Rose Rock Midstream 10-Q 2014 Q1 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 March 31, 2014

OR

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

For the transition period from                     to                    

Commission File Number: 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  o

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

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

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

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

At April 30, 2014, there were 18,149,448 common units, 8,389,709 subordinated units and 2,500,000 Class A units outstanding.

Rose Rock Midstream, L.P.

TABLE OF CONTENTS

	PART I – FINANCIAL INFORMATION
Item 1	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets – March 31, 2014 and December 31, 2013	6
	Condensed Consolidated Statements of Income – Three Months Ended March 31, 2014 and 2013	7
	Condensed Consolidated Statements of Cash Flows – Three Months Ended March 31, 2014 and 2013	8
	Notes to Condensed Consolidated Financial Statements	9
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3	Quantitative and Qualitative Disclosures about Market Risk	33
Item 4	Controls and Procedures	35
	PART II – OTHER INFORMATION
Item 1	Legal Proceedings	36
Item 1A	Risk Factors	36
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3	Defaults Upon Senior Securities	36
Item 4	Mine Safety Disclosures	36
Item 5	Other Information	36
Item 6	Exhibits	36
	SIGNATURE	37

Cautionary Note Regarding Forward-Looking Statements

Certain matters contained in this Form 10-Q include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act'), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

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 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:

• Insufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to pay the minimum quarterly distribution;

• Any sustained reduction in demand for or supply of crude oil in markets served by our midstream assets;

• Our ability to obtain new sources of supply of crude oil;

• The amount of collateral required to be posted from time to time in our transactions;

• Competition from other midstream energy companies;

• Our ability to comply with the covenants contained in, and maintain certain financial ratios required by, our credit facility;

• Our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations and equity;

• Our ability to renew or replace expiring storage contracts;

• The loss of, or a material nonpayment or nonperformance by, any of our key customers;

• The overall forward market for crude oil;

• The possibility that our hedging activities may result in losses or may have a negative impact on our financial results;

• Weather and other natural phenomena;

• Hazards or operating risks incidental to the gathering, transporting or storing of crude oil;

• Changes in laws and regulations and our failure to comply with new or existing laws or regulations, particularly with regard to taxes, safety and protection of the environment;

• The possibility that the construction or acquisition of new assets may not result in the corresponding anticipated revenue increases; and

• General economic, market and business conditions.

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.

Investors and others should note that we announce material company information using our investor relations website (www.rrmidstream.com), SEC filings, press releases, public conference calls and webcasts. We use these channels, as well as social media, to communicate with our investors and the public about our company, our businesses and our results of

operations. The information we post on social media could be deemed to be material information. Therefore, we encourage investors, the media and others interested in our company to review the information we post on the social media channels listed on our investor relations website.

_________________________________________________________________________________________________

As used in this Form 10-Q, and unless the context indicates otherwise, the term(s) (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), and its subsidiaries and affiliates, other than our general partner and us; (iii) “Rose Rock GP” or our “general partner” refer 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

(In thousands, except unit amounts)

	(Unaudited)
	March 31, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	2,823		$	15,459
Accounts receivable	278,429			217,213
Receivable from affiliates	40,631			56,220
Inventories	25,765			30,779
Other current assets	1,992			1,916
Total current assets	349,640			321,587
Property, plant and equipment (net of accumulated depreciation of $57,996 and $56,533 at March 31, 2014 and December 31, 2013, respectively)	308,270			311,616
Equity method investment	234,742			224,095
Goodwill	28,224			28,322
Other intangible assets (net of accumulated amortization of $2,021 and $1,155 at March 31, 2014 and December 31, 2013, respectively)	4,859			5,775
Other noncurrent assets, net	5,654			5,852
Total assets	$	931,389		$	897,247
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	266,602		$	211,298
Payable to affiliates	46,916			69,274
Accrued liabilities	9,111			8,645
Other current liabilities	4,206			3,814
Total current liabilities	326,835			293,031
Long-term debt	244,578			245,088
Commitments and contingencies (Note 6)
Partners’ capital:
Common units – public (13,759,739 units issued and outstanding at March 31, 2014 and December 31, 2013)	159,950			159,961
Common units – SemGroup (4,389,709 units issued and outstanding at March 31, 2014 and December 31, 2013)	79,141			79,218
Subordinated units – SemGroup (8,389,709 units issued and outstanding at March 31, 2014 and December 31, 2013)	(5,526		)	(5,375		)
Class A units - SemGroup (2,500,000 units issued and outstanding at March 31, 2014 and December 31, 2013)	40,653			40,772
General partner	6,232			5,995
Total Rose Rock Midstream, L.P. partners' capital	280,450			280,571
Noncontrolling interests in consolidated subsidiary	79,526			78,557
Total equity	359,976			359,128
Total liabilities and equity	$	931,389		$	897,247

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

Page 6

ROSE ROCK MIDSTREAM, L.P.

Unaudited Condensed Consolidated Statements of Income

(In thousands, except per unit data)

	Three Months Ended March 31,
	2014			2013
Revenues, including revenues from affiliates (Note 9):
Product	$	266,290		$	158,728
Service	24,633			12,504
Total revenues	290,923			171,232
Expenses, including expenses from affiliates (Note 9):
Costs of products sold, exclusive of depreciation and amortization	254,537			148,451
Operating	14,878			5,418
General and administrative	3,623			3,561
Depreciation and amortization	10,534			3,507
Total expenses	283,572			160,937
Earnings from equity method investment	11,080			3,453
Operating income	18,431			13,748
Interest expense	2,272			1,754
Net income	16,159			11,994
Less: net income attributable to noncontrolling interests	3,676			—
Net income attributable to Rose Rock Midstream, L.P.	$	12,483		$	11,994
Net income allocated to general partner	$	738		$	281
Net income allocated to common unitholders	$	8,114		$	6,767
Net income allocated to subordinated unitholders	$	3,750		$	4,773
Net income (loss) allocated to Class A unitholders	$	(119	)	$	173
Earnings (loss) per limited partner unit (Note 8):
Common unit (basic)	$	0.45		$	0.59
Common unit (diluted)	$	0.45		$	0.59
Subordinated unit (basic and diluted)	$	0.45		$	0.57
Class A unit (basic and diluted)	$	(0.05	)	$	0.16
Basic weighted average number of limited partner units outstanding:
Common units	18,149			11,465
Subordinated units	8,390			8,390
Class A units	2,500			1,097
Diluted weighted average number of limited partner units outstanding:
Common units	18,198			11,491
Subordinated units	8,390			8,390
Class A units	2,500			1,097

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

Page 7

ROSE ROCK MIDSTREAM, L.P.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

	Three Months Ended March 31,
	2014			2013
Cash flows from operating activities:
Net income	$	16,159		$	11,994
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	10,534			3,507
Gain on disposal of long-lived assets, net	(34		)	—
Amortization of debt issuance costs	260			198
Non-cash equity compensation	260			143
Net unrealized (gain) loss related to derivative instruments	606			(468		)
Earnings from equity method investment	(11,080		)	(3,453		)
Cash distributions from equity method investment	11,080			2,892
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	(61,216		)	(8,504		)
Decrease (increase) in receivable from affiliates	15,589			(177		)
Decrease (increase) in inventories	3,238			182
Decrease (increase) in other current assets	(76		)	1,137
Increase (decrease) in accounts payable and accrued liabilities	55,426			526
Increase (decrease) in payable to affiliates	(22,358		)	1,938
Net cash provided by operating activities	18,388			9,915
Cash flows from investing activities:
Capital expenditures	(4,908		)	(6,479		)
Proceeds from sale of long-lived assets	650			—
Investments in non-consolidated affiliate	(13,152		)	(53,898		)
Distributions in excess of equity in earnings of affiliates	2,505			—
Net cash used in investing activities	(14,905		)	(60,377		)
Cash flows from financing activities:
Debt issuance costs	(62		)	(1,610		)
Borrowings on revolving credit facility	46,000			191,500
Principal payments on revolving credit facility	(46,500		)	(43,500		)
Principal payments on capital lease obligations	(9		)	(6		)
Proceeds from common L.P. unit issuance, net of offering costs	—			57,886
Cash consideration in excess of historical cost of interest in SemCrude Pipeline, L.L.C.	—			(143,216		)
Cash distributions to partners	(12,841		)	(8,331		)
Cash distributions to noncontrolling interests	(4,324		)	—
Contributions from noncontrolling interests	1,617			—
Net cash provided by (used in) financing activities	(16,119		)	52,723
Net increase (decrease) in cash and cash equivalents	(12,636		)	2,261
Cash and cash equivalents at beginning of period	15,459			108
Cash and cash equivalents at end of period	$	2,823		$	2,369

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

Page 8

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

1. OVERVIEW

Rose Rock Midstream, L.P. is a Delaware limited partnership. 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.

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, and its subsidiaries. The term “SemGroup” refers to SemGroup Corporation and its controlled subsidiaries, including Rose Rock Midstream GP, LLC.

Basis of presentation

These condensed consolidated financial statements include the accounts of Rose Rock Midstream, L.P. and its controlled subsidiaries.

The condensed consolidated balance sheet at December 31, 2013, which is derived from audited financial statements, and the unaudited condensed consolidated interim 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 Partnership 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.

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 ended March 31, 2014, are not necessarily indicative of the results to be expected for the full year ending December 31, 2014.

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 consolidated financial statements and notes thereto for the year ended December 31, 2013, which are included in our Annual Report on Form 10-K for the year ended December 31, 2013, 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, 2013.

2. INVESTMENT IN NON-CONSOLIDATED AFFILIATE

SemCrude Pipeline, L.L.C.

Prior to our December 16, 2013 acquisition of additional ownership interests in SemCrude Pipeline, L.L.C. ("SCPL") (Note 3), we accounted for our interest in SCPL under the equity method. Under the equity method, we did not report the individual assets and liabilities of SCPL on our consolidated balance sheets. Instead, our membership interest was reflected in one line as a noncurrent asset on our consolidated balance sheets. Subsequent to our acquisition of additional ownership interest, we have consolidated SCPL and report a noncontrolling interest for the ownership interest in SCPL which was retained by SemGroup. Prior to consolidation, for the three months ended March 31, 2013, we recorded equity in earnings of SCPL of $3.5 million and received $2.9 million of cash distributions related to earnings for January and February 2013, as distributions are paid on a one-month lag.

SCPL's only substantial asset is a 51% interest in White Cliffs Pipeline, L.L.C. ("White Cliffs"), which is accounted for under the equity method.

White Cliffs Pipeline, L.L.C.

Under the equity method, we do not report the individual assets and liabilities of White Cliffs. Instead, our membership interest is reflected in one line as a noncurrent asset on our condensed consolidated balance sheets.

For the three months ended March 31, 2014, we recorded equity in earnings of White Cliffs of $11.1 million and received $13.6 million of cash distributions, of which, approximately 33% was distributed to SemGroup related to their noncontrolling interest in SCPL.

Page 9

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

2.    INVESTMENT IN NON-CONSOLIDATED AFFILIATE, Continued    

Certain summarized income statement information of White Cliffs for the three months ended March 31, 2014 and 2013 is shown below (in thousands):

	Three Months Ended March 31,
	2014		2013
Revenues	$	33,274	$	30,673
Operating, general and administrative expenses	$	6,768	$	5,179
Depreciation and amortization expense	$	4,393	$	4,715
Net income	$	22,113	$	20,779

The equity in earnings of White Cliffs for the three months ended March 31, 2014 and 2013 is less than 51% of the net income of White Cliffs for the same periods. This is due to certain general and administrative expenses incurred in managing the operations of White Cliffs that the other owners are not obligated to share. Such expenses are recorded by White Cliffs and are allocated to our ownership interest. White Cliffs recorded $0.4 million and $0.3 million of such general and administrative expense for the three months ended March 31, 2014 and 2013, respectively.

The members of SCPL are required to fund SCPL's capital contribution requirements for White Cliffs related to an expansion project adding a 12-inch line from Platteville, Colorado to Cushing, Oklahoma. For the three months ended March 31, 2014, on a consolidated basis, we contributed $12.8 million to White Cliffs. Remaining contributions will be made in 2014 and are expected to total $40.6 million, of which one-third will be funded directly by SemGroup which holds the noncontrolling interest in SCPL.

3. ACQUISITIONS

During the year ended December 31, 2013, we completed the following acquisitions:

• On January 11, 2013, we acquired a 33% interest in SCPL from SemGroup for (i) cash of approximately $189.5 million, (ii) the issuance of 1.5 million common units, (iii) the issuance of 1.25 million Class A units, and (iv) an increase of the capital account of our general partner and a related issuance of general partner interest, to allow our general partner to maintain its 2% general partner interest in us. SCPL owns a 51% membership interest in White Cliffs. Subsequent to the transaction, our condensed consolidated financial statements reflected our ownership in SCPL on an equity method basis. As the transaction was between entities under common control, we recorded our investment in SCPL based on SemGroup's historical cost. The purchase price in excess of historical cost was treated as an equity transaction with SemGroup, which reduced the partners' capital accounts of our general and limited partners on a pro-rata basis.

• On September 1, 2013, we completed the acquisition of the assets of Barcas Field Services, L.L.C. for $49.0 million. During the three months ended March 31, 2014, we recorded a non-cash adjustment to the purchase price allocation which decreased goodwill and other intangible assets by $0.1 million with an offsetting increase to property, plant and equipment.

• On November 8, 2013, we acquired a 12-mile, 12-inch crude oil pipeline from Noble Energy, Inc. that extends from Platteville, Colorado to Tampa, Colorado for a purchase price of $8.2 million.

• On December 16, 2013, we acquired an additional 33% interest in SCPL from SemGroup in exchange for (i) cash of approximately $173.1 million, (ii) the issuance of 1.5 million common units, (iii) the issuance of 1.25 million Class A units, and (iv) an increase of the capital account of our general partner and a related issuance of general partner interest, to allow our general partner to maintain its 2% general partner interest in us. Subsequent to the transaction, we consolidated SCPL and our condensed consolidated financial statements reflect our ownership of White Cliffs under the equity method. As the transaction was between entities under common control, we recorded our investment in White Cliffs based on SemGroup's historical cost. The purchase price in excess of historical cost was treated as an equity transaction with SemGroup, which reduced the partners' capital accounts of our general and limited partners on a pro-rata basis.

Page 10

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

4. 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 can be comprised of crude oil and natural gas liquids forward contracts and futures contracts. These are defined as follows:

Forward contracts – Over the counter ("OTC") 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 commodity derivative assets and liabilities at fair value at each balance sheet date with the exception of commitments which have been designated as normal purchases and sales. The table below summarizes the balances of these assets and liabilities at March 31, 2014 and December 31, 2013 (in thousands):

	March 31, 2014								December 31, 2013
	Level 1			Netting*		Total			Level 1			Netting*			Total
Assets	$	—		$	—	$	—		$	36		$	(36	)	$	—
Liabilities	666			—		666			96			(36		)	60
Net assets (liabilities) at fair value	$	(666	)	$	—	$	(666	)	$	(60	)	$	—		$	(60	)

* 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 are based on inputs consisting of unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. These include commodity futures contracts that are traded on an exchange.

“Level 2” measurements are based on inputs consisting of market observable and corroborated prices for similar derivative contracts. Assets and liabilities classified as Level 2 include OTC traded physical fixed priced purchases and sales forward contracts.

“Level 3” measurements are based on inputs from a pricing service and/or internal valuation models incorporating observable and unobservable market data.

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 March 31, 2014, 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 2 or Level 3 during the three months ended March 31, 2014 and 2013, as such no rollforward of activity has been presented.

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

Page 11

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

4. FINANCIAL INSTRUMENTS, Continued

	Three Months Ended March 31,
	2014	2013
Sales	815	610
Purchases	810	675

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):

	March 31, 2014				December 31, 2013
	Assets		Liabilities		Assets		Liabilities
Commodity contracts	$	—	$	666	$	—	$	60

We have posted margin deposits as collateral with brokers who have the right of set off associated with these funds. Our margin deposit balances were $1.4 million and $0.8 million as of March 31, 2014 and December 31, 2013, respectively. These margin account balances have not been offset against our net commodity derivative instrument (contract) positions. Had these margin account balances been netted against our net commodity derivative instrument (contract) positions as of March 31, 2014 and December 31, 2013, we would have had net asset positions of $0.7 million and $0.8 million, respectively.

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

	Three Months Ended March 31,
	2014			2013
Commodity contracts	$	(807	)	$	(544	)

Concentrations of risk

During the three months ended March 31, 2014, two third-party customers accounted for approximately 65% of our consolidated revenue. We purchased approximately $130 million of product from two third-party suppliers, which represented approximately 51% of our costs of products sold. At March 31, 2014, four third-party customers and one related party accounted for 78% of our consolidated accounts receivable.

5. LONG-TERM DEBT

Revolving credit facility

At March 31, 2014, we had outstanding borrowings of $244.5 million on our $585 million revolving credit facility, of which $19.5 million incurred interest at the alternate base rate ("ABR") plus an applicable margin, and $225 million incurred interest at the Eurodollar rate plus an applicable margin. The interest rate in effect at March 31, 2014, on $19.5 million of ABR borrowings was 4.0%. The interest rate in effect at March 31, 2014, on $225 million of Eurodollar rate borrowings was 1.99%.

We had $42.4 million in outstanding letters of credit at March 31, 2014 and the rate per annum was 1.75%. 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.

At March 31, 2014, we had $73.6 million of secured bilateral letters of credit outstanding. The interest rate in effect was 1.75%. Secured bilateral letters of credit are external to the facility and do not reduce revolving credit facility availability.

At March 31, 2014, we were in compliance with the terms of the credit agreement.

Page 12

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

5. LONG-TERM DEBT, Continued

At March 31, 2014, $4.6 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.

At March 31, 2014, we had $38 thousand ($116 thousand including current portion) of capital lease obligations reported as long-term debt on the consolidated balance sheet.

We estimate that the fair value of our long-term debt was not materially different than the reported values at March 31, 2014, and is categorized as a Level 3 measurement. It is our belief that neither the market interest rates nor our credit profile have changed significantly enough to have had a material impact on the fair value of our debt outstanding at March 31, 2014.

6. COMMITMENTS AND CONTINGENCIES

Bankruptcy matters

On July 22, 2008 (the “Petition Date”), SemGroup, L.P., SemCrude, L.P. (“SemCrude”), the predecessor of Rose Rock, 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, SemCrude, and Eaglwing emerged from bankruptcy protection on November 30, 2009 (the “Emergence Date”).

(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 SemGroup's 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. On August 27, 2013, the United States Court of Appeals for the Third Circuit issued an opinion, and on September 18, 2013 issued a judgment, reversing the District Court’s dismissal of the confirmation order and remanding the case to the District Court for consideration on the merits of Luke Oil’s appeal of the confirmation order. On October 1, 2013, at the request of the parties, the District Court entered an order staying the case and referring it to a magistrate judge for mediation. On January 28, 2014, the parties reached agreement to settle all outstanding disputes. A settlement agreement was executed by the parties pursuant to which each party granted the other a release of claims and causes of action and on March 5, 2014 the appeal was dismissed. We are indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement with SemGroup.

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.

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.

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

6. COMMITMENTS AND CONTINGENCIES, Continued

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. We are indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement with SemGroup.

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. We are indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement with SemGroup.

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 assisting Blueknight with movement of crude oil belonging to Blueknight’s customers and with 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 perform all services necessary for the movement of its crude oil and the operation of its Cushing terminal without SemCrude's assistance.

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 Blueknight was requested to substantiate its claim, Blueknight filed suit against SemGroup and other related companies in the District Court of Oklahoma County, Oklahoma. On May 1, 2012, the case was transferred to Tulsa County, Oklahoma. On July 2, 2012, the Tulsa County District Court appointed a Special Master to review terminal operations accounting records and determine whether 141,000 barrels of crude oil owned by Blueknight is missing after three months of operations in April through June, 2010. On June 11, 2013, the Special Master’s Report was filed with the District Court finding a shortage in Blueknight’s Cushing terminal and Oklahoma pipeline system of 148,000 barrels. However, after a review of all records created during that three month time period, the Special Master was unable to determine how the shortage might have occurred and was unable to determine the ownership of the potential shortage.

We are currently seeking discovery in the District Court of documentation and testimony on the potential cause and the impact, if any, of the shortage found by the Special Master. On February 20, 2014, the District Court issued an order denying all requests for summary judgment and ordering discovery to go forward. SemGroup will continue to defend its position; however, we cannot predict the outcome. We are indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement with SemGroup.

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

6. 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 derivatives at fair value with the exception of commitments which have been designated as normal purchases and sales, for which we do not record assets or liabilities related to these agreements until the product is purchased or sold. At March 31, 2014, such commitments included the following (in thousands):

	Volume (Barrels)	Value
Fixed price purchases	100	$	9,027
Fixed price sales	115	$	11,525
Floating price purchases	11,593	$	1,123,992
Floating price sales	12,006	$	1,171,662

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.

See Note 2 for commitments related to the White Cliffs Pipeline expansion.

7. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Unaudited condensed consolidated statement of changes in partners’ capital

The following table shows the changes in our partners’ capital accounts from December 31, 2013 to March 31, 2014 (in thousands):

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

7. PARTNERS’ CAPITAL AND DISTRIBUTIONS, Continued

	Common Units - Public			Common Units - SemGroup			Subordinated Units			Class A Units			General Partner Interest			Non-controlling Interests			Total Equity
Balance at December 31, 2013	$	159,961		$	79,218		$	(5,375	)	$	40,772		$	5,995		$	78,557		$	359,128
Net income	6,150			1,964			3,750			(119		)	738			3,676			16,159
Cash distributions to noncontrolling interest in SemCrude Pipeline	—			—			—			—			—			(4,324		)	(4,324		)
Contributions from noncontrolling interest in SemCrude Pipeline	—			—			—			—			—			1,617			1,617
Unvested distribution equivalent rights	(23		)	—			—			—			—			—			(23		)
Cash distributions to partners	(6,398		)	(2,041		)	(3,901		)	—			(501		)	—			(12,841		)
Non-cash equity compensation	260			—			—			—			—			—			260
Balance at March 31, 2014	$	159,950		$	79,141		$	(5,526	)	$	40,653		$	6,232		$	79,526		$	359,976

The following table shows the cash distributions paid or declared per common limited partner unit during 2014 and 2013:

Quarter Ended	Record Date	Payment Date	Distribution Per Unit
December 31, 2012	February 4, 2013	February 14, 2013	$0.4025
March 31, 2013	May 6, 2013	May 15, 2013	$0.4300
June 30, 2013	August 5, 2013	August 14, 2013	$0.4400
September 30, 2013	November 5, 2013	November 14, 2013	$0.4500
December 31, 2013	February 4, 2014	February 14, 2014	$0.4650
March 31, 2014	May 5, 2014	May 15, 2014	$0.4950

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 granted 24,389 restricted unit awards during the three months endedMarch 31, 2014, with a weighted average grant date fair value of $38.93. At March 31, 2014, there are 107,337 unvested restricted unit awards that have been granted pursuant to the Incentive Plan. There were no vestings of restricted unit awards during the three months endedMarch 31, 2014.

The holders of restricted units granted in 2012 are entitled to equivalent distributions (“UUDs”) to be received upon vesting of the restricted unit awards. At March 31, 2014, the value of these UUDs related to unvested restricted units was approximately $117 thousand. This is equivalent to 2,830 common units, based on the quarter end close of business market price of our common units of $41.49 per unit. Distributions related to the restricted unit awards granted subsequent to 2012 will be settled in cash upon vesting. At March 31, 2014, the value of these UUDs related to cash settled unvested restricted units was approximately $74 thousand.

On April 1, 2014, we granted 17,647 restricted unit awards. These awards will be ratably vested over five years.

Equity issuance

On August 13, 2013, we issued 4,750,000 common limited partner units to the public for proceeds of $152.5 million, net of underwriting discounts and commissions of $6.4 million. Our general partner contributed $3.2 million to the Partnership to maintain its 2% ownership. Proceeds were used to repay borrowings on our credit facility.

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

8. 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, such as 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.

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months ended March 31, 2014 and 2013 (in thousands, except per unit data):

	Three Months Ended March 31,
	2014			2013
Net income	$	12,483		$	11,994
Less: General partner's incentive distribution earned	488			41
Less: General partner's 2.0% ownership	250			240
Net income allocated to limited partners	$	11,745		$	11,713
Numerator for basic and diluted earnings per limited partner unit (*):
Allocation of net income among limited partner interests:
Net income allocable to common units	$	8,114		$	6,767
Net income allocable to subordinated units	3,750			4,773
Net income (loss) allocable to Class A units	(119		)	173
Net income allocated to limited partners	$	11,745		$	11,713
Denominator for basic and diluted earnings per limited partner unit:
Basic weighted average number of common units outstanding	18,149			11,465
Effect of non-vested restricted units	49			26
Diluted weighted average number of common units outstanding	18,198			11,491
Basic and diluted weighted average number of subordinated units outstanding	8,390			8,390
Basic and diluted weighted average number of Class A units outstanding	2,500			1,097
Net income per limited partner unit:
Common unit (basic)	$	0.45		$	0.59
Common unit (diluted)	$	0.45		$	0.59
Subordinated unit (basic and diluted)	$	0.45		$	0.57
Class A unit (basic and diluted)	$	(0.05	)	$	0.16

(*) We calculate net income allocated to limited partners based on the distributions pertaining to the current period’s available cash as defined by our partnership agreement. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, limited partners and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method. Incentive distribution rights do not participate in undistributed earnings. Class A units do not participate in cash distributions, but are allocated a proportional share of undistributed earnings.

9. 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 $6.2 million and $2.9 million during the three months ended March 31, 2014 and

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

9. RELATED PARTY TRANSACTIONS, Continued

2013, 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 $1.8 million and $1.3 million during the three months ended March 31, 2014 and 2013, respectively, for such allocated costs. These expenses were recorded to general and administrative expenses in our condensed consolidated statements of income.

NGL Energy Partners LP and subsidiaries (Gavilon, LLC and High Sierra Crude Oil and Marketing, LLC)

SemGroup holds limited partner common units and general partner ownership interests in NGL Energy Partners LP (“NGL Energy”). We generated revenues from NGL Energy of $134.1 million and $161.4 million for the three months ended March 31, 2014 and 2013, respectively. We made purchases of condensate at market prices from NGL Energy in the amount of $157.7 million and $139.9 million for the three months ended March 31, 2014 and 2013, respectively. We received reimbursements from NGL Energy for support services in the amount of $42.0 thousand and $42.0 thousand for the three months ended March 31, 2014 and 2013. Transactions with NGL Energy and its subsidiaries primarily relate to marketing, leased storage and transportation services of crude oil, including buy/sell transactions. In accordance with ASC 845-10-15, these transactions were reported as revenue on a net basis in our condensed consolidated statements income because the purchases of inventory and subsequent sales of the inventory were with the same counterparty. For comparability, prior year amounts above have been recast to include transactions with Gavilon, LLC, which was not a related party until December 2013.

SemGas, L.P.

We purchase condensate at market prices from SemGas, L.P. (“SemGas”), which is a wholly-owned subsidiary of SemGroup. Purchases from SemGas were $9.9 million and $4.1 million for the three months ended March 31, 2014 and 2013, respectively.

White Cliffs

We generated storage revenues from our equity investee, White Cliffs, of $0.8 million and $0.6 million for the three months ended March 31, 2014 and 2013, respectively. We incurred $0.9 million of cost for the three months ended March 31, 2014 related to transportation fees for shipments on White Cliffs.

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. We paid $0.1 million and $0.1 million in legal fees and related expenses to this law firm during the three months ended March 31, 2014 and 2013 (of which $54.0 thousand was paid by White Cliffs during the three months ended March 31, 2014).

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

10. SUPPLEMENTAL CASH FLOW INFORMATION

Acquisition

In the first quarter of 2013, in connection with the acquisition of a 33% interest in SCPL (Note 3), we issued 1.5 million common units and 1.25 million Class A units, valued at $44.4 million and $30.5 million, respectively, as non-cash consideration to SemGroup. In addition, a non-cash contribution of $2.7 million was recorded to the general partner's capital account.

As the transaction occurred between parties under common control, the purchase price in excess of SemGroup's historical cost of the 33% interest in SCPL was treated as an equity transaction with SemGroup, which reduced the partners' capital accounts pro-rata based on ownership percentages. Of the $221.0 million of purchase price in excess of historical cost, $143.2 million represented cash consideration in excess of historical cost and the remaining $77.8 million reduction represented the non-cash portion of the transaction related to equity consideration.

Other supplemental disclosures

We paid cash interest of $2.0 million and $0.4 million for the three months endedMarch 31, 2014 and 2013, respectively.

We accrued $0.3 million and $0.5 million for purchases of property, plant and equipment for the three months endedMarch 31, 2014 and 2013, respectively.

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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 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, 2013, filed with the Securities and Exchange Commission (the "SEC").

Overview of Business

We are a growth-oriented Delaware limited partnership formed by SemGroup Corporation ("SemGroup") in 2011 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, distribution and marketing in Colorado, Kansas, Louisiana, Montana, New Mexico, North Dakota, Oklahoma, Texas and Wyoming. 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 Denver-Julesburg Basin ("DJ Basin") and the Niobrara Shale in the Rocky Mountain region, and the Granite Wash and the Mississippi Lime Play 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 ("U.S."). 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.

Fee-Based Services

We charge a capacity or volume-based fee for the storage and transportation of crude oil and related ancillary services. Our fee-based services include substantially all of our operations in Cushing, Oklahoma and Platteville, Colorado, as well as trucking 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 March 31, 2014 and 2013, approximately 72% and 56%, respectively, of our Adjusted gross margin was generated by providing fee-based services to customers. (See “—How We Evaluate Our Operations —Adjusted Gross Margin” for definition of Adjusted Gross Margin.)

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 March 31, 2014 and 2013, approximately 10% and 22%, respectively, of our Adjusted gross margin was generated through fixed-margin transactions. (See “—How We Evaluate Our Operations—Adjusted Gross Margin” for definition of Adjusted Gross Margin.)

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 by using our pipeline, trucking and storage assets to capture location and quality differentials, including blending different crude oil grades to meet the refiners' preferred crude oil specifications. For the three months ended March 31, 2014 and 2013, approximately 18% and 22%, respectively, of our Adjusted gross margin was generated through marketing activities. (See “—How We Evaluate Our Operations—Adjusted Gross Margin” for definition of Adjusted Gross Margin.)

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 use 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. When we purchase crude oil, we may establish either a fixed or a 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

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•entering into futures and swaps contracts on the NYMEX or over-the-counter markets.

Our Property, Plant and Equipment

We own and operate all of our assets, which at March 31, 2014 include:

• 7.6 million barrels of crude oil storage capacity in Cushing, Oklahoma, of which 7.1 million barrels are leased to customers and an additional 500,000 barrels are used for crude oil operations;

• a 580-mile crude oil gathering and transportation pipeline system with over 620,000 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, Oklahoma;

• a crude oil gathering, storage, transportation and marketing business in the Bakken Shale in North Dakota and Montana in which we handled and marketed an average of 4,100 barrels of crude oil per day for the three months ended March 31, 2014;

• a 12-mile crude oil pipeline that connects our Platteville, Colorado crude oil terminal to the Tampa, Colorado crude oil market;

• a crude oil trucking fleet of over 130 transport trucks and 150 trailers; and

• a modern, sixteen-lane crude oil truck unloading facility with 230,000 barrels of associated storage capacity in Platteville, Colorado which connects to the origination point of the White Cliffs Pipeline.

Our Investment in White Cliffs Pipeline, L.L.C.

SemCrude Pipeline, L.L.C. ("SCPL") owns a 51% interest in White Cliffs Pipeline, L.L.C. ("White Cliffs"), which owns a 527-mile pipeline system that transports crude oil from Platteville, Colorado in the DJ Basin to Cushing, Oklahoma (the "White Cliffs Pipeline"). In January 2013, we purchased a one-third interest in SCPL from SemGroup, which was effectively a purchase of a 17% interest in White Cliffs. In December 2013, we purchased an additional one-third interest in SCPL from SemGroup, resulting in our owning a 67% interest in SCPL and indirectly owning a 34% interest in White Cliffs. We account for our ownership in SCPL as a consolidated subsidiary. White Cliffs is executing an expansion project which will increase the capacity of the pipeline from approximately 76,000 barrels per day to about 150,000 barrels per day. The expansion is anticipated to be in service in the third quarter of 2014. We operate the White Cliffs Pipeline and will operate the expanded pipeline.

Recent Developments

Much of the crude oil produced from shale formations in the U.S. is sweet, (i.e., low sulfur), with a relatively high specific gravity. This is not ideal for refineries which were designed to process crude oil that contains more sulfur and with lower specific gravity. We see an opportunity for potential profit by combining various crude oil types to produce a blended crude oil which is well suited to the refiners' preference. In order to acquire the tankage needed for such blending, we have arranged to take 600 thousand barrels of tankage out of leased storage service beginning in May 2014.

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 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

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environments because it measures the spread between the product sales price and cost of products sold. See “—Non-GAAP Financial Measures.”

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.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation and amortization, earnings from equity method investments and any other non-cash adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities plus cash distributions from equity method investments. 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, in our Bakken Shale operations and through our trucking fleet operations, 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, using our pipelines, trucking and storage assets, we conduct marketing activities involving the purchase and sale of crude oil or related derivative contracts and crude oil blending. We refer to the crude oil volumes purchased and sold or blended 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.

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 ended March 31, 2014 and 2013 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 Adjusted gross margin to operating income and of Adjusted EBITDA to net income and net cash provided by operating activities, their most directly comparable financial measures calculated and presented in accordance with GAAP, please see “—Non-GAAP Financial Measures” below.

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	Three Months Ended March 31,
(in thousands, except per unit and operating data)	2014			2013
Statements of income data:
Revenues, including revenues from affiliates:
Product	$	266,290		$	158,728
Service	24,633			12,504
Total revenues	290,923			171,232
Expenses, including expenses from affiliates:
Costs of products sold, exclusive of depreciation and amortization	254,537			148,451
Operating	14,878			5,418
General and administrative	3,623			3,561
Depreciation and amortization	10,534			3,507
Total expenses	283,572			160,937
Earnings from equity investment method	11,080			3,453
Operating income	18,431			13,748
Interest expense	2,272			1,754
Net income	16,159			11,994
Net income attributable to noncontrolling interests	3,676			—
Net income attributable to Rose Rock Midstream, L.P.	$	12,483		$	11,994
Net income per common unit (basic)	$	0.45		$	0.59
Net income per common unit (diluted)	$	0.45		$	0.59
Net income per subordinated unit (basic and diluted)	$	0.45		$	0.57
Net income (loss) per Class A unit (basic and diluted)	$	(0.05	)	$	0.16
Distributions paid per common and subordinated unit	$	0.4650		$	0.4025
Statements of cash flows data:
Net cash provided by (used in):
Operating activities	$	18,388		$	9,915
Investing activities	$	(14,905	)	$	(60,377	)
Financing activities	$	(16,119	)	$	52,723
Other financial data:
Adjusted gross margin	$	36,992		$	22,313
Adjusted EBITDA	$	27,774		$	16,369
Capital expenditures	$	4,908		$	6,479
Investments in non-consolidated affiliate (White Cliffs)	$	13,152		$	53,898
Operating data:
Cushing storage capacity (MMBbls as of period end)	7.600			7.250
Percent of Cushing storage capacity contracted (as of period end)	93		%	97		%
Transportation volumes (average Bbls/day)	109,900			55,700
Marketing volumes (average Bbls/day)	49,600			24,100
Unloading/Platteville volumes (average Bbls/day)	63,200			62,200

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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 before interest expense, income tax expense (benefit), depreciation and amortization, earnings from equity method investments, and any other non-cash adjustments to reconcile net income to net cash provided by operating activities plus cash distributions from equity method investments.

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 is the GAAP measure most directly comparable to Adjusted gross margin, and net income and cash provided by 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, net income and net cash provided by 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 tables present a reconciliation of: (i) operating income to Adjusted gross margin, and (ii) net income and net cash provided by (used in) operating activities to Adjusted EBITDA, the most directly comparable GAAP financial measures for each of the periods indicated.

	Three Months Ended March 31,
(Unaudited; in thousands)	2014			2013
Reconciliation of operating income to Adjusted gross margin:
Operating income	$	18,431		$	13,748
Add:
Operating expense	14,878			5,418
General and administrative expense	3,623			3,561
Depreciation and amortization	10,534			3,507
Less:
Earnings from equity method investment	11,080			3,453
Impact from derivatives instruments:
Total loss on derivatives, net	(807		)	(544		)
Total realized loss (cash flow) on derivatives, net	201			1,012
Non-cash unrealized gain (loss) on derivatives, net	(606		)	468
Adjusted gross margin	$	36,992		$	22,313

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	Three Months Ended March 31,
(Unaudited; in thousands)	2014			2013
Reconciliation of net income to Adjusted EBITDA:
Net income	$	16,159		$	11,994
Add:
Interest expense	2,272			1,754
Depreciation and amortization	10,534			3,507
Cash distributions from equity method investment	13,585			2,892
Non-cash equity compensation	260			143
Gain on disposal of long-lived assets, net	(34		)	—
Less:
Earnings from equity method investment	11,080			3,453
White Cliffs cash distributions attributable to noncontrolling interests	4,528
Impact from derivative instruments:
Total loss on derivatives, net	(807		)	(544		)
Total realized loss (cash flow) on derivatives, net	201			1,012
Non-cash unrealized gain (loss) on derivatives, net	(606		)	468
Adjusted EBITDA	$	27,774		$	16,369

	Three Months Ended March 31,
(Unaudited; in thousands)	2014			2013
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	18,388		$	9,915
Less:
Changes in operating assets and liabilities, net	(9,397		)	(4,898		)
White Cliffs cash distributions attributable to noncontrolling interests	4,528			—
Add:
Interest expense, excluding amortization of debt issuance costs	2,012			1,556
Distributions in excess of equity in earnings of affiliates	2,505			—
Adjusted EBITDA	$	27,774		$	16,369

Adjusted Gross Margin

The following table shows the calculation of Adjusted gross margin for the three months ended March 31, 2014 and 2013 (in thousands):

	Three Months Ended March 31,
	2014			2013
Revenue
Product	$	266,290		$	158,728
Service	24,633			12,504
Total Revenues	290,923			171,232
Less: Cost of products sold, exclusive of depreciation and amortization	254,537			148,451
Less: Non-cash unrealized gain (loss) on derivatives, net	(606		)	468
Adjusted gross margin	$	36,992		$	22,313

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Three months ended March 31, 2014 vs. three months ended March 31, 2013

The following tables show the Adjusted gross margin generated by our fee-based services, our fixed-margin transactions and our marketing activities for the three months ended March 31, 2014 and 2013 (in thousands):

Three Months Ended March 31, 2014	Storage		Transportation (1)		Marketing Activities			Other (2)		Total
Revenues	$	8,480	$	18,720	$	260,454		$	3,269	$	290,923
Less: Costs of products sold, exclusive of depreciation and amortization	—		—		254,537			—		254,537
Less: Unrealized gain (loss) on derivatives, net	—		—		(606		)	—		(606		)
Adjusted gross margin	$	8,480	$	18,720	$	6,523		$	3,269	$	36,992

(1) Transportation revenue is comprised of $1.4 million, $13.5 million and $3.8 million, related to pipeline transportation (fixed-fee), trucking (fixed-fee) and buy/sells (fixed margin), respectively.

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

Three Months Ended March 31, 2013	Storage		Transportation (1)		Marketing Activities		Other (2)		Total
Revenues	$	8,367	$	5,776	$	153,816	$	3,273	$	171,232
Less: Costs of products sold, exclusive of depreciation and amortization	—		—		148,451		—		148,451
Less: Unrealized gain (loss) on derivatives, net	—		—		468		—		468
Adjusted gross margin	$	8,367	$	5,776	$	4,897	$	3,273	$	22,313

(1) Transportation revenue is comprised of $0.9 million and $4.9 million, related to pipeline transportation (fixed-fee) and buy/sells (fixed margin), respectively.

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

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 table.) Adjusted gross margin increased in the three months ended March 31, 2014, to $37.0 million from $22.3 million in the three months ended March 31, 2013, due to:

• due to a higher concentration of short-haul activity, an increase in pipeline transportation volumes of approximately 1.0 million barrels, resulting in a $0.5 million decrease in Adjusted gross margin during the three months ended March 31, 2014, compared to the same period in 2013;

• truck transportation volumes of 3.8 million barrels generating an additional $13.5 million in Adjusted gross margin, reflecting the acquisition of trucking operations in September 2013. Related trucking costs are included in operating expense described below;

• a decrease in pumpover activity at Cushing, resulting in a $0.2 million decrease in Adjusted gross margin during the three months ended March 31, 2014, compared to the same period in 2013;

• an increase in unloading volumes from our Platteville operations of approximately 0.1 million barrels, contributing an additional $0.1 million Adjusted gross margin, during the three months ended March 31, 2014, compared to the same period in 2013;

• an increase in marketing volume of approximately 2.3 million barrels in the three months ended March 31, 2014, over the same period in 2013, 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 $1.74 for the three months ended March 31, 2014, from approximately $2.26 for the three months ended March 31, 2013. This resulted in a $1.6 million increase in Adjusted gross margin during the three months ended March 31, 2014, compared to the same period in 2013; and

• an increase in the average Cushing storage capacity to 7.6 million barrels for the three months ended March 31, 2014, from 7.25 million barrels for the three months ended March 31, 2013, contributing an additional $0.2 million Adjusted gross margin.

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Operating expense

Operating expenses increased in the three months ended March 31, 2014 to $14.9 million from $5.4 million for the three months ended March 31, 2013. Approximately $10.5 million of the increase is attributable to the newly-acquired trucking fleet, along with reductions in employee expense, field expense and outside services of approximately $0.5 million, $0.3 million and $0.2 million, respectively, exclusive of amounts related to trucking.

General and administrative expense

General and administrative expense remained flat at $3.6 million in the three months ended March 31, 2014 and 2013.

Depreciation and amortization expense

Depreciation and amortization expense increased in the three months ended March 31, 2014 to $10.5 million from $3.5 million for the three months ended March 31, 2013. Approximately $5.4 million of the increase in depreciation expense is due to a revision of the estimated useful life relating to a 62-mile section of the Kansas and Oklahoma pipeline system. An additional $0.8 million in depreciation expense is due to project completions and the acquisition of the crude oil trucking fleet. Amortization expense increased $0.8 million due to a contract acquired as part of the crude oil trucking fleet acquisition in 2013.

Earnings from equity method investment

Earnings from equity method investments increased in the three months ended March 31, 2014 to $11.1 million from $3.5 million for the three months ended March 31, 2013. The increase is due to our December 2013 acquisition of ownership interest in SCPL and change to the consolidation method of accounting of SCPL (see Note 2 of our condensed consolidated financial statements in this Form 10-Q). These earnings are attributable to fixed-fee pipeline transportation operations.

Interest expense

Interest expense increased in the three months ended March 31, 2014 to $2.3 million from $1.8 million for the three months ended March 31, 2013. The increase in interest expense relates primarily to an increase in the average daily outstanding debt balance to $248.8 million for the three months ended March 31, 2014 from $134.5 million at March 31, 2013. The increase in the outstanding debt balance is due to additional draws on the revolving credit facility to fund the drop down of an additional one-third interest in SCPL and cash calls on the White Cliffs Pipeline project.

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 or common units and the sale of assets. 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 related capital expenditures and working capital deficits through cash on hand, borrowings under our credit facility and the issuance of debt securities and common units;

• acquisitions through cash on hand, borrowings under our credit facility, the issuance of debt securities and common units; and

• debt principal payments through cash from operating activities and refinancing when the revolving 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.

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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 expenditure commitments for the coming year.

Cash Flows

The following table summarizes our changes in cash and cash equivalents for the periods presented (in thousands):

	Three Months Ended March 31,
	2014			2013
Cash flows provided by (used in):
Operating activities	$	18,388		$	9,915
Investing activities	(14,905		)	(60,377		)
Financing activities	(16,119		)	52,723
Change in cash and cash equivalents	(12,636		)	2,261
Cash and cash equivalents at beginning of period	15,459			108
Cash and cash equivalents at end of period	$	2,823		$	2,369

Operating Activities

The components of operating cash flows can be summarized as follows (in thousands):

	Three Months Ended March 31,
	2014			2013
Net income	$	16,159		$	11,994
Non-cash expenses, net	11,626			2,819
Changes in operating assets and liabilities, net	(9,397		)	(4,898		)
Net cash flows provided by operating activities	$	18,388		$	9,915

For the three months ended March 31, 2014, we experienced operating cash inflows of $18.4 million. Net income of $16.2 million included $11.6 million of non-cash expenses, comprised primarily of depreciation and amortization of $10.5 million and $0.6 million of unrealized losses related to our derivative instruments. Operating assets and liabilities changed $9.4 million for the three months ended March 31, 2014. The primary changes to operating assets and liabilities included an increase in accounts receivable of $61.2 million and a decrease in payables to affiliates of $22.4 million, offset by a decrease in receivables from affiliates of $15.6 million, a decrease in inventories of $3.2 million and an increase to accounts payable and accrued liabilities of $55.4 million. The impact of accounts receivable, accounts payable, accrued liabilities, and inventories is subject to the timing of purchases and sales. Increases in the magnitude of these balances is primarily due to higher prices and volumes.

For the three months ended March 31, 2013, we experienced operating cash inflows of $9.9 million. Net income of $12.0 million included $2.8 million of non-cash expenses, comprised primarily of depreciation and amortization of $3.5 million, offset by the $0.6 million net impact of $2.9 million in cash distributions from equity method investment and $3.5 million in earnings from equity method investment. Operating assets and liabilities changed $4.9 million for the three months ended March 31, 2013. The primary changes to operating assets and liabilities included an increase to accounts receivable of $8.5 million, an increase in payables to affiliates of $1.9 million, a decrease in other current assets of $1.1 million and an increase in accounts payable and accrued liabilities of $0.5 million. The increases to accounts receivable and accounts payable and accrued liabilities are primarily due to our ability to capture value related to market conditions and demand around our Kansas and Oklahoma system and Bakken Shale operations through marketing and buy/sell transactions. The impact to accounts receivable and accounts payable is subject to the timing of purchases and sales. The changes in affiliate payables is related to transactions with SemGroup and White Cliffs.

Investing Activities.

For the three months ended March 31, 2014, our cash outflows from investing activities related primarily to capital expenditures of $4.9 million and investment in non-consolidated affiliate of $13.2 million, offset by distributions in excess of equity in earnings of affiliates of $2.5 million. Year to date capital expenditures primarily relate to our Cushing expansion and

Page 28

transportation projects. The investment in non-consolidated affiliate primarily relates to capital calls to fund the White Cliffs Pipeline expansion.

For the three months ended March 31, 2013, our cash outflows from investing activities related primarily to capital expenditures of $6.5 million and investment in non-consolidated affiliate of $53.9 million. The capital expenditures related primarily to the construction of storage tanks and pipeline infrastructure at our terminal in Cushing, Oklahoma. The investment in non-consolidated affiliate was the acquisition of a 33% interest in SCPL and capital calls in connection with the expansion project to construct a 12" pipeline from Platteville, Colorado to Cushing, Oklahoma. As the investment transaction was between entities under common control, it was recorded based on SemGroup's historical cost.

Financing Activities.

Net cash outflows of $16.1 million from financing activities for the three months ended March 31, 2014 were driven primarily by $0.5 million net principal payments on our revolving credit facility ($46.0 million of borrowings, net of $46.5 million in principal payments on our revolving credit facility) and $12.8 million cash distributions to partners. In addition, financing activities include $4.3 million of distributions to and $1.6 million of contributions from SemGroup as the noncontrolling interest holder in SCPL. Borrowings were used for capital expenditures and normal operations.

Cash inflows from financing activities for the three months ended March 31, 2013, consisted primarily of $191.5 million in debt borrowings and $57.9 million in proceeds from the issuance of limited partner units. A majority of the debt borrowings and all of the proceeds from the issuance of limited partner units were the acquisition of a 33% interest in SCPL. Offsetting the proceeds from the debt borrowings and limited partner unit issuance was a $143.2 million reduction of partners' capital for the purchase price in excess of the historical cost of the interest in SCPL, $43.5 million in debt principal repayments, and $8.3 million in distributions to partners.

Revolving Credit Facility

Our revolving credit facility has a capacity of $585 million and includes a $150 million sub-limit for letters of credit. The credit agreement permits the increase of the facility by not more than $200 million, subject to certain conditions. The agreement allows the Partnership to incur unsecured or subordinated debt without limitation, subject to certain conditions, and provides alternative financial performance covenants at our election after the issuance of $200 million or more unsecured or subordinated debt, in aggregate. The credit agreement expires on September 20, 2018.

At our option, amounts borrowed under the credit agreement will bear interest at either the Eurodollar rate or an alternate base rate (“ABR”), plus, in each case, an applicable margin. The applicable margin will range from 1.75% to 3.00% in the case of a Eurodollar rate loan, and from 0.75% to 2.00% in the case of an ABR loan, in each case, based on a leverage ratio specified in the credit agreement. 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.

At March 31, 2014, we had outstanding cash borrowings of $244.5 million, of which $19.5 million incurred interest at ABR plus an applicable margin, and $225 million incurred interest at the Eurodollar rate plus an applicable margin. The interest rate in effect at March 31, 2014, on $19.5 million of ABR borrowings was 4.00%. The interest rate in effect at March 31, 2014, on $225 million of Eurodollar rate borrowings was 1.99%.

At March 31, 2014, we had $42.4 million in outstanding letters of credit and the rate per annum was 1.75%. In addition, a fronting fee of 0.25% is charged on outstanding letters of credit.

At March 31, 2014, we had $73.6 million of secured bilateral letters of credit outstanding. The interest rate in effect was 1.75%. Secured bilateral letters of credit are external to the facility and do not reduce revolver availability.

The credit agreement contains representations and warranties and affirmative and negative covenants. The negative covenants limit or restrict our ability (as well as the ability of our Restricted Subsidiaries, as defined in the credit agreement) to:

• permit the ratio of our consolidated EBITDA to our consolidated cash interest expense at the end of any fiscal quarter, for the immediately preceding four quarter period, to be less than 2.50 to 1.00;

• permit the ratio of our consolidated net debt to our consolidated EBITDA at the end of any fiscal quarter, for the immediately preceding four quarter period, to be greater than 5.00 to 1.00 (or 5.50 to 1.00 during a temporary period from the date of funding of the purchase price of certain acquisitions (as described in the credit agreement) until the last day of the third fiscal quarter following such acquisitions);

Page 29

• incur additional debt, subject to customary carve outs for certain permitted additional debt, incur certain liens on assets, subject to customary carve outs for certain permitted liens, or enter into certain sale and leaseback transactions;

• make investments in or make loans or advances to persons that are not Restricted Subsidiaries, subject to customary carve out for certain permitted investments, loans and advances;

• make certain cash distributions, provided that we may make distributions of available cash so long as no default under the credit agreement then exists or would result therefrom;

• dispose of assets in excess of an annual threshold amount;

• make certain amendments, modifications or supplements to organization documents, other material indebtedness documents and material contracts or enter into certain restrictive agreements or make certain payments on subordinated indebtedness;

• engage in business activities other than our business as described in the credit agreement, incidental or related thereto or a reasonable extension of the foregoing;

• enter into hedging agreements, subject to a customary carve out for agreements entered into in the ordinary course of business for non-speculative purposes;

• make changes to our fiscal year or other significant changes to our accounting treatment and reporting practices;

• engage in certain mergers or consolidations and transfers of assets; and

• enter into transactions with affiliates unless the terms are not less favorable, taken as a whole, than would be obtained in an arms-length transaction, subject to customary exceptions.

Upon the initial incurrence of at least $200 million of unsecured debt in accordance with the credit agreement, we will have a one-time option to elect to comply with the ratio of our consolidated EBITDA to our consolidated cash interest expense and the ratio of our consolidated net debt to our consolidated EBITDA as detailed above or the following alternative covenants:

• a minimum ratio of our consolidated EBITDA to our consolidated cash interest expense at the end of any fiscal quarter, for the immediately preceding four quarter period, of 2.50 to 1.00;

• a maximum ratio of our consolidated net debt to our consolidated EBITDA at the end of any fiscal quarter, for the immediately preceding four quarter period, of 5.50 to 1.00; and

• and a maximum ratio of senior secured debt to our consolidated EBITDA of 3.50 to 1.00.

The credit agreement defines events of default, including events of default relating to non-payment of principal and other amounts owing under the agreement from time to time, including in respect to letter of credit disbursement obligations, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payments-defaults of us and our restricted subsidiaries to any material indebtedness, cross acceleration to any material indebtedness, bankruptcy and insolvency events, the occurrence of a change of control, certain unsatisfied judgments, certain ERISA events, certain environmental matters and certain assertions of or actual invalidity of certain loan documents. A default under the credit agreement would permit the participating banks to terminate commitments, require immediate repayment of any outstanding loans with interest and any unpaid accrued fees, and require the cash collateralization of outstanding letter of credit obligations.

The agreement is guaranteed by all of our material subsidiaries and secured by a lien on substantially all of our property and assets, subject to customary exceptions.

As of March 31, 2014, we were in compliance with our covenants under our credit agreement.

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Shelf Registration Statement

We have an effective shelf registration statement with the SEC that, subject to market conditions and effectiveness at the time of use, allows us to issue up to an aggregate of $500 million of debt or equity securities. In August 2013, we used this shelf registration statement to sell 4.750 million common units representing limited partner interests for proceeds of $152.5 million, net of underwriting discounts and commissions of $6.4 million. This shelf registration statement expires in May 2016.

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 $22.8 million and $28.6 million at March 31, 2014 and December 31, 2013, respectively.

Capital Requirements

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

• expansion related 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; or

• maintenance capital expenditures, which are cash expenditures (including expenditures 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.

During the three months ended March 31, 2014, we invested $4.9 million (cash basis), on capital projects. Projected capital expenditures for 2014 include $63 million for expansion projects, including contributions to fund growth projects of equity method investees excluding amounts to be funded by noncontrolling interests, and $12 million in maintenance projects. During the three months ended March 31, 2014, we invested $12.8 million in the expansion of the White Cliffs Pipeline, which will add a second 12-inch line from Platteville, Colorado to Cushing, Oklahoma. On a consolidated basis, we expect to invest an additional $40.6 million in 2014. However, one-third of the $40.6 million White Cliffs expansion costs will be funded by the noncontrolling interest holder, SemGroup.

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 cash from operations, borrowings under our credit facility and the issuance of debt and equity securities.

Distributions

The table below shows cash distributions declared or paid during 2013 and 2014:

Quarter Ended	Record Date	Payment Date	Distribution Per Unit
December 31, 2012	February 4, 2013	February 14, 2013	$0.4025
March 31, 2013	May 6, 2013	May 15, 2013	$0.4300
June 30, 2013	August 5, 2013	August 14, 2013	$0.4400
September 30, 2013	November 5, 2013	November 14, 2013	$0.4500
December 31, 2013	February 4, 2014	February 14, 2014	$0.4650
March 31, 2014	May 5, 2014	May 15, 2014	$0.4950

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.

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Customer Concentration

Shell Trading (US) Company and BP Oil Supply Company each accounted for more than 10% of our total revenue for the three months ended March 31, 2014, at approximately 53% and 12%, respectively. Although we have contracts with customers of varying durations, 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 revenue.

Purchase and Sale Commitments

For information regarding purchase and sales commitments, see the discussion under the caption "Purchase and sale commitments" in Note 6 of our condensed consolidated financial statements of this Form 10-Q, which information is incorporated by reference into this Item 2.

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 March 31, 2014 and December 31, 2013, we had outstanding letters of credit of approximately $116.0 million and $95.8 million, respectively.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

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, 2013.

Recent Accounting Pronouncements

None.

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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 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 ended March 31, 2014 and 2013, and for the year ended December 31, 2013.

	Light Sweet Crude Oil Futures ($ per Barrel)
Three Months Ended March 31, 2014
High	$104.92
Low	$91.66
High/Low Differential	$13.26
Three Months Ended March 31, 2013
High	$97.94
Low	$90.12
High/Low Differential	$7.82
Year Ended December 31, 2013
High	$110.53
Low	$86.68
High/Low Differential	$23.85

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 and from our trucking operations. 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 market-related indices at various locations.

Based on our open derivative contracts at March 31, 2014, an increase in the applicable market price or prices for each derivative contract would result in a decrease in the contribution from these derivatives to our crude oil sales revenues. A decrease in the applicable market price or prices for each derivative contract would result in an 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

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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.

The notional volumes and fair value of our commodity derivatives open positions as of March 31, 2014, 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	225	$	(666	)	$	(2,286	)	$	2,286	April 2014

Margin deposits or other credit support, including letters of credit, are generally required on derivative instruments used 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 revolving credit facility. The credit markets have recently experienced very low 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 floating rate revolving 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 revolving credit facility of $2.3 million during the three months ended March 31, 2014. An increase in interest rates of 1% would have increased our interest expense by $611 thousand during the three months ended March 31, 2014.

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Item 4. Controls and Procedures

Evaluation of 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 Rule 13a-15(e) under the Exchange Act) are effective as of March 31, 2014. 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.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the most recently completed fiscal quarter ended March 31, 2014, 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 6 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, 2013.

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
10.1	Employment Agreement dated as of March 6, 2014, by and among SemManagement, L.L.C., SemGroup Corporation, Rose Rock Midstream GP, LLC and Carlin G. Conner (filed as Exhibit 10.1 to the Registrant's current report on Form 8-K (file No. 001-35365), filed with the Commission on March 12, 2014, and incorporated herein by reference).
31.1	Rule 13a-14(a)/15d-14(a) Certification of Carlin G. Conner, 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 Carlin G. Conner, Chief Executive Officer.
32.2	Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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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: May 9, 2014	ROSE ROCK MIDSTREAM, L.P.
	By:	Rose Rock Midstream GP, LLC, its general partner
		/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
10.1	Employment Agreement dated as of March 6, 2014, by and among SemManagement, L.L.C., SemGroup Corporation, Rose Rock Midstream GP, LLC and Carlin G. Conner (filed as Exhibit 10.1 to the Registrant's current report on Form 8-K (file No. 001-35365), filed with the Commission on March 12, 2014, and incorporated herein by reference).
31.1	Rule 13a-14(a)/15d-14(a) Certification of Carlin G. Conner, 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 Carlin G. Conner, Chief Executive Officer.
32.2	Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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