Attached files

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EX-10.3 - RRMS 6.30.15 EXH 10.3 BOARD OF DIRECTORS COMPENSATION PLAN - Rose Rock Midstream, L.P.rrms63015exhibit103.htm
EX-32.2 - RRMS 6.30.15 EXH 32.2 SECTION 1350 CERT - FITZGERALD - Rose Rock Midstream, L.P.rrms63015exhibit322.htm
EX-31.2 - RRMS 6.30.15 EXH 31.2 SECTION 302 CERT - FITZGERALD - Rose Rock Midstream, L.P.rrms63015exhibit312.htm
EX-32.1 - RRMS 6.30.15 EXH 32.1 SECTION 1350 CERT - CONNER - Rose Rock Midstream, L.P.rrms63015exhibit321.htm
EX-31.1 - RRMS 6.30.15 EXH 31.1 SECTION 302 CERT - CONNER - Rose Rock Midstream, L.P.rrms63015exhibit311.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________________________________________________________ 
FORM 10-Q
___________________________________________________________ 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2015
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                    
Commission File Number: 1-35365
___________________________________________________________ 
ROSE ROCK MIDSTREAM, L.P.
(Exact name of registrant as specified in its charter)
___________________________________________________________ 
Delaware
45-2934823
(State or other jurisdiction of
incorporation or organization)
(IRS Employer
Identification Number)
Two Warren Place
6120 S. Yale Avenue, Suite 700
Tulsa, OK 74136-4216
(Address of principal executive offices and zip code)
(918) 524-7700
(Registrant’s telephone number, including area code)
___________________________________________________________ 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days:    Yes  x    No  o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files):    Yes  x    No  o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
x
Accelerated filer
o
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 July 31, 2015, there were 36,790,363 common units outstanding.



Rose Rock Midstream, L.P.
TABLE OF CONTENTS
 
 
PART I – FINANCIAL INFORMATION
 
 
 
 
Item 1
 
 
 
 
 
Item 2
Item 3
Item 4
 
 
 
 
PART II – OTHER INFORMATION
 
 
 
 
Item 1
Item 1A
Item 2
Item 3
Item 4
Item 5
Item 6
 
 
 
 



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, or supply of, crude oil in markets served by our midstream assets;
Our ability to obtain new sources of supply of crude oil;
The amount of collateral required to be posted from time to time in our purchase, sale or derivative transactions;
Competition from other midstream energy companies;
Our ability to comply with the covenants contained in our credit facility and the indentures governing our senior notes, including requirements under our credit facility to maintain certain financial ratios;
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, transportation and related 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;
A cyber attack involving our information systems and related infrastructure, or that of our business associates;
Hazards or operating risks incidental to the gathering, transporting or storing of crude oil;
Changes in laws and regulations and our failure to comply with new or existing laws or regulations, particularly with regard to taxes, safety and protection of the environment;
The possibility that the construction or acquisition of new assets may not result in the corresponding anticipated revenue increases; and
General economic, market and business conditions.
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor, or combination of factors, may cause actual results to differ from those contained in any forward-looking statement.
Readers are cautioned not to place undue reliance on any forward-looking statements contained in this Form 10-Q, which reflect management’s opinions only as of the date hereof. Except as required by law, we undertake no obligation to revise or publicly release the results of any revision to any forward-looking statements.
_________________________________________________________________________________________________
Investors and others should note that we announce material company information using our investor relations website (www.rrmidstream.com), SEC filings, press releases, public conference calls and webcasts. We use these channels, as well as social media, to communicate with our investors and the public about our company, our businesses and our results of operations. The information we post on social media could be deemed to be material information. Therefore, we encourage



investors, the media and others interested in our company to review the information we post on the social media channels listed on our investor relations website.
________________________________________________________________________________________
As used in this Form 10-Q, and unless the context indicates otherwise, the term(s) (i) the "Partnership," "Rose Rock," "we," "our," "us" or like terms, refer to Rose Rock Midstream, L.P., its subsidiaries and its predecessor; (ii) "SemGroup" refers to SemGroup Corporation (NYSE: SEMG), and its subsidiaries and affiliates, other than our general partner and us; (iii) "Rose Rock GP" or our "general partner" refer to Rose Rock Midstream GP, LLC; and (iv) "unitholders" refer to our common and subordinated unitholders, and not our general partner.




PART 1.
FINANCIAL INFORMATION
Item 1.
Financial Statements

ROSE ROCK MIDSTREAM, L.P.
Condensed Consolidated Balance Sheets
(In thousands, except unit amounts)
 
(Unaudited)
 
 
 
June 30,
2015
 
December 31,
2014
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
68,102

 
$
3,625

Accounts receivable
251,240

 
224,881

Receivable from affiliates
17,613

 
15,485

Inventories
67,331

 
26,722

Other current assets
4,234

 
4,056

Total current assets
408,520

 
274,769

Property, plant and equipment (net of accumulated depreciation of $102,823 and $82,646 at June 30, 2015 and December 31, 2014, respectively)
419,458

 
396,066

Equity method investments
426,058

 
269,635

Goodwill
36,116

 
36,116

Other intangible assets (net of accumulated amortization of $907 and $370 at June 30, 2015 and December 31, 2014, respectively)
16,103

 
16,640

Other noncurrent assets, net
17,583

 
13,037

Total assets
$
1,323,838

 
$
1,006,263

LIABILITIES AND PARTNERS' CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
241,284

 
$
211,300

Payable to affiliates
31,477

 
27,909

Accrued liabilities
31,230

 
23,282

Other current liabilities
4,125

 
3,191

Total current liabilities
308,116

 
265,682

Long-term debt
744,339

 
432,092

Commitments and contingencies (Note 6)

 

Partners’ capital:
 
 
 
Common units – public (16,085,945 and 13,765,451 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively)
98,338

 
69,929

Common units – SemGroup (20,704,418 and 6,814,709 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively)
162,659

 
155,367

Subordinated units – SemGroup (0 and 8,389,709 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively)

 
(60,760
)
Class A units - SemGroup (0 and 3,750,000 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively)

 
76,321

General partner
10,386

 
67,632

Total partners' capital
271,383

 
308,489

Total liabilities and partners' capital
$
1,323,838

 
$
1,006,263

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

Page 6



ROSE ROCK MIDSTREAM, L.P.
Unaudited Condensed Consolidated Statements of Income
(In thousands, except per unit data)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Revenues, including revenues from affiliates (Note 9):
 
 
 
 
 
 
 
Product
$
193,525


$
267,087


$
300,092


$
533,377

Service
29,778


25,069


57,904


51,293

Total revenues
223,303


292,156


357,996


584,670

Expenses, including expenses from affiliates (Note 9):







Costs of products sold, exclusive of depreciation and amortization
173,133


255,745


269,370


510,282

Operating
23,656


17,438


44,607


32,653

General and administrative
6,329


6,191


11,949


9,938

Depreciation and amortization
10,608


7,276


20,751


18,758

Total expenses
213,726


286,650


346,677


571,631

Earnings from equity method investments
17,683


12,291


38,547


23,371

Operating income
27,260


17,797


49,866


36,410

Other expenses, net:







Interest expense
10,197


2,730


18,203


5,117

Other income
(5
)

(21
)

(5
)

(21
)
Total other expenses, net
10,192


2,709


18,198


5,096

Net income
17,068


15,088


31,668


31,314

Less: net income attributable to noncontrolling interests


4,082




7,758

Net income attributable to Rose Rock Midstream, L.P.
$
17,068

 
$
11,006

 
$
31,668

 
$
23,556

Net income allocated to general partner
$
5,323

 
$
1,067

 
$
10,065

 
$
1,872

Net income allocated to common unitholders
$
11,745


$
7,513


$
21,603


$
15,619

Net income allocated to subordinated unitholders
$


$
3,063


$


$
6,860

Net loss allocated to Class A unitholders
$


$
(637
)

$


$
(795
)
Net income (loss) per limited partner unit:
 
 
 
 
 
 
 
Common unit (basic)
$
0.32


$
0.41


$
0.60


$
0.86

Common unit (diluted)
$
0.32


$
0.41


$
0.60


$
0.85

Subordinated unit (basic and diluted)
$


$
0.37


$


$
0.82

Class A unit (basic and diluted)
$


$
(0.25
)

$


$
(0.31
)
Basic weighted average number of limited partner units outstanding:
 
 
 
 
 
 
 
Common units
36,790

 
18,336

 
35,803

 
18,243

Subordinated units

 
8,390

 

 
8,390

Class A units

 
2,596

 

 
2,548

Diluted weighted average number of limited partner units outstanding:
 
 
 
 
 
 
 
Common units
36,839

 
18,397

 
35,849

 
18,297

Subordinated units

 
8,390

 

 
8,390

Class A units

 
2,596

 

 
2,548

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

Page 7


ROSE ROCK MIDSTREAM, L.P.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
 
 
Six Months Ended June 30,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net income
$
31,668

 
$
31,314

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
20,751

 
18,758

Loss (gain) on disposal of long-lived assets, net
130

 
(61
)
Amortization of debt issuance costs
1,210

 
520

Inventory valuation adjustment
1,235

 

Non-cash equity compensation
655

 
390

Net unrealized loss (gain) related to derivative instruments
1,116

 
(245
)
Changes in assets and liabilities, net of the effects of acquisitions:
 
 
 
Decrease (increase) in accounts receivable
(26,359
)
 
(2,185
)
Decrease (increase) in receivable from affiliates
(2,128
)
 
29,444

Decrease (increase) in inventories
(41,844
)
 
(3,526
)
Decrease (increase) in other current assets
(1,407
)
 
(1,229
)
Increase (decrease) in accounts payable and accrued liabilities
31,161

 
(8,584
)
Increase (decrease) in payable to affiliates
3,683

 
(39,478
)
Net cash provided by operating activities
19,871


25,118

Cash flows from investing activities:
 
 
 
Capital expenditures
(36,262
)
 
(21,838
)
Proceeds from sale of long-lived assets
126

 
710

Contributions to equity method investments
(23,462
)
 
(51,774
)
Acquisitions
(205,071
)
 
(133,993
)
Distributions from equity investments in excess of equity in earnings
13,077

 
4,681

Net cash used in investing activities
(251,592
)

(202,214
)
Cash flows from financing activities:
 
 
 
Debt issuance costs
(5,688
)
 
(62
)
Borrowings on revolving credit facility and issuance of senior unsecured notes, net of discount
676,208

 
296,000

Principal payments on revolving credit facility
(364,000
)
 
(93,500
)
Principal payments on capital lease obligations
(24
)
 
(18
)
Proceeds from common L.P. unit issuance, net of offering costs
89,119

 

Contribution from general partner

 
8,327

Cash consideration in excess of historical cost of acquisitions from SemGroup
(46,264
)
 
(24,413
)
Cash distributions to partners
(53,153
)
 
(26,744
)
Cash distributions to noncontrolling interests

 
(9,025
)
Contributions from noncontrolling interests

 
14,367

Net cash provided by financing activities
296,198


164,932

Net increase (decrease) in cash and cash equivalents
64,477

 
(12,164
)
Cash and cash equivalents at beginning of period
3,625

 
15,437

Cash and cash equivalents at end of period
$
68,102

 
$
3,273

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

Page 8


ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements

1.
OVERVIEW
Rose Rock Midstream, L.P. is a Delaware limited partnership. The general partner of Rose Rock Midstream, L.P. is Rose Rock Midstream GP, LLC, which is a wholly-owned subsidiary of SemGroup Corporation. SemGroup Corporation is a Delaware corporation headquartered in Tulsa, Oklahoma that provides diversified midstream services to the energy industry.
The terms "we," "our," "us," "Rose Rock," the "Partnership" and similar language used in these notes to the unaudited condensed consolidated financial statements refer to Rose Rock Midstream, L.P, and its subsidiaries. The term "SemGroup" refers to SemGroup Corporation and its controlled subsidiaries, including Rose Rock Midstream GP, LLC.
Basis of presentation
These condensed consolidated financial statements include the accounts of Rose Rock Midstream, L.P. and its controlled subsidiaries.
Prior period financial information has been recast to reflect the effects of a common control acquisition completed on February 13, 2015. See Note 3 for additional information.
The condensed consolidated balance sheet at December 31, 2014, which is derived from audited financial statements and the unaudited condensed consolidated interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States and the rules and regulations of the SEC. These condensed consolidated financial statements include all normal and recurring adjustments that, in the opinion of management, are necessary to present fairly the financial position of the Partnership and the results of its operations and its cash flows. All significant transactions between Rose Rock Midstream, L.P. and its consolidated subsidiaries have been eliminated.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures in the financial statements. Although management believes these estimates are reasonable, actual results could differ materially from these estimates. The results of operations for the three months and six months ended June 30, 2015, are not necessarily indicative of the results to be expected for the full year ending December 31, 2015.
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, 2014, which are included in our Current Report on Form 8-K, filed with the SEC on May 11, 2015.
Our significant accounting policies are consistent with those described in Note 2 of our audited consolidated financial statements for the year ended December 31, 2014, which are included in our Current Report on Form 8-K, filed with the SEC on May 11, 2015.
Recent Accounting Pronouncements
In July 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory," which requires that inventory within the scope of the guidance be measured at the lower of cost and net realizable value rather than the lower of cost or market. The standard will be effective for public business entities for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The new guidance shall be applied prospectively and early adoption is permitted. We will adopt this guidance in the first quarter of 2017. The impact is not expected to be material.
On April 30, 2015, the FASB issued ASU 2015-06, "Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a Consensus of the FASB Emerging Issues Task Force)", which requires a master limited partnership ("MLP") to allocate earnings (losses) of the transferred business entirely to the general partner when calculating earnings per unit ("EPU") for periods before the dropdown transaction occurred. The EPU that the limited partners previously reported would not change as a result of the dropdown transaction. The ASU also requires an MLP to disclose how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing EPU under the two-class method. The standard will be effective for U.S. public companies for annual reporting periods beginning after December 15, 2015 and early adoption is permitted. The new guidance shall be applied

Page 9

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements
1.
OVERVIEW, Continued

on a retrospective basis for all periods presented. We early adopted this guidance in the first quarter of 2015 and the impact was not material.
On April 7, 2015, the FASB issued ASU 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” which is designed to simplify presentation of debt issuance costs. The standard requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The standard will be effective for U.S. public companies for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. The new guidance shall be applied on a retrospective basis for all periods presented. We will adopt this guidance in the first quarter of 2016. The impact is not expected to be material.
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers", which supersedes nearly all existing revenue recognition guidance under accounting principles generally accepted in the United States ("U.S. GAAP"). The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP.
The standard permits using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). On July 9, 0215, the FASB approved a one-year deferral and the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein. We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and have not yet determined the method by which we will adopt the standard. We will adopt this guidance in the first quarter of 2018.

2.
EQUITY METHOD INVESTMENTS
Under the equity method, we do not report the individual assets and liabilities of our investees. Instead, our membership interests are reflected in one line as a noncurrent asset on our condensed consolidated balance sheets.
Our equity method investments consist of the following (in thousands):
 
June 30, 2015
 
December 31, 2014
White Cliffs Pipeline, L.L.C.
$
281,627

 
$
269,635

Glass Mountain Pipeline LLC
144,431

 

Total equity method investments
$
426,058

 
$
269,635

Our earnings from equity method investments consist of the following (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
White Cliffs Pipeline, L.L.C.
$
15,545

 
$
12,291

 
$
34,635

 
$
23,371

Glass Mountain Pipeline LLC
2,138

 

 
3,912

 

Total earnings from equity method investments
$
17,683

 
$
12,291

 
$
38,547

 
$
23,371

Cash distributions received from equity method investments consist of the following (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
White Cliffs Pipeline, L.L.C.
$
20,551

 
$
14,467

 
$
44,705

 
$
28,052

Glass Mountain Pipeline LLC
5,009

 

 
6,920

 

Total cash distributions received from equity method investments
$
25,560

 
$
14,467

 
$
51,625

 
$
28,052


Page 10

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements

2.    EQUITY METHOD INVESTMENTS, Continued

White Cliffs Pipeline, L.L.C.
Certain unaudited summarized income statement information of White Cliffs Pipeline, L.L.C. ("White Cliffs") for the three months and six months ended June 30, 2015 and 2014 is shown below (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Revenues
$
48,509

 
$
34,533

 
$
103,123

 
$
67,807

Operating, general and administrative expenses
$
9,045

 
$
5,539

 
$
17,398

 
$
12,307

Depreciation and amortization expense
$
8,587

 
$
4,537

 
$
17,125

 
$
8,930

Net income
$
30,870

 
$
24,457

 
$
68,593

 
$
46,570

Our equity in earnings of White Cliffs for the three months and six months ended June 30, 2015 and 2014 is less than 51% of the net income of White Cliffs for the same periods. This is due to certain general and administrative expenses incurred in managing the operations of White Cliffs that the other owners are not obligated to share. Such expenses are recorded by White Cliffs and are allocated to our ownership interest. White Cliffs recorded $0.4 million and $0.4 million of such general and administrative expense for the three months ended June 30, 2015 and 2014, respectively. White Cliffs recorded $0.7 million and $0.8 million of such general and administrative expense for the six months ended June 30, 2015 and 2014, respectively.
The members of White Cliffs are required to contribute capital to White Cliffs to fund various projects. For the six months ended June 30, 2015, we contributed $21.4 million to these projects, including $13.1 million of contributions for an expansion project adding approximately 65,000 barrels per day of capacity. Remaining contributions related to the expansion project will be paid in 2015 and 2016 and are expected to total approximately $23.6 million. The project is expected to be completed in late 2015.
Glass Mountain Pipeline LLC
Certain summarized unaudited income statement information of Glass Mountain Pipeline LLC ("Glass Mountain") for the three months and six months ended June 30, 2015 is shown below (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2015
Revenues
$
9,788

 
$
20,909

Cost of sales
$

 
$
1,982

Operating, general and administrative expenses
$
1,473

 
$
2,911

Depreciation and amortization expense
$
3,932

 
$
7,976

Net income
$
4,381

 
$
8,036

Our equity in earnings of Glass Mountain for the three months and six months ended June 30, 2015 is less than 50% of the net income of Glass Mountain for the same period due to amortization of capitalized interest for the period.
For the six months ended June 30, 2015, we contributed $1.4 million to Glass Mountain related to capital projects.

3.
ACQUISITIONS

During the six months ended June 30, 2015, we completed the following acquisition:

Page 11

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements

3.
ACQUISITIONS, Continued    


On February 13, 2015, we acquired the Wattenberg Oil Trunkline ("WOT") and Glass Mountain Holding, LLC, which owns a 50% interest in Glass Mountain, from SemGroup in exchange for (i) cash of approximately $251.2 million, (ii) the issuance of 1.75 million common units, and (iii) an increase of the capital account of our general partner and a related issuance of general partner interest, to allow our general partner to maintain its 2% general partner interest in us. The WOT is a 75-mile, 12-inch diameter crude oil gathering pipeline system that transports crude oil from production facilities in the DJ Basin to White Cliffs' pipeline. It has a capacity of approximately 85,000 barrels per day. Glass Mountain owns a 215-mile crude oil pipeline in western and north central Oklahoma that is operated by Rose Rock.
The cash consideration was funded through a borrowing under our credit facility and the issuance and sale of common units in an underwritten public offering (Note 7). As the transaction was between entities under common control, we recorded the acquired assets and liabilities 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 capital accounts of our general and limited partners on a pro-rata basis.
The acquisition of WOT created a change in reporting entity, which required our historical results to be recast as if WOT had been part of Rose Rock in prior periods. The historical financial statements have been recast to reflect this change. The impact to prior periods was not significant. Prior period earnings of WOT have been allocated to the general partner.
The acquisition of Glass Mountain Holding, LLC, is equivalent to the acquisition of an equity method investment which does not create a change in reporting entity. As such, prior periods have not been recast to include the historical results of Glass Mountain. The Glass Mountain acquisition is reflected in our results as of January 1, 2015, which was the agreed upon date of transfer between SemGroup and Rose Rock. The difference between accounting for the transfer on January 1, 2015 versus the closing date of the transaction, February 13, 2015, is not significant to our financial results.

During the year ended December 31, 2014, we completed the following acquisitions:
On June 23, 2014, we acquired the remaining 33% interest in SemCrude Pipeline, L.L.C. ("SCPL") from SemGroup for (i) cash of approximately $114.4 million, (ii) the issuance of 2.425 million common units, (iii) the issuance of 1.25 million Class A units, and (iv) an increase of the capital account of our general partner and a related issuance of general partner interest, to allow our general partner to maintain its 2% general partner interest in us. SCPL owns a 51% membership interest in White Cliffs. As the transaction was between entities under common control, we recorded our investment in SCPL based on SemGroup's historical cost. The purchase price in excess of historical cost was treated as an equity transaction with SemGroup, which reduced the partners' capital accounts of our general and limited partners on a pro-rata basis.
On June 24, 2014, we acquired crude oil trucking assets from a subsidiary of Chesapeake Energy Corporation for $44.0 million in cash.

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:

Page 12

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements
4.
FINANCIAL INSTRUMENTS, Continued

Forward contracts – Over the counter ("OTC") contracts to buy or sell a commodity at an agreed upon future date. The buyer and seller agree on specific terms (price, quantity, delivery period, and location) and conditions at the inception of the contract.
Futures contracts – Exchange traded contracts to buy or sell a commodity. These contracts are standardized by the exchange in terms of quality, quantity, delivery period and location for each commodity.
We record commodity derivative assets and liabilities at fair value at each balance sheet date with the exception of commitments which have been designated as normal purchases and sales. The table below summarizes the balances of these assets and liabilities at June 30, 2015 and December 31, 2014 (in thousands):
 
June 30, 2015
 
December 31, 2014
 
Level 1
 
Netting*
 
Total
 
Level 1
 
Netting*
 
Total
Assets
$
762

 
$
(317
)
 
$
445

 
$
3,198

 
$
(1,637
)
 
$
1,561

Liabilities
$
317

 
$
(317
)
 
$

 
$
1,637

 
$
(1,637
)
 
$

* Relates primarily to exchange traded futures. Gain and loss positions on multiple contracts are settled net on a daily basis with the exchange.
"Level 1" measurements are based on inputs consisting of unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. These include commodity futures contracts that are traded on an exchange.
"Level 2" measurements are based on inputs consisting of market observable and corroborated prices for similar derivative contracts. Assets and liabilities classified as Level 2 include OTC traded physical fixed priced purchases and sales forward contracts.
"Level 3" measurements are based on inputs from a pricing service and/or internal valuation models incorporating observable and unobservable market data.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value levels. At June 30, 2015, 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 recorded at fair value which were classified as Level 2 or Level 3 during the three months and six months ended June 30, 2015 and 2014. As such, no rollforward of Level 3 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 June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Sales
7,721

 
1,135

 
13,452

 
1,950

Purchases
7,508

 
1,005

 
13,413

 
1,815

We have not designated any of our commodity derivative instruments as accounting hedges. We record the fair value of the derivative instruments on our condensed consolidated balance sheets in other current assets and other current liabilities. The fair value of our commodity derivative assets and liabilities recorded to other current assets and other current liabilities was as follows (in thousands):
 
June 30, 2015
 
December 31, 2014
 
Assets
 
Liabilities
 
Assets
 
Liabilities
Commodity contracts
$
445

 
$

 
$
1,561

 
$

We have posted margin deposits as collateral with brokers who have the right of set off associated with these funds. Our margin deposit balances were $1.1 million and $0.8 million as of June 30, 2015 and December 31, 2014, respectively.

Page 13

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements
4.
FINANCIAL INSTRUMENTS, Continued

These margin account balances have not been offset against our net commodity derivative instrument (contract) positions. Had these margin account balances been netted against our net commodity derivative instrument (contract) positions as of June 30, 2015 and December 31, 2014, we would have had net asset positions of $1.5 million and $2.4 million, respectively.
Realized and unrealized losses from our commodity derivatives were recorded to product revenue in the following amounts (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Commodity contracts
$
(2,202
)
 
$
(1,942
)
 
$
(2,846
)
 
$
(2,749
)
Concentrations of risk
During the three months ended June 30, 2015, two third-party customers accounted for approximately 59% of our consolidated revenue. We purchased approximately $20.5 million of product from one third-party supplier, which represented approximately 12% of our costs of products sold.
During the six months ended June 30, 2015, two third-party customers accounted for approximately 67% of our consolidated revenue. We purchased approximately $98.5 million of product from two third-party suppliers, which represented approximately 37% of our costs of products sold.
At June 30, 2015, one third-party customer accounted for 53% of our total accounts receivable.


5.
LONG-TERM DEBT
Our long-term debt consisted of the following (in thousands):
 
June 30,
2015
 
December 31,
2014
Rose Rock 5.625% senior unsecured notes due 2022
$
400,000

 
$
400,000

Rose Rock 5.625% senior unsecured notes due 2023
344,276

 

Rose Rock revolving credit facility

 
32,000

Capital leases
107

 
132

Total long-term debt
$
744,383

 
$
432,132

Less: current portion of long-term debt
44

 
40

Noncurrent portion of long-term debt
$
744,339

 
$
432,092

Senior unsecured notes due 2022
At June 30, 2015, we had $400 million of 5.625% senior unsecured notes due 2022 outstanding ("2022 Notes"). Rose Rock and Rose Rock Finance Corporation ("Finance Corp.") are co-issuers of the 2022 Notes. For the three months and six months ended June 30, 2015, we incurred $5.9 million and $11.7 million, respectively, of interest expense related to these notes, including amortization of debt issuance costs.
Senior unsecured notes due 2023
On May 14, 2015, Rose Rock and its wholly-owned subsidiary, Finance Corp., as co-issuer, sold $350 million of 5.625% senior unsecured notes due 2023 (the “2023 Notes”) to certain initial purchasers for resale to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), and to non-U.S. persons outside the United States pursuant to Regulation S of the Securities Act.
The 2023 Notes were sold at 98.345% of par, a discount of $5.8 million. The discount is reported as a reduction to the face value of the 2023 Notes on our condensed consolidated balance sheets and is being amortized over the life of the 2023 Notes using the interest method. At June 30, 2015, the unamortized discount was $5.7 million.

Page 14

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements
5.
LONG-TERM DEBT, Continued

The net proceeds from the offering of $337.7 million, after the discount and $6.5 million of underwriters' fees and offering expenses, were used to repay amounts borrowed under our revolving credit facility and for general partnership purposes.
The 2023 Notes are governed by an indenture between the Partnership, its subsidiary guarantors, Finance Corp. and Wilmington Trust, National Association, as trustee (the “Indenture”). The Indenture includes customary covenants, including limitations on our ability to incur additional indebtedness or issue certain preferred shares; pay dividends and make certain distributions, investments and other restricted payments; create certain liens; sell assets; enter into transactions with affiliates; merge, consolidate, sell or otherwise dispose of all or substantially all of our assets; and designate our subsidiaries as unrestricted under the Indenture.
The Indenture includes customary events of default. A default would permit the trustee or holders of at least 25% in aggregate principal amounts of the 2023 Notes then outstanding to declare all amounts owing under the 2023 Notes to be due and payable.
The 2023 Notes are effectively subordinated in right of payment to any of our, and the subsidiary guarantors', existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness.
The Partnership may issue additional notes under the Indenture from time to time, subject to the terms of the Indenture.
Except as described below, the 2023 Notes are not redeemable at the Partnership's option prior to May 15, 2019. From and after May 15, 2019, the Partnership may redeem the 2023 Notes, in whole or in part, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if redeemed during the twelve-month period beginning on May 15 of each of the years indicated below:
Year
 
Percentage
2019
 
102.813%
2020
 
101.406%
2021 and thereafter
 
100.000%
Prior to May 15, 2018, the Partnership may, at its option, on one or more occasions, redeem up to 35% of the sum of the original aggregate principal amount of the 2023 Notes at a redemption price equal to 105.625% of the aggregate principal amount thereof, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings of the Partnership, or the parent of the Partnership to the extent such net proceeds are contributed to the Partnership, subject to certain conditions.
Prior to May 15, 2019, the Partnership may also redeem all or part of the 2023 Notes at a price equal to the principal plus a premium equal to the greater of 1% of the principal or the excess of the present value of the May 15, 2019 redemption price from the table above plus all required interest payments due through May 15, 2019, computed using a discount rate based on a published United States Treasury Rate plus 50 basis points, over the principal value of such 2023 Note.
In the event of a change of control, the Partnership is required to offer to repurchase the 2023 Notes at an amount equal to 101% of the principal plus accrued and unpaid interest.
The 2023 Notes are also subject to a Registration Rights Agreement which requires the Partnership to file a registration statement with the SEC and to use commercially reasonable efforts to consummate such exchange offer within one year of the settlement date of the 2023 Notes so that holders of the 2023 Notes can exchange the 2023 Notes and related guarantees for registered notes (the "Exchange Notes") and guarantees that have substantially identical terms as the 2023 Notes and related guarantees. The guarantees of the Exchange Notes will be full and unconditional and will constitute the joint and several obligations of the subsidiary guarantors. Failure to meet the terms of the Registration Rights Agreement will require the Partnership to pay incremental interest of 0.25% per annum, increased by an additional 0.25% per annum for each 90-day period for which registration default continues (up to a maximum of 1.0% per annum).
Interest on the 2023 Notes is payable in arrears on May 15th and November 15th to holders of record on May 1st and November 1st each year until maturity.
For the three months and six months ended June 30, 2015, we incurred $2.7 million, of interest expense related to these notes, including amortization of debt issuance costs and discount.

Page 15

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements
5.
LONG-TERM DEBT, Continued

Subsidiary Guarantors
The 2022 Notes and the 2023 Notes are guaranteed by all of our existing subsidiaries other than Finance Corp. Such guarantees of the 2022 Notes and the 2023 Notes are full and unconditional and constitute the joint and several obligations of the subsidiary guarantors. Each of the subsidiary guarantors is 100% owned by the Partnership. The Partnership has no assets or operations independent of its subsidiaries and there are no significant restrictions upon the ability of the Partnership, or any of its subsidiaries, to obtain funds from its respective subsidiaries by dividend or loan. None of the assets of the Partnership's subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.
Revolving credit facility
At June 30, 2015, we had no outstanding borrowings on our $585 million revolving credit facility.
We had $24.6 million in outstanding letters of credit at June 30, 2015, and the rate per annum was 2.75%.
At June 30, 2015, we had $36.0 million of secured bilateral letters of credit outstanding. The interest rate in effect was 1.75%. Secured bilateral letters of credit are external to the facility and do not reduce availability for borrowing on our revolving credit facility.
We incurred $2.0 million and $2.6 million of interest expense related to this facility during the three months ended June 30, 2015 and 2014, respectively, including amortization of debt issuance costs. We incurred $4.2 million and $4.8 million of interest expense related to this facility during the six months ended June 30, 2015 and 2014, respectively, including amortization of debt issuance costs.
Fair value
We estimate the fair value of our 2022 Notes and 2023 Notes to be $392 million and $340 million, respectively, at June 30, 2015, based on unadjusted, transacted market prices, which are categorized as Level 1 measurements.

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").
Claims reconciliation process
A large number of parties made claims against SemGroup and the other debtors for obligations alleged to have been incurred prior to the bankruptcy filing. SemGroup has resolved or settled all of these outstanding claims and has made all required distributions. The Plan of Reorganization has therefore been fully administered.
On November 7, 2014, SemGroup Corporation and the other reorganized debtors moved for a final decree from the bankruptcy court closing the debtors’ bankruptcy cases. The United States Bankruptcy Court for the District of Delaware granted the request and entered its Order Granting Motion of Remaining Debtors for Entry of Final Decree on December 18, 2014. Accordingly, the bankruptcy cases for SemCrude, L.P., Eaglwing, L.P., SemCanada II, L.P., SemCanada L.P., SemGas, L.P., SemGroup, L.P., SemMaterials, L.P., and SemStream, L.P. have been closed. As part of its decree, the Court retained jurisdiction over certain on-going adversary proceedings, but the debtors have estimated and paid the claims associated with these remaining adversaries, leaving the non-debtor parties to the adversaries to resolve their remaining claims amongst themselves.
On January 2, 2015, Bettina M. Whyte, the duly appointed Trustee of the SemGroup Litigation Trust (the “Litigation Trustee”), filed a notice of appeal of the Bankruptcy Court’s December 18, 2014 order closing the aforementioned bankruptcy cases. However, the Bankruptcy Court’s order of final decree was effective upon entry, and the appeal does not stay the effect of the order. The Litigation Trustee’s appeal to the United States District Court for the District of

Page 16

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements

6.
COMMITMENTS AND CONTINGENCIES, Continued

Delaware is currently pending and will be opposed by SemGroup Corporation and the other remaining reorganized debtors.
We are indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement with SemGroup.
Environmental
We may, from time to time, experience leaks of petroleum products from our facilities and, as a result of which, we may incur remediation obligations or property damage claims. In addition, we are subject to numerous environmental regulations. Failure to comply with these regulations could result in the assessment of fines or penalties by regulatory authorities.
The Kansas Department of Health and Environment ("KDHE") initiated discussions during SemGroup’s bankruptcy proceeding regarding five of our sites in Kansas that the KDHE believes, based on their historical use, may have soil or groundwater contamination in excess of state standards. The 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 the KDHE to conduct environmental assessments on the sites and to pay the KDHE’s costs associated with their oversight of this matter. SemGroup has conducted Phase II investigations at all sites. Four of the five sites have limited amounts of soil contamination that will be excavated and/or remediated on site. Three of the five sites appeared to have ground water contamination requiring further delineation and/or on-going monitoring. One site was closed and we anticipate closure in 2015 for one of the remaining four sites. SemGroup does not anticipate any penalties or fines for these historical sites. We are indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement with SemGroup.
Dimmit County, TX claims
An employee of Rose Rock Midstream Field Services, LLC was involved in a tractor trailer accident on January 15, 2015 in Dimmit County, Texas.  A second accident followed resulting in six fatalities and multiple injuries. At this time, the following lawsuits have been filed in either the District Court of Zavala County, Texas or the District Court of Dimmit County, Texas, Olga D. Rubio and Carlos Rubio, Individually and on Behalf of All Statutory Wrongful Death Beneficiaries of Carlos Rubio, Jr., Deceased vs. Rose Rock Midstream Field Services, LLC and Jesus T. Riojas; David Rodriguez and Maribel Rodriguez vs. Rose Rock Midstream Field Services, LLC and Jesus T. Riojas; David Rodriguez and Maribel Rodrigues, Plaintiffs and Alejandra Abigail Ortega, Individually and as next friend of K.A.P., a minor, and as Representative of the Estate of Eduardo Pena, and Julian Pena and Nelva G. Suifuentes Pena Intervenors vs. Rose Rock Midstream Field Services, LLC, Jesus Riojas, and Roberto Rivera; Derek Muhlenbruch vs. Rose Rock Midstream Field Services, LLC and Jesus T. Riojas; and Agustin Lara, Sr., Individually, and Elsa Zamarripa, Individually and As Representative of the Estate of Justin Lara, Deceased vs. Rose Rock Midstream Field Services, LLC and Jesus T. Riojas; Jorge A Porras vs. Rose Rock Midstream Field Services, LLC; Nancy Garcia vs. Rose Rock Midstream Field Services, LLC; Veronica Veyro vs. Rose Rock Midstream Field Services, LLC; Veronica Veyro a/n/f of Sergio Veyro, Jr. vs. Rose Rock Midstream Field Services, LLC; Veronica Veyro as Rep of Estate of Sergio Veyro Sr., deceased vs. Rose Rock Midstream Field Services, LLC; Veronica Kimberly Veyro vs. Rose Rock Midstream Field Services, LLC; Roberto Rivera-Castilla vs. Rose Rock Midstream Field Services, LLC; Mary Alice Medellin vs. Rose Rock Midstream Field Services, LLC; Mary Medellin as Rep of Estate of Juan Medellin, Jr. vs. Rose Rock Midstream Field Services, LLC; Mary Medellin on behalf of those entitled to recover for the Wrongful Death of Juan Medellin, Jr. vs. Rose Rock Midstream Field Services, LLC; Elizabeth Rolon vs. Rose Rock Midstream Field Services, LLC; Juan Francisco Medellin, III vs. Rose Rock Midstream Field Services, LLC and David Rodriguez and Maribel Rodriguez vs. Rose Rock Midstream Field Services, LLC and Jesus T. Riojas. We are currently working with counsel for the interested parties to investigate the accident, and no determination of liability has been made.  We will continue to defend our position and believe that any liability that may arise from this incident will be covered by our insurance; however, we cannot predict the outcome.
Blueknight claim
Blueknight Energy Partners, L.P. ("Blueknight"), which was formerly a subsidiary of SemGroup, LP, 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 Corporation). The services provided by

Page 17

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements

6.
COMMITMENTS AND CONTINGENCIES, Continued

SemCrude to Blueknight under this agreement included from time to time certain operational tasks as requested by Blueknight in order that Blueknight could operate its Oklahoma pipeline system and its Cushing, Oklahoma terminal. Under the subsequent amendments to the agreement, certain of these services were phased out and Blueknight began to perform all services necessary for the operation of its Cushing terminal without SemCrude's assistance.
In a letter dated August 18, 2011, Blueknight claimed that SemCrude owes Blueknight approximately 141,000 barrels of crude oil, and that SemCrude came to possess this oil as a result of a breach of the agreement and other tortious conduct. SemGroup responded to Blueknight’s letter denying their charges and requesting documentation from Blueknight of its claim for missing barrels. On February 14, 2012, after months of interaction between the parties through which Blueknight was requested to substantiate its claim, Blueknight filed suit against SemGroup and other related companies in the District Court of Oklahoma County, Oklahoma. On May 1, 2012, the case was transferred to Tulsa County, Oklahoma. On July 2, 2012, the Tulsa County District Court appointed a Special Master to review terminal operations accounting records and determine whether 141,000 barrels of crude oil owned by Blueknight is missing after three months of operations in April through June, 2010. On June 11, 2013, the Special Master’s Report was filed with the District Court finding a shortage in Blueknight’s Cushing terminal and Oklahoma pipeline system of 148,000 barrels. However, after a review of all records created during that three month time period, the Special Master was unable to determine how the shortage might have occurred and was unable to determine the ownership of the potential shortage.
The parties completed discovery in the District Court, where substantial documentation was exchanged and deposition testimony was taken. All parties are seeking complete or partial summary adjudication on the various pending claims and counterclaims. These requests for summary adjudication are currently being briefed by the parties and have yet to be ruled upon by the Court. SemGroup will continue to defend its position; however, we cannot predict the outcome. We are indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement with SemGroup.
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 June 30, 2015, such commitments included the following (in thousands):
 
Volume
(Barrels)
 
Value
Fixed price purchases
1,935

 
$
114,568

Fixed price sales
2,660

 
$
159,148

Floating price purchases
15,960

 
$
930,753

Floating price sales
17,876

 
$
1,063,405


Page 18

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.
We have a take-or-pay obligation with our equity method investee, White Cliffs, for approximately 5,000 barrels per day of space on White Cliffs' pipeline subject to completion of an expansion project related to our Platteville facilities. The agreement is expected to become effective in November 2015 and has a term of 5 years. Annual payments to White Cliffs under the agreement are expected to be $9.4 million.
See Note 2 for capital contribution requirements related to the White Cliffs 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, 2014 to June 30, 2015 (in thousands):
 
Common
Units -
Public
 
Common
Units -
SemGroup
 
Subordinated
Units
 
Class A Units
 
General
Partner
Interest
 
Total Partners' Capital
Balance at December 31, 2014
$
69,929

 
$
155,367

 
$
(60,760
)
 
$
76,321

 
$
67,632

 
$
308,489

Net income
9,446

 
12,157

 

 

 
10,065

 
31,668

Equity issuance
89,119

 
70,560

 

 

 
3,259

 
162,938

Equity adjustment related to common control acquisition
(51,452
)
 
(39,246
)
 
(26,838
)
 

 
(61,580
)
 
(179,116
)
Conversion to common units

 
(16,479
)
 
92,800

 
(76,321
)
 

 

Unvested distribution equivalent rights
(98
)
 

 

 

 

 
(98
)
Cash distributions to partners
(19,261
)
 
(19,700
)
 
(5,202
)
 

 
(8,990
)
 
(53,153
)
Non-cash equity compensation
655

 

 

 

 

 
655

Balance at June 30, 2015
$
98,338

 
$
162,659

 
$

 
$

 
$
10,386

 
$
271,383

 
The December 31, 2014 balance for the general partner interest above has been recast to include equity related to WOT prior to its acquisition from SemGroup. The acquisition of WOT, an entity under common control with Rose Rock, created a change in reporting entity which required prior period financial information to be recast to include WOT (Note 3). "Equity adjustment related to common control acquisition" includes a $59.2 million reduction to general partner interest which reflects the payment made to SemGroup related to the historical value of WOT, which was included in the general partner interest due to the recast. The remaining amounts in "equity adjustment related to common control acquisition" represent the excess of the acquisition price of WOT and a 50% interest in Glass Mountain over SemGroup's historical value of those assets of $205.1 million. As Rose Rock recorded the acquisition based on SemGroup's historical value, the purchase price in excess of historical cost is treated as an equity distribution to SemGroup.
The following table shows the cash distributions paid or declared per common unit during 2015 and 2014:

Page 19

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements

7.
PARTNERS’ CAPITAL AND DISTRIBUTIONS, Continued

Quarter Ended
 
Record Date
 
Payment Date
 
Distribution Per Unit
December 31, 2013
 
February 4, 2014
 
February 14, 2014
 
$0.4650
March 31, 2014
 
May 5, 2014
 
May 15, 2014
 
$0.4950
June 30, 2014
 
August 4, 2014
 
August 14, 2014
 
$0.5350
September 30, 2014
 
November 4, 2014
 
November 14, 2014
 
$0.5750
December 31, 2014
 
February 3, 2015
 
February 13, 2015
 
$0.6200
March 31, 2015
 
May 5, 2015
 
May 15, 2015
 
$0.6350
June 30, 2015
 
August 4, 2015
 
August 14, 2015
 
$0.6500
Equity incentive plan
We granted 25,178 restricted unit awards during the six months ended June 30, 2015, with a weighted average grant date fair value of $47.10. At June 30, 2015, there were 98,243 unvested restricted unit awards that have been granted pursuant to our equity incentive plan. During the six months ended June 30, 2015, 29,275 restricted unit awards vested of which 12,116 were withheld to satisfy tax withholding obligations. The cost associated with the withheld awards of $0.5 million is reflected in the condensed consolidated financial statements as a cash distribution to common public unitholders.
The holders of restricted units granted in 2012 were entitled to equivalent distributions (“UUDs”) to be received upon vesting of the restricted unit awards. The distributions were 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. In January 2015, 3,335 units were issued upon the vesting of the 2012 restricted units. Distributions related to the restricted unit awards granted subsequent to 2012 will be settled in cash upon vesting. At June 30, 2015, the value of these UUDs related to cash settled unvested restricted units was approximately $276 thousand.
Equity issuance
On February 13, 2015, we issued and sold 2.3 million common limited partner units to the public for net proceeds of $89.1 million. Proceeds were used to acquire the WOT and a 50% interest in Glass Mountain from SemGroup. See Note 3 for additional information related to the acquisition including units issued to SemGroup as consideration.
Conversion of subordinated and Class A units
On January 1, 2015, based upon the satisfaction of certain operational targets by White Cliffs, all 3,750,000 Class A units were converted to common units on a one-for-one basis. The conversion did not impact the total number of our outstanding units representing limited partner interests.
On February 17, 2015, certain targets specified in our partnership agreement were achieved and all 8,389,709 subordinated units were converted to common units. The conversion did not impact the total number of our outstanding units representing limited partner interests.

8.
EARNINGS PER LIMITED PARTNER UNIT
Net income is allocated to the general partner and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations, such as incentive distributions that are allocated to the general partner.
Basic and diluted earnings per limited partner unit is determined by dividing net income allocated to the limited partners by the weighted average number of limited partner units for such class outstanding during the period. Diluted earnings per limited partner unit reflects, where applicable, the potential dilution that could occur if securities or other agreements to issue additional units of a limited partner class, such as restricted unit awards, were exercised, settled or converted into such units.
The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three months and six months ended June 30, 2015 and 2014 (in thousands, except per unit data):

Page 20

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements

8.
EARNINGS PER LIMITED PARTNER UNIT, Continued


 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Net income attributable to Rose Rock Midstream, L.P.
$
17,068

 
$
11,006

 
$
31,668

 
$
23,556

Less: General partner's incentive distribution earned
4,981

 
888

 
9,431

 
1,376

Less: General partner's 2.0% ownership
342

 
179

 
634

 
496

Net income allocated to limited partners
$
11,745

 
$
9,939

 
$
21,603

 
$
21,684

Numerator for basic and diluted earnings per limited partner unit (*):
 
 
 
 
 
 
 
Allocation of net income among limited partner interests:
 
 
 
 
 
 
 
Net income allocable to common units
$
11,745

 
$
7,513

 
$
21,603

 
$
15,619

Net income allocable to subordinated units

 
3,063

 

 
6,860

Net loss allocable to Class A units

 
(637
)
 

 
(795
)
Net income allocated to limited partners
$
11,745

 
$
9,939

 
$
21,603

 
$
21,684

Denominator for basic and diluted earnings per limited partner unit:
 
 
 
 
 
 
 
Basic weighted average number of common units outstanding
36,790

 
18,336

 
35,803

 
18,243

Effect of non-vested restricted units
49

 
61

 
46

 
54

Diluted weighted average number of common units outstanding
36,839

 
18,397

 
35,849

 
18,297

Basic and diluted weighted average number of subordinated units outstanding

 
8,390

 

 
8,390

Basic and diluted weighted average number of Class A units outstanding

 
2,596

 

 
2,548

Net income (loss) per limited partner unit:
 
 
 
 
 
 
 
Common unit (basic)
$
0.32

 
$
0.41

 
$
0.60

 
$
0.86

Common unit (diluted)
$
0.32


$
0.41


$
0.60


$
0.85

Subordinated unit (basic and diluted)
$


$
0.37


$


$
0.82

Class A unit (basic and diluted)
$


$
(0.25
)

$


$
(0.31
)
(*) 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. Prior to the conversion of the Class A units in January 2015, the Class A units did not participate in cash distributions, but were allocated a proportional share of undistributed earnings. As distributions related to the available cash exceeded net income, the Class A units reflect a loss for the three months and six months ended June 30, 2014.

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. Allocations are based on the actual costs of employees operating Rose Rock, including employees added through growth and acquisitions. SemGroup charged us $11.8 million and $7.8 million during the three months ended June 30, 2015 and 2014, respectively, for direct employee costs. SemGroup charged us $22.1 million and $14.0 million during the six months ended June 30, 2015 and 2014, respectively, for direct employee costs. These expenses were recorded to operating expenses and general and administrative expenses in our condensed consolidated statements of income.

Page 21

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements
9.
RELATED PARTY TRANSACTIONS, Continued

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 $3.7 million and $3.1 million during the three months ended June 30, 2015 and 2014, respectively, for such allocated costs. SemGroup charged us $6.3 million and $5.0 million during the six months ended June 30, 2015 and 2014, respectively, for such allocated costs. These expenses were recorded to general and administrative expenses in our condensed consolidated statements of income.
NGL Energy Partners LP
SemGroup holds limited partner common units and general partner ownership interests in NGL Energy Partners LP ("NGL Energy"). We generated revenues from NGL Energy of $72.1 million and $99.5 million for the three months ended June 30, 2015 and 2014, respectively. We made purchases of condensate at market prices from NGL Energy in the amount of $75.0 million and $110.1 million for the three months ended June 30, 2015 and 2014, respectively. We received reimbursements from NGL Energy for support services in the amount of $14.0 thousand and $42.0 thousand for the three months ended June 30, 2015 and 2014, respectively.
We generated revenues from NGL Energy of $114.5 million and $233.6 million for the six months ended June 30, 2015 and 2014, respectively. We made purchases of condensate at market prices from NGL Energy in the amount of $110.2 million and $267.8 million for the six months ended June 30, 2015 and 2014, respectively. We received reimbursements from NGL Energy for support services in the amount of $56.0 thousand and $84.0 thousand for the six months ended June 30, 2015 and 2014, respectively.
Transactions with NGL Energy and its subsidiaries primarily relate to marketing, leased storage and transportation services of crude oil, including buy/sell transactions. In accordance with ASC 845-10-15, these transactions were reported as revenue on a net basis in our condensed consolidated statements of income because the purchases of inventory and subsequent sales of the inventory were with the same counterparty.
SemGas, L.P.
We purchase condensate at market prices from SemGas, L.P. ("SemGas"), which is a wholly-owned subsidiary of SemGroup. Purchases from SemGas were $6.4 million and $9.8 million for the three months ended June 30, 2015 and 2014, respectively. Purchases from SemGas were $12.4 million and $19.7 million for the six months ended June 30, 2015 and 2014, respectively.
White Cliffs
We generated storage revenues from our equity investee, White Cliffs, of $1.1 million and $0.7 million for the three months ended June 30, 2015 and 2014, respectively. We generated storage revenues from White Cliffs of $2.1 million and $1.5 million for the six months ended June 30, 2015 and 2014, respectively. We incurred $1.1 million and $0.8 million of costs for the three months months ended June 30, 2015 and 2014, respectively, related to transportation fees for shipments on the White Cliffs Pipeline. We incurred $1.8 million and $1.7 million of costs for the six months ended June 30, 2015 and 2014, respectively, related to transportation fees for shipments on the White Cliffs Pipeline. We received $0.1 million and $0.1 million in management fees from White Cliffs for the three months ended June 30, 2015 and 2014, respectively. We received $0.2 million and $0.2 million in management fees from White Cliffs for the six months ended June 30, 2015 and 2014, respectively.
Glass Mountain Pipeline, LLC
We incurred $0.7 million and $0.1 million of costs for the three months ended June 30, 2015 and 2014, respectively, related to transportation fees for shipments on Glass Mountain's pipeline. We incurred $1.2 million and $0.1 million of costs for the six months ended June 30, 2015 and 2014, respectively, related to transportation fees for shipments on Glass Mountain's pipeline. We received $0.2 million and $0.1 million in fees from Glass Mountain for the three months ended June 30, 2015 and 2014, respectively, related to support services associated with Glass Mountain's pipeline operations. We received $0.4 million and $0.2 million in fees from Glass Mountain for the six months ended June 30, 2015 and 2014, respectively, related to support services associated with Glass Mountain's pipeline operations. We made purchases of crude oil of $1.5 million from Glass Mountain during the six months ended June 30, 2015.

Page 22

ROSE ROCK MIDSTREAM, L.P.
Notes to Unaudited Condensed Consolidated Financial Statements
9.
RELATED PARTY TRANSACTIONS, Continued

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 $4.1 thousand and $42.1 thousand in legal fees and related expenses to this law firm during the three months ended June 30, 2015 and 2014, respectively. We paid $4.1 thousand and $0.1 million in legal fees and related expenses to this law firm during the six months ended June 30, 2015 and 2014, respectively. Our equity method investee, White Cliffs, paid legal fees and related expenses to this law firm of $0.1 thousand and $27.0 thousand during the three months ended June 30, 2015 and 2014, respectively. Our equity method investee, White Cliffs, paid legal fees and related expenses to this law firm of $3.4 thousand and $81.0 thousand during the six months ended June 30, 2015 and 2014, respectively.

10.
SUPPLEMENTAL CASH FLOW INFORMATION

Acquisitions
In connection with the first quarter 2015 acquisition of the WOT and a 50% interest in Glass Mountain (Note 3), we issued 1.75 million common units valued at $70.6 million as non-cash consideration to SemGroup. The valuation of the units is based on the offering price for units concurrently sold in a public offering. In addition, a non-cash contribution of $3.3 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 was treated as an equity transaction with SemGroup, which reduced the partners' capital accounts pro-rata based on ownership percentages. The $46.3 million of cash consideration in excess of historical cost is reflected as a distribution to SemGroup in the condensed consolidated cash flow statement. The entire amount of non-cash equity consideration was in excess of the historical cost and was reduced to zero value in the statement of equity.
In connection with the second quarter 2014 acquisition of the remaining 33% interest in SCPL (Note 3), we issued 2.425 million common units and 1.25 million Class A units, valued at $120.0 million and $58.6 million, respectively, as non-cash consideration to SemGroup. In addition, a non-cash contribution of $3.6 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. The $24.4 million of cash consideration in excess of historical cost is reflected as a distribution to SemGroup in the condensed consolidated cash flow statement. The entire amount of non-cash equity consideration was in excess of the historical cost and was reduced to zero value in the statement of equity.
In connection with this transaction, at June 30, 2014, we accrued a $1.7 million distribution to the non-controlling interest in SCPL. This amount represents the cash distribution to be paid to SemGroup in July related to the June earnings of SCPL. This amount is not reflected in the cash flow statement for the six months ended June 30, 2014.
Senior unsecured note issuance
On June 27, 2014, we agreed to sell $400 million of 5.625% senior unsecured notes due 2022 (Note 5). The net proceeds from the offering of $391.9 million, after underwriters' fees and offering expenses, were received on July 2, 2014, and were used to pay down the revolving credit facility balance. At June 30, 2014, we recorded a receivable for the proceeds and $8.7 million of debt issuance costs. These non-cash transactions have not been reflected in the cash flow statement for the six months ended June 30, 2014.
Other supplemental disclosures
We paid cash interest of $15.8 million and $5.3 million for the six months ended June 30, 2015 and 2014, respectively.
We accrued $9.1 million for purchases of property, plant and equipment for the six months ended June 30, 2015. No significant amounts were accrued for purchases of property, plant and equipment for the six months ended June 30, 2014.


Page 23


Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the notes thereto included in Part I, Item 1 of this Quarterly Report on Form 10-Q, and our audited consolidated financial statements and notes thereto for the year ended December 31, 2014, which are included in our Current Report on Form 8-K filed with the Securities and Exchange Commission (the "SEC") on May 11, 2015.
Overview of Business
We are a growth-oriented Delaware limited partnership formed by SemGroup Corporation ("SemGroup") in 2011 to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We are engaged in the business of crude oil gathering, transportation, storage, distribution and marketing in Colorado, Kansas, Montana, North Dakota, Ohio, Oklahoma, Texas and Wyoming. We operate in 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 NYMEX crude oil futures contracts and is one of the largest crude oil marketing hubs in the United States ("U.S."). We believe that our connectivity in Cushing and our numerous interconnections with third-party pipelines, refineries and storage terminals provide our customers with the flexibility to access multiple points for the receipt and delivery of crude oil.

Fee-Based Services
We charge a capacity or volume-based fee for the storage and transportation of crude oil and related ancillary services. Our fee-based services include substantially all of our operations in Cushing, Oklahoma and Platteville, Colorado, as well as trucking and a portion of the transportation services we provide on our Kansas and Oklahoma pipeline system. Some of our fee-based contracts are take-or-pay contracts whereby the customer is required to pay us a fixed minimum monthly fee regardless of usage. For the three months ended June 30, 2015 and 2014, approximately 61% and 71%, respectively, of our Adjusted gross margin was generated by providing fee-based services to customers. For the six months ended June 30, 2015 and 2014, approximately 64% and 69%, respectively, of our Adjusted gross margin was generated by providing fee-based services to customers. (See "—How We Evaluate Our Operations—Adjusted Gross Margin" for definition of Adjusted gross margin.)
Fixed-Margin Transactions
We purchase crude oil from a producer or supplier at a designated receipt point at an index price, less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price, thereby locking in a fixed margin that is, in effect, economically equivalent to a transportation fee. We refer to these arrangements as "fixed-margin" or "buy/sell" transactions. These fixed-margin transactions account for a portion of the Adjusted gross margin we generate on our Kansas and Oklahoma pipeline system and through our Bakken Shale operations. For the three months ended June 30, 2015 and 2014, approximately 8% and 9%, respectively, of our Adjusted gross margin was generated through fixed-margin transactions. For the six months ended June 30, 2015 and 2014, approximately 9% and 10%, 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 by using our pipeline, trucking and storage assets to capture location and quality differentials, including blending different crude oil grades to meet the refiners' preferred crude oil specifications. For the three months ended June 30, 2015 and 2014, approximately 31% and 20%, respectively, of our Adjusted gross margin was generated through marketing activities. For the six months ended June 30, 2015 and 2014, approximately 27% and 21%, 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.

Page 24


More specifically, we use futures and forward contracts to manage our exposure to market changes in commodity prices to protect our Adjusted gross margin on our purchased crude oil. When we purchase crude oil, we may establish a fixed 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 forward contracts on the NYMEX or over-the-counter markets.

Our Property, Plant and Equipment
We own and operate all of our assets, which at June 30, 2015 include:
7.6 million barrels of crude oil storage capacity in Cushing, Oklahoma, of which 6.5 million barrels are leased to customers and 1.1 million barrels are used for crude oil operations and marketing activities;
a 570-mile crude oil gathering and transportation pipeline system with over 650,000 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;
the Wattenberg Oil Trunkline ("WOT"), a 75-mile, 12-inch diameter crude oil gathering pipeline system that transports crude oil from production facilities in the DJ Basin to the pipeline owned by White Cliffs Pipeline, L.L.C. The WOT has a capacity of approximately 85,000 barrels per day as well as 210,000 barrels of operational storage and an additional 150,000 barrels of storage currently under construction;
a twenty-lane crude oil truck unloading facility with 330,000 barrels of associated storage capacity in Platteville, Colorado which connects to the origination point of the White Cliffs Pipeline. An additional ten bays and 5,000 barrels of storage are currently under construction;
an 16-mile crude oil pipeline that connects our Platteville, Colorado crude oil terminal to the Tampa, Colorado crude oil market; and
a crude oil trucking fleet of over 270 transport trucks and 275 trailers.

Our Investment in White Cliffs Pipeline, L.L.C.
We wholly own SemCrude Pipeline, L.L.C. ("SCPL"), which owns a 51% interest in White Cliffs Pipeline, L.L.C. ("White Cliffs"). White Cliffs owns a pipeline system consisting of two 527-mile parallel lines that transport crude oil from Platteville, Colorado in the DJ Basin to Cushing, Oklahoma (the "White Cliffs Pipeline"), which we operate. The White Cliffs Pipeline is currently undergoing an expansion which will increase the capacity from approximately 150,000 barrels per day to approximately 215,000 barrels per day.

Our Investment in Glass Mountain Pipeline, LLC
We wholly own Glass Mountain Holding, L.L.C. ("GMH"), which owns a 50% interest in Glass Mountain Pipeline, LLC ("Glass Mountain"). Glass Mountain owns a 215-mile pipeline that transports crude oil in western and north central Oklahoma (the "Glass Mountain Pipeline"), which we operate. It has capacity of approximately 140,000 barrels per day as well as 440,000 barrels of operational storage.

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

Page 25


meaningful comparison of the operating results between our fee-based activities, which do not involve the purchase or sale of crude oil, and our fixed-margin and marketing operations, which do. In addition, Adjusted gross margin allows us to make a meaningful comparison of the results of our fixed-margin and marketing operations across different commodity price environments because it measures the spread between the product sales price and cost of products sold. See "—Non-GAAP Financial Measures."
 
Operating Expenses
Our management seeks to maximize the profitability of our operations, in part, by managing operating expenses. These expenses are comprised of salary and wage expense, fuel, utility costs, insurance premiums, taxes and other operating costs, some of which are independent of the volumes we handle.
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.
See "—Non-GAAP Financial Measures."
Contracted Storage Capacity and Transportation, Marketing and Unloading Volumes
In our Cushing storage operations, we charge our customers a fee for storage capacity provided, regardless of actual usage. On our Kansas and Oklahoma system, in our Bakken Shale and Platteville, Colorado operations and through our trucking fleet operations, we provide transportation services on a fee basis or pursuant to fixed-margin transactions, but in either case, the Adjusted gross margin we generate is dependent on the volume of crude oil transported (if on a fee basis) or purchased and sold (if pursuant to a fixed-margin transaction). We refer to these volumes, in the aggregate, as transportation volumes. Similarly, using our pipelines, trucking and storage assets, we conduct marketing activities involving the purchase and sale of crude oil or related derivative contracts and crude oil blending. We refer to the crude oil volumes 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.

Selected Consolidated Financial and Operating Data
The following table provides selected historical condensed consolidated financial operating data as of and for the periods shown. The statement of income data for the three months and six months ended June 30, 2015 and 2014 have been derived from our unaudited financial statements for those periods. The selected financial data provided below should be read in conjunction with our condensed consolidated financial statements and related notes included in this Form 10-Q.
The following table presents the non-GAAP financial measures of Adjusted gross margin and Adjusted EBITDA, which we use in our business and view as important supplemental measures of our performance and, in the case of Adjusted EBITDA, our liquidity. Adjusted gross margin and Adjusted EBITDA are not calculated or presented in accordance with GAAP. For definitions of Adjusted gross margin and Adjusted EBITDA and a reconciliation of Adjusted gross margin to operating income and of Adjusted EBITDA to net income and net cash provided by operating activities, their most directly comparable financial measures calculated and presented in accordance with GAAP, please see "—Non-GAAP Financial Measures" below.

Page 26



 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in thousands, except per unit and operating data)
2015
 
2014
 
2015
 
2014
Statements of income data:
 
 
 
 
 
 
 
Revenues, including revenues from affiliates:
 
 
 
 
 
 
 
Product
$
193,525

 
$
267,087

 
$
300,092

 
$
533,377

Service
29,778

 
25,069

 
57,904

 
51,293

Total revenues
223,303

 
292,156

 
357,996

 
584,670

Expenses, including expenses from affiliates:
 
 
 
 
 
 
 
Costs of products sold, exclusive of depreciation and amortization
173,133

 
255,745

 
269,370

 
510,282

Operating
23,656

 
17,438

 
44,607

 
32,653

General and administrative
6,329

 
6,191

 
11,949

 
9,938

Depreciation and amortization
10,608

 
7,276

 
20,751

 
18,758

Total expenses
213,726

 
286,650

 
346,677

 
571,631

Earnings from equity method investments
17,683

 
12,291

 
38,547

 
23,371

Operating income
27,260

 
17,797

 
49,866

 
36,410

Other expenses, net
10,192

 
2,709

 
18,198

 
5,096

Net income
17,068

 
15,088

 
31,668

 
31,314

Less: net income attributable to noncontrolling interests

 
4,082

 

 
7,758

Net income attributable to Rose Rock Midstream, L.P.
$
17,068

 
$
11,006

 
$
31,668

 
$
23,556

Net income (loss) per limited partner unit:
 
 
 
 
 
 
 
Common unit (basic)
$
0.32

 
$
0.41

 
$
0.60

 
$
0.86

Common unit (diluted)
$
0.32

 
$
0.41

 
$
0.60

 
$
0.85

Subordinated unit (basic and diluted)
$

 
$
0.37

 
$

 
$
0.82

Class A unit (basic and diluted)
$

 
$
(0.25
)
 
$

 
$
(0.31
)
Distributions paid per common and subordinated unit
$
0.6350

 
$
0.4950

 
$
1.2550

 
$
0.9600

 
 
 
 
 
 
 
 
Statements of cash flows data:
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
Operating activities
$
26,941

 
$
6,931

 
$
19,871

 
$
25,118

Investing activities
$
(21,195
)
 
$
(184,513
)
 
$
(251,592
)
 
$
(202,214
)
Financing activities
$
49,033

 
$
(151,636
)
 
$
296,198

 
$
(164,932
)
 
 
 
 
 
 
 
 
Other financial data:
 
 
 
 
 
 
 
Adjusted gross margin
$
48,755

 
$
35,560

 
$
89,742

 
$
74,143

Adjusted EBITDA
$
44,718

 
$
21,700

 
$
86,836

 
$
50,604

Capital expenditures
$
20,831

 
$
14,134

 
$
36,262

 
$
21,838

Acquisitions
$

 
$
133,993

 
$
205,071

 
$
133,993

Contributions to equity method investments
$
8,280

 
$
38,622

 
$
23,462

 
$
51,774

 
 
 
 
 
 
 
 
Operating data:
 
 
 
 
 
 
 
Cushing storage capacity (MMBbls as of period end)
7.6

 
7.6

 
7.6

 
7.6

Percent of Cushing storage capacity contracted to third parties (as of period end)
86
%
 
86
%
 
86
%
 
86
%
Transportation volumes (average Bbls/day)
196,400

 
134,000

 
184,000

 
131,400

Marketing volumes (average Bbls/day)
100,200

 
39,300

 
87,800

 
44,400

Unloading/Platteville volumes (average Bbls/day)
68,600

 
58,200

 
70,000

 
60,700


Page 27



Non-GAAP Financial Measures
We define Adjusted gross margin as total revenues minus cost of products sold and unrealized gain (loss) on derivatives. We define Adjusted EBITDA as net income before interest expense, income tax expense (benefit), depreciation and amortization, earnings from equity method investments and any other non-cash adjustments to reconcile net income to net cash provided by operating activities plus cash distributions from equity method investments.
Adjusted gross margin and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.
Operating income is the GAAP measure most directly comparable to Adjusted gross margin, and net income and cash provided by operating activities are the GAAP measures most directly comparable to Adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measures. These non-GAAP financial measures have important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider Adjusted gross margin and Adjusted EBITDA in isolation or as substitutes for analysis of our results as reported under GAAP. Because Adjusted gross margin and Adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Management compensates for the limitation of Adjusted gross margin and Adjusted EBITDA as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin and Adjusted EBITDA, on the one hand, and operating income, net income and net cash provided by operating activities, on the other hand, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.
The following tables present a reconciliation of: (i) operating income to Adjusted gross margin, and (ii) net income and net cash provided by operating activities to Adjusted EBITDA, the most directly comparable GAAP financial measures for each of the periods indicated.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(Unaudited; in thousands)
2015
 
2014
 
2015
 
2014
Reconciliation of operating income to Adjusted gross margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income
$
27,260

 
$
17,797

 
$
49,866

 
$
36,410

Add:
 
 
 
 
 
 
 
Operating expense
23,656

 
17,438

 
44,607

 
32,653

General and administrative expense
6,329

 
6,191

 
11,949

 
9,938

Depreciation and amortization expense
10,608

 
7,276

 
20,751

 
18,758

Less:
 
 
 
 
 
 
 
Earnings from equity method investments
17,683

 
12,291

 
38,547

 
23,371

Non-cash unrealized gain (loss) on derivatives, net
1,415

 
851

 
(1,116
)
 
245

Adjusted gross margin
$
48,755

 
$
35,560

 
$
89,742

 
$
74,143



Page 28


 
Three Months Ended June 30,
 
Six Months Ended June 30,
(Unaudited; in thousands)
2015
 
2014
 
2015
 
2014
Reconciliation of net income to Adjusted EBITDA:
 
 
 
 
 
 
 
Net income
$
17,068

 
$
15,088

 
$
31,668

 
$
31,314

Add:
 
 
 
 
 
 
 
Interest expense
10,197

 
2,730

 
18,203

 
5,117

Depreciation and amortization expense
10,608

 
7,276

 
20,751

 
18,758

Cash distributions from equity method investments
25,560

 
14,467

 
51,625

 
28,052

Inventory valuation adjustment
48

 

 
1,235

 

Non-cash equity compensation
357

 
130

 
655

 
390

Loss (gain) on disposal of long-lived assets, net
(22
)
 
(27
)
 
130

 
(61
)
Less:
 
 
 
 
 
 
 
Earnings from equity method investments
17,683

 
12,291

 
38,547

 
23,371

White Cliffs cash distributions attributable to noncontrolling interests


4,822

 

 
9,350

   Impact from derivative instruments:
 
 
 
 
 
 
 
Total loss on derivatives, net
(2,202
)
 
(1,942
)
 
(2,846
)
 
(2,749
)
Total realized loss (cash flow) on derivatives, net
3,617

 
2,793

 
1,730

 
2,994

Non-cash unrealized gain (loss) on derivatives, net
1,415

 
851

 
(1,116
)
 
245

Adjusted EBITDA
$
44,718

 
$
21,700

 
$
86,836

 
$
50,604


 
Three Months Ended June 30,
 
Six Months Ended June 30,
(Unaudited; in thousands)
2015
 
2014
 
2015
 
2014
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
 
 
 
 
 
 
 
Net cash provided by operating activities
$
26,941

 
$
6,931

 
$
19,871

 
$
25,118

Less:
 
 
 
 
 
 
 
Changes in operating assets and liabilities, net
(386
)
 
(14,945
)
 
(36,894
)
 
(25,558
)
White Cliffs cash distributions attributable to noncontrolling interests

 
4,822

 

 
9,350

Add:
 
 
 
 
 
 
 
Interest expense, excluding amortization of debt issuance costs
9,515

 
2,470

 
16,994

 
4,597

Distributions from equity investments in excess of equity in earnings
7,876

 
2,176

 
13,077

 
4,681

Adjusted EBITDA
$
44,718

 
$
21,700

 
$
86,836

 
$
50,604



Three months ended June 30, 2015 vs. three months ended June 30, 2014
Adjusted Gross Margin
The following table shows the calculation of Adjusted gross margin for the three months ended June 30, 2015 and 2014 (in thousands):

Page 29


 
Three Months Ended June 30,
 
2015
 
2014
Revenue
 
 
 
Product
$
193,525

 
$
267,087

Service
29,778

 
25,069

Total revenues
223,303

 
292,156

Less: Cost of products sold, exclusive of depreciation and amortization
173,133

 
255,745

Less: Non-cash unrealized gain on derivatives, net
1,415

 
851

Adjusted gross margin
$
48,755

 
$
35,560

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 June 30, 2015 and 2014 (in thousands):
Three Months Ended June 30, 2015
 
Storage
 
Transportation
 
Marketing
Activities
 
Other (2)
 
Total
Revenues
 
$
7,698

 
$
22,426

 
$
189,475

 
$
3,704

 
$
223,303

Less: Costs of products sold, exclusive of depreciation and amortization
 

 

 
173,133

 

 
173,133

Less: Unrealized gain on derivatives, net
 

 

 
1,415

 

 
1,415

Adjusted gross margin
 
$
7,698

 
$
22,426

(1)
$
14,927

 
$
3,704

 
$
48,755


(1)
Transportation Adjusted gross margin is comprised of $4.3 million, $14.0 million and $4.1 million, related to pipeline transportation (fixed-fee), trucking (fixed-fee) and buy/sells (fixed margin), respectively.
(2)
This category includes fee-based services such as unloading and ancillary storage terminal services.
 
Three Months Ended June 30, 2014
 
Storage
 
Transportation
 
Marketing
Activities
 
Other (2)
 
Total
Revenues
 
$
7,756

 
$
17,805

 
$
263,738

 
$
2,857

 
$
292,156

Less: Costs of products sold, exclusive of depreciation and amortization
 

 

 
255,745

 

 
255,745

Less: Unrealized gain on derivatives, net
 

 

 
851

 

 
851

Adjusted gross margin
 
$
7,756

 
$
17,805

(1)
$
7,142

 
$
2,857

 
$
35,560


(1)
Transportation Adjusted gross margin is comprised of $3.0 million, $11.4 million and $3.4 million related to pipeline transportation (fixed-fee), trucking (fixed-fee) and buy/sells (fixed margin), respectively.
(2)
This category includes fee-based services such as unloading and ancillary storage terminal services.

We define Adjusted gross margin as total revenues minus costs of products sold and unrealized gain (loss) on derivatives. (See "—Non-GAAP Financial Measures" for Adjusted gross margin table.) Adjusted gross margin increased for the three months ended June 30, 2015, to $48.8 million from $35.6 million for the three months ended June 30, 2014, due to:
an increase in marketing volume of approximately 5.5 million barrels for the three months ended June 30, 2015, over the same period in 2014, partially offset by a lower spread between the acquisition and sale price for volumes of crude oil sold, as the excess of our average sales price per barrel over our average acquisition cost per barrel decreased to approximately $1.65 for the three months ended June 30, 2015, from approximately $2.00 for the three months ended June 30, 2014, resulted in a $7.8 million increase in Adjusted gross margin during the three months ended June 30, 2015, compared to the same period in 2014. The increase in volume was primarily due to crude oil blending and transactions related to contango market conditions;
additional truck transportation volumes of 3.3 million barrels generated an additional $2.6 million in Adjusted gross margin, reflecting the acquisition of trucking operations in June 2014. Related trucking costs are included in operating expense described below;

Page 30


an increase in pipeline transportation and buy/sell volumes of approximately 2.3 million barrels resulted in a $2.0 million increase in Adjusted gross margin during the three months ended June 30, 2015, compared to the same period in 2014;
an increase in pumpover activity at Cushing resulted in a $0.6 million increase in Adjusted gross margin during the three months ended June 30, 2015, compared to the same period in 2014;
an increase in unloading volumes from our Platteville operations contributed an additional $0.2 million Adjusted gross margin during the three months ended June 30, 2015, compared to the same period in 2014;
the additional 0.1 million barrels of storage capacity located at our Platteville, Colorado truck unloading facility contributed an additional $0.2 million Adjusted gross margin during the three months ended June 30, 2015 compared to the same period in 2014; and
although total Cushing storage capacity remained constant compared to the same period of the prior year, we reduced our leased storage capacity by 0.6 million barrels as we redeployed three tanks for our marketing activities. The reduction in leased storage resulted in a $0.2 million decrease to Adjusted gross margin during the three months ended June 30, 2015, compared to the same period in 2014.
Operating expense
Operating expenses increased for the three months ended June 30, 2015 to $23.7 million from $17.4 million for the three months ended June 30, 2014. Approximately $6.1 million of the increase ($17.2 million compared to $11.1 million) is attributable to the crude oil trucking fleet. In addition, there were increases in field expense, employee expense and other expenses of $0.3 million, $0.2 million and $0.1 million, respectively. These increases were partially offset by a $0.4 million reduction in maintenance and repair expense.
General and administrative expense
General and administrative expense increased to $6.3 million for the three months ended June 30, 2015 from $6.2 million for the three months ended June 30, 2014. This increase is due to additional overhead allocation of $0.7 million, partially offset by a reduction in outside services and employee expense of $0.4 million and $0.2 million, respectively.
Depreciation and amortization expense
Depreciation and amortization expense increased for the three months ended June 30, 2015 to $10.6 million from $7.3 million for the three months ended June 30, 2014. Approximately $1.9 million of the increase in depreciation expense is due to the 2014 revision of the estimated useful life relating to a section of the Kansas and Oklahoma pipeline system. An additional $2.0 million in depreciation expense is due to project completions and the acquisition of trucking operations in June 2014. Amortization expense related to contracts acquired as part of the crude oil trucking fleet acquisitions in 2013 and 2014 decreased by $0.6 million.
Earnings from equity method investments
Earnings from our equity method investments increased for the three months ended June 30, 2015 to $17.7 million from $12.3 million for the three months ended June 30, 2014. The increase is due to our June 2014 acquisition of ownership interest in SCPL combined with the commissioning of White Cliffs' second line in August 2014 and our January 2015 acquisition of ownership interest in GMH (see Note 2 of our condensed consolidated financial statements in this Form 10-Q). These earnings are attributable to fixed-fee pipeline transportation operations.
Interest expense
Interest expense increased for the three months ended June 30, 2015 to $10.2 million from $2.7 million for the three months ended June 30, 2014. The increase is primarily the result of the issuance of $400 million of 5.625% senior unsecured notes on July 2, 2014 and the issuance of $350 million of 5.625% senior unsecured notes on May 14, 2015.

Six months ended June 30, 2015 vs. six months ended June 30, 2014
Adjusted Gross Margin
The following table shows the calculation of Adjusted gross margin for the six months ended June 30, 2015 and 2014 (in thousands):

Page 31


 
Six Months Ended June 30,
 
2015
 
2014
Revenue
 
 
 
Product
$
300,092

 
$
533,377

Service
57,904

 
51,293

Total revenues
357,996

 
584,670

Less: Cost of products sold, exclusive of depreciation and amortization
269,370

 
510,282

Less: Non-cash unrealized gain (loss) on derivatives, net
(1,116
)
 
245

Adjusted gross margin
$
89,742

 
$
74,143

The following tables show the Adjusted gross margin generated by our fee-based services, our fixed-margin transactions and our marketing activities for the six months ended June 30, 2015 and 2014 (in thousands):
Six Months Ended June 30, 2015
 
Storage
 
Transportation
 
Marketing
Activities
 
Other (2)
 
Total
Revenues
 
$
15,296

 
$
42,753

 
$
292,436

 
$
7,511

 
$
357,996

Less: Costs of products sold, exclusive of depreciation and amortization
 

 

 
269,370

(3)

 
269,370

Less: Unrealized loss on derivatives, net
 

 

 
(1,116
)
 

 
(1,116
)
Adjusted gross margin
 
$
15,296

 
$
42,753

(1)
$
24,182

 
$
7,511

 
$
89,742


(1)
Transportation Adjusted gross margin is comprised of $8.5 million, $26.6 million and $7.7 million, related to pipeline transportation (fixed-fee), trucking (fixed-fee) and buy/sells (fixed margin), respectively.
(2)
This category includes fee-based services such as unloading and ancillary storage terminal services.
(3)
Costs of products sold includes a $1.2 million lower of cost or market inventory adjustment.
 
Six Months Ended June 30, 2014
 
Storage
 
Transportation
 
Marketing
Activities
 
Other (2)
 
Total
Revenues
 
$
16,236

 
$
36,110

 
$
526,198

 
$
6,126

 
$
584,670

Less: Costs of products sold, exclusive of depreciation and amortization
 

 

 
510,282

 

 
510,282

Less: Unrealized gain on derivatives, net
 

 

 
245

 

 
245

Adjusted gross margin
 
$
16,236

 
$
36,110

(1)
$
15,671

 
$
6,126

 
$
74,143


(1)
Transportation Adjusted gross margin is comprised of $6.0 million, $22.9 million and $7.2 million related to pipeline transportation (fixed-fee), trucking (fixed-fee) and buy/sells (fixed margin), respectively.
(2)
This category includes fee-based services such as unloading and ancillary storage terminal services.

We define Adjusted gross margin as total revenues minus costs of products sold and unrealized gain (loss) on derivatives. (See "—Non-GAAP Financial Measures" for Adjusted gross margin table.) Adjusted gross margin increased for the six months ended June 30, 2015, to $89.7 million from $74.1 million for the six months ended June 30, 2014, due to:
an increase in marketing volume of approximately 7.9 million barrels for the six months ended June 30, 2015, over the same period in 2014, partially offset by a lower spread between the acquisition and sale price for volumes of crude oil sold, as the excess of our average sales price per barrel over our average acquisition cost per barrel decreased to approximately $1.53 for the six months ended June 30, 2015, from approximately $1.95 for the six months ended June 30, 2014, resulted in a $8.5 million increase in Adjusted gross margin during the six months ended June 30, 2015, compared to the same period in 2014. The increase in volume was primarily due to crude oil blending and transactions related to contango market conditions;
additional truck transportation volumes of 5.6 million barrels generated an additional $3.7 million in Adjusted gross margin, reflecting the acquisition of trucking operations in June 2014. Related trucking costs are included in operating expense described below;

Page 32


an increase in pipeline transportation and buy/sell volumes of approximately 3.9 million barrels resulted in a $3.0 million increase in Adjusted gross margin during the six months ended June 30, 2015, compared to the same period in 2014;
an increase in pumpover activity at Cushing resulted in a $0.8 million increase in Adjusted gross margin during the six months ended June 30, 2014, compared to the same period in 2014;
an increase in unloading volumes from our Platteville operations contributed an additional $0.5 million Adjusted gross margin during the six months ended June 30, 2014, compared to the same period in 2014;
the additional 0.1 million barrels of storage capacity located at our Platteville, Colorado truck unloading facility contributed an additional $0.2 million Adjusted gross margin during the six months ended June 30, 2015 compared to the same period in 2014; and
although total Cushing storage capacity remained constant compared to the same period of the prior year, we reduced our leased storage capacity by 0.6 million barrels as we redeployed three tanks for our marketing activities. The reduction in leased storage resulted in a $1.1 million decrease to Adjusted gross margin during the six months ended June 30, 2015 compared to the same period in 2014.
Operating expense
Operating expenses increased for the six months ended June 30, 2015 to $44.6 million from $32.7 million for the six months ended June 30, 2014. Approximately $10.6 million of the increase ($32.1 million compared to $21.5 million) is attributable to the crude oil trucking fleet. In addition, there were increases in employee expense, outside services and other expenses of $1.1 million, $0.4 million and $0.2 million, respectively. These increases were partially offset by a $0.4 million reduction in maintenance and repair expense.
General and administrative expense
General and administrative expense increased to $11.9 million for the six months ended June 30, 2015 from $9.9 million for the six months ended June 30, 2014. This increase is due to additional overhead allocation, outside services and insurance and taxes of $1.4 million, $0.8 million and $0.5 million, respectively. These increases were partially offset by a reduction of employee expense and other expenses of $0.6 million and $0.1 million, respectively.
Depreciation and amortization expense
Depreciation and amortization expense increased for the six months ended June 30, 2015 to $20.8 million from $18.8 million for the six months ended June 30, 2014. A $0.5 million decrease in depreciation expense is due to the 2014 revision of the estimated useful life relating to a section of the Kansas and Oklahoma pipeline system. An additional $3.7 million in depreciation expense is due to project completions and the acquisition of trucking operations in June 2014. Amortization expense related to contracts acquired as part of the crude oil trucking fleet acquisitions in 2013 and 2014 decreased by $1.2 million.
Earnings from equity method investments
Earnings from our equity method investments increased for the six months ended June 30, 2015 to $38.5 million from $23.4 million for the six months ended June 30, 2014. The increase is due to our June 2014 acquisition of ownership interest in SCPL combined with the commissioning of White Cliffs' second line in August 2014 and our January 2015 acquisition of ownership interest in GMH (see Note 2 of our condensed consolidated financial statements in this Form 10-Q). These earnings are attributable to fixed-fee pipeline transportation operations.
Interest expense
Interest expense increased for the six months ended June 30, 2015 to $18.2 million from $5.1 million for the six months ended June 30, 2014. The increase is primarily the result of the issuance of $400 million of 5.625% senior unsecured notes on July 2, 2014 and the issuance of $350 million of 5.625% senior unsecured notes on May 14, 2015.


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

Page 33


operating expenses, maintenance capital expenditures and cash distributions through existing cash and cash from operating activities;
expansion related capital expenditures and working capital deficits through cash on hand, borrowings under our credit facility and the issuance of debt securities and common units;
acquisitions through cash on hand, borrowings under our credit facility and the issuance of debt securities and common units; and
debt principal payments through cash from operating activities and refinancing when the revolving credit facility and senior unsecured notes become 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 and general partner units and meet our capital expenditure commitments for the coming year.
Cash Flows
The following table summarizes our changes in cash and cash equivalents for the periods presented (in thousands):
 
Six Months Ended June 30,
 
2015
 
2014
Cash flows provided by (used in):
 
 
 
Operating activities
$
19,871

 
$
25,118

Investing activities
(251,592
)
 
(202,214
)
Financing activities
296,198

 
164,932

Change in cash and cash equivalents
64,477

 
(12,164
)
Cash and cash equivalents at beginning of period
3,625

 
15,437

Cash and cash equivalents at end of period
$
68,102

 
$
3,273

Operating Activities
The components of operating cash flows can be summarized as follows (in thousands):
 
Six Months Ended June 30,
 
2015
 
2014
Net income
$
31,668

 
$
31,314

Non-cash expenses, net
25,097

 
19,362

Changes in operating assets and liabilities, net
(36,894
)
 
(25,558
)
Net cash flows provided by operating activities
$
19,871

 
$
25,118

For the six months ended June 30, 2015, we experienced operating cash inflows of $19.9 million. Net income of $31.7 million included $25.1 million of non-cash expenses, comprised primarily of depreciation and amortization of $20.8 million, $1.1 million in net unrealized losses related to derivative instruments and $1.2 million in inventory valuation adjustments. Changes in operating assets and liabilities accounted for net cash outflows of $36.9 million for the six months ended June 30, 2015. The primary changes to operating assets and liabilities included an increase to accounts payable and accrued liabilities of $31.2 million, an increase in accounts receivable of $26.4 million, an increase in receivables from affiliates of $2.1 million, an increase in inventories of $41.8 million, an increase in payables to affiliates of $3.7 million and an increase in other current assets of $1.4 million. The impact of accounts receivable, accounts payable, accrued liabilities and inventories is subject to the timing of purchases and sales and fluctuations in commodity pricing. Additionally, the increase in inventory is due, in part, to approximately 700 thousand additional barrels in storage compared to the beginning of the period. This is partially due to a strategic build to capture margins due to forward market crude oil prices being higher than spot market prices.

Page 34


For the six months ended June 30, 2014, we experienced operating cash inflows of $25.1 million. Net income of $31.3 million included $19.4 million of non-cash expenses, comprised primarily of depreciation and amortization of $18.8 million. Operating assets and liabilities changed $25.6 million for the six months ended June 30, 2014. The primary changes to operating assets and liabilities included a decrease in payables to affiliates of $39.4 million, a decrease to accounts payable and accrued liabilities of $8.6 million, inventory related cash outflows of $3.5 million primarily due to linefill, an increase in accounts receivable of $2.2 million and an increase in other current assets of $1.2 million, offset by a decrease in receivables from affiliates of $29.4 million. The impact of accounts receivable, accounts payable, accrued liabilities, and inventories is subject to the timing of purchases and sales and fluctuations in commodity pricing.
Investing Activities.
For the six months ended June 30, 2015, our cash outflows from investing activities of $251.6 million related primarily to acquisition payments of $205.1 million, contributions to equity method investments of $23.5 million and capital expenditures of $36.3 million, offset by distributions from equity method investments in excess of equity in earnings of $13.1 million. Acquisitions represent the historical cost of Wattenberg Oil Trunkline and a 50% interest in Glass Mountain purchased from SemGroup. Consideration in excess of historical cost is reported as a financing activity in the cash flow statement. Contributions to equity method investments related to capital calls to fund the expansion of the White Cliffs Pipeline and capital expenditures related to the Wattenberg Pipeline extension and other projects.
For the six months ended June 30, 2014, our cash outflows from investing activities of $202.2 million related primarily to acquisition payments of $134.0 million, contributions to equity method investment of $51.8 million and capital expenditures of $21.8 million, offset by distributions from equity method investment in excess of equity in earnings of $4.7 million. Acquisitions include $90.0 million related to the acquisition of the remaining 33% SCPL interest, excluding cash consideration in excess of historical cost, and $44.0 million related to the acquisition of crude oil trucking assets from Chesapeake. Capital expenditures primarily related to our Cushing expansion and transportation projects. Contributions to equity method investment primarily relate to capital calls to fund the White Cliffs Pipeline expansion.
Financing Activities.
Net cash inflows of $296.2 million from financing activities for the six months ended June 30, 2015 were driven primarily by the issuance of $344.2 million of senior unsecured notes due 2023, net of a $5.8 million discount, $32 million net payments on our revolving credit facility ($332.0 million of borrowings less $364.0 million in principal payments) and $89.1 million in proceeds from the issuance of common limited partner units reduced by $53.2 million of cash distributions to partners and $46.3 million cash consideration in excess of historical cost of the Wattenberg Oil Trunkline and a 50% interest in Glass Mountain. Proceeds from the issuance of common limited partner units were primarily used to fund the acquisition of the Wattenberg Oil Trunkline and a 50% interest in Glass Mountain from SemGroup. Proceeds from the issuance of senior unsecured notes due 2023 were used to pay amounts owed under our revolving credit facility and for general partnership purposes.
Net cash inflows of $164.9 million from financing activities for the six months ended June 30, 2014 were driven primarily by $202.5 million net borrowings on our revolving credit facility ($296.0 million of borrowings less $93.5 million in principal payments), $26.7 million of cash distributions to partners and $24.4 million cash consideration in excess of historical cost of the remaining 33% interest in SCPL. In addition, financing activities include $9.0 million of distributions to and $14.4 million of contributions from SemGroup as the noncontrolling interest holder in SCPL, prior to our acquisition of SemGroup's remaining ownership interest in SCPL. Additionally, $8.3 million was contributed by the general partner related to the Wattenberg Oil Trunkline. Borrowings were used for acquisitions, capital expenditures and normal operations.
Long-term Debt
At June 30, 2015, we had $400 million and $350 million of senior unsecured notes outstanding which become due in 2022 and 2023, respectively, and no outstanding borrowings on our $585 million revolving credit facility, which expires in 2018. At June 30, 2015, our available borrowing capacity on our revolving credit facility was $560.4 million, which includes the impact of $24.6 million of outstanding letters of credit which reduce the capacity available for borrowings.
Shelf Registration Statement
We have an effective shelf registration statement with the SEC that, subject to market conditions and effectiveness at the time of use, allows us to issue up to an aggregate of $500 million of debt or equity securities. In August 2013, we used this shelf registration statement to sell 4.75 million common units representing limited partner interests for proceeds of $152.5 million, net of underwriting discounts and commissions of $6.4 million. On February 13, 2015, we issued and sold 2.3 million common units representing limited partner interests for net proceeds of $89.1 million under this shelf registration statement.

Page 35


Proceeds were used in connection with our acquisition of the Wattenberg Oil Trunkline and a 50% interest in Glass Mountain from SemGroup. This shelf registration statement expires in May 2016.
We also have an effective shelf registration statement for the offer and sale, from time to time, of common units representing limited partner interests in us having an aggregate offering price of up to $150 million. On May 12, 2015, we entered into an Equity Distribution Agreement under which we are able to make such sales over a period of time and, from time to time, in transactions at prices which are market prices prevailing at the time of sale, prices related to market price or at negotiated prices. The counterparties to the Equity Distribution Agreement may act as sales agents for the common units or may purchase common units for their own accounts as principals. To date, no such sales have been made.
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 $100.4 million and $9.1 million at June 30, 2015 and December 31, 2014, respectively. The increase in working capital at June 30, 2015 as compared to December 31, 2014 is primarily due to a $64.5 million increase in cash and cash equivalents resulting from our May 14, 2015 issuance of $350 million of senior unsecured notes due 2023.
Capital Requirements
The midstream energy business can be capital intensive, requiring significant investments for the maintenance of existing assets or acquisition or development of new systems and facilities. We categorize our capital expenditures as either:
expansion related capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long-term; or
maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new capital assets) made to maintain our long-term operating income or operating capacity.
During the six months ended June 30, 2015, we invested $59.7 million (cash basis) on capital projects, including contributions to equity method investments. Projected capital expenditures for 2015 include $175 million for expansion projects including contributions to fund growth projects of equity method investees and acquisitions from third parties and $10 million in maintenance projects.
We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by cash from operations, borrowings under our credit facility and the issuance of debt and equity securities.
Distributions
The table below shows cash distributions declared or paid during 2014 and 2015:
Quarter Ended
 
Record Date
 
Payment Date
 
Distribution Per Unit
December 31, 2013
 
February 4, 2014
 
February 14, 2014
 
$0.4650
March 31, 2014
 
May 5, 2014
 
May 15, 2014
 
$0.4950
June 30, 2014
 
August 4, 2014
 
August 14, 2014
 
$0.5350
September 30, 2014
 
November 4, 2014
 
November 14, 2014
 
$0.5750
December 31, 2014
 
February 3, 2015
 
February 14, 2015
 
$0.6200
March 31, 2015
 
May 5, 2015
 
May 15, 2015
 
$0.6350
June 30, 2015
 
August 4, 2015
 
August 14, 2015
 
$0.6500
Credit Risk
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We examine the creditworthiness of third party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

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Customer Concentration
Shell Trading (US) Company and BP Oil Supply Co accounted for more than 10% of our total revenue for the three months ended June 30, 2015, at approximately 42% and 17%, respectively. Shell Trading (US) Company and BP Oil Supply Co accounted for more than 10% of our total revenue for the six months ended June 30, 2015, at approximately 46% and 21%, respectively. Although we have contracts with customers of varying durations, if one or more of our major customers were to default on their contract, or if we were unable to renew our contract with one or more of these customers on favorable terms, we might not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our revenues and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenue.
Purchase and Sale Commitments
For information regarding purchase and sales commitments, see the discussion under the caption "Purchase and sale commitments" in Note 6 of our condensed consolidated financial statements of this Form 10-Q, which information is incorporated by reference into this Item 2.
Letters of Credit
In connection with our purchasing activities, we provide certain suppliers and transporters with irrevocable standby and performance letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded as accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for 50- to 70-day periods (with a maximum of a 364-day period) and are terminated upon completion of each transaction. At June 30, 2015 and December 31, 2014, we had outstanding letters of credit of approximately $60.6 million and $85.1 million, respectively.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Critical Accounting Policies and Estimates
For disclosure regarding our critical accounting policies and estimates, see the discussion under the caption "Critical Accounting Policies and Estimates" in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2014.

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. Our risk management policies and procedures are designed to monitor physical and financial commodity positions and the resulting outright commodity price risk as well as basis risk resulting from differences in commodity grades, purchase and sales locations and purchase and sale timing. We have a risk management function that has responsibility and authority for our Comprehensive Risk Management Policy, which governs our enterprise-wide risks, including the market risks discussed in this item. Subject to our Comprehensive Risk Management Policy, our finance and treasury function has responsibility and authority for managing exposure to interest rates.
Commodity Price Risk
The table below outlines the range of NYMEX prompt month daily settle prices for crude oil futures provided by an independent, third-party broker for the three months and six months ended June 30, 2015 and 2014, and for the year ended December 31, 2014.
 
 
Light Sweet
Crude Oil
Futures
($ per Barrel)
Three Months Ended June 30, 2015
 

High
 
$61.43
Low
 
$49.14
High/Low Differential
 
$12.29
 
 
 
Three Months Ended June 30, 2014
 
 
High
 
$107.26
Low
 
$99.42
High/Low Differential
 
$7.84
 
 
 
Six Months Ended June 30, 2015
 
 
High
 
$61.43
Low
 
$43.46
High/Low Differential
 
$17.97
 
 
 
Six Months Ended June 30, 2014
 
 
High
 
$107.26
Low
 
$91.66
High/Low Differential
 
$15.60
 
 
 
Year Ended December 31, 2014
 
 
High
 
$107.26
Low
 
$53.27
High/Low Differential
 
$53.99
Revenue from our asset-based activities is dependent on throughput volume, tariff rates, the level of fees generated from our pipeline systems, capacity contracted to third parties, capacity that we use for our own operational or marketing activities and the level of other fees generated at our storage facilities and from our trucking operations. Profit from our marketing

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activities is dependent on our ability to sell crude oil at prices in excess of our aggregate cost. Margins may be affected during transitional periods between a backwardated market (when the prices for future deliveries are lower than the current prices) and a contango market (when the prices for future deliveries are higher than the current prices). Our crude oil marketing activities are generally not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and relative fluctuations in market-related indices at various locations.
Based on our open derivative contracts at June 30, 2015, 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 of June 30, 2015, 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
555

 
$
445

 
$
(3,301
)
 
$
3,301

 
July 2015
Margin deposits or other credit support, including letters of credit, are generally required on derivative instruments used to manage our price exposure. As commodity prices increase or decrease, the fair value of our derivative instruments changes, thereby increasing or decreasing our margin deposit or other credit support requirements. Although a component of our risk-management strategy is intended to manage the margin and other credit support requirements on our derivative instruments, volatile spot and forward commodity prices, or an expectation of increased commodity price volatility, could increase the cash needed to manage our commodity price exposure and thereby increase our liquidity requirements. This may limit amounts available to us through borrowing, decrease the volume of petroleum products we purchase and sell or limit our commodity price management activities.
Interest Rate Risk
We have exposure to changes in interest rates under our revolving credit facility. The credit markets have recently experienced very low interest rates. If the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. Interest rates on our floating rate revolving credit facility and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.
We recorded interest expense related to our revolving credit facility of $2.0 million during the three months ended June 30, 2015, including amortization of debt issuance cost. An increase in interest rates of 1% for the three months ended June 30, 2015 would have increased our interest expense by $0.3 million. We recorded interest expense related to our revolving credit facility of $4.2 million during the six months ended June 30, 2015, including amortization of debt issuance cost. An increase in interest rates of 1% for the six months ended June 30, 2015 would have increased our interest expense by $0.7 million.


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Item 4.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer of our general partner have concluded that the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) under the Exchange Act) are effective as of June 30, 2015. 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 June 30, 2015, 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," "Dimmit County, TX claims," 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, 2014.

Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchases of our common units by us during the quarter ended June 30, 2015:
 
 
Total Number of Shares Purchased (1)
 
Weighted Average Price Paid per Share (2)
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
April 1, 2015 - April 30, 2015
 
1,579

 
$52.47
 

 

May 1, 2015 - May 31, 2015
 

 

 

 

June 1, 2015 - June 30, 2015
 

 

 

 

Total
 
1,579

 
$52.47
 

 


(1
)
 
Represents shares of common units withheld from certain of our employees for payment of taxes associated with the vesting of restricted unit awards.
(2
)
 
The price paid per common unit represents the closing price as posted on the New York Stock Exchange on the day that the units vested.


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: 

Page 41


Exhibit
Number
Description
4.1
Indenture, dated as of May 14, 2015, by and among Rose Rock Midstream, L.P., Rose Rock Finance Corporation, the Guarantors party thereto and Wilmington Trust, National Association, as Trustee (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 18, 2015, and incorporated herein in its entirety by reference).

4.2
Form of 5.625% Senior Note due 2023 (included as Exhibit 1 to Exhibit 4.1 of this Quarterly Report on Form 10-Q).
4.3
Registration Rights Agreement, dated as of May 14, 2015, by and among Rose Rock Midstream, L.P., the Guarantors signatory thereto and Wells Fargo Securities, LLC, as representative of the several initial purchasers (filed as Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 18, 2015, and incorporated herein in its entirety by reference).
10.1
Purchase Agreement, dated May 11, 2015, by and among Rose Rock Midstream, L.P., Rose Rock Finance Corporation, the guarantors party thereto and Wells Fargo Securities, LLC, as representative of the initial purchasers named therein (filed as Exhibit 1.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 13, 2015, and incorporated herein in its entirety by reference).
10.2
Equity Distribution Agreement, dated May 12, 2015, by and among Rose Rock Midstream, L.P., Rose Rock Midstream GP, LLC, Wells Fargo Securities, LLC, Citigroup Global Markets Inc. and SunTrust Robinson Humphrey, Inc. (filed as Exhibit 1.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 13, 2015, and incorporated herein in its entirety by reference).
10.3
Rose Rock Midstream GP, LLC Board of Directors Compensation Plan (effective December 1, 2015).
31.1
Rule 13a-14(a)/15d-14(a) Certification of Carlin G. Conner, Chief Executive Officer.
31.2
Rule 13a-14(a)/15d-14(a) Certification of Robert N. Fitzgerald, Chief Financial Officer.
32.1
Section 1350 Certification of Carlin G. Conner, Chief Executive Officer.
32.2
Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer.
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
 

Page 42


SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
Date: August 7, 2015
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

Page 43


EXHIBIT INDEX
The following exhibits are filed or furnished as part of this Quarterly Report on Form 10-Q: 
Exhibit
Number
Description
4.1
Indenture, dated as of May 14, 2015, by and among Rose Rock Midstream, L.P., Rose Rock Finance Corporation, the Guarantors party thereto and Wilmington Trust, National Association, as Trustee (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 18, 2015, and incorporated herein in its entirety by reference).
4.2
Form of 5.625% Senior Note due 2023 (included as Exhibit 1 to Exhibit 4.1 of this Quarterly Report on Form 10-Q).
4.3
Registration Rights Agreement, dated as of May 14, 2015, by and among Rose Rock Midstream, L.P., the Guarantors signatory thereto and Wells Fargo Securities, LLC, as representative of the several initial purchasers (filed as Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 18, 2015, and incorporated herein in its entirety by reference).
10.1
Purchase Agreement, dated May 11, 2015, by and among Rose Rock Midstream, L.P., Rose Rock Finance Corporation, the guarantors party thereto and Wells Fargo Securities, LLC, as representative of the initial purchasers named therein (filed as Exhibit 1.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 13, 2015, and incorporated herein in its entirety by reference).
10.2
Equity Distribution Agreement, dated May 12, 2015, by and among Rose Rock Midstream, L.P., Rose Rock Midstream GP, LLC, Wells Fargo Securities, LLC, Citigroup Global Markets Inc. and SunTrust Robinson Humphrey, Inc. (filed as Exhibit 1.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 13, 2015, and incorporated herein in its entirety by reference).
10.3
Rose Rock Midstream GP, LLC Board of Directors Compensation Plan (effective December 1, 2015).
31.1
Rule 13a-14(a)/15d-14(a) Certification of Carlin G. Conner, Chief Executive Officer.
31.2
Rule 13a-14(a)/15d-14(a) Certification of Robert N. Fitzgerald, Chief Financial Officer.
32.1
Section 1350 Certification of Carlin G. Conner, Chief Executive Officer.
32.2
Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer.
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.

Page 44