Rose Rock Midstream 10-Q 2013 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, 2013

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 such5-7-13 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, 2013, there were 11,893,581 common units, 8,389,709 subordinated units and 1,250,000 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, 2013 and December 31, 2012	4
	Condensed Consolidated Statements of Income – Three Months Ended March 31, 2013 and 2012	5
	Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2013 and 2012	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3	Quantitative and Qualitative Disclosures about Market Risk	32
Item 4	Controls and Procedures	34
	PART II – OTHER INFORMATION
Item 1	Legal Proceedings	35
Item 1A	Risk Factors	35
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3	Defaults Upon Senior Securities	35
Item 4	Mine Safety Disclosures	35
Item 5	Other Information	35
Item 6	Exhibits	35
	SIGNATURE	36

Cautionary Note Regarding Forward-Looking Statements

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

_________________________________________________________________________________________________

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, 2013		December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	2,369	$	108
Accounts receivable	231,366		222,862
Receivable from affiliates	234		57
Inventories	24,202		24,840
Other current assets	1,613		2,750
Total current assets	259,784		250,617
Property, plant and equipment (net of accumulated depreciation of $38,087 at March 31, 2013 and $34,580 at December 31, 2012)	295,384		291,530
Equity method investment	54,459		—
Other noncurrent assets, net	3,992		2,579
Total assets	$	613,619	$	544,726
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	221,704	$	220,791
Payable to affiliates	4,587		2,649
Accrued liabilities	4,632		4,681
Other current liabilities	3,343		3,722
Total current liabilities	234,266		231,843
Long-term debt	152,556		4,562
Commitments and contingencies (Note 6)
Partners’ capital:
Common units – public (9,003,872 units issued and outstanding at March 31, 2013 and 7,000,000 at December 31, 2012)	98,166		129,134
Common units – SemGroup (2,889,709 units issued and outstanding at March 31, 2013 and 1,389,709 at December 31, 2012)	53,835		37,992
Subordinated units – SemGroup (8,389,709 units issued and outstanding at March 31, 2013 and December 31, 2012)	52,053		135,036
Class A units - (1,250,000 units issued and outstanding at March 31, 2013)	18,144		—
General partner	4,599		6,159
Total partners’ capital	226,797		308,321
Total liabilities and partners’ capital	$	613,619	$	544,726

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

Page 4

ROSE ROCK MIDSTREAM, L.P.

Unaudited Condensed Consolidated Statements of Income

(In thousands, except per unit data)

	Three Months Ended March 31,
	2013		2012
Revenues, including revenues from affiliates (Note 9):
Product	$	158,728	$	169,386
Service	12,504		10,334
Other	—		(5		)
Total revenues	171,232		179,715
Expenses, including expenses from affiliates (Note 9):
Costs of products sold, exclusive of depreciation and amortization	148,451		160,508
Operating	5,418		5,227
General and administrative	3,561		2,703
Depreciation and amortization	3,507		2,967
Total expenses	160,937		171,405
Earnings from equity method investment	3,453		—
Operating income	13,748		8,310
Other expenses:
Interest expense	1,754		480
Other expense	—		72
Total other expenses	1,754		552
Net income	$	11,994	$	7,758
Net income allocated to general partner	$	281	$	155
Net income allocated to common unitholders	$	6,767	$	3,801.5
Net income allocated to subordinated unitholders	$	4,773	$	3,801.5
Net income allocated to Class A unitholders	$	173	$	—
Earnings per limited partner unit (Note 8):
Common unit (basic and diluted)	$	0.59	$	0.45
Subordinated unit (basic and diluted)	$	0.57	$	0.45
Class A unit (basic and diluted)	$	0.16	$	—
Basic weighted average number of limited partner units outstanding:
Common units	11,465		8,390
Subordinated units	8,390		8,390
Class A units	1,097		—
Diluted weighted average number of limited partner units outstanding:
Common units	11,491		8,390
Subordinated units	8,390		8,390
Class A units	1,097		—

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

Page 5

ROSE ROCK MIDSTREAM, L.P.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

	Three Months Ended March 31,
	2013			2012
Cash flows from operating activities:
Net income	$	11,994		$	7,758
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	3,507			2,967
Amortization of debt issuance costs	198			85
Non-cash equity compensation	143			61
Net unrealized (gain) loss related to derivative instruments	(468		)	146
Earnings from equity method investment	(3,453		)	—
Cash distributions from equity method investment	2,892			—
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	(8,504		)	(83,532		)
Decrease (increase) in receivable from affiliates	(177		)	(3,865		)
Decrease (increase) in inventories	182			4,714
Decrease (increase) in other current assets	1,137			401
Decrease (increase) in other noncurrent assets	—			(20		)
Increase (decrease) in accounts payable and accrued liabilities	526			68,834
Increase (decrease) in payable to affiliates	1,938			2,211
Net cash provided by (used in) operating activities	9,915			(240		)
Cash flows from investing activities:
Capital expenditures	(6,479		)	(3,044		)
Investments in non-consolidated affiliate	(53,898		)	—
Net cash used in investing activities	(60,377		)	(3,044		)
Cash flows from financing activities:
Debt issuance costs	(1,610		)	(41		)
Borrowings on credit facility	191,500			53,000
Principal payments on credit facility	(43,500		)	(53,000		)
Principal payments on capital lease obligations	(6		)	(6		)
Proceeds from common L.P. unit issuance, net of offering costs	57,886			—
Purchase price in excess of historical cost of interest in SemCrude Pipeline, L.L.C.	(143,216		)	—
Cash distributions to partners	(8,331		)	(1,147		)
Net cash provided by (used in) financing activities	52,723			(1,194		)
Net increase (decrease) in cash and cash equivalents	2,261			(4,478		)
Cash and cash equivalents at beginning of period	108			9,709
Cash and cash equivalents at end of period	$	2,369		$	5,231

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

Page 6

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

1. OVERVIEW

Rose Rock Midstream, L.P. 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. SemGroup Corporation is the successor entity of SemGroup, L.P., which was an Oklahoma limited partnership.

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

Basis of presentation

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

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

These condensed consolidated financial statements are unaudited. The condensed consolidated balance sheet at December 31, 2012, is derived from audited financial statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures in the financial statements. Although management believes these estimates are reasonable, actual results could differ materially from these estimates. The results of operations for the three months ended March 31, 2013, are not necessarily indicative of the results to be expected for the full year ending December 31, 2013.

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, 2012, which are included in our Annual Report on Form 10-K for the year ended December 31, 2012, 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, 2012.

Recent accounting pronouncements

On January 31, 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") 2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities," which clarifies the scope of the offsetting disclosure requirements in ASU 2011-11, "Disclosures About Offsetting Assets and Liabilities." Under ASU 2013-01, the disclosure requirements apply to derivative instruments accounted for in accordance with Accounting Standards Codification ("ASC") 815, "Derivatives and Hedging," including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending arrangements that are either offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement. ASU 2013-01 is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those years. Retrospective application is required for all comparative periods presented. We adopted this guidance in the first quarter of 2013. The impact of adoption was not material.

On February 28, 2013, the FASB issued ASU 2013-04, "Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date (a consensus of the FASB Emerging Issues Task Force)." The ASU requires entities to “measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of the following:

Page 7

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

1. OVERVIEW, Continued

•The amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors; and

•Any additional amount the reporting entity expects to pay on behalf of its co-obligors.”

Required disclosures include a description of the joint and several arrangement and the total outstanding amount of the obligation for all joint parties. The ASU permits entities to aggregate disclosures (as opposed to providing separate disclosures for each joint-and-several obligation). These disclosure requirements are incremental to the existing related-party disclosure requirements in ASC 850, "Related Party Disclosures." The ASU is effective for public entities for all prior periods in fiscal years beginning on or after December 15, 2013 (and interim reporting periods within those years). We will adopt this guidance in the first quarter of 2014. The impact is not expected to be material.

2. ACQUISITION

Contribution Agreement

On January 8, 2013, we entered into a Contribution Agreement (the “Contribution Agreement”) with SemGroup and certain of its subsidiaries. Pursuant to the terms of the Contribution Agreement, on January 11, 2013, we acquired a 33% interest in SemCrude Pipeline, L.L.C. (“SCPL”) from SemGroup in exchange 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 two percent general partner interest in us. SCPL owns a 51% membership interest in White Cliffs Pipeline, L.L.C. ("White Cliffs"), which owns a 527-mile pipeline system ("the White Cliffs Pipeline") that transports crude oil from Platteville, Colorado in the Denver-Julesburg Basin to Cushing, Oklahoma.

The Class A units are not entitled to receive any distributions of available cash (other than upon liquidation) prior to the first day of the month immediately following the first month for which the average daily throughput volumes on the White Cliffs Pipeline for such month are 125,000 barrels per day or greater. Upon such date, the Class A units will automatically convert into common units.

The cash consideration was funded through a borrowing under our credit facility of approximately $130.3 million and the sale of 2.0 million common units through a private placement, as described below. The 1.5 million common units were valued at $29.63 per unit, or $44.4 million, based on the sales price to third-parties in the private placement. The Class A units were valued at $29.63 per unit discounted for the expected forbearance of distributions, or $30.5 million. The contribution to the general partner's capital account was made in the amount of $2.7 million. Subsequent to the transaction, SemGroup holds the 2% general partner interest and 58.2% of the limited partnership interest in Rose Rock. We incurred $3.5 million of expense, of which $1.4 million of equity issuance costs were offset against proceeds, $1.6 million were related to the borrowing and were deferred, and $0.5 million were expensed.

We own a 33% interest in SCPL, which is effectively a 17% interest in White Cliffs. We account for our membership in SCPL as an equity method investment. We will be required to fund 33% of SCPL's capital contribution requirements for White Cliffs. This amount is expected to be $39 million in 2013 and $10 million in 2014, related to an expansion project to add a 12" line from Platteville, Colorado to Cushing, Oklahoma. 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.

Common Unit Purchase Agreement

On January 8, 2013, we entered into a Common Unit Purchase Agreement with certain purchasers (the “Purchasers”), pursuant to which, on January 11, 2013, 2.0 million common units were issued and sold to the Purchasers in a private placement at a price of $29.63 per common unit for aggregate consideration of approximately $59.3 million (the “Private Placement”). The Partnership used the net proceeds from the Private Placement to fund a portion of the purchase of a 33% interest in SCPL.

Registration Rights Agreement

In connection with the closing of the Private Placement, on January 11, 2013, we entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Purchasers. Pursuant to the terms of the Registration Rights Agreement, within 30 days following the closing of the Private Placement, we were required to prepare and file a

Page 8

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

2. ACQUISITION, Continued

registration statement (the “Registration Statement”) to permit the public resale of the common units sold to the Purchasers in the Private Placement.

On February 5, 2013, we filed the Registration Statement with the SEC. The Registration Statement was declared effective by the SEC at 9:00 a.m. (Washington, D.C. time) on February 13, 2013. If the Purchasers become prohibited from using the Registration Statement under certain circumstances, or if the Registration Statement ceases to be effective or unusable for certain periods of time, we could be liable to the Purchasers for liquidated damages calculated in accordance with a formula, and subject to the limitations set forth in the Registration Rights Agreement.

3. INVESTMENT IN NON-CONSOLIDATED AFFILIATE

SemCrude Pipeline

We account for our 33% interest in SCPL under the equity method. Under the equity method, we do not report the individual assets and liabilities of SCPL on our condensed consolidated balance sheets. 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, 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. Thus, our 33% interest in SCPL is effectively a 17% interest in White Cliffs.

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

	Three Months Ended March 31, 2013
Revenue	$	30,673
Operating, general and administrative expenses	$	5,179
Depreciation and amortization expense	$	4,715
Net income	$	20,779

The equity in earnings of White Cliffs for the three months ended March 31, 2013, recorded by SCPL, is less than 51% of the net income of White Cliffs for the same period, which ultimately reduces our equity in earnings of SCPL such that our share of earnings is less than 17% of the net income of White Cliffs. This is due to certain general and administrative expenses SCPL incurs 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 SCPL's ownership interest. White Cliffs recorded $0.3 million of such general and administrative expense for the three months ended March 31, 2013.

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:

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

4. FINANCIAL INSTRUMENTS, Continued

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

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

We record certain commodity derivative assets and liabilities at fair value at each balance sheet date. The tables below summarize the balances of these assets and liabilities at March 31, 2013 and December 31, 2012 (in thousands):

	March 31, 2013									December 31, 2012
	Level 1			Netting*			Total			Level 1			Netting*			Total
Assets	$	96		$	(96	)	$	—		$	22		$	(22	)	$	—
Liabilities	662			(96		)	566			1,056			(22		)	1,034
Net assets (liabilities) at fair value	$	(566	)	$	—		$	(566	)	$	(1,034	)	$	—		$	(1,034	)

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

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

“Level 3” measurements use as inputs information from a pricing service and internal valuation models incorporating observable and unobservable market data. These include physical fixed price purchases and sales forward contracts with an affiliate for which there is not a highly liquid OTC market and, therefore, are not included in Level 1 or Level 2 above.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the measurement requires judgment, and may affect the valuation of assets and liabilities and their placement within the fair value levels. At March 31, 2013, 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, 2013 and March 31, 2012, 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):

	Three Months Ended March 31,
	2013	2012
Sales	610	383
Purchases	675	451

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, 2013				December 31, 2012
	Assets		Liabilities		Assets		Liabilities
Commodity contracts	$	—	$	566	$	—	$	1,034

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

4. FINANCIAL INSTRUMENTS, Continued

We have posted margin deposits as collateral with brokers who have the right of set off associated with these funds. Margin deposits outstanding for the periods ended March 31, 2013 and December 31, 2012 were $1.1 million and $1.9 million, respectively. These margin deposits have not been offset against our net commodity derivative instrument (contract) positions. Had these margin deposits been netted against our commodity derivative instrument (contract) positions for the periods ended March 31, 2013 and December 31, 2012, we would have had net asset positions of $0.5 million and $0.8 million, respectively.

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

	Three Months Ended March 31,
	2013			2012
Commodity contracts	$	(544	)	$	(1,125	)

5. LONG-TERM DEBT

On January 11, 2013, our credit facility capacity was increased to $385 million and we borrowed $133.5 million in connection with the purchase of a 33% interest in SCPL from SemGroup and to pay transaction related expenses. We have the ability to increase our facility capacity by an additional $165 million. Approximately $1.6 million of related costs have been capitalized and will be amortized over the remaining life of the facility.

At March 31, 2013, we had outstanding borrowings of $152.5 million on this facility, of which $52.5 million incurred interest at the alternate base rate ("ABR") plus an applicable margin, and $100 million incurred interest at the Eurodollar rate plus an applicable margin. The interest rate in effect at March 31, 2013 on $52.5 million of ABR borrowings was 5.0%. The interest rate in effect at March 31, 2013 on $100 million of Eurodollar rate borrowings was 3.04%.

We had $48.9 million in outstanding letters of credit at March 31, 2013 and the rate per annum was 2.75%. 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, 2013, we had $6.1 million of secured bilateral letters of credit outstanding. The interest rate in effect was 1.75% on $1.1 million and 2.0% on $5.0 million. Secured bilateral letters of credit are external to the facility and do not reduce revolver availability.

At March 31, 2013, we were in compliance with the terms of the credit agreement.

At March 31, 2013, $2.9 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, 2013, we had $56 thousand ($81 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, 2013, 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, 2013.

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”).

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

6. COMMITMENTS AND CONTINGENCIES, Continued

(a) Confirmation order appeal

Luke Oil appeal. On October 21, 2009, Luke Oil Company, C&S Oil/Cross Properties, Inc., Wayne Thomas Oil and Gas and William R. Earnhardt Company (collectively, “Luke Oil”) filed an objection to the Plan of Reorganization “to the extent that the Plan of Reorganization may alter, impair, or otherwise adversely affect Luke Oil’s legal rights or other interests.” On October 28, 2009, the bankruptcy court overruled the Luke Oil objection and entered the confirmation order. On November 6, 2009, Luke Oil filed a Notice of Appeal. On December 23, 2009, Luke Oil’s appeal was docketed in the United States District Court for the District of Delaware. SemGroup filed a motion to dismiss the appeal as equitably moot. On May 21, 2012, the District Court entered an order granting our motion to dismiss Luke Oil’s appeal of the confirmation order. On June 18, 2012, Luke Oil filed its Notice of Appeal, notifying the District Court and the parties to the lawsuit that it was appealing the decision of the District Court to the United States Court of Appeals for the Third Circuit. The appeal has been fully briefed. The Court of Appeals heard oral argument on January 22, 2013, and has not yet ruled. While SemGroup believes that this action is without merit and is vigorously defending this matter on appeal, an adverse ruling on this account could have a material adverse impact on us. We are indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement.

(b) Claims reconciliation process

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

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

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

Environmental

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

The Kansas Department of Health and Environment (“KDHE”) initiated discussions during SemGroup’s bankruptcy proceeding regarding five of our sites in Kansas that KDHE believed, based on their historical use, may have soil or groundwater contamination in excess of state standards. KDHE sought our agreement to undertake assessments of these sites to determine whether they are contaminated. SemGroup entered into a Consent Agreement and Final Order with KDHE to conduct environmental assessments on the sites and to pay KDHE’s costs associated with their oversight of this matter. SemGroup has conducted Phase II investigations at all sites. Three of the five sites have limited amounts of soil contamination that will be excavated and/or remediated on site. Three of the five sites appear to have ground water contamination that may require further delineation and/or on-going monitoring. Work plans have been submitted to, and

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

6. COMMITMENTS AND CONTINGENCIES, Continued

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.

Blueknight claim

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

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

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, 2013, such commitments included the following (in thousands):

	Volume (Barrels)	Value
Fixed price purchases	16	$	1,432
Fixed price sales	91	$	8,792
Floating price purchases	20,067	$	1,941,213
Floating price sales	20,577	$	2,017,882

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

6. COMMITMENTS AND CONTINGENCIES, Continued

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, 2012 to March 31, 2013 (in thousands):

	Common Units - Public			Common Units - SemGroup			Subordinated Units			Class A Units			General Partner Interest			Total Partners’ Capital
Balance at December 31, 2012	$	129,134		$	37,992		$	135,036		$	—		$	6,159		$	308,321
Net income	5,143			1,624			4,773			173			281			11,994
Equity issuance	57,886			44,445			—			30,543			2,744			135,618
Purchase price in excess of historical cost of interest in SemCrude Pipeline, L.L.C.	(90,516		)	(29,063		)	(84,379		)	(12,572		)	(4,418		)	(220,948		)
Cash distributions	(3,624		)	(1,163		)	(3,377		)	—			(167		)	(8,331		)
Non-cash equity compensation	143			—			—			—			—			143
Balance at March 31, 2013	$	98,166		$	53,835		$	52,053		$	18,144		$	4,599		$	226,797

Distribution rights

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

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

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

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

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

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

Page 14

ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

7. PARTNERS’ CAPITAL AND DISTRIBUTIONS, Continued

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

The following table shows the distributions paid or declared per common limited partner unit for the three months ended March 31, 2013 and 2012:

Quarter Ended	Record Date	Payment Date	Distribution Per Unit
December 31, 2011	February 3, 2012	February 13, 2012	$0.0670	*
March 31, 2012	May 7, 2012	May 15, 2012	$0.3725
December 31, 2012	February 4, 2013	February 14, 2013	$0.4025
March 31, 2013	May 6, 2013	May 15, 2013	$0.4300

* Calculated as the $0.3625 minimum quarterly distribution, prorated based on the length of time during the three months ended December 31, 2011, that was subsequent to our initial public offering.

Equity incentive plan

On December 8, 2011, the board of directors of our general partner adopted the Rose Rock Midstream Equity Incentive Plan (the “Incentive Plan”). We have reserved 840,000 limited partner common units for issuance to non-management directors and employees under the Incentive Plan. We granted approximately 39,000 restricted unit awards during the three months ended March 31, 2013. At March 31, 2013, there are 79,029 unvested restricted unit awards that have been granted pursuant to the Incentive Plan. Generally, the awards vest three years after the date of grant for employees and one year after the date of grant for non-managerial directors, contingent upon the continued service of the recipients and may be subject to accelerated vesting in the event of involuntary terminations. We had vestings of 3,872 restricted unit awards for the three months ended March 31, 2013.

The holders of these restricted units granted in 2012 are entitled to equivalent distributions (“Unvested Unit Distributions” or “UUDs”) to be received upon vesting of the restricted unit awards. The distributions will be settled in common units based on the market price of our limited partner common units as of the close of business on the vesting date. The UUDs are subject to the same forfeiture and acceleration conditions as the associated restricted units. Of the 3,872 restricted unit awards that vested for the three months ended March 31, 2013, 140 were UUDs that vested. At March 31, 2013, the value of the UUDs related to unvested restricted units was approximately $58 thousand. This is equivalent to 1,468 common units based on the quarter end close of business market price of our common units of $39.65 per unit. Distributions related to the 2013 restricted unit awards will be settled in cash upon vesting.

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.

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

8. EARNINGS PER LIMITED PARTNER UNIT, Continued

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months ended March 31, 2013 and 2012 (in thousands, except per unit data):

	Three Months Ended March 31,
	2013		2012
Net income	$	11,994	$	7,758
Less: General partner’s incentive distribution earned (*)	41		—
Less: General partner’s 2.0% ownership (**)	240		155
Net income allocated to limited partners	$	11,713	$	7,603
Numerator for basic and diluted earnings per limited partner unit (**):
Allocation of net income among limited partner interests:
Net income allocable to common units	$	6,767	$	3,801.5
Net income allocable to subordinated units	4,773		3,801.5
Net income allocable to Class A units	173		—
Net income allocated to limited partners	$	11,713	$	7,603
Denominator for basic and diluted earnings per limited partner unit:
Basic weighted average number of limited partner common units outstanding	11,465		8,390
Effect of non-vested restricted units	26		—
Diluted weighted average number of limited partner common units outstanding	11,491		8,390
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	1,097		—
Basic & diluted net income per limited partner unit:
Common units	$	0.59	$	0.45
Subordinated units	$	0.57	$	0.45
Class A units	$	0.16	$	—

(*) Based on the amount of the distribution declared per common and subordinated unit related to earnings for the three months ended March 31, 2012, our general partner was not entitled to receive incentive distributions for that period.

(**) 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.

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 $2.9 million and $2.9 million during the three months ended March 31, 2013 and 2012, 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 $1.3 million and $1.2 million during the three months ended March 31, 2013 and 2012, respectively, for such allocated costs. These expenses were recorded to general and administrative expenses in our condensed consolidated statements of income.

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ROSE ROCK MIDSTREAM, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements

9. RELATED PARTY TRANSACTIONS, Continued

NGL Energy

SemGroup holds certain ownership interests in NGL Energy Partners LP (“NGL Energy”) and its general partner. During the three months ended March 31, 2012, we made purchases of condensate at market prices from NGL Energy in the amount of $14.4 million. There were no purchases from NGL Energy during the three months ended March 31, 2013.

SemGas

We purchase condensate at market prices from SemGas, L.P. (“SemGas”), which is a wholly-owned subsidiary of SemGroup. Purchases from SemGas were $4.1 million and $2.7 million for the three months ended March 31, 2013 and 2012, respectively.

White Cliffs

SemGroup owns 51% of White Cliffs and exercises significant influence over it, of which we indirectly own 33% through our investment in SCPL subsequent to our January 2013 acquisition. We generated storage revenues from White Cliffs of $0.6 million and $0.6 million for the three months ended March 31, 2013 and 2012, respectively.

Legal services

The law firm of Conner & Winters, LLP, of which Mark D. Berman is a partner, performs legal services for us. Mr. Berman is the spouse of Candice L. Cheeseman, General Counsel and Secretary. Mr. Berman does not perform any legal services for us. 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, 2013 and 2012, respectively.

10. SUPPLEMENTAL CASH FLOW INFORMATION

Acquisition

In connection with the acquisition of a 33% interest in SCPL (Note 2), 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 $0.4 million and $0.1 million for the the three months ended March 31, 2013 and 2012, respectively.

We accrued $0.5 million and $1.9 million for purchases of property, plant and equipment for the the three months ended March 31, 2013 and 2012, 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 interim financial statements and the notes thereto included in Part I, Item 1 of this Quarterly Report on Form 10-Q, and our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC.

Overview of Business

We are a growth-oriented Delaware limited partnership formed by 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, Minnesota, Montana, North Dakota, Oklahoma and Texas. We serve areas that are experiencing strong production growth and drilling activity through our exposure to the Bakken Shale in North Dakota and Montana, the 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 ("the 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.

Our Property, Plant and Equipment

We own and operate all of our assets, which at March 31, 2013 include:

• 7.25 million barrels of crude oil storage capacity in Cushing, Oklahoma, with an additional 350,000 barrels currently under construction;

• a 640-mile crude oil gathering and transportation pipeline system with over 660,000 barrels of associated storage capacity in Kansas and northern Oklahoma that is connected to several third-party pipelines and refineries and our storage terminal in Cushing, 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 8,100 barrels of crude oil per day for the three months ended March 31, 2013; 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

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. We account for our ownership in SCPL as an equity method investment. White Cliffs received sufficient binding shipper commitments during its recent open season to move forward with an expansion project which will increase the capacity of the pipeline from approximately 70,000 barrels per day to about 150,000 barrels per day. Subject to regulatory approvals, the expansion is anticipated to be in service in the first half of 2014. We operate the expanded pipeline.

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

Page 18

crude oil, and our fixed-margin and marketing operations, which do. In particular, Adjusted gross margin provides a way to compare the actual transportation fee received under fixed-fee contracts with the effective transportation fee realized through a fixed-margin transaction. In addition, Adjusted gross margin allows us to make a meaningful comparison of the results of our fixed-margin and marketing operations across different commodity price environments because it measures the spread between the product sales price and cost of products sold. See “Selected Consolidated Financial and Operating Data—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, we provide transportation services on a fee basis or pursuant to fixed-margin transactions, but in either case, the Adjusted gross margin we generate is dependent on the volume of crude oil transported (if on a fee basis) or purchased and sold (if pursuant to a fixed-margin transaction). We refer to these volumes, in the aggregate, as transportation volumes. Similarly, on our Kansas and Oklahoma system, and through our Bakken Shale operations, we conduct marketing activities involving the purchase and sale of crude oil or related derivative contracts. We refer to the crude oil volumes purchased and sold in our marketing operations as marketing volumes. Finally, at our Platteville truck unloading facility, we charge our customers a fee based on the volumes unloaded. We refer to these as unloading volumes.

How We Generate Adjusted Gross Margin

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

Fee-Based Services

We charge a capacity or volume-based fee for the unloading, transportation and storage of crude oil and related ancillary services. Our fee-based services include substantially all of our operations in Cushing, Oklahoma and Platteville, Colorado and a portion of the transportation services we provide on our Kansas and Oklahoma pipeline system. Some of our fee-based contracts are take-or-pay contracts whereby the customer is required to pay us a fixed minimum monthly fee regardless of usage. For the three months ended March 31, 2013 and 2012, approximately 56% and 53%, respectively, of our Adjusted gross margin was generated by providing fee-based services to customers.

Fixed-Margin Transactions

We purchase crude oil from a producer or supplier at a designated receipt point at an index price, less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price, thereby locking in a fixed margin that is, in effect, economically equivalent to a transportation fee. We refer to these

Page 19

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, 2013 and 2012, approximately 22% and 17%, respectively, of our Adjusted gross margin was generated through fixed-margin transactions.

Marketing Activities

We conduct marketing activities by purchasing crude oil for our own account from producers, aggregators and traders and selling crude oil to traders and refiners. Our marketing activities account for a portion of the Adjusted gross margin we generate on our Kansas and Oklahoma pipeline system and through our Bakken Shale operations. For the three months ended March 31, 2013 and 2012, approximately 22% and 30%, respectively, of our Adjusted gross margin was generated through marketing activities.

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

More specifically, we utilize futures and swap contracts to manage our exposure to market changes in commodity prices to protect our Adjusted gross margin on our purchased crude oil. As we purchase crude oil from suppliers, 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

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

Adjusted Gross Margin

The following table shows Adjusted gross margin generated by product revenue and service revenue for the three months ended March 31, 2013 and 2012 (in thousands):

	Three Months Ended March 31,
	2013		2012
Revenues:
Product	$	158,728	$	169,386
Service	12,504		10,334
Other	—		(5		)
Total Revenues	171,232		179,715
Less: Costs of products sold, exclusive of depreciation and amortization	148,451		160,508
Less: Net unrealized gain (loss) related to derivative instruments	468		(146		)
Adjusted gross margin	$	22,313	$	19,353

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, 2013 and 2012 (in thousands):

Three Months Ended March 31, 2013	Storage		Transportation		Marketing Activities		Other  (1)		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: Net unrealized gain (loss) related to derivative instruments	—		—		468		—		468
Adjusted gross margin	$	8,367	$	5,776	$	4,897	$	3,273	$	22,313

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Three Months Ended March 31, 2012	Storage		Transportation		Marketing Activities			Other (1)		Total
Revenues	$	7,410	$	4,357	$	166,175		$	1,773	$	179,715
Less: Costs of products sold, exclusive of depreciation and amortization	—		—		160,508			—		160,508
Less: Net unrealized gain (loss) related to derivative instruments	—		—		(146		)	—		(146		)
Adjusted gross margin	$	7,410	$	4,357	$	5,813		$	1,773	$	19,353

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

Selected Consolidated Financial and Operating Data

The following table provides selected historical condensed consolidated financial operating data as of and for the periods shown. The statement of income data for the three months ended March 31, 2013 and 2012 have been derived from our unaudited financial statements for those periods. The selected financial data provided below should be read in conjunction with our condensed consolidated financial statements and related notes included in this Form 10-Q.

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

	Three Months Ended March 31,
	2013			2012
	(in thousands, except per unit and operating data)
Statements of income data:
Total revenues	$	171,232		$	179,715
Operating income	$	13,748		$	8,310
Net income	$	11,994		$	7,758
Net income per common unit (basic and diluted)	$	0.59		$	0.45
Net income per subordinated unit (basic and diluted)	$	0.57		$	0.45
Net income per Class A unit (basic and diluted)	$	0.16		N/A
Distributions paid per unit	$	0.4025		$	0.0670
Statements of cash flows data:
Net cash provided by (used in):
Operating activities	$	9,915		$	(240	)
Investing activities	$	(60,377	)	$	(3,044	)
Financing activities	$	52,723		$	(1,194	)
Other financial data:
Adjusted gross margin	$	22,313		$	19,353
Adjusted EBITDA	$	16,369		$	11,412
Capital expenditures	$	6,479		$	3,044
Operating data:
Cushing storage capacity (MMBbls as of period end)	7.250			7.000
Percent of Cushing capacity contracted (as of end of period)	97		%	96		%
Transportation volumes (average Bbls/day)	55,700			44,800
Marketing volumes (average Bbls/day)	24,100			22,700
Unloading/Platteville volumes (average Bbls/day)	62,200			42,400

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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 (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.

Adjusted gross margin and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.

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

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

The following table presents a reconciliation of: (i) operating income to Adjusted gross margin, (ii) net income 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.

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	Three Months Ended March 31,
	2013			2012
	(Unaudited; in thousands)
Reconciliation of operating income to Adjusted gross margin:
Operating income	$	13,748		$	8,310
Add:
Operating expense	5,418			5,227
General and administrative	3,561			2,703
Depreciation and amortization	3,507			2,967
Less:
Earnings from equity method investment	3,453			—
Unrealized gain (loss) on derivatives, net	468			(146		)
Adjusted gross margin	$	22,313		$	19,353
Reconciliation of net income to Adjusted EBITDA:
Net income	$	11,994		$	7,758
Add:
Interest expense	1,754			480
Depreciation and amortization	3,507			2,967
Cash distributions from equity method investment	2,892			—
Non-cash equity compensation	143			61
Less:
Earnings from equity method investment	3,453			—
Impact from derivative instruments:
Total gain (loss) on derivatives, net	(544		)	(1,125		)
Total realized (gain) loss (cash outflow) on derivatives, net	1,012			979
Non-cash unrealized gain (loss) on derivatives, net	468			(146		)
Adjusted EBITDA	$	16,369		$	11,412
Reconciliation of net cash provided by (used in) operating activities to Adjusted EBITDA:
Net cash provided by (used in) operating activities	$	9,915		$	(240	)
Less:
Changes in assets and liabilities	(4,898		)	(11,257		)
Add:
Interest expense, excluding amortization of debt issuance costs	1,556			395
Adjusted EBITDA	$	16,369		$	11,412

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Results of Operations

	Three Months Ended March 31,
	2013		2012
	(Unaudited, in thousands except per unit data)
Statements of income data:
Revenues, including revenues from affiliates:
Product	$	158,728	$	169,386
Service	12,504		10,334
Other	—		(5		)
Total revenues	171,232		179,715
Expenses, including expenses from affiliates:
Costs of products sold, exclusive of depreciation and amortization	148,451		160,508
Operating	5,418		5,227
General and administrative	3,561		2,703
Depreciation and amortization	3,507		2,967
Total expenses	160,937		171,405
Earnings from equity method investment	3,453		—
Operating income	13,748		8,310
Other expenses:
Interest expense	1,754		480
Other expense	—		72
Total other expenses	1,754		552
Net income	$	11,994	$	7,758
Net income per common unit (basic and diluted)	$	0.59	$	0.45
Net income per subordinated unit (basic and diluted)	$	0.57	$	0.45
Net income per Class A unit (basic and diluted)	$	0.16	$	—
Distribution paid per unit	$	0.4025	$	0.0670
Adjusted gross margin (1)	$	22,313	$	19,353
Adjusted EBITDA (1)	$	16,369	$	11,412

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

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

Three months ended March 31, 2013 vs. three months ended March 31, 2012

Revenue

Revenue decreased in the three months ended March 31, 2013, to $171.2 million from $179.7 million for the three months ended March 31, 2012, as shown in the following table:

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	Three Months Ended March 31,
	2013			2012
	(in thousands)
Gross product revenue	$	630,447		$	501,478
Nonmonetary transaction adjustment (ASC 845-10-15)	(472,187		)	(331,946		)
Unrealized gain (loss) on derivatives, net	468			(146		)
Product revenue, net	158,728			169,386
Service revenue	12,504			10,334
Other	—			(5		)
Total revenue	$	171,232		$	179,715

Gross product revenue increased in the three months ended March 31, 2013, to $630.4 million from $501.5 million in the three months ended March 31, 2012. The increase was primarily a result of an increase in sales volumes to 6.8 million barrels for the three months ended March 31, 2013 from 5.0 million barrels for the same period in 2012, offset by a decrease in the average sales price of crude oil to $93 per barrel for the three months ended March 31, 2013 from $101 per barrel for the same period in 2012. The increase in volume relates primarily to increased buy/sell and marketing activity as a result of new crude oil production around our assets and directed efforts to maximize the use of those assets.

ASC 845-10-15, “Nonmonetary Transactions,” requires certain transactions – those where inventory is purchased from a customer then resold to the same customer – to be presented in the income statement on a net basis, resulting in a reduction of revenue and costs of products sold by the same amount, but has no effect on operating income (loss). However, changes in the level of such purchase and sale activity between periods can have an effect on the comparison between those periods. Gross product revenue was reduced by $472.2 million and $331.9 million during the three months ended March 31, 2013 and 2012, respectively, in accordance with ASC 845-10-15.

Service revenue increased in the three months ended March 31, 2013, to $12.5 million from $10.3 million for the three months ended March 31, 2012, due to fees on leased crude oil storage at Cushing, Oklahoma which averaged 7.0 million barrels in the first quarter of 2013 compared to an average of 6.0 million barrels in the same period of 2012, as well as additional truck unloading and pumpover fees.

Costs of Products Sold

Costs of products sold decreased in the three months ended March 31, 2013, to $148.5 million from $160.5 million for the same period in 2012. Costs of products sold were reduced by $472.2 million and $331.9 million in the three months ended March 31, 2013 and 2012, respectively, in accordance with ASC 845-10-15. Costs of products sold decreased in the three months ended March 31, 2013, primarily as a combined result of an increase in the volume sold, a decrease in the average cost of crude oil per barrel to $91 from $98 per barrel and a higher proportion of transactions subject to ASC 845-10-15 for the same period in 2012.

Adjusted Gross Margin

We define Adjusted gross margin as total revenues minus costs of products sold and unrealized gain (loss) on derivatives. (See “—Selected Consolidated Financial and Operating Data—Non-GAAP Financial Measures” for Adjusted gross margin tables.) Adjusted gross margin increased in the three months ended March 31, 2013, to $22.3 million from $19.4 million in the three months ended March 31, 2012, due to:

• an increase in marketing volume (which is a subset of the total gross product revenue volume sold as shown above) of approximately 0.1 million barrels in the three months ended March 31, 2013, over the same period in 2012, offset by a lower spread between the purchase and sale price for volumes of crude oil sold, as the excess of our average sales price per barrel over our average purchase cost per barrel decreased to approximately $2.30 for the three months ended March 31, 2013, from approximately $2.80 for the three months ended March 31, 2012. This lower realized spread resulted in a $0.7 million reduction in Adjusted gross margin during the three months ended March 31, 2013, compared to the same period in 2012;

• an increase in transportation volumes of approximately 0.9 million barrels, contributing an additional $1.4 million Adjusted gross margin during the three months ended March 31, 2013, compared to the same period in 2012;

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• an increase in unloading volumes from our Platteville operations of approximately 1.7 million barrels, contributing an additional $0.6 million Adjusted gross margin, during the three months ended March 31, 2013, compared to the same period in 2012;

• an increase in the average storage capacity from 6.0 million barrels for the three months ended March 31, 2012, to 7.0 million barrels for the three months ended March 31, 2013, contributing an additional $1.0 million Adjusted gross margin; and

• an increase in pumpover activity at Cushing, contributing an additional $1.0 million Adjusted gross margin during the three months ended March 31, 2013, compared to the same period in 2012.

Operating expense

Operating expenses increased in the three months ended March 31, 2013 to $5.4 million from $5.2 million for the three months ended March 31, 2012. Field expense, maintenance and lease expense increased approximately $0.2 million, $0.1 million and $0.1 million, respectively. Employment expense decreased approximately $0.2 million.

General and administrative expense

General and administrative expense increased in the three months ended March 31, 2013, to $3.6 million from $2.7 million for the three months ended March 31, 2012. This increase is primarily the result of financial and legal advisors' costs associated with the drop down to us of a 33% interest in SemCrude Pipeline, LLC from SemGroup.

Depreciation and amortization expense

Depreciation and amortization expense increased in the three months ended March 31, 2013 to $3.5 million from $3.0 million for the three months ended March 31, 2012. This increase is due primarily to depreciation of new storage facilities in Cushing, Oklahoma.

Liquidity and Capital Resources

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

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

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

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

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

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

Cash Flows

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

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	Three Months Ended March 31,
	2013			2012
	(in thousands)
Cash flows provided by (used in):
Operating activities	$	9,915		$	(240	)
Investing activities	(60,377		)	(3,044		)
Financing activities	52,723			(1,194		)
Change in cash and cash equivalents	2,261			(4,478		)
Cash and cash equivalents at beginning of period	108			9,709
Cash and cash equivalents at end of period	$	2,369		$	5,231

Operating Activities

The components of operating cash flows can be summarized as follows:

	Three Months Ended March 31,
	2013			2012
	(in thousands)
Net income	$	11,994		$	7,758
Non-cash expenses, net	2,819			3,259
Changes in operating assets and liabilities, net	(4,898		)	(11,257		)
Net cash flows provided by operating activities	$	9,915		$	(240	)

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.

For the three months ended March 31, 2012, we experienced operating cash outflows of $0.2 million. Net income of $7.8 million included $3.3 million of non-cash expenses, comprised primarily of depreciation and amortization. The primary changes to operating assets and liabilities included an $83.5 millionincrease in accounts receivable, a $68.8 millionincrease in accounts payable and accrued liabilities, a $4.7 million decrease in inventories, a $3.9 million increase in receivables from affiliates and a $2.2 millionincrease in payables to affiliates.

Investing Activities.

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 SemCrude Pipeline, L.L.C. and capital calls in connection with an 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.

For the three months ended March 31, 2012, our cash outflows from investing activities related primarily to capital expenditures of $3.0 million primarily for the construction of storage tanks at our terminal in Cushing, Oklahoma.

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Financing Activities.

Net cash inflows from financing activities for the three months ended March 31, 2013, were primarily $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 SemCrude Pipeline, L.L.C. 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 SemCrude Pipeline, L.L.C., $43.5 million in debt principal repayments, and $8.3 million in distributions to partners.

Cash outflows from financing activities for the three months ended March 31, 2012, consisted primarily of cash distributions to SemGroup of $1.1 million.

Revolving Credit Facility

On November 10, 2011, we entered into a five-year senior secured revolving credit facility agreement. The credit facility under this agreement became effective upon completion of our initial public offering on December 14, 2011.

On January 11, 2013, our credit facility capacity was increased from $150 million to $385 million. The borrowing capacity under this facility can be increased by an additional $165 million. The credit facility includes a $75 million sub-limit for the issuance of letters of credit. All amounts outstanding under the agreement will be due and payable on December 14, 2016.

On January, 11, 2013, the credit facility capacity was increased to $385 million and we borrowed $133.5 million in connection with the purchase of a 33% interest in SCPL from SemGroup and to pay transaction related expenses.

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 2.25% to 3.25% in the case of a Eurodollar rate loan, and from 1.25% to 2.25% in the case of an ABR loan, in each case, based on a leverage ratio specified in the credit agreement.

At March 31, 2013, we had outstanding cash borrowings of $152.5 million, of which $52.5 million incurred interest at ABR plus an applicable margin, and $100 million incurred interest at the Eurodollar rate plus an applicable margin. The interest rate in effect at March 31, 2013 on $52.5 million of ABR borrowings was 5.0%. The interest rate in effect at March 31, 2013 on $100 million of Eurodollar rate borrowings was 3.04%.

At March 31, 2013, we had $48.9 million in outstanding letters of credit and the rate per annum was 2.75%. 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, 2013, we had $6.1 million of secured bilateral letters of credit outstanding. The interest rate in effect was 1.75% on $1.1 million and 2.0% on $5.0 million. Secured bilateral letters of credit are external to the facility and do not reduce revolver availability.

The credit facility contains representations and warranties and affirmative and negative covenants customary for transactions of this nature. The negative covenants limit or restrict our ability (as well as the ability of our Restricted Subsidiaries, as defined in the credit facility) 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 4.50 to 1.00 (or 5.00 to 1.00 during a temporary period from the date of funding of the purchase price of certain acquisitions (as described in the credit facility) until the last day of the third fiscal quarter following such acquisitions);

• 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;

Page 28

• 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, our risk management policy, 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 herein, 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.

The credit agreement also contains events of default customary for transactions of this nature, including the failure by SemGroup to directly or indirectly own a majority of the equity interests of our general partner. Upon the occurrence and during the continuation of an event of default under the credit facility, the lenders may, among other things, terminate their revolving loan commitments, accelerate and declare the outstanding loans to be immediately due and payable and exercise remedies against us and the collateral as may be available to the lenders under the credit facility and other loan documents.

As of March 31, 2013, we were in compliance with our covenants under our credit facility.

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 $25.5 million and $18.8 million at March 31, 2013 and December 31, 2012, 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:

• 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; or

• 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.

Projected capital expenditures for 2013 include $17 million for expansion projects and $4 million in maintenance projects. In addition, during 2013 we expect to invest $39 million in the expansion of the White Cliffs Pipeline, which will add a second 12-inch line from Platteville, Colorado to Cushing, Oklahoma.

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 facilities and the issuance of debt and equity securities.

Distributions

The following table sets forth cash distributions paid during 2012 and 2013:

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Quarter Ended	Record Date	Payment Date	Distribution Per Unit
December 31, 2011	February 3, 2012	February 13, 2012	$0.0670	*
March 31, 2012	May 7, 2012	May 15, 2012	$0.3725
June 30, 2012	August 6, 2012	August 14, 2012	$0.3825
September 30, 2012	November 5, 2012	November 14, 2012	$0.3925
December 31, 2012	February 4, 2013	February 14, 2013	$0.4025
March 31, 2013	May 6, 2013	May 15, 2013	$0.4300	**

*The cash distribution paid in the first quarter of 2012 was $0.0670 per unit. This prorated amount corresponds to the minimum quarterly cash distribution of $0.3625 per unit, or $1.45 per unit on an annualized basis. The proration period began on December 15, 2011, immediately after the closing date of our initial public offering, and continued through December 31, 2011.

**The cash distribution of the first quarter of 2013 is $0.43 per unit, or $1.72 per unit on an annualized basis. The distribution will be paid on May 15, 2013, to all holders of record on May 6, 2013.

Credit Risk

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

Customer Concentration

Tesoro Refining and Marketing Company, Shell Trading, Flint Hills Resources and Phillips 66 each accounted for more than 10% of our total revenue for the three months ended March 31, 2013, at approximately 22%, 11%, 11%, and 11%, 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 Adjusted gross margin.

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, 2013 and December 31, 2012, we had outstanding letters of credit of approximately $55.0 million and $43.8 million, respectively.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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, 2012.

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Recent Accounting Pronouncements

See Note 1 to our condensed consolidated financial statements.

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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 to crude oil prices. 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, 2013 and 2012, and for the years ended December 31, 2012 and 2011.

	Light Sweet Crude Oil Futures ($ per Barrel)
Three Months Ended March 31, 2013
High	$	97.94
Low	$	90.12
High/Low Differential	$	7.82
Three Months Ended March 31, 2012
High	$	109.77
Low	$	96.36
High/Low Differential	$	13.41
Year Ended December 31, 2012
High	$	109.77
Low	$	77.69
High/Low Differential	$	32.08
Year Ended December 31, 2011
High	$	113.93
Low	$	75.67
High/Low Differential	$	38.26

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

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Based on our open derivative contracts at March 31, 2013, 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 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 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	135	$	(566	)	$	(1,313	)	$	1,313	May 2013

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

Interest Rate Risk

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

We recorded interest expense related to our credit facility of $1.8 million during the three months ended March 31, 2013. An increase in interest rates of 1% would have increased our interest expense by $341 thousand during the three months ended March 31, 2013.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of our general partner have concluded that the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) under the Exchange Act) are effective as of March 31, 2013. 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, 2013, 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, 2012.

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

For information on unregistered sales of equity securities and use of proceeds, see our current report on Form 8-K filed with the SEC on January 14, 2013.

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	Contribution Agreement, dated as of January 8, 2013, by and among SemGroup Corporation, Rose Rock Midstream Holdings, LLC, Rose Rock Midstream GP, LLC, Rose Rock Midstream, L.P. and Rose Rock Midstream Operating, LLC (filed as Exhibit 2.1 to the Registrant's current report on Form 8-K (File No. 001-35365), filed with the Commission on January 14, 2013, and incorporated herein by reference).
10.2	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Rose Rock Midstream, L.P. and the Purchasers identified therein (filed as Exhibit 3.1 to the Registrant's current report on Form 8-K (File No. 001-35365), filed with the Commission on January 14, 2013, and incorporated herein by reference).
10.3	Registration Rights Agreement, dated as of January 11, 2013, by and among Rose Rock Midstream, L.P. and the Purchasers Identified therein (filed as Exhibit 4.1 to the Registrant's current report on Form 8-K (File No. 001-35365), filed with the Commission on January 14, 2013, and incorporated herein by reference).
10.4	Common Unit Purchase Agreement, dated as of January 8, 2013, by and among Rose Rock Midstream, L.P. and the Purchasers identified therein (filed as Exhibit 10.1 to the Registrant's current report on Form 8-K (file No. 001-35365), filed with the Commission on January 14, 2013, and incorporated herein by reference).
31.1	Rule 13a-14(a)/15d-14(a) Certification of Norman J. Szydlowski, Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Robert N. Fitzgerald, Chief Financial Officer.
32.1	Section 1350 Certification of Norman J. Szydlowski, Chief Executive Officer.
32.2	Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer.
101	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) the Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012, (ii) the Condensed Consolidated Statements of Income for the three months ended March 31, 2013 and 2012, (iii) the Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012, and (iv) the Notes to the Consolidated Financial Statements.

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SIGNATURE

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

Date: May 9, 2013	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	Contribution Agreement, dated as of January 8, 2013, by and among SemGroup Corporation, Rose Rock Midstream Holdings, LLC, Rose Rock Midstream GP, LLC, Rose Rock Midstream, L.P. and Rose Rock Midstream Operating, LLC (filed as Exhibit 2.1 to the Registrant's current report on Form 8-K (File No. 001-35365), filed with the Commission on January 14, 2013, and incorporated herein by reference).
10.2	Amendment No. 1 to the Second Amended and Restated Agreement of Limited Partnership of Rose Rock Midstream, L.P. and the Purchasers identified therein (filed as Exhibit 3.1 to the Registrant's current report on Form 8-K (File No. 001-35365), filed with the Commission on January 14, 2013, and incorporated herein by reference).
10.3	Registration Rights Agreement, dated as of January 11, 2013, by and among Rose Rock Midstream, L.P. and the Purchasers Identified therein (filed as Exhibit 4.1 to the Registrant's current report on Form 8-K (File No. 001-35365), filed with the Commission on January 14, 2013, and incorporated herein by reference).
10.4	Common Unit Purchase Agreement, dated as of January 8, 2013, by and among Rose Rock Midstream, L.P. and the Purchasers identified therein (filed as Exhibit 10.1 to the Registrant's current report on Form 8-K (file No. 001-35365), filed with the Commission on January 14, 2013, and incorporated herein by reference).
31.1	Rule 13a-14(a)/15d-14(a) Certification of Norman J. Szydlowski, Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Robert N. Fitzgerald, Chief Financial Officer.
32.1	Section 1350 Certification of Norman J. Szydlowski, Chief Executive Officer.
32.2	Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer.
101	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) the Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012, (ii) the Condensed Consolidated Statements of Income for the three months ended March 31, 2013 and 2012, (iii) the Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012, and (iv) the Notes to the Consolidated Financial Statements.

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