin

We define adjusted gross margin as total revenues minus costs of products sold and unrealized gain (loss) on derivatives. (See “Non-GAAP Financial Measures” for adjusted gross margin tables.) Adjusted gross margin increased in the six months ended June 30, 2012 to $36 million from $31 million in the six months ended June 30, 2011, due to:

• an increase in marketing volume (which is a subset of the total volume sold as shown above) of approximately 2 million barrels, offset by a lower spread between the purchase and sale price for volumes of crude oil sold, as the excess of our average sales price per barrel over our average purchase cost per barrel decreased to approximately $2 from approximately $3. These offsetting factors resulted in no net change to adjusted gross margin;

• an increase in transportation volumes of approximately 3.3 million barrels, contributing an additional $0.8 million adjusted gross margin;

• an increase in unloading volumes from our Platteville operations of approximately 2.3 million barrels, contributing an additional $0.4 million adjusted gross margin; and

Page 26

• an increase from our storage operations of approximately 6.2 million barrels in contracted storage capacity to 7.0 million barrels, contributing an additional $3.8 million adjusted gross margin.

Operating Expense

Operating expense increased in the six months ended June 30, 2012, to $11 million from $9 million in the six months ended June 30, 2011. This increase is due primarily to increased compensation expense ($900,000), field expenses ($300,000) and maintenance ($170,000). In addition, a recovery in 2011 of a previously written off account receivable ($600,000) did not reoccur in 2012.

General

All other expenses for the six months ended June 30, 2012 remained roughly consistent with like expenses for the six months ended June 30, 2011.

Liquidity and Capital Resources

Our principal sources of short-term liquidity are cash generated from operations and borrowings under our revolving credit facility. Potential sources of long-term liquidity include the issuance of debt securities and common units. Our primary cash requirements currently are operating expenses, capital expenditures and quarterly distributions to our unitholders and general partner. In general, we expect to fund:

• operating expenses, maintenance capital expenditures and cash distributions through existing cash and cash from operating activities;

• expansion capital expenditures and working capital deficits through cash on hand and borrowings on our revolving credit facility; and

• debt principal payments through cash from operating activities and refinancing when the credit facility becomes due.

Our ability to meet our financing requirements and fund our planned capital expenditures will depend on our future operating performance, which will be affected by prevailing economic conditions in our industry. In addition, we are subject to conditions in the debt and equity markets for debt securities and limited partner units. There can be no assurance we will be able or willing to access the public or private markets in the future. If we would be unable or unwilling to access those markets, we could be required to restrict future expansion capital expenditures and potential future acquisitions.

We believe our cash from operations and our remaining borrowing capacity allow us to manage our day-to-day cash requirements, distribute the minimum quarterly distribution on all our outstanding common, subordinated and general partner units, and meet our capital expenditures commitments for the coming year.

Cash Flows

The following table summarizes our changes in cash for the periods presented:

	Six Months Ended June 30,
	2012			2011
	(in thousands)
Cash flows provided by (used in):
Operating activities	$	20,079		$	26,724
Investing activities		(9,246	)		(15,876	)
Financing activities		(7,587	)		(11,151	)
Change in cash and cash equivalents		3,246			(303	)
Cash and cash equivalents at beginning of period		9,709			303
Cash and cash equivalents at end of period	$	12,955		$	—

Operating Activities.

For the six months ended June 30, 2012, we experienced operating cash inflows of $20 million. Net income of $13 million included $6 million of non-cash expenses, comprised primarily of depreciation and amortization. The primary changes to working capital included an increase to accounts receivable of $22 million and a decrease in payables to affiliates of $4 million, partially offset by an increase in accounts payable and accrued liabilities of $16 million and a decrease in inventory of $10 million.

Page 27

For the six months ended June 30, 2011, we experienced operating cash inflows of $27 million. Net income of $13 million included $3 million of non-cash expenses, comprised primarily of depreciation and amortization. The primary changes to working capital included a $37 million increase in accounts payable and a $7 million decrease in inventories, which was partially offset by a $35 million increase in accounts receivable.

Investing Activities.

For the six months ended June 30, 2012 and 2011, our cash outflows from investing activities related primarily to capital expenditures of $9 million and $16 million, respectively. These capital expenditures related primarily to the construction of storage tanks at our terminal in Cushing, Oklahoma.

Financing Activities.

Cash outflow from financing activities for the six months ended June 30, 2012 and 2011 consisted primarily of distributions to our unitholders and our general partner in the amount of $8 million and $12 million, respectively.

Revolving Credit Facility

At June 30, 2012, we had no outstanding borrowing under our $150 million revolving credit facility. We had $35.0 million in outstanding letters of credit, which are not reflected as borrowings on our balance sheet but they do reduce our borrowing capacity. We had $2.7 million outstanding in secured bilateral letters of credit which are external to the credit facility and do not reduce our borrowing capacity. Our borrowing capacity under this credit facility can be increased by an additional $200 million, subject to commitments from new lenders or additional commitments from existing lenders. The credit agreement includes customary affirmative and negative covenants and also restricts our ability to make certain types of payments including cash distributions to unitholders, however, we may make those distributions unless we are in default under the credit agreement or the distribution would result in a default. At June 30, 2012, we were in compliance with the terms of the credit agreement.

Working Capital

Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital was $28.7 million and $26.0 million at June 30, 2012 and December 31, 2011, respectively.

Capital Requirements

The midstream energy business can be capital intensive, requiring significant investment for the maintenance of existing assets or acquisition or development of new systems and facilities. We categorize our capital expenditures as either:

• maintenance capital expenditures, which are cash expenditures (incurred for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or

• expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long-term.

We budgeted $37.4 million in capital expenditures for the year ending December 31, 2012, of which $33.7 million represents expansion capital expenditures related to the construction of 1.95 million barrels of storage capacity at our Cushing terminal, a truck unloading bay expansion at Platteville and other strategic growth projects. $3.7 million represents maintenance capital expenditures, of which $0.9 million is related to truck replacements, and $2.8 million is related primarily to increased pipeline integrity management expenses to comply with new regulations. We spent $9 million and $16 million in capital expenditures during the six months ended June 30, 2012 and 2011, respectively.

In addition to our budgeted capital program, we anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under our credit facility and the issuance of debt and equity securities.

Distributions

The cash distribution for the fourth quarter of 2011 was $0.0670 per unit. This prorated amount corresponds to the minimum quarterly cash distribution of $0.3625 per unit, or $1.45 per unit on an annualized basis. The proration period began on December 15, 2011, immediately after the closing date of our initial public offering, and continued through December 31, 2011. The distribution was paid on February 13, 2012 to all unitholders of record as of February 3, 2012.

Page 28

The cash distribution for the first quarter of 2012 was $0.3725 per unit, or $1.49 per unit on an annualized basis. This represented a 2.8% increase over the prior quarter on an annualized basis and marked the first increase in the distribution to our limited partner unitholders. The distribution was paid on May 15, 2012 to all unitholders of record as of May 7, 2012.

The cash distribution for the second quarter of 2012 is $0.3825 per unit, or $1.53 per unit on an annualized basis. This represents a 2.7% increase over the prior quarter on an annualized basis. The distribution will be paid on August 14, 2012 to all unitholders of record as of August 6, 2012.

Credit Risk

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We examine the creditworthiness of third party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

Customer Concentration

Shell Trading (US) Company, 4K Fuel Supply, LLC, Vitol S.A., and Phillips 66, each accounted for more than 10% of our total revenue for the three months ended June 30, 2012, at approximately 22%, 14%, 12% and 11%, respectively. Shell Trading (US) Company, 4K Fuel Supply, LLC, Vitol S.A., and BP Canada Energy Marketing Corp., each accounted for more than 10% of our total revenue for the six months ended June 30, 2012, at approximately 18%, 17%, 15% and 10%, respectively. Although we have contracts with customers of varying duration, if one or more of our major customers were to default on their contract or if we were unable to renew our contract with one or more of these customers on favorable terms, we might not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our revenues and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our adjusted gross margin.

Purchases and Sales Commitments

We routinely enter into agreements to purchase and sell petroleum products at specified future dates. We establish a margin for these purchases by entering into various types of physical and financial sales and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases, on the one hand, and sales and future delivery obligations, on the other. We account for these commitments as normal purchases and sales, and therefore we do not record assets or liabilities related to these agreements until the product is purchased or sold. At June 30, 2012, such commitments included the following (in thousands):

	Volume (Barrels)		Value
Fixed price purchases		76	$	5,907
Fixed price sales		75	$	6,260
Floating price purchases		28,277	$	2,508,059
Floating price sales		28,824	$	2,573,122

Certain of the commitments shown in the table above relate to agreements to purchase product from a counterparty and to sell a similar amount of product (in a different location) to the same counterparty. Many of the commitments shown in the table above are cancellable by either party, as long as notice is given within the time frame specified in the agreement, generally 30 to 120 days.

Letters of Credit

In connection with our purchasing activities, we provide certain suppliers and transporters with irrevocable standby and performance letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded as accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for 50- to 70-day periods (with a maximum of a 364-day period) and are terminated upon completion of each transaction. At June 30, 2012 and December 31, 2011, we had outstanding letters of credit of approximately $35.0 million and $39.6 million, respectively.

Page 29

Off-Balance Sheet Arrangements

We do not use any off-balance sheet arrangements to enhance our liquidity and capital resources, or for any other purpose.

Critical Accounting Policies and Estimates

For disclosure regarding our critical accounting policies and estimates, see the discussion under the caption “Critical Accounting Policies and Estimates” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2011.

Recent Accounting Pronouncements

See Note 1 to our condensed consolidated financial statements.

Page 30

Item 3. Quantitative and Qualitative Disclosures about Market Risk

This discussion on market risks represents an estimate of possible changes in future earnings that would occur assuming hypothetical future movements in commodity prices and interest rates. Our views on market risk are not necessarily indicative of actual results that may occur, and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.

We are exposed to various market risks, including volatility in crude oil prices and interest rates. We have in the past used, and expect that in the future we will continue to use, various derivative instruments to manage such exposure. Our risk management policies and procedures are designed to monitor physical and financial commodity positions and the resulting outright commodity price risk as well as basis risk resulting from differences in commodity grades, purchase and sales locations and purchase and sale timing. We have a risk management function that has responsibility and authority for our Comprehensive Risk Management Policy, which governs our enterprise-wide risks, including the market risks discussed in this item. Subject to our Comprehensive Risk Management Policy, our finance and treasury function has responsibility and authority for managing exposure to interest rates.

Commodity Price Risk

The table below outlines the range of NYMEX prompt month daily settle prices for crude oil futures provided by an independent, third-party broker for the three months and six months ended June 30, 2012 and 2011 and for the years ended December 31, 2011 and 2010.

	Light Sweet Crude Oil Futures ($ per Barrel)			Light Sweet Crude Oil Futures ($ per Barrel)
Three Months Ended June 30, 2012			Three Months Ended June 30, 2011
High	$	106.16	High	$	113.93
Low	$	77.69	Low	$	90.61
High/Low Differential	$	28.47	High/Low Differential	$	23.32
Six Months Ended June 30, 2012			Six Months Ended June 30, 2011
High	$	109.77	High	$	113.93
Low	$	77.69	Low	$	84.32
High/Low Differential	$	32.08	High/Low Differential	$	29.61
Year Ended December 31, 2011			Year Ended December 31, 2010
High	$	113.93	High	$	91.51
Low	$	75.67	Low	$	68.01
High/Low Differential	$	38.26	High/Low Differential	$	23.50

Revenue from our asset-based activities is dependent on throughput volume, tariff rates, the level of fees generated from our pipeline systems, capacity contracted to third parties, capacity that we use for our own operational or marketing activities and the level of other fees generated at our storage facilities. Profit from our marketing activities is dependent on our ability to sell crude oil at prices in excess of our aggregate cost. Margins may be affected during transitional periods between a backwardated market (when the prices for future deliveries are lower than the current prices) and a contango market (when the prices for future deliveries are higher than the current prices). Our crude oil marketing activities are generally not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and relative fluctuations in marked-related indices.

Based on our open derivative contracts at June 30, 2012, a 10% increase in the applicable market price or prices for each derivative contract would result in an approximate $0.8 million decrease in the contribution from these derivatives to our crude oil sales revenues. A 10% decrease in the applicable market price or prices for each derivative contract would result in an approximate $0.8 million increase in the contribution from these derivatives to our crude oil sales revenues. However, the increases or decreases in crude oil sales revenues we recognize from our open derivative contracts are substantially offset by higher or lower crude oil sales revenues when the physical sale of the product occurs. These contracts may be for the purchase or sale of crude oil or in markets different from the physical markets in which we are attempting to hedge our exposure, or may have timing differences relative to the physical markets. As a result of these factors, our hedges may not eliminate all price risks.

Page 31

The notional volumes and fair value of our commodity derivatives open positions as well as the change in fair value that would be expected from a 10% market price increase or decrease is shown in the table below (in thousands):

	Notional Volume (Barrels)			Fair Value		Effect of 10% Price Increase			Effect of 10% Price Decrease		Settlement Date
Crude oil:
Futures contracts		(90	)	$	40	$	(765	)	$	765		July 2012

Margin deposits or other credit support, including letters of credit, are generally required on derivative instruments utilized to manage our price exposure. As commodity prices increase or decrease, the fair value of our derivative instruments changes, thereby increasing or decreasing our margin deposit or other credit support requirements. Although a component of our risk-management strategy is intended to manage the margin and other credit support requirements on our derivative instruments, volatile spot and forward commodity prices, or an expectation of increased commodity price volatility, could increase the cash needed to manage our commodity price exposure and thereby increase our liquidity requirements. This may limit amounts available to us through borrowing, decrease the volume of petroleum products we purchase and sell or limit our commodity price management activities.

Interest Rate Risk

We have exposure to changes in interest rates under our new credit facility. The credit markets have recently experienced historical lows in interest rates. If the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. Interest rates on our credit facility and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

We recorded interest expense related to our credit facility of $0.5 million and $1.0 million during the three months and six months ended June 30, 2012, respectively. An increase in interest rates of 1% would have increased our interest expense by $94 thousand and $171 thousand during the three months and six months ended June 30, 2012.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of our general partner have concluded that the design and operation of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective as of June 30, 2012. This conclusion is based on an evaluation conducted under the supervision and participation of the Chief Executive Officer and Chief Financial Officer of our general partner along with our management. Disclosure controls and procedures are those controls and procedures designed to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that such information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2012, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information regarding legal proceedings, see the discussion under the captions “Bankruptcy matters,” “Other matters,” “Environmental,” and “Blueknight Claim” in Note 4 of our unaudited condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report on Form 10-Q, which information is incorporated by reference into this Item 1.

Item 1A. Risk Factors

There have been no material changes to the risk factors involving us from those previously disclosed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The following exhibits are filed or furnished as part of this Quarterly Report on Form 10-Q:

Exhibit Number	Description
31.1	Rule 13a-14(a)/15d-14(a) Certification of Norman J. Szydlowski, Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Robert N. Fitzgerald, Chief Financial Officer.
32.1	Section 1350 Certification of Norman J. Szydlowski, Chief Executive Officer.
32.2	Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer.
101	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) the Condensed Consolidated Balance Sheets at June 30, 2012 and December 31, 2011, (ii) the Condensed Consolidated Statements of Income for the three months and six months ended June 30, 2012 and 2011, (iii) the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011, and (iv) the Notes to the Consolidated Financial Statements.

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SIGNATURE

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

Date: August 9, 2012	ROSE ROCK MIDSTREAM, L.P.
	By:	/s/ Robert N. Fitzgerald
		Robert N. Fitzgerald
		Senior Vice President and Chief Financial Officer

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EXHIBIT INDEX

The following exhibits are filed or furnished as part of this Quarterly Report on Form 10-Q:

Exhibit Number	Description
31.1	Rule 13a-14(a)/15d-14(a) Certification of Norman J. Szydlowski, Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Robert N. Fitzgerald, Chief Financial Officer.
32.1	Section 1350 Certification of Norman J. Szydlowski, Chief Executive Officer.
32.2	Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer.
101	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) the Condensed Consolidated Balance Sheets at June 30, 2012 and December 31, 2011, (ii) the Condensed Consolidated Statements of Income for the three months and six months ended June 30, 2012 and 2011, (iii) the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011, and (iv) the Notes to the Condensed Consolidated Financial Statements.

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