Attached files
| file | filename |
|---|---|
| EXCEL - IDEA: XBRL DOCUMENT - Rose Rock Midstream, L.P. | Financial_Report.xls |
| EX-31.1 - CERTIFICATION PUSUANT TO SECTION 302 - Rose Rock Midstream, L.P. | d279284dex311.htm |
| EX-32.1 - CERTIFICATION PURSUANT TO SECTION 1350 - Rose Rock Midstream, L.P. | d279284dex321.htm |
| EX-31.2 - CERTIFICATION PUSUANT TO SECTION 302 - Rose Rock Midstream, L.P. | d279284dex312.htm |
| EX-32.2 - CERTIFICATION PURSUANT TO SECTION 1350 - Rose Rock Midstream, L.P. | d279284dex322.htm |
| EX-23.1 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - Rose Rock Midstream, L.P. | d279284dex231.htm |
| EX-10.3.1 - FORM OF RESTRICTED UNIT AWARD AGREEMENT (EMPLOYEES) - Rose Rock Midstream, L.P. | d279284dex1031.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2011
or
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-35365
ROSE ROCK MIDSTREAM, L.P.
(Exact name of registrant as specified in its charter)
| Delaware | 45-2934823 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
Two Warren Place
6120 S. Yale Avenue, Suite 700
Tulsa, OK 74136-4216
(918) 524-7700
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class |
Name of Each Exchange on Which Registered | |
| Common Units | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ¨ No x
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 ¨ No x
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large Accelerated Filer | ¨ | Accelerated Filer | ¨ | |||
| Non-Accelerated Filer | x (Do not check if a smaller reporting company) | Smaller Reporting Company | ¨ | |||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨ No x
The registrant cannot calculate the aggregate market value of its common units held by non-affiliates as of the last business day of its most recently completed second fiscal quarter because there was no established public trading market for its common units as of such date.
At January 31, 2012, there were 8,428,922 common units and 8,389,709 subordinated units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
NONE
ROSE ROCK MIDSTREAM, L.P.
FORM 10-K—2011 ANNUAL REPORT
Table of Contents
Cautionary Note Regarding Forward-Looking Statements
Certain matters contained in this Form 10-K include “forward-looking statements.” All statements, other than statements of historical fact, included in this Form 10-K 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 this Form 10-K, entitled “Risk Factors,” beginning on page 20, risk factors discussed in other reports that we file with the SEC, and the following:
| • | Our ability to generate sufficient cash flow from operations to enable us to pay the minimum quarterly distribution to holders of our common units, general partner units and subordinated units; |
| • | Our profitability depends on the demand for crude oil in the markets we serve; |
| • | Our ability to obtain new sources of crude oil; |
| • | Restrictions in our revolving credit facility could adversely affect our business, results of operations, financial condition and ability to make cash distributions to our unitholders; |
| • | Our future debt may limit our flexibility to obtain financing and pursue business opportunities; |
| • | The credit profile of SemGroup Corporation could adversely affect our credit rating which could increase our borrowing costs; |
| • | Our ability to renew or replace expiring storage contracts; |
| • | The loss or nonpayment by one of our key customers could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders; |
| • | Our ability to minimize risk exposure associated with the marketing of crude oil; and |
| • | Our preparedness towards the many hazards and operational risks associated with our business, many of which may not be covered by insurance. |
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement.
Readers are cautioned not to place undue reliance on any forward-looking statements contained in this Form 10-K, which reflect management’s opinions only as of the date hereof. Except as required by law, we undertake no obligation to revise or publicly release the results of any revision to any forward-looking statements.
As used in this Form 10-K, and unless the context indicates otherwise, the terms (i) the “Partnership,” “Rose Rock,” “we,” “our,” “us” or like terms, refer to Rose Rock Midstream, L.P., its subsidiaries and its predecessor; (ii) “SemGroup” refers to SemGroup Corporation (NYSE: SEMG) 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.
Items 1 and 2. Business and Properties
Overview
We are a growth-oriented Delaware limited partnership formed by SemGroup Corporation 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, Oklahoma and Texas. We serve areas that are experiencing strong production growth and drilling activity through our exposure to the Bakken Shale in North Dakota and Montana, the Denver-Julesburg (DJ) Basin and the Niobrara Shale in the Rocky Mountain region, and the Granite Wash and the Mississippian oil trend in the Mid-Continent region. The majority of our assets are strategically located in, or connected to, the Cushing, Oklahoma crude oil marketing hub. Cushing is the designated point of delivery specified in all NYMEX crude oil futures contracts and is one of the largest crude oil marketing hubs in the United States. We believe that our connectivity in Cushing and our numerous interconnections with third-party pipelines, refineries and storage terminals provide our customers with the flexibility to access multiple points for the receipt and delivery of crude oil.
Company Information
Our principal executive offices are located at Two Warren Place, 6120 South Yale Avenue, Suite 700, Tulsa, OK 74136-4216, and our telephone number is (918) 524-7700. Our website is located at www.rrmidstream.com. Our Annual Report on Form 10-K, future quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as well as other information we file with, or furnish to, the SEC are available free of charge on our website. We will make these documents available as soon as reasonably practicable after we electronically file them with, or furnish them to, the SEC. The information contained on our website, or available by hyperlink from our website, is not incorporated into this Form 10-K or other documents we file with, or furnish to, the SEC. We intend to use our website as a means of disclosing material non-public information and for complying with our disclosure obligations under Regulation FD. Such disclosures will be included on our website in the ‘Investor Relations’ sections. Accordingly, investors should monitor such portions of our website, in addition to following our press releases, SEC filings and public conference calls and webcasts.
Our History
Rose Rock Midstream, L.P. (“Rose Rock”) is a Delaware limited partnership. We are based in Tulsa, Oklahoma, and are engaged in providing midstream energy related services such as the gathering, storage, transportation and marketing of crude oil.
The general partner of Rose Rock is Rose Rock Midstream GP, LLC (“Rose Rock GP”), which is a wholly-owned subsidiary of SemGroup Corporation. SemGroup Corporation is a Delaware corporation headquartered in Tulsa, Oklahoma that provides diversified midstream services to the energy industry. SemGroup Corporation is the successor entity of SemGroup, L.P., which was an Oklahoma limited partnership.
On July 22, 2008, SemGroup, L.P. and certain of its subsidiaries, including the entities comprising our predecessor, filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy code. Later during 2008, certain other U.S. subsidiaries filed petitions for reorganization. While in bankruptcy, SemGroup filed a plan of reorganization with the court, which was confirmed on October 28, 2009. 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 emerged from bankruptcy on November 30, 2009. Since 2008, SemGroup has taken numerous steps to restructure its business portfolio and to shift away from trading activities and toward a business heavily weighted in fee-based and fixed-margin activities. SemGroup’s Class A common stock trades on the New York Stock Exchange, or (“NYSE”), under the symbol “SEMG.”
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Rose Rock was formed in August 2011. On November 29, 2011, SemGroup Corporation contributed a wholly-owned subsidiary, SemCrude, L.P., to Rose Rock in return for limited partner interests, general partner interests, and certain incentive distribution rights in Rose Rock. On December 14, 2011, Rose Rock completed an initial public offering in which it sold 7,000,000 common units representing limited partner interests.
We are managed and operated by our general partner, Rose Rock GP. SemGroup Corporation owns all of the ownership interest in our general partner. SemGroup owns and operates a substantial portfolio of midstream assets and holds a significant interest in us through its ownership of a 57.0% limited partner interest and 2.0% general partner interest in us, as well as all of our incentive distribution rights.
Our operations are conducted through, and our operating assets are owned by our wholly-owned subsidiary, Rose Rock Midstream Operating, LLC, and its subsidiaries. Rose Rock Midstream Operating, LLC and its subsidiaries have no employees. The employees who conduct our business are employed by an affiliate of our general partner.
Industry Overview
We move crude oil throughout the U.S. We provide gathering, transportation, storage, distribution, marketing and other midstream services to producers and users of crude oil. The market we serve, which begins at the point of purchase at the source of production and extends to the point of distribution to the end-user customer, is commonly referred to as the “midstream” market.
Crude Oil Industry Overview
Refined petroleum products, such as jet fuel, gasoline and distillate fuel oil, are all sources of energy derived from crude oil. According to 2010 data compiled by the Energy Information Administration (“EIA”), petroleum currently accounts for about 44% of the nation’s total annual energy consumption. Growth in petroleum consumption is expected to keep pace with growth in overall energy consumption over the next 20 to 25 years. The EIA expects U.S. annual petroleum consumption to grow 13.5% from 17.1 million barrels per day in 2009 to 19.4 million barrels per day in 2035. The diagram below depicts the segments of the crude oil value chain and our participation in the crude oil industry.
Our crude oil business operates in Colorado, Kansas, Montana, North Dakota, Oklahoma and Texas where there are extensive crude oil production operations. Our assets extend from gathering systems in and around producing fields to transportation pipelines carrying crude oil to logistics hubs, such as Cushing, where we have a storage facility that aids our customers in managing the delivery of crude oil.
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Gathering and Transportation
Pipeline transportation is generally the lowest cost method for shipping crude oil and transports about two-thirds of the petroleum shipped in the U.S. Crude oil pipelines transport oil from the wellhead to logistics hubs and refineries. Crude oil gathering assets generally consist of a network of smaller diameter pipelines that are connected directly to the well site or central receipt points delivering into larger diameter trunk lines. Logistic hubs like Cushing provide storage and connections to other pipeline systems and modes of transportation, such as tankers, railroads and trucks. Trucking complements pipeline gathering systems by gathering crude oil from operators at remote wellhead locations not served by pipeline gathering systems. Trucking is generally limited to low volume, short haul movements because trucking costs escalate sharply with distance, making trucking the most expensive mode of crude oil transportation.
Barges and railroads provide additional transportation capabilities for shipping crude oil between gathering storage systems, pipelines, terminals and storage centers and end-users. Barge and railroad transportation are typically cost-efficient modes of transportation that allows for the ability to transport large volumes of crude oil over long distances.
Competition in the crude oil gathering industry is typically regional and based on proximity to crude oil producers, as well as access to attractive delivery points. Overall demand for gathering services in a particular area is generally driven by crude oil producer activity in the area.
Storage Terminals and Supply
Terminals are facilities in which crude oil is transferred to or from a storage facility or transportation system, such as a gathering pipeline, to another transportation system, such as trucks or another pipeline. Terminals play a key role in moving crude oil to end-users, such as refineries, by providing the following services:
| • | inventory management; |
| • | distribution; and |
| • | upgrading to achieve marketable grades or qualities of crude oil. |
Storage terminals complement crude oil pipeline gathering and transportation systems and address a fundamental imbalance in the energy industry wherein crude oil is often produced in different locations and at different times than it is ultimately consumed. Within the United States, there are also geographical imbalances, as a substantial majority of the petroleum refining that occurs in the United States east of the Rocky Mountains is concentrated in the Gulf Coast region, particularly Louisiana and Texas, which, according to the EIA, accounts for approximately 48% of all refining capacity in the United States. Over time, the crude oil storage business has evolved from its beginnings as a component of integrated production processes into a mature, stand-alone operation.
Overview of Cushing
Following Cushing’s early beginnings as an oil boom town and refining center, industry participants constructed storage facilities and interconnecting pipelines to support the refining activities. As nearby production slowed and the importance of refining waned, these operators opted to continue to use the complex logistical infrastructure they had established in Cushing to transport and store crude oil. With that history, Cushing has become one of the largest crude oil marketing hubs in the United States and is the designated point of delivery specified in all NYMEX crude oil futures contracts. As the NYMEX delivery point and a cash market hub, Cushing serves as a significant source of refinery feedstock for Mid-Continent refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil.
Because of this, Cushing is one of the largest commercial crude oil storage terminals in the United States. According to EIA data, Cushing shell storage capacity more than doubled to 66.5 million barrels, with 55.0 million barrels of working capacity, from 2004 to September 2011. At any given time, Cushing holds 5% to 10% of the total U.S. crude oil inventory.
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Storage capacity at Cushing, while relatively constant through the 1990s and early 2000s, began to increase significantly from 2004-2009. This growth in capacity was a direct result of the strong economics associated with crude oil storage. With the recent discovery and production of crude oil from unconventional plays, including the Mississippian oil trend, Granite Wash, Bakken Shale and Canadian oil sands, Cushing has continued to play an important role in aggregating these volumes for further transportation and delivery to end-users.
With multiple inbound and outbound pipeline interconnections, the Cushing hub serves as a liquidity point for crude oil. Recently, Cushing has experienced a shortfall in takeaway pipeline capacity, which has been cited as a principal reason for the decline in the WTI Index price used at Cushing compared to other crude oil price indices. However, the following planned major pipeline projects, if completed, should provide significant additional takeaway capacity, which we believe will allow Cushing to remain the predominant benchmarking and transportation hub for crude oil in the United States:
| • | TransCanada’s Keystone Pipeline—The $13 billion Keystone pipeline system will play an important role in linking a growing supply of Canadian crude oil with the largest refining markets in the United States. Keystone Cushing (Phase II), an extension of the Keystone Pipeline from Steele City, Nebraska to Cushing, went into service in February 2011. Phase III of the Keystone Pipeline, which would be built to deliver 500,000 barrels per day (“Bpd”) from Cushing to refineries in Port Arthur, Texas, is waiting U.S. government approval. |
| • | Seaway Pipeline Reversal—Enterprise Products Partners L.P. and Enbridge Inc. have announced plans to reverse the direction of crude oil flows on the Seaway Pipeline to allow it to transport crude oil from Cushing to the U.S. Gulf Coast. Pending regulatory approval, the line could operate in reversed service with an initial capacity of 150,000 barrels per day by the second quarter of 2012. Following pump station additions and modifications, anticipated to be completed by early 2013, the capacity of the reversed Seaway Pipeline is expected to be up to 400,000 barrels per day in mixed service. |
| • | Magellan Midstream Partners, LP—Magellan Midstream Partners, LP recently announced that it was exploring a project to link existing pipelines from Cushing to Gulf Coast refineries. The project would have 60,000 to 70,000 Bpd of capacity. |
We cannot provide any assurances regarding when, or if, any of these pipeline projects will be completed, or the actual effect that any of them may have on crude oil prices at Cushing.
Overview of the Williston and Denver-Julesburg (DJ) Basins
The Williston Basin is spread across North Dakota, South Dakota, Montana and parts of southern Canada. The basin produces oil and natural gas from numerous producing horizons including, but not limited to, the Bakken, Three Forks, Madison and Red River formations. Commercial oil production activities began in the Williston Basin in the 1950’s with the first well drilled in 1953. Much of North Dakota’s production increases are associated with accelerating horizontal drilling programs in the Bakken Shale formation. A 2008 United States Geological Survey, or USGS, assessment estimated 3.0 to 4.3 billion barrels of undiscovered, technically recoverable oil in the United States portion of the Bakken Shale. The USGS report classified the formation as the largest continuous oil accumulation ever assessed by it in the contiguous United States. The 2008 USGS assessment showed a 25-fold increase in the amount of technically recoverable oil as compared to the agency’s 1995 estimate of 151 million barrels of oil. New geologic models applied to the Bakken Shale, advances in drilling and production technologies, and additional oil discoveries resulted in these substantially larger technically recoverable oil volumes. Approximately 135 million barrels of oil were produced from the Bakken between 1953 and 2008, with 36 million barrels produced in 2008 alone. According to state statistics, oil production from the Bakken in North Dakota has steadily increased from about 28 million barrels in 2008, to 50 million
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barrels in 2009 to approximately 86 million barrels in 2010. According to an EIA report issued July 27, 2011, North Dakota’s oil production is expected to continue to increase as operators intensify development activity in the Bakken and underlying Sanish/Three Forks formations.
The Denver-Julesburg Basin (“DJ Basin”) is a structural basin located in eastern Colorado, southeastern Wyoming, western Kansas, and the Nebraska Panhandle and covers an area of more than 60,000 square miles. The basin has a long history of oil and gas exploration and production. Gas production is dominated by the Wattenberg tight gas field. Development activity is currently focused on exploitation of the Wattenberg field including the use of recompletions, multi-stage fracturing, and infill drilling. The Niobrara Shale formation, primarily an oil play in the DJ Basin, is situated in northeastern Colorado and parts of adjacent Wyoming, Nebraska, and Kansas. A USGS study estimated mean undiscovered hydrocarbons from the Niobrara at 40 million barrels of oil, 32 million barrels of natural gas liquids, and 330 billion cubic feet of natural gas in the DJ Basin. The Niobrara Shale is in its early stages of development and companies have been leasing land for future drilling. We expect exploration and production companies to apply horizontal drilling techniques proven in the Bakken Shale to access large amounts of oil deposits in the Niobrara Shale.
Overview of the Granite Wash and Mississippian Oil Trend
The Granite Wash is part of the Anadarko Basin and spans an estimated 1,180 square miles (3,056 square kilometers) across western Oklahoma and the north-eastern Texas Panhandle. The USGS has estimated mean undiscovered hydrocarbons from Granite Wash at 16 million barrels of oil, 3 million barrels of natural gas liquids and 90 billion cubic feet of natural gas. As an unconventional emerging play, several major players have obtained large acreage positions and have transitioned to horizontal drilling techniques, and efficiency gains are generally expected. Much of the Granite Wash development activity is in the southern flank of the Anadarko Basin within the Texas Panhandle where granite wash fields were deposited as deep-water turbidites, consisting of laterally-extensive and liquids-rich reservoirs.
The Mississippian oil trend is an expansive carbonate stratigraphic trap producing at relatively shallow depths and is located in northern Oklahoma near the panhandle and in southern Kansas. For the past 50 years, it has been a proven, commercial trend producing from thousands of vertical wells, and in the last several years, current players have begun drilling horizontal laterals in existing vertical wells and in new wells. Underlying the uppermost Mississippian layer is the Mississippian “lime,” a limestone sequence that enhances porosity and permeability. In 2011, over 150 horizontal wells are planned to be drilled with much of the recent activity focused within Woods and Alfalfa counties in Oklahoma.
Regional Production of Petroleum Products in the U.S.
The U.S. Department of Energy divides the continental U.S. into five geographic regions called Petroleum Administration for Defense Districts, or “PADDs”. PADD 2 is the Midwest region of the U.S. PADD 2 is the second largest PADD in terms of refinery production, surpassed only by PADD 3. As a result of the flow of petroleum products across and throughout the Midwest region, we believe PADD 2 is an important crude oil production, logistics, and refining center.
According to EIA data, as of November 2011, approximately 21%, or 3.7 million Bpd, of total U.S. daily refining capacity was in PADD 2. Also, according to November 2011 EIA data, PADD 2 produces approximately 14%, or 0.8 million Bpd, of total U.S. daily crude oil production and imports approximately 13.6%, or 1.7 million Bpd, of total U.S. daily imports.
PADD 2 refiners source crude oil from the Gulf Coast, Rocky Mountain, Canada’s Western Canadian Sedimentary Basin, which includes Alberta and parts of Saskatchewan to the East and British Columbia to the West, and major commodity hubs in the U.S. The production of petroleum products by PADD 2 refiners and processors historically has been less than the demand for petroleum products within that region with the shortfall being supplied via common carrier pipelines primarily from the Gulf Coast, Canada and, to a lesser extent, the Rocky Mountain and East Coast regions. Additional petroleum product supply is available via barge transport up the Mississippi River with significant deliveries into local markets along the Ohio River.
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Increased Importance of Independents and Specialization
In the 1990s, the major oil companies began focusing primarily on large-scale oil and gas projects. Until recently, this resulted in the major oil companies focusing more on foreign and deep-water exploration and production activities. As a result, they sold many of their North American integrated oil and gas assets, including producing properties, proprietary transportation systems, storage and distribution networks and refineries to independent operators. Whereas the major oil companies typically owned and operated proprietary networks that handled every aspect of the production, refining, storage, transportation and marketing of petroleum products, independent operators have generally focused on a single activity. As a result, the North American market is increasingly characterized by independent oil and gas producers and refiners that are generally without their own gathering, transportation, storage and distribution infrastructure. We focus on providing these services, using our asset base and distribution, processing and marketing expertise to provide independent operators with a stable source of supply and market access for their petroleum products.
Our Business
We are a growth-oriented Delaware limited partnership formed in 2011 by SemGroup to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We are engaged in the business of crude oil gathering, transportation, storage and marketing in Colorado, Kansas, Montana, North Dakota, Oklahoma and Texas. We serve areas that are experiencing strong production growth and drilling activity through our exposure to the Bakken Shale in North Dakota and Montana, the DJ Basin and the Niobrara Shale in the Rocky Mountain region, and the Granite Wash and the Mississippian oil trend in the Mid-Continent region. The majority of our assets are strategically located in, or connected to, the Cushing, Oklahoma crude oil marketing hub. Cushing is the designated point of delivery specified in all NYMEX crude oil futures contracts and is one of the largest crude oil marketing hubs in the United States. We expect that throughput and demand for storage services at the Cushing hub will continue to increase with the expansion of existing, and construction of new, pipelines and other transportation related logistical assets into and away from the hub. We believe that our connectivity in Cushing and our numerous interconnections with third-party pipelines, refineries and storage terminals provide our customers with the flexibility to access multiple points for the receipt and delivery of crude oil.
We gather, purchase, transport, store, distribute and market crude oil to markets primarily in the Midwest, ensuring that our customers have consistent access to petroleum products’ supply and markets. Our strategically located pipelines, terminals and storage tanks, with access to North American transportation pipeline interconnects, are well positioned to benefit from the continuing need to transport and gather petroleum products from areas of supply to areas of demand.
For the years ended December 31, 2011 and 2010, approximately 70% and 85% of our adjusted gross margin, respectively, was generated from fee-based contracts, some of which provide for fixed fees that are not dependent on usage, or fixed-margin transactions. For a definition of adjusted gross margin and a reconciliation of adjusted gross margin to operating income (loss), its most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States, or (“GAAP”), please see “Selected Historical Consolidated Financial and Operating Data – Non-GAAP Financial Measures” beginning on page 54.
Our Property, Plant and Equipment
We own and operate all of our assets, which include:
| • | over 5.0 million barrels of crude oil storage capacity in Cushing, with an additional 1.95 million barrels of capacity scheduled to be placed into service before the end of 2012; |
| • | a 640-mile crude oil gathering and transportation pipeline system with over 530,000 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, and an additional 130,000 barrels of storage currently under construction; |
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| • | a crude oil gathering, storage, transportation and marketing business in the Bakken Shale in North Dakota and Montana in which we handled an average of 6,600 barrels of crude oil per day for the year ended December 31, 2011; and |
| • | a modern, ten-lane crude oil truck unloading facility with 220,000 barrels of associated storage capacity in Platteville, Colorado which connects to the origination point of SemGroup’s White Cliffs Pipeline, with an additional six truck unloading lanes and 10,000 barrels of storage expected to be completed by the end of 2012. |
How We Generate Adjusted Gross Margin
We generate adjusted gross margin by providing fee-based services, by entering into fixed-margin transactions and through marketing activities.
Fee-Based Services. We charge a capacity or volume-based fee for the unloading, transportation and storage of crude oil and related ancillary services. Our fee-based services include substantially all of our operations in Cushing and Platteville and a portion of the transportation services we provide on our Kansas and Oklahoma pipeline system. For the years ended December 31, 2011 and 2010, approximately 56% and 80% of our adjusted gross margin, respectively, was generated by providing fee-based services to customers.
Fixed-Margin Transactions. We purchase crude oil from a producer or supplier at a designated receipt point at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price, thereby locking in a fixed margin that is, in effect, economically equivalent to a transportation fee. We refer to these arrangements as “fixed-margin” or “buy/sell” transactions. These fixed-margin transactions account for a portion of the adjusted gross margin we generate on our Kansas and Oklahoma pipeline system and through our Bakken Shale operations. For the years ended December 31, 2011 and 2010, approximately 14% and 5% of our adjusted gross margin, respectively, 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. 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 in order to manage risk and mitigate financial exposure. Our marketing activities account for a portion of the adjusted gross margin we generate on our Kansas and Oklahoma pipeline system and through our Bakken Shale operations. For the years ended December 31, 2011 and 2010, approximately 30% and 15% of our adjusted gross margin, respectively, was generated through marketing activities.
Competitive Strengths
We believe that the following competitive strengths position us to successfully execute our principal business objective:
| • | Strategically located assets that provide a strong platform for growth and operational flexibility to our customers. The majority of our assets are located in or connected to Cushing, and our numerous interconnections to other terminals and pipelines provide our customers with multiple options for the receipt and delivery of crude oil. We believe that we are well positioned to take advantage of both the increased throughput at Cushing that is expected to result from the construction of additional transportation capacity to and from the hub and the growing production in the Bakken Shale, DJ Basin, Niobrara Shale, Granite Wash and Misissippian oil trend. |
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| • | Modern crude oil storage and unloading assets. Our Cushing storage tanks and our Platteville facility have all been placed into service since the beginning of 2009. The recent construction of these facilities results in reduced maintenance costs, and we believe that customers prefer the additional reliability and safety that is generally associated with newer assets. |
| • | Stable cash flow. For the years ended 2011 and 2010, approximately 70% and 85%, respectively, of our adjusted gross margin was generated from fee-based services and fixed-margin transactions. Our fee-based and fixed-margin activities mitigate our exposure to margin fluctuations caused by commodity price volatility. |
| • | Affiliation with SemGroup. We believe that our relationship with SemGroup strengthens our ability to make strategic acquisitions and to access other business opportunities. In addition, we believe that SemGroup, as the owner of a substantial interest in us, will be motivated to promote and support the successful execution of our business strategies. |
| • | Experienced, knowledgeable management team with a proven track record. Our management team has an average of over 28 years of experience in the energy industry, including building, acquiring, integrating and operating midstream assets. In addition, our management team has established strong relationships throughout the U.S. upstream and midstream industries, which we believe will be beneficial to us in pursuing acquisition and organic expansion opportunities. |
Business Strategy
Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while maintaining the on-going stability of our business. We expect to achieve this objective through the following strategies:
| • | Capitalizing on organic growth opportunities associated with our existing assets. We seek to identify and evaluate economically organic expansion and asset enhancement opportunities that leverage our existing asset footprint and strategic relationships with our customers. We are currently (i) constructing an additional 1.95 million barrels of crude oil storage capacity at Cushing, (ii) expanding capacity on portions of our Kansas and Oklahoma pipeline systems through de-bottlenecking projects, (iii) evaluating additional markets for our Bakken Shale operations, and (iv) constructing an additional 100,000 barrels of storage capacity, and planning for the construction of six additional truck unloading lanes and an additional 10,000 barrels of storage capacity at our Platteville facility. |
| • | Growing our business through strategic and accretive asset acquisitions from third parties and SemGroup. We plan to pursue accretive acquisitions from SemGroup and third parties of midstream energy assets that are complementary to our existing asset base or that provide attractive potential returns in new operating regions or business lines. |
| • | Focusing on stable, fee-based services and fixed-margin transactions. We focus on opportunities to provide midstream services under fee-based arrangements and fixed-margin transactions, which minimize our direct exposure to commodity price fluctuations. |
| • | Mitigating commodity price exposure. We mitigate the commodity price exposure of substantially all of our crude oil marketing operations by entering into “back-to-back” transactions, which are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered, and through the use of derivative contracts. |
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| • | Maintaining financial flexibility and utilizing leverage prudently. We plan to pursue a disciplined financial policy and maintain a conservative capital structure to allow us to execute on our identified growth projects, as well as pursue additional growth projects and acquisitions, even in challenging market environments. We have minimal debt following the closing of our initial public offering. |
Our Relationship with SemGroup
One of our principal strengths is our relationship with SemGroup. SemGroup provides gathering, transportation, processing, storage, distribution, marketing, and other midstream services primarily to independent oil and natural gas producers, refiners of petroleum products, and other market participants located in the Mid-Continent and Rocky Mountain regions of the United States and in Canada, Mexico and the United Kingdom. Since 2008, SemGroup has taken numerous steps to restructure its business portfolio and to shift away from trading activities and toward a business heavily weighted in fee-based and fixed-margin activities. As of December 31, 2011, excluding the assets contributed to us in connection with our December 2011 initial public offering, SemGroup had a midstream asset portfolio that included, among other assets:
| • | a 51% interest in the White Cliffs Pipeline, which SemGroup operates; |
| • | a 7.5% interest in NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP; |
| • | 8.93 million common units of NGL Energy Partners LP; |
| • | more than 1,700 miles of natural gas and natural gas liquids transportation, gathering and distribution pipelines in Arizona, Arkansas, Kansas, Montana, Oklahoma and Texas and Alberta, Canada; |
| • | 8.7 million barrels of owned multiproduct storage capacity located in the United Kingdom; |
| • | 14 asphalt terminals in Mexico; |
| • | majority interests in four natural gas processing plants located in Alberta, Canada, with a combined licensed capacity of 654 million cubic feet per day (“MMcf/d”); and |
| • | three natural gas processing plants located in Oklahoma and Texas, with a combined operating capacity of 78 MMcf/d. |
SemGroup’s Class A common stock trades on the NYSE, under the symbol “SEMG.”
SemGroup owns and operates a substantial portfolio of midstream assets and retains a significant interest in us through its ownership of a 57.0% limited partner interest and 2.0% general partner interest in us, as well as all of our incentive distribution rights. Given SemGroup’s significant ownership in us, we believe that SemGroup continues to be motivated to promote and support the successful execution of our business strategies. This support could include the potential contribution to us over time of additional midstream assets that SemGroup currently owns or acquires or develops in the future and the facilitation of accretive acquisitions. However, SemGroup is under no obligation to offer any assets or business opportunities to us or accept any offer for its assets that we may choose to make. SemGroup constantly evaluates acquisitions and dispositions and may elect to acquire or dispose of assets in the future without offering us the opportunity to purchase those assets. SemGroup has retained such flexibility because it believes it is in the best interests of its shareholders to do so. We cannot say with any certainty which, if any, opportunities to acquire assets from SemGroup may be made available to us or if we will choose to pursue any such opportunity. Moreover, the consideration to be paid by us for assets offered to us by SemGroup, if any, as well as the consummation and timing of any acquisition by us of these assets, would depend upon, among other things, the timing of SemGroup’s decision to sell, transfer or otherwise dispose of these assets, our ability to successfully negotiate a purchase price and other terms, and our ability to obtain financing.
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We entered into an omnibus agreement with SemGroup and our general partner that governs our relationship with them regarding certain indemnification matters, among other things. Please read “Agreements with SemGroup and its Affiliates – Omnibus Agreement”, beginning on page 92. While our relationship with SemGroup provides us with a significant advantage, it is also a source of potential conflicts. For example, SemGroup is not restricted from competing with us, and may acquire, construct or dispose of midstream energy assets without any obligation to offer us the opportunity to acquire or construct such assets. Please read “Conflicts of Interest” beginning on page 91 and “Risk Factors—Risks Inherent in an Investment in Us — SemGroup owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. SemGroup and our general partner will have conflicts of interest with us and may favor their own interests to your detriment” beginning on page 35.
Our Business Operations
The following sections present an overview of our business operations, including general information, assets and operations, and markets and competitive strengths.
Cushing Storage
General. We own and operate 19 crude oil storage tanks in Cushing with an aggregate storage capacity of approximately 5.0 million barrels. Our storage terminal has a combined capacity to receive or deliver 240,000 barrels of crude oil per day, and has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Cimarron Pipeline from Boyer, Kansas, our Kansas and Oklahoma gathering system and two-way interconnections with all of the other major storage terminals in Cushing, including the delivery point specified in all crude oil futures contracts traded on the NYMEX. Connection with this terminal provides our customers with access to multiple pipelines outbound from Cushing. Our Cushing terminal also includes truck unloading facilities.
Our Cushing storage tanks have all been built since the beginning of 2008 and had a weighted average age of only 2.5 years as of December 31, 2011. The design and construction specifications of our storage tanks meet or exceed the minimums established by the American Petroleum Institute, or “API”. Our storage tanks also undergo regular maintenance and inspection programs, and we believe that these design specifications and maintenance and inspection programs reduce our maintenance capital expenditures.
In part, as a result of its role as the designated point of delivery specified in all NYMEX crude oil futures contracts, Cushing is one of the largest crude oil marketing hubs in the United States. Cushing serves as a significant source of refinery feedstock for Mid-Continent refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil. Recently, Cushing has experienced a shortfall in takeaway pipeline capacity, which has been cited as a principal reason for the decline in price of the West Texas Intermediate Index (“WTI” Index) compared to other crude oil price indices. We believe that if and when any of several planned takeaway pipeline expansion projects are completed, this price differential will narrow and Cushing will remain the predominant benchmarking and transportation hub for crude oil in the United States. Please read “Industry Overview—Overview of Cushing” beginning on page 3.
Adjusted Gross Margin and Contracts. We generate adjusted gross margin from our Cushing storage by charging third parties a fee for the use of the storage tanks. Approximately 95% of our Cushing storage is committed under long-term contracts with third parties that provide for a fixed fee that is not tied to usage. Our existing storage contracts had a weighted average remaining life of 4 years as of December 31, 2011, and none of our third-party contracts expire before 2015.
Customers. Our primary customers at Cushing are crude oil traders and pipeline companies.
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Competition. Competition for crude oil storage customers is intense and is based primarily on price, access to supply, access to logistics assets, distribution capabilities, the ability to meet regulatory requirements, and maintenance of quality of service and customer relationships. Our major competitors in Cushing include Enbridge Energy Partners, L.P., Magellan Midstream Partners, L.P., Plains All American Pipeline, L.P., Blueknight Energy Partners, L.P. and Enterprise Products Partners L.P. Several of these competitors have announced their intention to significantly expand their storage capacity at Cushing.
Growth Opportunities. We expect to place into service an additional 1.95 million barrels of crude oil storage capacity before the end of 2012, all of which is backed by third-party, five-year contracts that will commence on the in-service date of the new storage capacity, and we have 100 acres of additional land as well as additional infrastructure which we believe will be sufficient to grow our storage capacity by approximately six million barrels in the future.
Kansas and Oklahoma System
General. We own and operate an approximately 640-mile crude oil gathering and transportation pipeline system and over 530,000 barrels of associated storage in Kansas and northern Oklahoma, with an additional 130,000 barrels of storage currently under construction. This system gathers crude oil from throughout the region and delivers it to third-party pipelines and refineries and our Cushing terminal. The system can currently transport in excess of 40,000 barrels of crude oil per day. During the years ended December 31, 2011 and 2010, we transported an average of approximately 36,000 and 31,000 barrels per day, respectively, from approximately three receipt points. The system has pipeline diameters ranging from four to twelve inches and has 28 pump stations. This system also includes 18 truck unloading stations.
Delivery Points. Our Kansas and Oklahoma system connects to pipelines owned by Sunoco Logistics Partners L.P., Plains All American Pipeline, L.P., Kaw Pipeline Company, Jayhawk Pipeline LLC and MV Purchasing, LLC in Kansas and Oklahoma, and refineries owned by Frontier Oil Corporation and ConocoPhillips Company, and our storage terminal in Cushing, thereby providing our customers with multiple delivery options.
Supply. According to the EIA, crude oil production in Kansas grew from approximately 35.6 million barrels in 2006 to approximately 40.5 million barrels in 2010, and in Oklahoma it grew from approximately 62.8 million barrels in 2006 to approximately 69.5 million barrels in 2010. As of September 2011, year-to-date production (annualized) in Kansas and Oklahoma was approximately 41.5 million barrels and 72.7 million barrels, respectively. We expect that the strong pricing environment for crude oil will continue to drive increasing crude oil production in Kansas and Oklahoma.
Adjusted Gross Margin and Contracts. We primarily generate adjusted gross margin from our Kansas and Oklahoma system by charging a flat volumetric transportation fee to our customers or by purchasing crude oil from an aggregator at a receipt point on our system at an index price, less a transportation fee, and simultaneously selling an identical volume of crude oil at a delivery point on our system to the same party at the same index price, through which we are able to lock in a fixed margin that is, in effect, economically equivalent to a transportation fee.
We also generate adjusted gross margin through marketing activities, whereby we purchase crude oil from one party and sell it to another. 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 marketing activities are subject to a comprehensive risk management policy, which establishes limits in order to attempt to manage risk and mitigate financial exposure.
Our crude oil purchases in our Kansas and Oklahoma operations are made at prices that are typically based on published or “posted” prices, plus or minus a differential. The differential is determined based on the grade of oil produced, transportation costs and competitive factors. Both the price and the differential change in response to market conditions. Posted prices can change daily and differentials, in general, can change every 30 days as contracts renew. We sell crude oil primarily to refiners and other resellers in various types of sale and exchange transactions, at market prices for terms ranging from one to twelve months.
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Two of the contracts on our Kansas and Oklahoma system are take-or-pay contracts, whereby the customer is required to pay us a fixed minimum monthly transportation fee regardless of the volumes actually transported on our system. For the year ended December 31, 2011, approximately 27% of the adjusted gross margin associated with our Kansas and Oklahoma system was derived from a take-or-pay contract. Most of our fixed fee and fixed margin contracts are 30-day, evergreen contracts, although some extend for up to four years.
Customers. The primary customers for our Kansas and Oklahoma system are aggregators, local producers and refineries.
Competition. Competition for crude oil volumes is primarily based on reputation, commercial terms, reliability, interconnectivity, location and available capacity. Our major competitors are MV Purchasing, LLC, Plains All American Pipeline, L.P. and the National Cooperative Refinery Association. Magellan Midstream Partners, L.P. has recently completed a line to Cushing, which has diverted some volumes from our system, but to date we have been able to replace those volumes and maintain our throughput.
Growth Opportunities. We believe that we will be able to increase the utilization of our Kansas and Oklahoma system as a result of the increased drilling activity that we expect will occur, as described above under “—Supply.” We are currently expanding capacity on portions of our Kansas and Oklahoma system through de-bottlenecking projects.
Bakken Shale Operations
General. We own and operate a crude oil gathering, storage, transportation and marketing business in the Bakken Shale area in western North Dakota and eastern Montana. Using our fleet of trucks and two truck unloading facilities, we purchase crude oil at the wellhead, transport it via our trucks and third-party pipelines, including the Enbridge North Dakota System (utilizing historically accrued allocation rights), and market it to customers, primarily at the crude oil marketing hub in Clearbrook, Minnesota. We own tanks in Trenton and Stanley, North Dakota, with an aggregate storage capacity of 60,200 barrels that connect into the Enbridge North Dakota System. During the year ended December 31, 2011, we handled and marketed an average of approximately 6,600 barrels per day.
Adjusted Gross Margin and Contracts. We generate adjusted gross margin in our Bakken Shale operations through the purchase and sale of crude oil. 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 marketing activities are subject to a comprehensive risk management policy, which establishes limits in order to attempt to manage risk and mitigate financial exposure.
Customers. We purchase our crude oil from producers in the Bakken Shale. We then sell the crude oil to traders or refiners.
Competition. We compete for crude oil volumes with other midstream operators, including Plains All American Pipeline, L.P. and Eighty Eight Oil LLC. Competition is primarily based on reputation, commercial terms, reliability, interconnectivity, location and available capacity. Although competition can be intense, we believe that it is currently mitigated to some degree by the shortage of takeaway capacity out of the Bakken Shale, which reduces the number of options that producers have for getting their crude oil to market. However, additional midstream operators are constructing additional pipeline capacity in the Bakken Shale and existing operators are expanding their pipeline capacity and building or expanding railcar facilities; therefore, competition may intensify in the future.
Growth Opportunities. We believe that significant new drilling activity in the Bakken Shale will result in crude oil production growing faster than available takeaway capacity over the medium term. We anticipate that through a combination of additional allocated capacity on Enbridge Inc.’s planned expansion of its North Dakota pipeline, which is scheduled for completion in early 2013, additional rail capacity and infrastructure expansion, we will be able to significantly expand our operations in North Dakota and Montana.
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Platteville Facility
General. We own and operate a modern, ten-lane crude oil truck unloading facility in Platteville, Colorado, which connects to the origination point of SemGroup’s White Cliffs Pipeline, which was first placed into service in 2009. Substantially all of the crude oil production from the DJ Basin and the nearby Niobrara Shale must initially be transported by truck due to a shortage of gathering capacity, and the White Cliffs Pipeline is the only direct pipeline out of the DJ Basin to the Cushing market and to Mid-Continent refineries. Throughput at the facility averaged 32,400 barrels per day and 25,800 barrels per day for the years ended December 31, 2011 and 2010, respectively. The facility includes 220,000 barrels of crude oil storage capacity.
Adjusted Gross Margin and Contracts. We generate adjusted gross margin at our Platteville facility by charging our customers a volumetric fee for unloading their crude oil at our facility. In connection with their entry into long-term, take-or-pay transportation contracts on the White Cliffs Pipeline, the two largest shippers on White Cliffs entered into contracts with us that provide for the payment to us of a fixed fee per barrel of oil unloaded at our facility, with a discounted fee for volumes in excess of 10,000 barrels per day. Additional shippers on the White Cliffs Pipeline have also entered into fixed-fee contracts with us to unload crude oil at our facility, which is the only point in Colorado through which crude oil can be delivered into the White Cliffs Pipeline.
Customers. Our primary customers at our Platteville facility include two crude oil producers which have entered into 10,000 barrel per day take-or-pay transportation contracts on the White Cliffs Pipeline.
Competition. Our Platteville facility is the only injection point in Colorado into the White Cliffs Pipeline, and the White Cliffs Pipeline is the only pipeline out of the DJ Basin to Cushing. As a result, we do not face direct competition with respect to our Platteville facility. However, producers in the region served by this facility do have other options for the delivery of crude oil, including delivery to local refineries or through rail transportation.
Growth Opportunities. We believe that throughput at our Platteville facility will continue to grow due to increasing production from the DJ Basin and Niobrara Shale and a shortage of takeaway capacity from the Rocky Mountain region. We expect to build an additional six truck unloading lanes, which we anticipate will be supported by long-term contracts, and 10,000 barrels of additional storage capacity at the facility by the end of 2012.
Operational Hazards and Insurance
Pipelines, terminals, storage tanks and other facilities may experience damage as a result of an accident, natural disaster or deliberate act. These hazards can also cause personal injury and loss of life, severe damage to, and destruction of, property and equipment, pollution or environmental damage and suspension of operations. Through the services of a major national insurance broker, we maintain insurance of various types and varying levels of coverage similar to that maintained by other companies in the industry and which we consider adequate, under the circumstances, to cover our operations and properties, including coverage for natural catastrophes, pollution related events and acts of terrorism and sabotage. The limit of operational insurance maintained covering loss of, or damage to, property and products is $300 million per loss incident and includes business interruption loss. For claims arising under general liability, automobile liability and excess liability, the limits maintained total $250 million per occurrence/claim. Primary and excess liability insurance limits maintained for pollution liability claims vary by location for claims arising from gradual pollution with limits of $20 million per claim and $40 million in the aggregate. The combined primary and excess liability insurance limits for claims arising from sudden and accidental pollution total $270 million per claim and $290 million in the aggregate. This insurance does not cover every potential risk associated with operating our pipelines, terminals and other facilities. We have a favorable claims history enabling us to self-insure the “working layer” of loss activity utilizing deductibles and self-insured retentions commensurate with our financial abilities and in line with industry standards, in order to create a more efficient and cost effective program and a consistent risk profile. The working layer consists of high frequency/low severity losses that are best retained and managed in-house. Sizeable or difficult self-insured claims or losses may be handled by professional adjusting firms hired by us.
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With a few limited exceptions, our customers have not agreed to indemnify us for losses arising from a release of crude oil, and we may instead be required to indemnify our customers in the event of a release or other incident.
Risk Governance and Comprehensive Risk Management Policy
The board of directors of our general partner is responsible for oversight of our enterprise-wide risk and has approved our comprehensive risk management policy. The comprehensive risk management policy is designed to ensure we:
| • | identify and communicate our risk appetite and risk tolerances; |
| • | establish an organizational structure that prudently separates responsibilities for executing, valuing and reporting our business activities; |
| • | value (where appropriate), report and manage all material business risks in a timely and accurate manner; |
| • | effectively delegate authority for committing our resources; |
| • | foster the efficient use of capital and collateral; and |
| • | minimize the risk of a material adverse event. |
The audit committee of the board of directors of our general partner has oversight responsibilities for the implementation of, and compliance with, our comprehensive risk management policy.
Our executive management committee, comprised of certain of our general partner’s corporate and business segment officers, oversees the financial and non-financial risks associated with all activities governed by our comprehensive risk management policy, including: asset operations; marketing and trading; investments, divestitures, and other capital expenditures and dispositions; credit risk management; and other strategic activities. We also have a risk management group that is assigned responsibility for independently monitoring compliance with, reporting on and enforcing the provisions of our comprehensive risk management policy.
With respect to our commodity marketing activities, our comprehensive risk management policy provides a set of limits for specified activities related to the purchase and sale of physical commodities, the purchase and sale of derivatives and capital transactions involving market and credit risk. With respect to market risk activities involving commodity price risk, our comprehensive risk management policy provides a set of limits that considers our commodity and owned and leased asset positions. Our comprehensive risk management policy also specifies the types of transactions that may be executed by incumbents of named positions without specific approval of the board of directors of our general partner or the executive management committee. It also restricts proprietary trading activities within limits significantly more restrictive than the corporate market risk management limits.
Regulation
General
Our operations are subject to extensive regulation. The following discussion of certain laws and regulations affecting our operations should not be relied on as an exhaustive review of all regulatory considerations affecting us, due to the myriad of complex federal, state and local regulations that may affect our business.
Regulation of Transportation and Storage Operations
Interstate Commerce Act and State Regulation. Our Kansas and Oklahoma gathering pipeline system is operated as an intrastate pipeline system which carries crude oil owned by us and by third parties. We believe that our pipeline facilities and services meet the traditional tests that FERC has used to determine that the pipeline services provided are
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not in interstate commerce, and therefore are not subject to the Interstate Commerce Act (“ICA”), or would qualify for a waiver from FERC’s reporting and filing requirements under the ICA, if applicable. However, in the future, FERC could determine that some or all of our Kansas and Oklahoma gathering pipeline system, and the services we provide on that system, are within its jurisdiction under the ICA. The ICA prescribes that interstate tariffs must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC regulations require that interstate oil pipeline transportation rates and terms of service be filed with FERC and posted publicly.
The ICA permits interested persons to challenge proposed new or changed rates or rules and authorizes FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it may require the pipeline to refund the revenues together with interest in excess of the prior tariff during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates and related rules that are already in effect and may order a pipeline to change them prospectively. Upon an appropriate showing, a shipper may obtain reparations and refunds for a period of up to two years prior to the filing of its complaint.
Our Kansas and Oklahoma gathering pipeline system may be subject to various regulations and statutes administered by state regulatory authorities. For example, while the Kansas Corporation Commission (“KCC”) has authority to regulate common carriers, we believe that it has informally elected not to actively regulate oil pipelines, instead allowing pipelines to negotiate transportation rates directly with customers. If the KCC were to change its approach and regulate our operations in Kansas, we could be required to publish and file tariffs, rates, rules and charges and to adhere to other state commission regulations. In addition, shippers could challenge our intrastate tariff rates and practices on our intrastate pipeline system.
Although we operate the pipeline gathering system as an unregulated system, no assurances can be given that in the future the gathering system will not be subject to regulation under the ICA by FERC or under state regulation by a state commission.
Department of Transportation. All crude oil interstate pipelines, and certain intrastate crude oil pipelines and storage facilities, are subject to regulation by the Department of Transportation (“DOT”) with respect to the design, construction, operation and maintenance of the pipeline systems and storage facilities. The DOT routinely conducts audits of regulated assets and we must make certain records and reports available to the DOT for review as required by the Secretary of Transportation. In some states, the DOT has given a state agency authority to assume all or part of the regulatory and enforcement responsibility over the intrastate assets.
Trucking Regulation. We own and operate a fleet of trucks to transport crude oil. We are licensed to perform both intrastate and interstate motor carrier services and are subject to certain safety regulations issued by the DOT. DOT regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on the trucks and trailer vehicles, drug and alcohol testing, safety of operation and equipment and many other aspects of truck operations. We are also subject to Occupational Safety and Health Administration (“OSHA”) regulations with respect to our trucking operations.
Environmental, Health and Safety Regulation
General. Our operations are subject to varying degrees of stringent and complex laws and regulations by multiple levels of government relating to the production, transportation, storage, processing, release and disposal of crude oil, crude oil-based products and other materials or otherwise relating to protection of the environment. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall costs of business, including our capital costs to construct, maintain and upgrade pipelines, equipment and facilities. The failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of removal or remedial obligations and the issuance of injunctions limiting or prohibiting our activities.
The clear trend in environmental regulation, particularly with respect to crude oil facilities, is the placement of more restrictions and limitations on activities that may affect the environment and, thus, any changes in environmental laws and regulations or re-interpretations of enforcement policies that result in costly waste handling, storage, transport,
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disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased costs to our customers. Moreover, accidental releases, leaks or spills may occur in the course of our operations and we may incur significant costs and liabilities as a result, including those related to claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on us, there can be no assurance that the current conditions will continue in the future.
The following is a summary of the more significant current environmental, health and safety laws and regulations to which our operations are subject:
Water Discharges. Our operations can result in the discharge of pollutants, including oil. The Oil Pollution Act, or (“OPA”), was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972, as amended, the Clean Water Act, as amended, and other statutes as they pertain to prevention of, and response to, oil spills. The OPA, the Clean Water Act and analogous state and local laws subject owners of facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone of the U.S. In the event of an oil spill from one of our facilities into navigable waters, substantial liabilities could be imposed. Spill prevention, control and countermeasure requirements of these laws require appropriate containment berms or dikes and other containment structures at storage facilities to prevent contamination of soil, surface water and groundwater in the event of an oil overflow, rupture or leak.
The federal Clean Water Act and analogous state and local laws impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States and state waters, including groundwater in many jurisdictions. Permits must be obtained to discharge pollutants into these waters. The Clean Water Act and analogous state and local laws provide significant penalties for unauthorized discharges and can impose liability for responding to and cleaning up spills. In addition, the Clean Water Act and analogous state and local laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities.
Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state and local laws. These laws and regulations regulate emissions of air pollutants from various sources, including certain of our facilities, and impose various monitoring and reporting requirements. Pursuant to these laws and regulations, we may be required to obtain environmental agency pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with the terms of air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. We may be required to incur certain capital expenditures in the future for air pollution control equipment and leak detection and monitoring systems in connection with obtaining or maintaining operating permits and approvals for air emissions. There are significant potential monetary fines for violating air emission standards and permit provisions.
Climate Change. On December 15, 2009, the Environmental Protection Agency (“EPA”) issued a notice of its final finding and determination that emissions of CO2, methane, and other Greenhouse Gases (“GHG”) present an endangerment to public health and the environment because emissions of such gases contribute to warming of the Earth’s atmosphere and other climatic changes. This final finding and determination allows the EPA to begin regulating GHG emissions under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted regulations that require a reduction in emissions of GHGs from motor vehicles and also trigger permit review for GHG emissions from certain large stationary sources. In addition, the EPA issued a final rule, effective in December 2009, requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., beginning in 2011 for emissions occurring in 2010 (EPA’s Greenhouse Gas Reporting Program, or “GHGRP”). Further, on November 8, 2010, EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA’s GHG Reporting Rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year will be required to report annual GHG emissions to EPA, with the first report due on March 31, 2012. In December 2010, the EPA issued three concurrent actions related to its GHGRP which require the collection of certain additional business related data, and therefore, it is deferring the reporting of certain information.
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Although in March 2011 the House of Representatives Energy and Power Committee passed legislation that would prevent EPA from regulating GHG emissions for purposes of addressing climate change, the United States Congress has also been considering legislation to reduce such emissions and almost one-half of the states, either individually or through multi-state regional initiatives, have already begun implementing legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or GHG cap and trade programs. In addition, both President Obama and the Administrator of the EPA have repeatedly indicated their preference for comprehensive legislation to address this issue and create the framework for a clean energy economy, with the Obama Administration supporting an emission allowance system. Depending on the particular program and scope thereof, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations or could face additional taxes and higher costs of doing business. Although we would not be impacted to a greater degree than other similarly situated midstream energy service providers, a stringent GHG control program could have an adverse effect on our cost of doing business and could reduce demand for crude oil.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such new federal, state or regional restrictions on emissions of GHGs that may be imposed in areas in which we conduct business could also have an adverse affect on our cost of doing business and demand for crude oil.
Hazardous Substances and Wastes. The environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater and surface water, and include measures to prevent and control pollution. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous wastes, and may require investigatory and corrective actions at facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA”, also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. Potentially responsible persons can include the current owner or operator of the site where a release previously occurred and companies that disposed, or arranged for the disposal, of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the potentially responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. Although “petroleum,” as well as natural gas and natural gas liquids (“NGLs”), previously have been for the most part excluded from CERCLA’s definition of a “hazardous substance,” more recent regulations have begun incorporating these activities within the scope of CERCLA and RCRA. In the course of ordinary operations, we may generate wastes that may fall within the definition of a “hazardous substance.” In addition, there are other laws and regulations that can create liability for releases of petroleum. Moreover, we may be responsible under CERCLA or other laws for all or part of the costs required to clean up sites at which such wastes have been disposed.
We also generate, and may in the future generate, both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, or “RCRA”, and/or comparable state laws. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes as currently defined under RCRA. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated by us that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Changes in applicable laws or regulations may result in an increase in our capital expenditures, facility operating expenses or otherwise impose limits or restrictions on our operations.
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We currently own or lease, and have in the past owned or leased, and in the future we may own or lease, properties that have been used over the years for petroleum product operations. Solid waste disposal practices within the oil and natural gas and related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some petroleum products and other solid wastes have been disposed of on, or under, various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we had no control as to such entities’ handling of petroleum products or other wastes and the manner in which such substances may have been disposed of or released. These properties and the wastes disposed of thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination, or to take action to prevent future contamination.
Employee Safety. We are subject to the requirements of OSHA, the purpose of which is to protect the health and safety of workers. In addition, the OSHA hazard communication standard and comparable state statutes require us to organize and disclose information concerning hazardous materials used, produced or transported in our operations. Some of our facilities are subject to the OSHA Process Safety Management regulations that are designated to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.
Hazardous Materials Transportation Requirements. DOT regulations affecting pipeline safety require pipeline operators to implement measures designed to reduce the environmental impact of oil discharge from onshore oil pipelines. These regulations require operators to maintain comprehensive spill response plans, including extensive spill response training for pipeline personnel. In addition, DOT regulations contain detailed specifications for pipeline operation and maintenance.
Anti-Terrorism Measures. The federal Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security, or “DHS”, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with the interim rules. To the extent our facilities are subject to existing or new rules, it is possible that the costs to comply with such rules could be substantial.
Title to Properties
Substantially all of our pipelines are constructed on rights-of-way granted by the record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee. Our Cushing storage terminal and Platteville facility are on real property owned by us.
We believe that we have satisfactory title to all of the assets we own. Although title to such properties is subject to encumbrances in certain cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by us, we believe that none of these burdens will materially detract from the value of such properties or from our interest therein or will materially interfere with their use in the operation of our business.
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Office Facilities
In addition to our gathering, storage, terminalling and processing facilities discussed above, our general partner maintains its office headquarters in Tulsa, Oklahoma. We also have satellite offices located in Oklahoma City, Oklahoma; Cushing, Oklahoma; Platteville, Colorado and Wichita, Kansas. The current lease for our general partner’s Tulsa headquarters expires in May 2019. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
Employees
The officers of our general partner manage our operations and activities. As of December 31, 2011, SemGroup employed approximately 80 people who provide direct support to our operations. All of the employees required to conduct and support our operations are employed by SemGroup. None of these employees are covered by collective bargaining agreements, and SemGroup considers its employee relations to be good.
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Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the events described in the following risk factors were to occur, our business, results of operations, financial condition or ability to make cash distributions to our unitholders could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.
Risks Related to Our Business
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.
In order to pay the minimum quarterly distribution of $0.3625 per unit per quarter, or $1.45 per unit per year, we will require available cash of approximately $6.2 million per quarter, or approximately $24.8 million per year, based on the number of common and subordinated units outstanding following our initial public offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
| • | the price of crude oil and the level of production of, and demand for, crude oil in the markets we serve; |
| • | the volume of crude oil that we gather, transport, store and/or market; |
| • | the fees with respect to volumes that we handle; |
| • | the profitability of our marketing operations; |
| • | damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism or inadvertent damage to pipelines from construction, farm and utility equipment; |
| • | leaks or accidental releases of crude oil or other materials into the environment, whether as a result of human error or otherwise; |
| • | demand charges and volumetric fees associated with our transportation services; |
| • | the level of competition from other midstream energy companies; |
| • | the level of our operating, maintenance and general and administrative costs; |
| • | regulatory action affecting the supply of, or demand for, crude oil, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; |
| • | changes in tax laws; and |
| • | prevailing economic conditions. |
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In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
| • | the level of capital expenditures we make; |
| • | the cost of acquisitions; |
| • | our debt service requirements and other liabilities; |
| • | fluctuations in our working capital needs; |
| • | our ability to borrow funds and access capital markets; |
| • | restrictions contained in debt agreements to which we are a party; and |
| • | the amount of cash reserves established by our general partner. |
The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we will have available for distribution will depend primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.
Our profitability depends on the demand for crude oil in the markets we serve.
Any sustained reduction in demand for crude oil in markets served by our midstream assets could result in a significant reduction in the volume of crude oil that we handle, thereby adversely affecting our business, results of operations, financial condition and ability to make cash distributions to our unitholders. A reduction in demand could result from a number of factors including:
| • | an increase in the price of products derived from crude oil; |
| • | higher taxes, including federal excise taxes, severance taxes or sales taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of crude oil based products; |
| • | adverse economic conditions which result in lower spending by consumers and businesses on products derived from crude oil; |
| • | the effects of weather, natural phenomena, terrorism, war, or other similar acts; |
| • | an increase in fuel economy, whether as a result of a shift by consumers to more fuel efficient vehicles, technological advances by manufacturers or federal or state regulations; |
| • | decisions by our customers or suppliers to use alternate service providers for a portion or all of their needs, operate in different markets not served by us, reduce operations or cease operations entirely; and |
| • | an increase in the use of alternative fuel sources, such as ethanol, biodiesel, fuel cells, solar and wind power, or of other fossil fuels, including natural gas. |
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Most of our operating costs are fixed and do not vary with our throughput. These costs may not decline ratably or at all should we experience a reduction in throughput, which would result in a decline in our margins and profitability.
Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of crude oil, which is dependent on certain factors beyond our control. Any decrease in the volumes of crude oil that we gather, transport, store and market could adversely affect our business and operating results.
The volumes that support our business are dependent on the level of production from crude oil wells in our areas of operation, the production of which will naturally decline over time. As a result, in order to maintain or increase the amount of crude oil that we handle, we must obtain new sources of crude oil. The primary factors affecting our ability to obtain new sources of crude oil include the level of successful drilling activity near our systems or operations and our ability to compete for volumes.
We have no control over the level of drilling activity or the amount of reserves in our areas of operation, or the rate at which production in any of our areas of operation will decline. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, geological considerations, governmental regulations, the availability of drilling rigs and other production and development costs. Fluctuations in energy prices can also greatly affect investments in the development of new crude oil reserves. Because of these factors, even if new crude oil reserves are known to exist in our areas of operation, producers may choose not to develop those reserves. Declines in crude oil prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our assets and a reduced need for our marketing operations.
If competition or reductions in drilling activity result in our inability to maintain the current levels of crude oil that we gather, transport, store and market, it could have an adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
A prolonged decline in index prices at Cushing, relative to other index prices, could reduce the demand for our transportation to, and storage in, Cushing.
Shifts in the overall supply of and demand for crude oil in regional, national and global markets, over which we have no control, could have an adverse impact on crude oil index prices in the markets we serve relative to other index prices. For example, Cushing has experienced a shortfall in takeaway pipeline capacity which has, in turn, led to an oversupply of crude oil at Cushing. This has been cited as a principal reason for the decline in the WTI Index price used at Cushing relative to other crude oil price indexes, including the Brent Crude Index. A prolonged decline in the WTI Index price relative to other index prices may cause reduced demand for our transportation to, and storage in, Cushing, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
We face intense competition in our gathering, transportation, storage and marketing activities. Competition from other providers of those services that are able to supply our customers with those services at a lower price or on otherwise better terms could adversely affect our business and operating results.
We are subject to competition from other crude oil gathering, transportation, storage and marketing operations that may be able to supply our customers with the same or comparable services at a lower price or otherwise on better terms. We compete with national, regional and local gathering, transportation and storage companies of widely varying sizes, financial resources and experience, including the major integrated oil companies. With respect to our gathering and transportation services, these competitors include Enterprise Products Partners L.P., Plains All American Pipeline, L.P., ConocoPhillips Company, Sunoco Logistics Partners L.P. and National Cooperative Refinery Association, among others. With respect to our storage services, these competitors include Magellan Midstream Partners, L.P., Enbridge Energy
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Partners, L.P., Blueknight Energy Partners, L.P. and Plains All American Pipeline, L.P. Several of our competitors conduct portions of their operations through publicly traded partnerships with structures similar to ours, including Plains All American Pipeline, L.P., Enterprise Products Partners L.P., Sunoco Logistics Partners L.P., Enbridge Energy Partners, L.P., Blueknight Energy Partners, L.P. and Magellan Midstream Partners, L.P. Our ability to compete could be harmed by numerous factors, including:
| • | price competition; |
| • | the perception that another company can provide better service; |
| • | a reluctance to contract with us due to SemGroup’s bankruptcy filing; and |
| • | the availability of alternative supply points, or supply points located closer to the operations of our customers. |
Some of our competitors have greater financial, managerial and other resources than we do, and control substantially more storage or transportation capacity than we do. Our competitors may expand their assets or operations, creating additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, transportation and storage systems or marketing operations in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers.
In addition, SemGroup owns midstream assets and is not limited in its ability to compete with us. If we are unable to compete with services offered by other midstream enterprises, including SemGroup, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Restrictions in our revolving credit facility could adversely affect our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
We have entered into a revolving credit facility which limits our ability to, among other things:
| • | incur additional debt; |
| • | make cash distributions on, or redeem or repurchase, units; |
| • | make certain investments and acquisitions; |
| • | incur certain liens or permit them to exist; |
| • | enter into certain transactions with affiliates; |
| • | merge or consolidate with another company or otherwise engage in a change of control; and |
| • | transfer or otherwise dispose of assets. |
Our revolving credit facility also contains covenants requiring us to maintain certain financial ratios.
The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of this facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.
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Our future debt may limit our flexibility to obtain financing and pursue business opportunities.
We entered into a $150.0 million senior secured revolving credit agreement effective December 11, 2011, which includes a $75.0 million sub-limit for the issuance of letters of credit. At December 31, 2011, we had no outstanding borrowings on the revolving credit facility and had $22.6 million outstanding in letters of credit. Our future debt could have important consequences to us, including the following:
| • | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; |
| • | our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt; |
| • | we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and |
| • | our flexibility in responding to changing business and economic conditions may be limited. |
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms or at all.
Our access to credit markets may be limited, which may adversely impact our liquidity.
We may require additional capital from outside sources from time to time. Our ability to arrange financing or renew existing facilities, along with the cost of such capital, is dependent upon a number of variables, including:
| • | general economic, financial and business conditions; |
| • | industry specific conditions; |
| • | credit availability from banks and other financial institutions; |
| • | investor confidence in us; |
| • | our cash flow and adjusted EBITDA levels; |
| • | competitive, legislative and regulatory matters; and |
| • | provisions of tax and securities laws that may impact raising capital. |
In addition, volatility in the capital markets may adversely affect our ability to access any available borrowing capacity under our new revolving credit facility. Our access to these funds is dependent on the ability of the lenders to meet their funding obligations under this revolving credit facility. Lenders may not be able to meet their funding commitments if they experience shortages of capital and liquidity, resulting in a reduction of our available borrowing capacity.
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The credit profile of SemGroup could adversely affect our credit rating, which could increase our borrowing costs or hinder our ability to raise capital.
The credit profile of SemGroup may be a factor considered in credit evaluations of us. This is because SemGroup, through our general partner, controls our business activities, including our cash distribution policy, acquisition strategy and business risk profile. If we seek a credit rating in the future, our credit rating may be adversely affected by the credit profile of SemGroup and its 2008 bankruptcy filing, because the rating agencies may consider SemGroup’s ownership interest in and control of us and the strong operational links between SemGroup and us. If SemGroup’s credit profile adversely affects our credit rating, it would increase our cost of borrowing or hinder our ability to access financing in the capital markets, which could impair our ability to grow our business or make cash distributions to our unitholders.
Our general partner is an obligor under, and subject to a pledge related to, SemGroup’s credit agreement. In the event SemGroup is unable to meet its obligations under that agreement, or is declared bankrupt, SemGroup’s lenders may gain control of our general partner or, in the case of bankruptcy, our partnership may be dissolved.
Our general partner is an obligor under, and all of its assets and SemGroup’s ownership interest in it are subject to, a lien related to SemGroup’s credit agreement. In the event SemGroup is unable to satisfy its obligations under the credit agreement and the lenders foreclose on their collateral, the lenders will own our general partner and all of its assets, which include the general partner interest in us and our incentive distribution rights. In such event, the lenders would control our management and operations. Moreover, in the event SemGroup becomes insolvent or is declared bankrupt, our general partner may be deemed insolvent or declared bankrupt as well. Under the terms of our partnership agreement, the bankruptcy or insolvency of our general partner will cause a dissolution of our partnership.
We may not be able to renew or replace expiring storage contracts.
We have significant exposure to market risk at the time our existing storage contracts expire and are subject to renegotiation and renewal. As of December 31, 2011, the weighted average remaining tenor of our existing portfolio of firm storage contracts was approximately 4 years. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
| • | the level of existing and new competition to provide storage services to our markets; |
| • | the macroeconomic factors affecting crude oil storage economics for our current and potential customers; |
| • | the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets; |
| • | the extent to which the customers in our markets are willing to contract on a long-term basis; and |
| • | the effects of federal, state or local regulations on the contracting practices of our customers. |
Any failure to extend or replace a significant portion of our existing contracts, or extend or replace them at comparable rates, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
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We depend on a limited number of customers for a substantial portion of our revenues. The loss of, or a material nonpayment or nonperformance by, any of these key customers could adversely affect our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
We rely on a limited number of customers for a substantial portion of our revenues. Gavilon, L.L.C., Vitol SA and BP Canada Energy Marketing Corporation each accounted for more than 10% of our total revenue for the year ended December 31, 2011, at approximately 20%, 18% and 16%, respectively. Gavilon, L.L.C. accounted for more than 10% of our total revenue for the year ended December 31, 2010, at approximately 42%. We may be unable to negotiate extensions or replacements of contracts with our key customers on favorable terms. In addition, some of these key customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The loss of all, or even a portion, of the contracted volumes of these key customers as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties, including our hedge counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial and operating results.
Although we attempt to assess the creditworthiness of our customers, suppliers and contract counterparties, including the counterparties to our hedging arrangements, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, there can be no assurance that our counterparties will perform or adhere to existing or future contractual arrangements.
The procedures and policies we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, in some cases, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our procedures and policies prove to be inadequate, our financial and operational results may be negatively impacted.
Some of our counterparties may be highly leveraged or have limited financial resources and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. For example, we have certain hedging arrangements with MF Global Inc. with a balance of approximately $0.2 million as of December 31, 2011. An affiliate of MF Global Inc. has recently filed for bankruptcy. In addition, volatility in commodity prices might have an impact on many of our counterparties which, in turn, could have a negative impact on their ability to meet their obligations to us and may also increase the magnitude of these obligations.
Any material nonpayment or nonperformance by our counterparties could require us to pursue substitute counterparties for the affected operations, reduce operations or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.
Our storage operations are influenced by the overall forward market for crude oil, and certain market conditions may adversely affect our financial and operating results and, in turn, our ability to make cash distributions to our unitholders.
Our storage operations are influenced by the overall forward market for crude oil. A contango market (meaning that the price of crude oil for future delivery is higher than the current price) is associated with greater demand for crude oil storage capacity, because a party can simultaneously purchase crude oil at current prices for storage and sell at higher prices for future delivery. A backwardated market (meaning that the price of crude oil for future delivery is lower than
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the current price) is associated with lower demand for crude oil storage capacity because a party can capture a premium for prompt delivery of crude oil rather than storing it for future sale. A prolonged backwardated market, or other adverse market conditions, could have an adverse impact on our ability to negotiate favorable prices under new or renewing storage contracts, which could have an adverse impact on our storage revenues. Finally, higher absolute levels of crude oil prices increase the costs of financing and insuring crude oil in storage, which negatively affects storage economics. As a result, the overall forward market for crude oil may have an adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Our risk management policy governing our marketing activities cannot eliminate all risks associated with the marketing of crude oil, and we cannot ensure that employees of our general partner will fully comply with the policy at all times, both of which could impact our financial and operational results and, in turn, our ability to make cash distributions to our unitholders.
We have in place a risk management policy that seeks to establish limits for marketing exposure by requiring that we restrict net open positions (i.e., positions that are not fully hedged as to commodity price risk) to specified levels. Our risk management policy has restrictive terms with respect to acquiring and holding physical inventory, futures contracts and derivative products. These policies and practices, however, cannot eliminate all risks. Derivatives contracts and contracts for the future delivery of crude oil expose us to the risk of non-delivery under product purchase contracts or the failure of gathering and transportation systems to supply us with crude oil. Any event that disrupts our anticipated physical supply of crude oil could create a net open position that would expose us to risk of loss resulting from price changes.
Moreover, we are exposed to price movements on products that are not hedged, including certain of our inventory, such as linefill, which must be maintained to operate our pipelines and gathering system. We are also exposed to certain price risks that cannot be readily hedged, such as price risks for “basis differentials.” Basis differentials can be created to the extent that we hold or sell crude oil of a grade or quality, at a location or at a time that differs from the specific delivery terms with respect to grade or quality, time or location of the applicable offsetting agreement or derivative instrument. If this occurs, we may not be able to use the physical or derivative commodity markets to fully hedge our price risk. Our exposure to price risks could impact our operational and financial results and our ability to make cash distributions to our unitholders.
We are also subject to the risk that employees of our general partner involved in our marketing operations may not comply at all times with our risk management policy. Even with management oversight, we cannot ensure that all violations of the risk management policy, particularly if deception or other intentional misconduct is involved, will be detected prior to our businesses being materially affected.
Our hedging arrangements could reduce our quarterly or annual profits or increase our cash obligations, which could negatively impact our financial position or our ability to make cash distributions to our unitholders.
We hedge our exposure to price fluctuations for our crude oil marketing activities by utilizing physical purchase and sale agreements, futures contracts traded on the NYMEX, options contracts or over-the-counter transactions. We could experience material fluctuations in our quarterly or annual results of operations as a result of marking our hedging positions to market. In addition, to the extent these hedges are entered into on a public exchange or in the over-the-counter market, we may be required to post margin or provide collateral, which could result in material cash obligations.
Laws regulating derivatives established under the Dodd-Frank Act, and the regulations being promulgated thereunder, could adversely affect our ability to manage business and financial risks by reducing the availability of, and increasing our cost of using, derivative instruments as hedges against fluctuating commodity prices and interest rates.
The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, establishes a new regulatory framework for derivative instruments, including a requirement that certain transactions be cleared on a
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derivatives clearing organization and traded on an exchange or a swap execution facility, and a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or “CFTC”, federal regulators of banks and other financial institutions, or the prudential regulators, and the SEC to promulgate the rules implementing the new law, which are scheduled for final adoption during 2012. Until these regulations are adopted, effective and implemented in practice, we cannot determine what impact the new regulatory framework will have on our business.
At present, we are contractually required to post collateral with clearing brokers with respect to substantially all of our commitments and potential obligations under our hedging instruments. Depending on the final regulations adopted by the CFTC, the prudential regulators and the SEC, we may be subject to a margin requirement that will cause us to post collateral in excess of present levels. Such a requirement may increase our costs and decrease our profitability. Moreover, our counterparties may also be required to post margin on our transactions and comply with minimum capital requirements, which could result in additional costs being passed on to us, thereby decreasing our profitability.
The Dodd-Frank Act permits the CFTC to set position limits in derivative instruments. Our counterparties may be subject to these position limits, which may reduce our ability to enter into hedging transactions with these counterparties. In addition, the Dodd-Frank Act may also require the counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty. These changes might not only increase costs, but could also reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and potentially increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to make cash distributions to our unitholders. Increased volatility may make us less attractive to certain types of investors.
An increase in interest rates could impact demand for our storage capacity and cause the market price of our common units to decline.
There is a financing cost for a storage capacity user to own crude oil while it is stored. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user in addition to the commodity cost of the crude oil in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing crude oil for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.
In addition, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partner interests. Reduced demand for our common units resulting from investors seeking other, more favorable, investment opportunities may cause the trading price of our common units to decline.
From time to time, we are involved in litigation, claims and other proceedings which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
From time to time, we are involved in litigation, claims and other proceedings relating to the conduct of our business including, but not limited to, claims related to the operation of our assets, the services we provide to our customers and our marketing activities, as well as claims relating to environmental and regulatory matters. For example, SemGroup is involved in several proceedings relating to its bankruptcy and plan of reorganization. An adverse ruling in these proceedings could have a material adverse effect on us. The uncertainties of litigation and the uncertainties related to the collection of insurance and indemnification coverage make it difficult to accurately predict the ultimate financial effect of these claims. If we are unsuccessful in defending a claim or elect to settle a claim, we could incur material costs that could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Additionally, our insurance coverage may be insufficient to cover adverse judgments against us.
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Our business involves many hazards and operational risks, some of which may not be covered by insurance.
Leaks and other releases of crude oil are possible in our operations. Other possible operating risks include the breakdown or failure of equipment, information systems or processes; the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, or construction or manufacturing defects); operator error; labor disputes; disputes with interconnected facilities and carriers; and catastrophic events such as natural disasters, fires, explosions, acts of terrorism and other similar events, many of which are beyond our control.
These risks could result in substantial losses due to personal injury or loss of life, severe damage to, and destruction of, property and equipment and pollution or other environmental damage, and may result in curtailment or suspension of our related operations. We are not fully insured against all risks incident to our business. In addition, as a result of market conditions, premiums for our insurance could increase significantly. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. If a significant accident or event occurs that is not fully insured, it could adversely affect our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Even if a significant accident or event is covered by insurance, we may still have responsibility for applicable deductibles, and in addition, the proceeds of any such insurance may not be paid in a timely manner. With a few limited exceptions, our customers have not agreed to indemnify us for losses arising from a release of crude oil, and we may instead be required to indemnify our customers in the event of a release or other incident.
Adverse developments in our existing areas of operation could adversely impact our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Our operations are focused on gathering, transporting, storing and marketing crude oil and are principally located in the Mid-Continent and Rocky Mountain regions of the United States. As a result, our business, results of operations, financial condition and ability to make cash distributions to our unitholders depend upon the demand for our services in these regions. Due to our current lack of diversification in industry type and geographic location, adverse developments in our current segment of the midstream industry, or our existing areas of operation, could have a significantly greater impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders than they would if our operations were more diversified.
Our operations could be adversely affected if third-party pipelines or other facilities interconnected to our facilities become partially or fully unavailable.
Our facilities connect to other pipelines or facilities, some of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. These pipelines and other facilities may become unavailable, or available only at a reduced capacity. If any of these third-party pipelines or facilities becomes unable to transport the crude oil transported or stored by us, our business, results of operations, financial condition and ability to make cash distributions to our unitholders could be adversely affected.
We intend to grow our business, in part, by constructing new assets which may not result in the anticipated revenue increases.
One of the ways we intend to grow our business is through the construction of new assets. The construction of additions or modifications to our existing systems and of new assets involves numerous regulatory, environmental, political and legal uncertainties beyond our control. Any such construction projects, including our planned expansions of our storage terminal in Cushing and our Platteville facility, may not be completed on schedule, at their budgeted cost or at all. Revenues may not increase immediately upon the completion of a particular project, or we may construct facilities to capture anticipated future growth that does not materialize. In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way to capitalize on attractive expansion opportunities, or the cost of obtaining new rights-of-way may exceed our expectations.
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A key component of our growth strategy is to make acquisitions. We may not be able to make acquisitions on economically acceptable terms, which may limit our ability to grow. In addition, any acquisition that we pursue will involve risks that may adversely affect our business.
Our ability to grow in the future will depend, in part, on our ability to make acquisitions that result in an increase in the cash generated from our operations. We may be unable to make accretive acquisitions, including acquisitions from SemGroup or third parties, because we are unable to identify attractive acquisition candidates, negotiate acceptable purchase terms, or obtain financing for these acquisitions on economically acceptable terms or because we are outbid by competitors. If we are unable to successfully acquire new businesses or assets, our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.
Any acquisition that we pursue will involve potential risks, including
| • | performance from the acquired businesses or assets that is below the forecasts we used in evaluating the acquisition; |
| • | a significant increase in our indebtedness and working capital requirements; |
| • | the inability to timely and effectively integrate the operations of recently acquired businesses or assets; |
| • | the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets prior to our acquisition; |
| • | risks associated with operating in lines of business that are distinct and separate from our historical operations; |
| • | loss of customers or key employees from the acquired businesses; and |
| • | the diversion of management’s attention from other business concerns. |
Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from our acquisitions, realize other anticipated benefits or meet the debt service requirements of any debt incurred in connection with such acquisitions.
We do not own all of the land on which our pipelines and other facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and other facilities have been constructed and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
We are subject to regulation by multiple governmental agencies, which could adversely impact our business, results of operations and financial condition.
Our business activities are subject to regulation by multiple federal, state and local governmental agencies. Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions, or changes in
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regulation, or discovery of existing but unknown compliance issues. Additional proposals and proceedings that affect the midstream industry are regularly considered by Congress, as well as by state legislatures and federal and state regulatory commissions, agencies and courts. We cannot predict when or whether any such proposals may become effective or the magnitude of the impact changes in laws and regulations may have on our business. However, additions to the regulatory burden on our industry generally increase our cost of doing business and affect our profitability.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies, or a change in policy by those agencies, could result in increased regulation of our assets, which could affect existing costs and rates.
Intrastate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by FERC. However, the distinction between FERC-regulated interstate pipeline transportation on the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination. The classification and regulation of our crude oil pipelines are subject to change based on future determinations by FERC, federal courts, Congress or regulatory commissions, courts or legislatures in the states in which we operate.
Our Kansas and Oklahoma gathering pipeline system carries crude oil owned by us and by third parties. We own all of the crude oil shipped on our pipeline system across state lines. We believe that the pipeline segments on which we provide service to third parties and the services we provide to third parties on the gathering pipeline system meet the traditional tests that FERC has used to determine that the pipeline services provided are not in interstate commerce. We believe that the pipeline segments on which we transport only crude oil owned by us should not be subject to regulation by FERC under the ICA, or that these pipeline segments would qualify for waiver from FERC’s regulatory requirements, if applicable. However, we cannot provide assurance that FERC will not in the future, either at the request of other entities or on its own initiative, determine that some or all of our Kansas and Oklahoma gathering pipeline system and the services we provide on that system are within its jurisdiction, or that such a determination would not adversely affect our results of operations. If some or all of the gathering system were subject to FERC jurisdiction, and not otherwise exempt from any applicable regulatory requirements, for that portion of the gathering pipeline system we would be required to file a tariff with FERC, and if our tariff rates were subject to protest, provide a cost justification for the transportation rate subject to protest and provide service to all potential shippers without undue discrimination. In addition, if the services we provide on any segment(s) of our gathering system become regulated by FERC under the ICA, our services could be subject to a protest and/or complaint before FERC. If FERC were to determine, in response to a complaint, that our rates are unjust and unreasonable, we could be required to pay reparations and refunds dating to two years before the filing of the complaint. Furthermore, if in the future our services become subject to state regulation, they could be subject to a protest and/or complaint before a state commission with jurisdiction.
We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.
Our pipeline facilities are subject to regulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration (the “PHMSA”), pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as amended by the Pipeline Safety Improvement Act of 2002, and reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The PHMSA has adopted regulations requiring hazardous liquid pipeline operators to develop and implement integrity management programs for pipeline segments that, in the event of a leak or rupture, could affect “high consequence areas,” such as high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 expired on September 30, 2010 but operated under a continuing resolution that expired on March 4, 2011. The reauthorization of the Pipeline Safety Act being considered by Congress could result in new and more costly compliance requirements. Current regulations require operators of covered pipelines to:
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| • | perform on-going assessments of pipeline integrity on a recurring frequency schedule; |
| • | identify and characterize applicable potential threats to pipeline segments that could impact a high consequence area; |
| • | improve data collection, integration and analysis; |
| • | repair and remediate the pipeline as necessary; and |
| • | implement preventive and mitigating actions. |
In addition, states have adopted regulations similar to existing DOT regulations for intrastate hazardous liquid pipelines. We currently estimate that we will incur an aggregate cost of approximately $2.9 million during 2011 and 2012 to implement necessary pipeline integrity management program testing along certain segments of our pipelines required by existing DOT and state regulations. This estimate may not include all costs of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. At this time, we cannot predict the ultimate cost of compliance with these regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. Following the initial round of testing and repairs, we will continue our pipeline integrity testing programs on an on-going basis to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of our pipelines and, consequently, result in a reduction in our revenue and cash flows from shutting down our pipelines during the pendency of such repairs or upgrades.
The PHMSA adopted regulations requiring hazardous liquid pipelines that use supervisory control and data acquisition systems and have at least one controller and control room to develop written control room management procedures by August 1, 2011 and implement those procedures no later than February 1, 2013, although the PHMSA has proposed to accelerate the deadline by which the procedures must be implemented. Implementing these procedures could cause us to incur unanticipated operating expenditures.
The PHMSA has amended its pipeline safety regulations so that the pipeline safety requirements will apply, effective October 1, 2011, to all rural low-stress hazardous liquids pipelines, regardless of diameter, except for certain gathering lines.
We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental laws or regulations or an accidental release of hazardous substances, crude oil or wastes into the environment.
Our operations are subject to federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws include, for example:
| • | federal and comparable state laws that impose obligations related to air emissions; |
| • | federal and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from our facilities; |
| • | federal and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which our hazardous substances have been transported for disposal; and |
| • | federal and comparable state laws that regulate discharges of wastewater from our facilities, require spill protection planning and preparation and set requirements for other actions for protection of waters. |
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Failure to comply with these laws and regulations, or newly adopted laws or regulations, may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Claims pursued under certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or petroleum products have been disposed or otherwise released. Provisions also exist that may require remediation or other compensation to pay for damages to natural resources. Moreover, it is not uncommon for individuals to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, crude oil or waste products in the environment.
There is an inherent risk of incurring environmental costs and liabilities in connection with our operations due to our handling of crude oil, air emissions and water discharges related to our operations and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities for environmental cleanup and restoration costs, claims made by individuals for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. We may not be able to recover all or any of these costs from insurance and fines or penalties paid for compliance violations, whether alleged or proven, will not be covered by insurance.
Climate change legislation and related regulatory initiatives could result in increased operating costs and reduced demand for our services.
In December 2009, the U.S. EPA, published its findings that emissions of carbon dioxide, methane and other GHGs, present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that require a reduction in emissions of GHGs from motor vehicles and trigger permit review for GHG emissions from certain large stationary sources. In addition, the EPA issued a final rule, effective in December 2009, requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., beginning in 2011 for emissions occurring in 2010. Further, in March 2010, the EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA’s GHG Reporting Rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year will be required to report annual GHG emissions to EPA, with the first report due on March 31, 2012. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the crude oil we gather, transport, store or otherwise handle in connection with our services.
The United States Congress has been considering legislation to reduce such emissions and almost one half of the states, either individually or through multi-state regional initiatives, have already begun implementing legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or GHG cap and trade programs. In addition, both President Obama and the Administrator of the EPA have repeatedly indicated their preference for comprehensive legislation to address this issue and create the framework for a clean energy economy, with the Obama Administration supporting an emission allowance system. Depending on the particular program and scope thereof, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations or could face additional taxes and a higher cost of doing business. Although we would not be impacted to a greater degree than other similarly situated midstream energy service providers, a stringent GHG control program could have an adverse effect on our cost of doing business and could reduce demand for crude oil.
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The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHGs could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for crude oil, resulting in a decrease in the demand for our services.
Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil production in our areas of operation, which could adversely impact our business and results of operations.
An increasing percentage of crude oil production is being developed from unconventional sources such as shales. These reservoirs require hydraulic fracturing completion processes to release the crude oil from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate crude oil production. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, including on water quality and public health, with results of the study anticipated to be available by late 2012. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. For instance, the U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that act. Sponsors of bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers and service providers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating and compliance costs and additional regulatory burdens that could make it more difficult or commercially impracticable to perform hydraulic fracturing, delaying the development of unconventional resources from shale formations which are not commercial without the use of hydraulic fracturing. The Department of Energy, at the direction of the President, is also studying hydraulic fracturing in order to provide recommendations and identify best practices and other steps to enhance companies’ safety and environmental performance in their hydraulic fracturing operations. In addition, several states have already passed, or are considering, legislation that is intended to regulate hydraulic fracturing. We cannot predict what effect such legislation will have on the production of crude oil in our areas of operation. The imposition of additional regulations and permit requirements could lead to delays or increased operating costs for crude oil producers. A reduction in the production of crude oil in our areas of operation could have an adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
The loss of key employees could significantly reduce our ability to execute strategies.
Much of our future success depends on the continued availability and service of key personnel, including the executive team and skilled employees in technical and staff positions. All of the employees required to conduct and support our operations are employed by SemGroup. Experienced personnel in the midstream industry are in high demand and competition for their talents is high. We depend on current and new key officers and employees to meet the challenges and complexities of our businesses. If any such officers or employees resign, or become unable to continue in their present roles and are not adequately replaced, or if we are unable to fill currently vacant positions, our business operations could be materially adversely affected. There can be no assurance that we will continue to attract and retain key personnel.
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Because SemGroup’s and our predecessor’s financial statements reflect fresh-start reporting adjustments made upon SemGroup’s emergence from bankruptcy, and because of the effects of the transactions that became effective pursuant to SemGroup’s plan of reorganization, financial information in our current and future financial statements will not be comparable to financial information from prior periods.
In connection with SemGroup’s bankruptcy reorganization, it adopted fresh-start reporting effective as of the close of business on November 30, 2009, in accordance with the Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, “Reorganizations.” Its adoption of fresh-start reporting resulted in it becoming a new entity for financial reporting purposes. As required by fresh-start reporting, SemGroup’s assets and liabilities, including those contributed to us, were adjusted to reflect fair value at November 30, 2009. In addition to fresh-start reporting, SemGroup’s and our financial statements reflect the effects of all of the transactions implemented through SemGroup’s plan of reorganization. Accordingly, our financial statements for periods ending on or prior to November 30, 2009 are not comparable with our financial statements for periods ending subsequent to November 30, 2009. Furthermore, the estimates and assumptions used to implement fresh-start reporting are inherently subject to significant uncertainties and contingencies beyond our control. Accordingly, we cannot provide assurance that the estimates, assumptions, and values reflected in our valuations will be realized, and our actual results could vary materially.
The threat or attack of terrorists aimed at our facilities could adversely affect our business.
Since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack that may target our facilities, those of our customers or those of certain other pipelines, could have a material adverse effect on our businesses. In addition, any governmental body mandated actions to prepare for, or protect against, potential terrorist attacks could require us to expend money or modify our operations.
Risks Inherent in an Investment in Us
SemGroup owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. SemGroup and our general partner will have conflicts of interest with us and may favor their own interests to your detriment.
SemGroup owns and controls our general partner, as well as appoints all of the officers and directors of our general partner, some of whom will also be officers and/or directors of SemGroup. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, SemGroup. Therefore, conflicts of interest may arise between SemGroup and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of SemGroup over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
| • | Neither our partnership agreement nor any other agreement requires SemGroup to pursue a business strategy that favors us. |
| • | SemGroup is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us. |
| • | Our general partner is allowed to take into account the interests of parties other than us, such as SemGroup, in resolving conflicts of interest. |
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| • | All of the officers and certain of the directors of our general partner are also officers and/or directors of SemGroup and will owe fiduciary duties to SemGroup. The officers of our general partner also devote significant time to the business of SemGroup and will be compensated by SemGroup accordingly. |
| • | The limited partner interests that SemGroup owns will permit it to effectively control any vote of our limited partners. SemGroup is entitled to vote its units in accordance with its own interests, which may be contrary to your interests. |
| • | Our partnership agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. |
| • | Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval. |
| • | Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders. |
| • | Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units. |
| • | Our general partner determines which costs incurred by it are reimbursable by us. |
| • | Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period. |
| • | Our partnership agreement permits us to classify up to $25 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights. |
| • | Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf. |
| • | Our general partner intends to limit its liability regarding our contractual and other obligations. |
| • | Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units. |
| • | Our general partner controls the enforcement of the obligations that it and its affiliates owe to us. |
| • | Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
| • | Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the Conflicts Committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations. |
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Our general partner interest or the control of our general partner or SemGroup may be transferred to a third party without unitholder consent. A change in control of SemGroup or our general partner could result in a change in our business strategy that does not favor our unitholders or could otherwise have a material adverse effect on our business.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of SemGroup to transfer all or a portion of its ownership interest in our general partner to a third party, directly or indirectly. In addition, SemGroup may be acquired by a third party, or a third party may otherwise obtain control of SemGroup, which would result in such third party gaining control of our general partner. Proposals to acquire SemGroup may be received by SemGroup, and SemGroup may enter into an agreement with respect to such a transaction, at any time. Third parties may also seek to gain control of SemGroup through other methods, including tender offers, consent solicitations or proxy contests.
Any new owner of SemGroup, our general partner or our general partner interest would be in a position to replace our management and the board of directors of our general partner with its own designees, in each case without the consent of unitholders, and may change our business strategy. For example, any new owner may choose not to pursue our strategy to grow our business through acquisitions from SemGroup and may choose not to pursue business opportunities that our unitholders may consider beneficial to us. In addition, a new owner may sell our assets or the assets of SemGroup to third parties. Further, any such change in ownership may result in a change in our capitalization and may expose us to increased or unanticipated liabilities and costs, some of which may be material. The failure of SemGroup to own our general partner would be an event of default under our credit facility. Any of these changes, and any other changes as a result of a change in ownership of SemGroup, our general partner or our general partner interest, may lower the trading price of our common units and may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Pursuant to the SemGroup credit facility, our general partner and Rose Rock Midstream Holdings, LLC, the sole member of our general partner, pledged the general partner interest in us and the membership interests in our general partner, respectively. In the event that SemGroup is unable to meet its obligations under its credit facility, the lenders may foreclose on the pledged collateral and thereby acquire control of our general partner and its 2.0% general partner interest in us.
Pursuant to the SemGroup credit facility, our general partner and Rose Rock Midstream Holdings, LLC, the sole member of our general partner, entered into a pledge agreement with the lenders thereunder. Pursuant to the pledge agreement, the assets of Rose Rock Midstream Holdings, LLC and our general partner, including Rose Rock Midstream Holdings, LLC’s membership interest in our general partner our general partner’s general partner interest in us, are subject to a security interest in favor of such lenders. In the event that SemGroup is unable to meet its obligations under its credit facility and the lenders foreclose on the pledged collateral, the lenders will own our general partner and all of its assets, including its 2.0% general partner interest in us and all of our incentive distribution rights. In such event, the lenders would control our management and operations.
SemGroup is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
SemGroup is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, SemGroup may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while SemGroup may offer us the opportunity to buy additional assets from it, it will be under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed.
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Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
| • | how to allocate corporate opportunities among us and its affiliates; |
| • | whether to exercise its limited call right; |
| • | how to exercise its voting rights with respect to the units it owns; |
| • | whether to exercise its registration rights; |
| • | whether to elect to reset target distribution levels; and |
| • | whether to consent to any merger or consolidation of the partnership or amendment to the partnership agreement. |
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner, and also restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the fiduciary duties of our general partner and restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:
| • | provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in, or not opposed to, the interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; |
| • | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith; |
| • | provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and |
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| • | provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is: |
| (a) | approved by the Conflicts Committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; |
| (b) | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates; |
| (c) | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| (d) | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the Conflicts Committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Cost reimbursements due to SemGroup and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to you. The amount and timing of such reimbursements will be determined by our general partner.
Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by SemGroup and our general partner in managing and operating us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursements to SemGroup and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.
If you are not an Eligible Holder, your common units may be subject to redemption.
We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are limited partners whose (a) federal income tax status is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or an analogous regulatory body and (b) nationality, citizenship or other related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our general partner with the advice of counsel. If you are not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, your units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
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Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
Our partnership agreement requires that we distribute all of our available cash to our unitholders, and we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or in our new revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional bank borrowings (under our revolving credit facility or otherwise) or other debt to finance our growth strategy will result in increased interest expense which, in turn, may impact the available cash that we have to distribute to our unitholders.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen by SemGroup. Furthermore, if our unitholders become dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Even if holders of our common units are dissatisfied, they will not be able to remove our general partner without its consent.
The unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding limited partner units voting together as a single class is required to remove our general partner. SemGroup and its affiliates own 58.1% of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
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Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units without the prior approval of the board of directors of our general partner, cannot vote on any matter. Because SemGroup is an affiliate of, and appoints all the members of the board of directors of, our general partner, this provision ensures that SemGroup will maintain voting control with respect to decisions affecting the partnership.
Our general partner’s incentive distribution rights may be transferred to a third party without unitholder consent.
Our general partner may transfer all or a portion of its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner will not have the same incentive to grow our partnership and increase our quarterly distributions to unitholders over time as it would have had if it had retained ownership of its incentive distribution rights.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our general partner may elect to cause us to issue to it additional common and general partner units in connection with a resetting of the target distribution levels related to its incentive distribution rights without the approval of the Conflicts Committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the four most recently completed fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution levels, it will be entitled to receive the number of common units equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain its general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution
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levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.
Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. SemGroup owns approximately 16.5% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), SemGroup will own approximately 58.1% of our outstanding common units.
We may issue additional units without your approval, which would dilute your existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
| • | our existing unitholders’ proportionate ownership interest in us will decrease; |
| • | the amount of cash available for distribution on each unit may decrease; |
| • | because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; |
| • | the ratio of taxable income to distributions may increase; |
| • | the relative voting strength of each previously outstanding unit may be diminished; and |
| • | the market price of the common units may decline. |
SemGroup may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
At December 31, 2011, SemGroup holds an aggregate of 1,389,709 common units and 8,389,709 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, we have agreed to provide SemGroup with certain registration rights which may facilitate the sale by SemGroup of its common and subordinated units into the public markets.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
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| • | we were conducting business in a state but had not complied with that particular state’s partnership statute; or |
| • | your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. |
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
An increase in interest rates may cause the market price of our common units to decline.
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
We will incur increased costs as a result of being a publicly traded partnership.
Prior to our initial public offering in December 2011, we had no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. Public companies are required to comply with the rules and regulations of the SEC and the securities exchanges, as well as laws enacted by Congress such as the Sarbanes-Oxley Act of 2002. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors within one year following the date that our common units were initially listed on the NYSE, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We estimate that we will incur $1.9 million of incremental costs per year associated with being a publicly traded partnership. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
As a limited partnership, we are not required to, and do not intend to, have a majority of independent directors on our general partner’s board of directors or establish a compensation committee or a nominating and corporate
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governance committee, as is required for other NYSE-listed entities. Accordingly, unitholders will not have the same protections afforded to investors in other entities, including most corporations, that are subject to all of the NYSE corporate governance requirements.
If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
Upon the completion of our initial public offering, we became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. We prepare our consolidated financial statements in accordance with generally accepted accounting principles (“GAAP”), but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 for our fiscal year ending December 31, 2012. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
If we are deemed to be an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
Our assets consist of our ownership interests in our operating subsidiaries. If our assets are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or contract rights so as to fall outside of the definition of investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property from or to our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.
Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. If we were taxed as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
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Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or (“IRS”), were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state purposes, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible, in certain circumstances, for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were to be treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were to be treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
In Texas, we will be subject to an entity-level tax on any portion of our income that is generated in Texas in the prior year. Imposition of any such additional taxes on us or an increase in the existing tax rates would reduce the cash available for distribution to our unitholders.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
If we were to be subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes would reduce the cash available for distribution to you. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Recently, the Obama administration and members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships which, if enacted, may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.
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Your share of our income will be taxable to you for U.S. federal income tax purposes even if you do not receive any cash distributions from us.
Because you will be treated as a partner to whom we will allocate taxable income, which could be different in amount than the cash we distribute, your allocable share of our taxable income will be taxable to you, which may require the payment of federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that result from that income.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
Tax gain or loss on the disposition of your common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount you realize will include your share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.
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We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury regulations were to be issued, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. As a result, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and our allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
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The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if special relief from the IRS was not available) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We will initially own property or conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns.
Compliance with, and changes in, tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.
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Item 1B. Unresolved Staff Comments
None.
For information regarding legal proceedings, see the discussion under the captions “Bankruptcy matters”, “Other matters”, “Environmental” and “Blueknight claim” in Note 7 of our consolidated financial statements beginning on page F-1 of this Form 10-K, which information is incorporated by reference into this Item 3.
Item 4. Mine Safety Disclosures
Not applicable.
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Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common units commenced trading on the New York Stock Exchange on December 9, 2011, under the ticker symbol “RRMS.” Prior to December 9, 2011, there was no established public trading market for our common units. As of January 31, 2012, there were 28 holders of record of our common units. Rose Rock Midstream Holdings, LLC, a wholly-owned subsidiary of SemGroup, owns all of our subordinated units. Our general partner owns all of our general partner interests and incentive distribution rights. The high and low closing sales prices of our common units (New York Stock Exchange composite transactions) during the fourth quarter of 2011 (commencing December 9, 2011) were $20.90 and $19.00, respectively. At January 31, 2012, there were 8,428,922 common units and 8,389,709 subordinated units issued and outstanding.
Use of Proceeds from Sale of Securities
On December 14, 2011, we completed our initial public offering of 7,000,000 common units at a price of $20.00 per unit. The common units sold in the initial public offering were registered with the SEC pursuant to a registration statement on Form S-1, as amended (File No. 333-176260), initially filed on August 12, 2011, and such registration statement was declared effective on December 8, 2011. Barclays Capital Inc., Citigroup Global Markets Inc. and Deutsche Bank Securities Inc. acted as representatives of the underwriters participating in the initial public offering and as book-running managers of the initial public offering.
We received net proceeds from the initial public offering of approximately $127.1 million after deducting from gross proceeds approximately $12.9 million for underwriting discounts and commissions, structuring fees and offering expenses. On December 14, 2011, we made a cash distribution to SemGroup of all of the net proceeds from the offering in consideration of SemGroup’s contribution to us of all of the limited and general partner interests in SemCrude, L.P.
Performance Graph
Set forth below is a line graph comparing the cumulative total unitholder return on our common units with the cumulative total return of the S&P 500 Stock Index and the Alerian MLP Infrastructure Index (AMZIX) for the period from December 9, 2011 to December 31, 2011. AMZIX is a liquid, midstream-focused subset of the Alerian MLP index, comprised of 25 energy infrastructure master limited partnerships.
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The above performance graph and related information shall not be deemed “soliciting material” or be deemed to be “filed” with the SEC, nor shall such information be incorporated by reference into any filing under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.
Cash Distributions
The cash distribution for the fourth quarter of 2011 was $0.0670 per unit. This prorated amount corresponds to our minimum quarterly cash distribution of $0.3625 per unit, or $1.45 on a per unit annualized basis. The proration period began on December 15, 2011, immediately after the closing date of Rose Rock’s initial public offering and continued through December 31, 2011. The distribution was paid on February 13, 2012 to all unitholders of record on February 3, 2012.
We intend to pay a minimum quarterly distribution of $0.3625 per unit to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors.
Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:
| • | first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.3625, plus any arrearages from prior quarters; |
| • | second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.3625; and |
| • | third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.416875. |
If cash distributions to our unitholders exceed $0.416875 per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” The following table summarizes the incentive distribution levels:
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| Marginal Percentage Interest in Distributions |
||||||||||||||||||||
| Total Quarterly Distribution Per Unit Target Amount |
Unitholders | General Partner Interest |
Incentive Distribution Rights |
|||||||||||||||||
| Minimum Quarterly Distribution |
$ | 0.3625 | 98.0 | % | 2.0 | % | — | |||||||||||||
| First Target Distribution |
above $ | 0.3625 | up to $ | 0.416875 | 98.0 | % | 2.0 | % | — | |||||||||||
| Second Target Distribution |
above $ | 0.416875 | up to $ | 0.453125 | 85.0 | % | 2.0 | % | 13.0 | % | ||||||||||
| Third Target Distribution |
above $ | 0.453125 | up to $ | 0.54375 | 75.0 | % | 2.0 | % | 23.0 | % | ||||||||||
| Thereafter |
above $ | 0.54375 | 50.0 | % | 2.0 | % | 48.0 | % | ||||||||||||
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:
| • | Our cash distribution policy is subject to a condition under our revolving credit facility that we may not make a cash distribution if an event of default then exists or would result therefrom. If we were to be unable to satisfy this condition, we would be prohibited from making cash distributions notwithstanding our cash distribution policy. |
| • | Our general partner will have the authority to establish reserves for the proper conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must believe that the determination is in, or not opposed to, our interests. |
| • | While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended prior to the conversion of the subordinated units into common units without the approval of our public common unitholders other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by SemGroup) after the subordinated units have converted into common units. SemGroup owns our general partner and currently owns approximately 16.5% of our outstanding common units and all of our outstanding subordinated units, or 58.1% of all of the common and subordinated units currently outstanding. |
| • | Even if our cash distribution policy is not modified or revoked, the amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. |
| • | Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. |
| • | We may lack sufficient cash to pay distributions to our unitholders for a number of reasons, including as a result of increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. |
| • | If and to the extent our distributable cash flow materially declines, we may elect to reduce our quarterly cash distributions in order to service or repay our debt or fund expansion capital expenditures. |
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Item 6. Selected Financial Data
Selected Historical Consolidated Financial and Operating Data
The following table provides selected historical consolidated financial data as of and for the periods shown. The balance sheet data as of December 31, 2011, 2010, 2009 and as of November 30, 2009 and the statement of income data for the years ended December 31, 2011 and 2010, the month ended December 31, 2009, the eleven months ended November 30, 2009, and the year ended December 31, 2008 have been derived from our audited financial statements for those dates and periods. The balance sheet data as of December 31, 2008 and 2007 and the statement of income data for the year ended December 31, 2007 have been derived from our unaudited financial statements for those dates and period. The selected financial data provided below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included in this Form 10-K.
On July 22, 2008, SemGroup and certain of its subsidiaries, including the entities comprising our predecessor, filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Later during 2008, certain other U.S. subsidiaries filed petitions for reorganization. During the reorganization process, SemGroup filed a plan of reorganization with the court, which was confirmed on October 28, 2009. 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 emerged from bankruptcy on November 30, 2009.
Balance sheet data in the following table as of December 31, 2011, 2010 and 2009 and statement of income data for the years ended December 31, 2011 and 2010 and the month ended December 31, 2009, are subsequent to SemGroup’s emergence from bankruptcy. Balance sheet and statement of income data as of all other dates and for all other periods are prior to SemGroup’s emergence from bankruptcy. As described in Note 3 of our consolidated financial statements, we applied fresh-start reporting as of November 30, 2009. As a result, our financial data subsequent to emergence from bankruptcy is not comparable to that of our financial data prior to emergence from bankruptcy.
The consolidated financial data included in the following table include the activity of our predecessor prior to November 29, 2011. The predecessor included SemCrude, L.P. (“SemCrude”), a wholly-owned subsidiary of SemGroup Corporation (exclusive of SemCrude’s ownership interests in SemCrude Pipeline, L.L.C., which holds a 51% ownership interest in the White Cliffs Pipeline), and Eaglwing, L.P. (“Eaglwing”), which is also a wholly-owned subsidiary of SemGroup Corporation. Although Eaglwing is not currently conducting any revenue-generating operations and was not contributed to Rose Rock, it was included in the financial statements of the predecessor because it previously conducted operations that were similar to those of SemCrude. Eaglwing did not have a significant impact on these financial statements during the periods from 2009 through 2011, other than a $3.4 million reorganization items loss recorded to the statement of income for the eleven months ended November 30, 2009. Subsequent to November 29, 2011, the consolidated financial data included in the following table include the accounts of Rose Rock and its controlled subsidiaries, which include SemCrude, L.P.
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 (loss) and of adjusted EBITDA to net income (loss) and net cash provided by (used in) operating activities, their most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” beginning on page 54.
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| Subsequent to Emergence | Prior to Emergence | |||||||||||||||||||||||
| Year Ended December 31, 2011 |
Year Ended December 31, 2010 |
Month Ended December 31, 2009 |
Eleven
Months Ended November 30, 2009 |
Year Ended December 31, 2008 |
Year Ended December 31, 2007 |
|||||||||||||||||||
| (in thousands, except per unit and operating data) | ||||||||||||||||||||||||
| Statement of income data: |
||||||||||||||||||||||||
| Total revenues |
$ | 431,321 | $ | 208,081 | $ | 10,615 | $ | 237,487 | $ | 3,029,784 | $ | 3,176,097 | ||||||||||||
| Operating income (loss) |
$ | 24,861 | $ | 22,974 | $ | 1,022 | $ | 32,713 | $ | (991,520 | ) | $ | (392,965 | ) | ||||||||||
| Reorganization items gain (loss) |
$ | — | $ | — | $ | — | $ | 99,936 | $ | (94,424 | ) | $ | — | |||||||||||
| Net income (loss) |
$ | 23,235 | $ | 23,477 | $ | 1,285 | $ | 132,552 | $ | (1,088,045 | ) | $ | (393,841 | ) | ||||||||||
| Net income per common unit (basic and diluted) (1) |
$ | 0.06 | N/A | N/A | N/A | N/A | N/A | |||||||||||||||||
| Net income per subordinated unit (basic and diluted) (1) |
$ | 0.06 | N/A | N/A | N/A | N/A | N/A | |||||||||||||||||
| Distributions paid per unit (February 13, 2012) |
$ | 0.06 | N/A | N/A | N/A | N/A | N/A | |||||||||||||||||
| Statement of cash flows data: |
||||||||||||||||||||||||
| Net cash provided by (used in): |
||||||||||||||||||||||||
| Operating activities |
$ | 49,419 | $ | 31,492 | $ | 2,088 | $ | 58,931 | $ | (56,164 | ) | $ | (246,782 | ) | ||||||||||
| Investing activities |
$ | (31,631 | ) | $ | (16,723 | ) | $ | (2,047 | ) | $ | (34,490 | ) | $ | 58,836 | $ | (37,719 | ) | |||||||
| Financing activities |
$ | (8,382 | ) | $ | (14,466 | ) | $ | (1,056 | ) | $ | (23,426 | ) | $ | (27,931 | ) | $ | 266,068 | |||||||
| Other financial data: |
||||||||||||||||||||||||
| Adjusted gross margin |
$ | 64,269 | $ | 62,230 | $ | 4,364 | $ | 57,079 | $ | (1,661,071 | ) | $ | 388,666 | |||||||||||
| Adjusted EBITDA |
$ | 34,798 | $ | 38,564 | $ | 1,864 | $ | (40,412 | ) | $ | (2,020,618 | ) | $ | 260,045 | ||||||||||
| Capital expenditures |
$ | 31,635 | $ | 16,732 | $ | 2,047 | $ | 34,530 | $ | 76,192 | $ | 37,856 | ||||||||||||
| Balance sheet data (at period end): |
||||||||||||||||||||||||
| Property, plant and equipment, net |
$ | 276,246 | $ | 260,048 | $ | 253,706 | $ | 252,477 | $ | 82,346 | $ | 80,357 | ||||||||||||
| Total assets |
$ | 445,494 | $ | 357,131 | $ | 297,949 | $ | 298,799 | $ | 771,797 | $ | 1,340,110 | ||||||||||||
| Long-term debt |
$ | 87 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
| Partners’ capital (deficit) |
$ | 304,854 | $ | 289,988 | $ | 280,214 | $ | 280,370 | $ | (1,136,417 | ) | $ | (131,744 | ) | ||||||||||
| Operating data: |
||||||||||||||||||||||||
| Cushing storage capacity (MMBbls as of period end) |
4.7 | 4.7 | 3.9 | |||||||||||||||||||||
| Percent of Cushing capacity contracted (as of period end) |
95 | % | 95 | % | 100 | % | ||||||||||||||||||
| Transportation volumes (average Bpd) |
29,900 | 26,600 | 31,800 | |||||||||||||||||||||
| Marketing volumes (average Bpd) |
13,200 | 15,800 | 2,100 | |||||||||||||||||||||
| Unloading/Platteville volumes (average Bpd) |
32,400 | 25,800 | 21,700 | |||||||||||||||||||||
| (1) | Calculated on net income subsequent to initial public offering on December 14, 2011. |
We have experienced changes in our business during the periods shown in the table above which significantly limit the comparability of the financial data. Such changes include, but are not limited to, our bankruptcy during 2008 (which resulted in significant professional fee expenses) and our emergence from the bankruptcy during 2009 (which resulted in reorganization gains).
Non-GAAP Financial Measures
We define adjusted gross margin as total revenues minus cost of products sold and unrealized gain (loss) on derivatives. We define adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation and amortization and any non-cash adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities.
Adjusted gross margin and adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provide useful information to investors in assessing our financial condition and results of operations.
Operating income (loss) is the GAAP measure most directly comparable to adjusted gross margin, and net income (loss) and cash provided by (used in) operating activities are the GAAP measures most directly comparable to adjusted EBITDA. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measures. These non-GAAP financial measures have important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider adjusted gross margin and adjusted EBITDA in isolation or as substitutes for analysis of our results as reported under GAAP. Because adjusted gross margin and adjusted EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
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Management compensates for the limitation of adjusted gross margin and adjusted EBITDA as analytical tools by reviewing the comparable GAAP measures, understanding the differences between adjusted gross margin and adjusted EBITDA, on the one hand, and operating income (loss), net income (loss) and net cash provided by (used in) operating activities, on the other hand, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.
The following table presents a reconciliation of: (i) adjusted gross margin to operating income (loss), and (ii) adjusted EBITDA to net income (loss) and net cash provided by (used in) operating activities, the most directly comparable GAAP financial measures, on a historical basis for each of the periods indicated.
| Subsequent to Emergence | Prior to Emergence | |||||||||||||||||||||||
| Year Ended December 31, 2011 |
Year Ended December 31, 2010 |
Month Ended December 31, 2009 |
Eleven Months Ended November 30, 2009 |
Year Ended December 31, 2008 |
Year Ended December 31, 2007 |
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| (Unaudited; in thousands) | ||||||||||||||||||||||||
| Reconciliation of operating income (loss) to adjusted gross margin: |
||||||||||||||||||||||||
| Operating income (loss) |
$ | 24,861 | $ | 22,974 | $ | 1,022 | $ | 32,713 | $ | (991,520 | ) | $ | (392,965 | ) | ||||||||||
| Add: |
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| Unrealized (gain) loss on derivatives |
(787 | ) | 763 | (282 | ) | (254 | ) | (1,005,261 | ) | 643,458 | ||||||||||||||
| Operating expense |
18,973 | 20,398 | 1,536 | 15,614 | 298,874 | 62,179 | ||||||||||||||||||
| General and administrative expense |
9,843 | 7,660 | 1,270 | 5,813 | 33,841 | 69,134 | ||||||||||||||||||
| Depreciation and amortization expense |
11,379 | 10,435 | 818 | 3,193 | 2,995 | 6,860 | ||||||||||||||||||
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| Adjusted gross margin |
$ | 64,269 | $ | 62,230 | $ | 4,364 | $ | 57,079 | $ | (1,661,071 | ) | $ | 388,666 | |||||||||||
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| Reconciliation of net income (loss) to adjusted EBITDA: |
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| Net income (loss) |
$ | 23,235 | $ | 23,477 | $ | 1,285 | $ | 132,552 | $ | (1,088,045 | ) | $ | (393,841 | ) | ||||||||||
| Add: |
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| Interest expense |
1,823 | 482 | 43 | 1,699 | 2,907 | 3,589 | ||||||||||||||||||
| Income tax expense (benefit) |
— | — | — | — | — | — | ||||||||||||||||||
| Depreciation and amortization |
11,379 | 10,435 | 818 | 3,193 | 2,995 | 6,860 | ||||||||||||||||||
| Unrealized (gain) loss on derivatives |
(787 | ) | 763 | (282 | ) | (254 | ) | (1,005,261 | ) | 643,458 | ||||||||||||||
| (Gain) loss on impairment or sale of assets |
64 | 67 | — | (40 | ) | 2,901 | 49 | |||||||||||||||||
| Non-cash reorganization items |
— | — | — | (24,682 | ) | 63,896 | — | |||||||||||||||||
| Provision for uncollectible accounts receivable |
(916 | ) | 3,340 | — | — | (11 | ) | (70 | ) | |||||||||||||||
| Adjustments for plan effects and fresh start accounting |
— | — | — | (152,880 | ) | — | — | |||||||||||||||||
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| Adjusted EBITDA |
$ | 34,798 | $ | 38,564 | $ | 1,864 | $ | (40,412 | ) | $ | (2,020,618 | ) | $ | 260,045 | ||||||||||
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| Reconciliation of net cash provided by (used in) operating activities to adjusted EBITDA: |
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| Net cash provided by operating activities |
$ | 49,419 | $ | 31,492 | $ | 2,088 | $ | 58,931 | $ | (56,164 | ) | $ | (246,782 | ) | ||||||||||
| Less: |
||||||||||||||||||||||||
| Changes in assets and liabilities, net of acquisitions and deconsolidated subsidiaries |
16,444 | (6,590 | ) | 267 | 101,042 | 1,967,361 | (503,238 | ) | ||||||||||||||||
| Add: |
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| Interest expense |
1,823 | 482 | 43 | 1,699 | 2,907 | 3,589 | ||||||||||||||||||
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| Adjusted EBITDA |
$ | 34,798 | $ | 38,564 | $ | 1,864 | $ | (40,412 | ) | $ | (2,020,618 | ) | $ | 260,045 | ||||||||||
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are a growth-oriented Delaware limited partnership formed in 2011 by SemGroup to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We are engaged in the business of crude oil gathering, transportation, storage and marketing in Colorado, Kansas, Montana, North Dakota, Oklahoma and Texas. We serve areas that are experiencing strong production growth and drilling activity through our exposure to the Bakken Shale in North Dakota and Montana, the DJ Basin and the Niobrara Shale in the Rocky Mountain region, and the Granite Wash and the Mississippian oil trend in the Mid-Continent region. The majority of our assets are strategically located in or connected to the Cushing, Oklahoma crude oil marketing hub. Cushing is the designated point of delivery specified in all NYMEX crude oil futures contracts and is one of the largest crude oil marketing hubs in the United States. We believe that our connectivity in Cushing and our numerous interconnections with third-party pipelines, refineries and storage terminals provide our customers with the flexibility to access multiple points for the receipt and delivery of crude oil.
For the years ended December 31, 2011 and 2010, approximately 70% and 85% of our adjusted gross margin, respectively, was generated from fee-based services or fixed-margin transactions. For a definition of adjusted gross margin and a reconciliation of adjusted gross margin to operating income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Selected Historical Consolidated Financial and Operating Data—Non-GAAP Financial Measures” beginning on page 54.
How We Evaluate Our Operations
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include financial measures, including adjusted gross margin, operating expenses and adjusted EBITDA, and operating data, including contracted storage capacity and transportation, marketing and unloading volumes.
Adjusted Gross Margin
We view adjusted gross margin as an important performance measure of the core profitability of our operations, as well as our operating performance as compared to that of other companies in our industry, without regard to financing methods, historical cost basis, capital structure or the impact of fluctuating commodity prices. We define adjusted gross margin as total revenues minus cost of products sold and unrealized gain (loss) on derivatives. Adjusted gross margin allows us to make a meaningful comparison of the operating results between our fee-based activities, which do not involve the purchase or sale of crude oil, and our fixed-margin and marketing operations, which do. In particular, adjusted gross margin provides a way to compare the actual transportation fee received under fixed-fee contracts with the effective transportation fee realized through a fixed-margin transaction. In addition, adjusted gross margin allows us to make a meaningful comparison of the results of our fixed-margin and marketing operations across different commodity price environments because it measures the spread between the product sales price and cost of products sold. See “Selected Historical Consolidated Financial and Operating Data—Non-GAAP Financial Measures” beginning on page 54.
Operating Expenses
Our management seeks to maximize the profitability of our operations in part by minimizing operating expenses. These expenses are comprised of salary and wage expense, utility costs, insurance premiums, taxes and other operating costs, some of which are independent on the volumes we handle.
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The current high levels of crude oil exploration, development and production activities are increasing competition for personnel and equipment. This increased competition is placing upward pressure on the prices we pay for labor, supplies and miscellaneous equipment. To the extent we are unable to procure necessary services or offset higher costs, our operating results will be negatively impacted.
Adjusted EBITDA
We define adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation and amortization and any non-cash adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities. We use adjusted EBITDA as a supplemental performance and liquidity measure to assess:
| • | our operating performance as compared to that of other companies in our industry, without regard to financing methods, historical cost basis, capital structure or the impact of fluctuating commodity prices; |
| • | the ability of our assets to generate sufficient cash flow to make distributions to our partners; |
| • | our ability to incur and service debt and fund capital expenditures; and |
| • | the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities. |
Contracted Storage Capacity and Transportation, Marketing and Unloading Volumes
In our Cushing storage operations, we charge our customers a fee for storage capacity provided, regardless of actual usage. On our Kansas and Oklahoma system, we provide transportation services on a fee basis or pursuant to fixed-margin transactions, but in either case, the adjusted gross margin we generate is dependent on the volumes of crude oil transported (if on a fee basis) or purchased and sold (if pursuant to a fixed-margin transaction). We refer to these volumes, in the aggregate, as transportation volumes. Similarly, on our Kansas and Oklahoma system and through our Bakken Shale operations, we conduct marketing activities involving the purchase and sale of crude oil or related derivative contracts. We refer to the crude oil volumes purchased and sold in our marketing operations as marketing volumes. Finally, at our Platteville truck unloading facility, we charge our customers a fee based on the volumes unloaded. We refer to these as unloading volumes.
How We Generate Adjusted Gross Margin
We generate adjusted gross margin by providing fee-based services, by entering into fixed-margin transactions and through marketing activities. Revenues from our fee-based services are included in service revenue, and revenues from our fixed-margin and marketing activities are included in product revenue.
The following table shows the adjusted gross margin generated by our fee-based services, our fixed-margin transactions and our marketing activities for the year ended December 31, 2011 (in thousands):
| Storage | Transportation | Marketing Activities |
Other (1) | Total | ||||||||||||||||
| Revenues |
$ | 24,381 | $ | 14,833 | $ | 386,252 | $ | 5,855 | $ | 431,321 | ||||||||||
| Less: Costs of products sold, exclusive of depreciation and amortization |
— | — | (366,265 | ) | — | (366,265 | ) | |||||||||||||
| Less: Unrealized (gain) loss on derivatives |
— | — | (787 | ) | — | (787 | ) | |||||||||||||
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| Adjusted gross margin |
$ | 24,381 | $ | 14,833 | $ | 19,200 | $ | 5,855 | $ | 64,269 | ||||||||||
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| (1) | This category includes fee-based services such as unloading and ancillary storage terminal services. |
57
The following table shows the adjusted gross margin generated by our fee-based services, our fixed-margin transactions and our marketing activities for the year ended December 31, 2010 (in thousands):
| Storage | Transportation | Marketing Activities |
Other (1) | Total | ||||||||||||||||
| Revenues |
$ | 29,496 | $ | 18,448 | $ | 154,927 | $ | 5,210 | $ | 208,081 | ||||||||||
| Less: Costs of products sold, exclusive of depreciation and amortization |
— | — | (146,614 | ) | — | (146,614 | ) | |||||||||||||
| Less: Unrealized (gain) loss on derivatives |
— | — | 763 | — | 763 | |||||||||||||||
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| Adjusted gross margin |
$ | 29,496 | $ | 18,448 | $ | 9,076 | $ | 5,210 | $ | 62,230 | ||||||||||
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| (1) | This category includes fee-based services such as unloading and ancillary storage terminal services. |
Fee-Based Services
We charge a capacity or volume-based fee for the unloading, transportation and storage of crude oil and related ancillary services. Our fee-based services include substantially all of our operations in Cushing and Platteville 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 years ended December 31, 2011 and 2010, approximately 56% and 80% of our adjusted gross margin, respectively, was generated by providing fee-based services to customers.
Fixed-Margin Transactions
We purchase crude oil from a producer or supplier at a designated receipt point at an index price less a transportation fee, and simultaneously sell an identical volume of crude oil at a designated delivery point to the same party at the same index price, thereby locking in a fixed margin that is in effect economically equivalent to a transportation fee. We refer to these arrangements as “fixed-margin” or “buy/sell” transactions. These fixed-margin transactions account for a portion of the adjusted gross margin we generate on our Kansas and Oklahoma pipeline system and through our Bakken Shale operations. For the years ended December 31, 2011 and 2010, approximately 14% and 5% of our adjusted gross margin, respectively, was generated through fixed-margin transactions.
Marketing Activities
We conduct marketing activities by purchasing crude oil for our own account from producers, aggregators and traders and selling crude oil to traders and refiners. Our marketing activities account for a portion of the adjusted gross margin we generate on our Kansas and Oklahoma pipeline system and through our Bakken Shale operations. For the years ended December 31, 2011 and 2010, approximately 30% and 15% of our adjusted gross margin, respectively, was generated through marketing activities.
We mitigate the commodity price exposure of our crude oil marketing operations by limiting our net open positions through (i) the concurrent purchase and sale of like quantities of crude oil to create “back-to-back” transactions intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered or (ii) derivative contracts. All of our marketing activities are subject to our comprehensive risk management policy, which establishes limits to manage risk and mitigate financial exposure.
More specifically, we utilize futures and swap contracts to manage our exposure to market changes in commodity prices to protect our adjusted gross margin on our purchased crude oil. As we purchase inventory from suppliers, we may establish a fixed or variable margin with future sales by:
58
| • | selling a like quantity of crude oil for future physical delivery to create an effective back-to-back transaction; or |
| • | entering into futures and swaps contracts on the NYMEX or over-the-counter markets. |
Items Affecting the Comparability of Our Financial Results
Our future results of operations may not be comparable to our historical results of operations for the reasons described below:
| • | On July 22, 2008, SemGroup and certain of its U.S. subsidiaries, including our predecessor, filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. On November 30, 2009, SemGroup emerged from bankruptcy as a newly reorganized company. As a result, we applied fresh- start reporting on November 30, 2009. We recorded individual assets and liabilities based on their fair values at November 30, 2009, using the assistance of a valuation advisor to determine the values of certain assets. As a result of these factors (the bankruptcy and fresh-start reporting) and other factors, our post-emergence financial statements are not comparable with our pre-emergence financial statements for the first eleven months of 2009. Due to the effect of the bankruptcy on our financial statements, we present comparisons of our results of operations for (i) the year ended December 31, 2010 versus the eleven months ended November 30, 2009 and (ii) December 2009 versus the average of the eleven months ended November 30, 2009. |
| • | Prior to December 2010, our Bakken Shale operations were conducted through a different SemGroup subsidiary, so they are not reflected in our historical results of operations prior to that month. |
| • | We estimate that we will incur $1.5 million of incremental general and administrative expenses resulting from SemGroup’s allocation of additional overhead to us, primarily relating to financial reporting and legal expenses and corporate services. In addition, we expect to incur further incremental general and administrative expenses of approximately $1.9 million as a result of operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; and director and officer insurance expenses. None of these incremental general and administrative expenses are reflected in our historical consolidated financial statements. |
| • | Our business model changed dramatically from 2008 to 2009 as we shifted away from trading activities toward a business heavily weighted in fee-based services and fixed-margin transactions. Until July 2008, we engaged in significant crude oil marketing activities and substantially all of our revenues and costs of goods sold were associated with the purchase and sale of crude oil. During SemGroup’s bankruptcy in 2008, we no longer had access to the working capital necessary to continue this crude oil marketing business, and we abandoned this business model in or about July 2008. |
| • | We have begun to ship more crude oil under fixed-margin arrangements and less crude oil under fee-based transportation contracts on our Kansas and Oklahoma system. We believe that owning the volumes in the system, as opposed to shipping volumes owned by others, allows us to manage the system more efficiently and provides us with greater operational flexibility. In addition, we have found that some of our customers prefer to ship or receive crude oil under fixed-margin arrangements. The increase in fixed-margin arrangements and decrease in fee-based contracts has resulted in an increase in product revenue and a decrease in service revenues for the year ended December 31, 2011 compared to prior periods. We do not believe that the increase in fixed-margin arrangements has resulted in any material change to the adjusted gross margin we generate as compared to that generated under our prior fee-based contracts. |
59
General Trends and Outlook
We expect our business to continue to be affected by the key trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.
Commodity Prices
Our fee-based operations have minimal direct exposure to commodity prices. With respect to our fixed-margin and marketing operations, increases or decreases in commodity prices will directly affect revenues generated and the costs of products sold, but generally have significantly lesser impact on adjusted gross margin. As a result, our fixed-margin and marketing operations are generally not directly affected by the absolute level of crude oil prices, but are affected by overall levels of the supply of and demand for crude oil and relative fluctuations in market-related indices. However, to the extent that we do not enter into “back-to-back” purchase and sale transactions, our marketing operations have direct exposure to commodity price volatility.
All of our operations are indirectly affected by commodity prices. Crude oil prices have been highly volatile in the past, and we expect that volatility to continue. The demand for storage capacity results in part from our customers’ desire to have the ability to take advantage of profit opportunities created by volatility in the price of crude oil. The lack of a contango market for crude oil (when the prices for future deliveries are higher than the current prices) negatively affects the demand for our storage assets because the margin between crude oil futures prices relative to spot prices may not cover the cost of purchasing crude oil and holding it in storage. On the other hand, increased volatility in crude oil prices increases the value of these assets by increasing the option value of crude oil stored. Further, the higher the level of absolute crude oil prices, the higher the costs of financing and insuring crude oil in storage, which negatively affects storage economics. Changes in crude oil prices may also indirectly impact the volumes of crude oil we gather, transport and market.
Recently, Cushing has experienced a shortfall in takeaway pipeline capacity, which has been cited as a principal reason for the decline in the WTI Index price used at Cushing compared to other crude oil price indices. We believe that if and when any of several planned takeaway pipeline expansion projects are completed, this price differential will narrow and Cushing will remain the predominant benchmarking and transportation hub for crude oil in the United States.
Interest Rates
The credit markets recently have experienced near-record lows in interest rates. If the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. If this occurs, interest rates on floating rate credit facilities and future offerings in the debt capital markets could be higher than current levels, causing our financing costs to increase accordingly.
In addition, there is a financing cost for the storage capacity user to carry the cost of the inventory while it is stored in the facility. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user as well as the commodity cost of the crude oil in inventory. The higher the financing cost, the lower the margin that will be left over from the price spread that was intended to be captured. Accordingly, a significant increase in interest rates could impact the demand for storage capacity independent of other market fundamentals.
Our implied distribution yield is a product of our unit price and the level of our cash distributions. It is determined by dividing our annual cash distribution by our common unit price. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes.
60
Results of Operations
| Predecessor Historical Subsequent to Emergence |
Predecessor Historical Prior to Emergence |
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| Year Ended December 31, 2011 |
Year Ended December 31, 2010 |
Month Ended December 31, 2009 |
Eleven
Months Ended November 30, 2009 |
Year Ended December 31, 2008 |
Year Ended December 31, 2007 |
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| Statement of income data: | (in thousands, except per unit data) | |||||||||||||||||||||||
| Revenues, including revenues from affiliates: |
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| Product |
$ | 395,301 | $ | 158,308 | $ | 6,724 | $ | 197,203 | $ | 3,010,645 | $ | 3,152,563 | ||||||||||||
| Service |
35,801 | 49,408 | 3,891 | 40,281 | 19,129 | 22,521 | ||||||||||||||||||
| Other |
219 | 365 | — | 3 | 10 | 1,013 | ||||||||||||||||||
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| Total Revenues |
431,321 | 208,081 | 10,615 | 237,487 | 3,029,784 | 3,176,097 | ||||||||||||||||||
| Expenses, including expenses from affiliates: |
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| Costs of products sold, exclusive of depreciation and amortization shown below |
366,265 | 146,614 | 5,969 | 180,154 | 3,685,594 | 3,430,889 | ||||||||||||||||||
| Operating |
18,973 | 20,398 | 1,536 | 15,614 | 298,874 | 62,179 | ||||||||||||||||||
| General and administrative |
9,843 | 7,660 | 1,270 | 5,813 | 33,841 | 69,134 | ||||||||||||||||||
| Depreciation and amortization |
11,379 | 10,435 | 818 | 3,193 | 2,995 | 6,860 | ||||||||||||||||||
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| Total expenses |
406,460 | 185,107 | 9,593 | 204,774 | 4,021,304 | 3,569,062 | ||||||||||||||||||
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| Operating income (loss) |
24,861 | 22,974 | 1,022 | 32,713 | (991,520 | ) | (392,965 | ) | ||||||||||||||||
| Other expenses (income): |
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| Interest expense |
1,823 | 482 | 43 | 1,699 | 2,907 | 3,589 | ||||||||||||||||||
| Other expense (income), net |
(197 | ) | (985 | ) | (306 | ) | (1,602 | ) | (806 | ) | (2,713 | ) | ||||||||||||
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| Total other expenses (income) |
1,626 | (503 | ) | (263 | ) | 97 | 2,101 | 876 | ||||||||||||||||
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| Income (loss) before reorganization items |
$ | 23,235 | $ | 23,477 | $ | 1,285 | $ | 32,616 | $ | (993,621 | ) | $ | (393,841 | ) | ||||||||||
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| Reorganization items gain (loss), including expenses allocated from affiliates |
— | — | — | 99,936 | (94,424 | ) | — | |||||||||||||||||
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| Net income (loss) |
$ | 23,235 | $ | 23,477 | $ | 1,285 | $ | 132,552 | $ | (1,088,045 | ) | $ | (393,841 | ) | ||||||||||
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| Net income per common unit (basic and diluted) (2) |
$ | 0.06 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
| Net income per subordinated unit (basic and diluted) (2) |
$ | 0.06 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
| Distribution paid per unit |
$ | 0.06 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
| Adjusted gross margin (1) |
$ | 64,269 | $ | 62,230 | $ | 4,364 | $ | 57,079 | $ | (1,661,071 | ) | $ | 388,666 | |||||||||||
| Adjusted EBITDA (1) |
$ | 34,798 | $ | 38,564 | $ | 1,864 | $ | (40,412 | ) | $ | (2,020,618 | ) | $ | 260,045 | ||||||||||
| (1) | For a definition of adjusted gross margin, adjusted EBITDA and a reconciliation to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data – Non-GAAP Financial Measures” beginning on page 54. |
| (2) | Calculated on net income subsequent to initial public offering on December 14, 2011. |
ASC 845-10-15, “Nonmonetary Transactions,” requires certain transactions – those where inventory is purchased from a customer then resold to the same customer – to be presented in the income statement on a net basis, resulting in a reduction of revenue and costs of products sold by the same amount, but has no effect on operating income (loss). However, changes in the level of such purchase and sale activity between periods can have an effect on the comparison between those periods.
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2011 versus 2010
Revenue
Revenue increased in 2011 to $431 million from $208 million in 2010.
| Subsequent to Emergence | ||||||||
| Year Ended December 31, 2011 |
Year Ended December 31, 2010 |
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| (in thousands) | ||||||||
| Gross product revenue |
$ | 1,083,089 | $ | 556,518 | ||||
| Nonmonetary transaction adjustment |
(688,575 | ) | (397,447 | ) | ||||
| Net unrealized gain (loss) on derivatives |
787 | (763 | ) | |||||
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| Product revenue |
395,301 | 158,308 | ||||||
| Service revenue |
35,801 | 49,408 | ||||||
| Other |
219 | 365 | ||||||
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| Total revenue |
$ | 431,321 | $ | 208,081 | ||||
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Gross product revenue increased in 2011 to $1.1 billion from $557 million in 2010. The increase was primarily due to an increase in the average volume sold to 1.0 million barrels per month at an average sales price of $92 per barrel for 2011 from an average volume sold of 0.6 million barrels per month at an average sales price of $79 per barrel for 2010. The increase in volumes sold was attributable to newly contracted fixed-margin volumes as well as the shift, which began in the fourth quarter of 2010, in our Kansas and Oklahoma operations from fee-based transportation agreements, under which the volumes transported are not included in volumes sold and therefore do not increase gross product revenue, to fixed-margin transactions, under which the volumes transported are included in volumes sold and therefore increase gross product revenue. The increase in fixed-margin volumes was partially offset by fewer marketing volumes sold.
Gross product revenue was reduced by $689 million and $397 million during the 2011 and 2010, respectively, in accordance with ASC 845-10-15.
Service revenue decreased in 2011 to $36 million from $49 million for 2010. The decrease in service revenue was primarily due to a shift in our Kansas and Oklahoma operations to fixed-margin transactions, which are not included in service revenues, from fee-based agreements, which are included in service revenues.
Costs of Products Sold
Costs of products sold increased in 2011 to $366 million from $147 million in 2010. Costs of products sold reflected reductions of $689 million and $397 million in 2011 and 2010, respectively, in accordance with ASC 845-10-15. Costs of products sold increased due to the increase in the average barrels sold per month described above, combined with an increase in the average per barrel cost of crude oil to $88 for 2011 from $77 for 2010.
Adjusted Gross Margin
We define adjusted gross margin as total revenues minus costs of products sold and unrealized gain (loss) on derivatives. (See adjusted gross margin tables on pages 57 and 58.) Adjusted gross margin increased in 2011 to $64 million from $62 million in 2010, due to:
| • | an increase in adjusted gross margin from our marketing operations resulting from a higher spread between the purchase and sale price for volumes of crude oil sold, as the excess of our average sales price per barrel over our average purchase cost per barrel increased to approximately $4 from approximately $2, partially offset by lower marketing volumes sold; |
62
| • | an increase in adjusted gross margin from our Platteville operations resulting from increased unloading volumes of approximately 2.4 million barrels; |
| • | a decrease in adjusted gross margin from our storage operations due to a decrease in our average storage rate by $0.08 per barrel for 2011 from 2010, as well as the expiration of the recognition of approximately $4 million of deferred revenues attributable to a prepaid contract in January 2011, partially offset by an increase of approximately 4.5 to 4.8 million barrels in contracted storage capacity; and |
| • | a decrease in adjusted gross margin attributable to our fee-based and fixed-margin transportation operations due to an increase in short-haul volumes, leading to a decrease in average transportation rates. |
Operating Expense
Operating expenses decreased in 2011 to $19 million from $20 million during 2010, due primarily to an allowance for uncollectable accounts receivable of $3.3 million recorded during 2010 and to the recovery during 2011 of $1.1 million of these accounts receivable. This decrease was partially offset increased operating expenses, primarily employment expenses of $0.9 million, field expenses of $0.6 million and outside services of $0.5 million. During 2010, we assumed certain operations in the Bakken Shale area that had previously been managed by SemCanada Crude Company, which is subsidiary of SemGroup.
General and Administrative Expense
General and administrative expense increased in 2011 to $10 million from $8 million in 2010, primarily due to an increase in incentive compensation.
Depreciation
Depreciation increased in 2011 to $11 million from $10 million in 2010. The increase was attributable to the completion of additional storage capacity at Cushing and Platteville.
Year Ended December 31, 2010 Versus Eleven Months Ended November 30, 2009
Our results of operations for the year ended December 31, 2010 were generally affected by the additional month of operations included in the year ended December 31, 2010 when compared to the eleven months ended November 30, 2009. This is in addition to any other factors described below.
Revenue
Revenue decreased in 2010 to $208 million from $237 million in the eleven months ended November 30, 2009.
63
| Subsequent to Emergence |
Prior to Emergence | |||||||
| Year Ended December 31, 2010 |
Eleven Months Ended November 30, 2009 |
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| (in thousands) | ||||||||
| Gross product revenue |
$ | 556,518 | $ | 383,937 | ||||
| Nonmonetary transaction adjustment |
(397,447 | ) | (186,988 | ) | ||||
| Net unrealized gain (loss) on derivatives |
(763 | ) | 254 | |||||
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| Product revenue |
158,308 | 197,203 | ||||||
| Service revenue |
49,408 | 40,281 | ||||||
| Other |
365 | 3 | ||||||
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| Total revenue |
$ | 208,081 | $ | 237,487 | ||||
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Product revenue decreased in 2010 to $158 million from $197 million in the eleven months ended November 30, 2009. Gross product revenue prior to the ASC 845-10-15 adjustment actually increased due to an increase in the average sales price of crude oil to $79 per barrel for the year ended December 31, 2010 from $58 per barrel for the eleven months ended November 30, 2009. Associated volumes were similar for both periods. In accordance with ASC 845-10-15, gross product revenue was reduced by $397 million and $187 million in 2010 and the eleven months ended November 30, 2009, respectively. Because a larger volume of transactions were subject to netting pursuant to ASC 845-10-15, reported product revenue decreased, despite the increase in the average sales price per barrel of crude oil.
Service revenue increased in 2010 to $49 million from $40 million in the eleven months ended November 30, 2009, primarily due to the completion of additional storage expansion projects.
Costs of Products Sold
Costs of products sold decreased in 2010 to $147 million from $180 million in the eleven months ended November 30, 2009. Costs of products sold reflected reductions of $397 million and $187 million in 2010 and the eleven months ended November 30, 2009, respectively, in accordance with ASC 845-10-15. The average purchase cost of crude oil increased to $77 per barrel for the year ended December 31, 2010 from $55 per barrel for the eleven months ended November 30, 2009. Because a larger volume of transactions were subject to netting pursuant to ASC 845-10-15, reported costs of products sold decreased, despite the increase in the average purchase cost per barrel of crude oil.
Adjusted Gross Margin
Adjusted gross margin increased in 2010 to $62 million from $57 million in the eleven months ended November 30, 2009, due to:
| • | an increase of approximately $9 million in adjusted gross margin from our storage operations due to an increase in contracted storage capacity to approximately 4.5 million barrels as of December 31, 2010 from approximately 3.9 million barrels as of November 30, 2009; |
| • | a decrease of approximately $1 million in adjusted gross margin from transportation due to a reduction in truck transportation revenue received from SemCanada Crude Company. For a period in 2010, SemCanada Crude Company assumed responsibility for their own trucking; |
| • | a decrease of approximately $8 million in adjusted gross margin from marketing due to approximately $3.9 million realized from a contango strategy in the eleven months ended November 30, 2009 that was not continued in 2010; and |
| • | an increase of approximately $4 million in adjusted gross margin from terminalling and unloading fees. |
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Operating Expense
Operating expense increased in 2010 to $20 million from $16 million in the eleven months ended November 30, 2009. The increase was due primarily to bad debt expense of $3.3 million related to a customer that declared bankruptcy.
General and Administrative Expense
General and administrative expense increased in 2010 to $8 million from $6 million in the eleven months ended November 30, 2009. The increase was due primarily to the recognition of incentive compensation and restricted stock expense in general and administrative expense. During bankruptcy, certain costs related to the governance of our predecessor were classified as reorganization items. After emergence, such costs were classified as general and administrative expenses.
Depreciation and Amortization
Depreciation and amortization expense increased in 2010 to $10 million from $3 million in the eleven months ended November 30, 2009. This increase was due primarily to higher depreciation as a result of higher fixed asset values which were recorded as part of fresh-start reporting.
December 2009 Versus Average of Eleven Months Ended November 30, 2009
We desire to provide a meaningful comparison of our results of operations for December 2009 to those for the eleven months ended November 30, 2009. In order to make this comparison as useful as possible, we have based the comparison on the monthly average for the eleven months ended November 30, 2009. In this way, any significant changes from the average can be identified and become the subject of explanation.
Revenue
Revenue in December 2009 was approximately 51% less than the average revenue for the eleven months ended November 30, 2009.
| Subsequent to Emergence |
Prior to Emergence |
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| Month Ended December 31, 2009 |
Average Eleven Months Ended November 30, 2009 |
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| (in thousands) | ||||||||
| Gross product revenue |
$ | 22,509 | $ | 34,904 | ||||
| Nonmonetary transaction adjustment |
(16,067 | ) | (16,999 | ) | ||||
| Net unrealized gain (loss) on derivatives |
282 | 23 | ||||||
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| Product revenue |
6,724 | 17,928 | ||||||
| Service revenue |
3,891 | 3,662 | ||||||
| Other |
— | — | ||||||
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| Total revenue |
$ | 10,615 | $ | 21,590 | ||||
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Product revenue in December 2009 was approximately 62% less than the average revenues for the eleven months ended November 30, 2009, primarily because certain marketing activities that occurred in the first eleven months of 2009 did not occur in December due to the expiration of a third-party lease.
Service revenue in December 2009 was approximately 6% more than the average revenues for the eleven months ended November 30, 2009, primarily due to completion of additional storage expansion projects.
65
Costs of Products Sold
Costs of products sold in December 2009 were approximately 64% less than the average of the costs of products sold for the eleven months ended November 30, 2009, because certain marketing activities that occurred in the first eleven months of 2009 did not occur in December, as described above.
Adjusted Gross Margin
Adjusted gross margin in December 2009 was approximately 16% less than the average adjusted gross margin for the eleven months ended November 30, 2009, due to the combination of events described in revenue and costs of products sold above.
Operating Expense
Operating expense in December 2009 was approximately 8% higher than the average operating expense for the eleven months ended November 30, 2009.
General and Administrative Expense
General and administrative expense in December 2009 was approximately 141% higher than the average general and administrative expense for the eleven months ended November 30, 2009. During bankruptcy, certain costs related to the reorganization and governance of our predecessor were classified as reorganization items. After emergence from bankruptcy, such costs were classified as general and administrative expenses.
Depreciation and Amortization
Depreciation and amortization in December 2009 was approximately three times the average depreciation and amortization for the eleven months ended November 30, 2009. The increase reflected higher depreciation as a result of higher fixed asset values which were recorded as part of fresh-start reporting.
Liquidity and Capital Resources
Our sources of liquidity may include:
| • | cash generated from operations; |
| • | borrowings under our new credit facility; and |
| • | issuances of debt and equity securities. |
We believe that the cash generated from these sources will be sufficient to allow us to distribute the minimum quarterly distribution on all of our outstanding common, subordinated and general partner units and meet our requirements for working capital and capital expenditures for the foreseeable future.
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 $26 million, $29 million and $25 million at December 31, 2011, 2010 and 2009, respectively.
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Cash Flows
Operating Activities. We experienced operating cash inflows of $49 million during the year ended 2011. Net income of $23 million included $10 million of non-cash expenses. The primary non-cash expense was $11 million of depreciation. Changes in working capital increased operating cash flows by $16 million. The primary changes to working capital were an increase to accounts payable and accrued liabilities of $67 million and a net increase in payables to affiliates of $8 million, partially offset by an increase in accounts receivable of $57 million. This was due primarily to a shift in our Kansas and Oklahoma operations from fee-based transportation agreements to fixed-margin transactions. The fixed-margin transactions involve the purchase of product at pipeline origin points and the sale of product at pipeline destination points, increasing both accounts receivable and accounts payable. The increase in accounts payable greater than the increase in accounts receivable was, in part, due to the timing of inventory purchases and sales and the timing of the related payments and collections.
We experienced operating cash inflows of $31 million during the year ended December 31, 2010. Net income of $23 million included $14 million of non-cash expenses, and we used $6 million of cash for working capital. The use of cash for working capital included a $70 million increase in accounts receivable, which was partially offset by a $48 million increase in accounts payable and accrued liabilities, due primarily to a shift in our Kansas and Oklahoma operations from fee-based transportation agreements to fixed-margin transactions. Operating cash flows also included a $17 million decrease in restricted cash. This cash had been temporarily restricted pursuant to an agreement with a customer, and this restriction expired during the year ended December 31, 2010.
We experienced operating cash inflows of $2 million during the month ended December 31, 2009. Net income of $1 million included $1 million of non-cash expenses.
We experienced operating cash inflows of $59 million during the eleven months ended November 30, 2009. Net income of $133 million included non-cash income (net of non-cash expenses) of $174 million, including a $153 million gain upon adoption of fresh-start reporting. We generated $101 million of cash from the reduction of working capital, which was due in part to the resolution of disputes with customers who had contested receivables. Many of these receivables were collected or written off during the eleven months ended November 30, 2009.
Investing Activities. Our cash outflows from investing activities related primarily to capital expenditures of $32 million for the year ended December 31, 2011, $17 million for the year ended December 31, 2010, $2 million for the month ended December 31, 2009, and $34 million for the eleven months ended November 30, 2009. These capital expenditures related primarily to the construction of storage tanks at our terminal in Cushing, Oklahoma.
Financing Activities. Upon completion of our initial public offering on December 14, 2011, we received $127 million of net offering proceeds.
Prior to the initial public offering, our cash outflows from financing activities consisted primarily of changes in our intercompany accounts with SemGroup and its other controlled subsidiaries. As described in Note 12 of our consolidated financial statements beginning on page F-1, we participated in SemGroup’s cash management program prior to our initial public offering. Under this program, cash we receive from customers was transferred to SemGroup on a regular basis, and when we remitted payments to suppliers, SemGroup transferred cash to us to cover the payments. We recorded these transactions to intercompany accounts, and the change in the intercompany accounts during each period was reported as a net cash flow from financing activities in our consolidated statements of cash flows. Given the nature of this cash management system, we typically had a low balance of cash on hand. As a result, our cash flows from financing activities reflected the transfer to SemGroup of any cash we generated from operating and financing activities, or the receipt from SemGroup of cash to cover any net cash we expended from our operating and financing activities. Our net payments to SemGroup through these intercompany accounts were $20.3 million for the period during 2011 prior to the initial public offering, $14 million for the year ended December 31, 2010, $1 million for the month ended December 31, 2009 and $22 million for the eleven months ended November 30, 2009. We also financed cash outflows associated with changes in book overdrafts, which amounted to $1 million during the eleven months ended November 30, 2009.
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Capital Requirements
The midstream energy business can be capital intensive, requiring significant investment for the maintenance of existing assets or acquisition or development of new systems and facilities. We categorize our capital expenditures as either:
| • | maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or |
| • | expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. |
We have budgeted $37.4 million in capital expenditures for the year ending December 31, 2012, of which $33.7 million represents expansion capital expenditures, which are expected to relate primarily to the construction of 1.95 million barrels of storage capacity at our Cushing terminal and a truck unloading bay expansion at Platteville, and $3.7 million represents maintenance capital expenditures, of which $0.9 million is expected to relate to truck replacements, and the remaining $2.8 million is expected to related primarily to increased integrity management expenses to comply with new regulations.
In addition to our budgeted capital program, we anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under our new credit facility and the issuance of debt and equity securities.
Distributions
The cash distribution for the fourth quarter of 2011 was $0.0670 per unit. This prorated amount corresponds to the minimum quarterly cash distribution of $0.3625 per unit, or $1.45 per unit on an annualized basis. The proration period began on December 15, 2011, immediately after the closing date of our initial public offering, and continued through December 31, 2011. The distribution was paid on February 13, 2012 to all unitholders of record as of February 3, 2012.
Revolving Credit Facility
On November 10, 2011, we entered into a $150 million senior secured revolving credit agreement with The Royal Bank of Scotland, as administrative agent, and a syndicate of lenders. The credit facility is available to fund working capital, for the issuance of up to $75.0 million of letters of credit, to finance capital expenditures and other permitted payments and for other lawful corporate purposes and will allow us to request that the maximum amount of the credit facility be increased by up to an additional $200 million, subject to receiving increased commitments from lenders or commitments from other financial institutions. At December 31, 2011, we had no outstanding borrowings on the revolving credit facility and had $22.6 million outstanding in letters of credit. Our obligations under the credit facility are secured by a first priority lien on substantially all of our material assets. The credit facility matures on December 14, 2016. Borrowings under the credit facility bear interest at either an alternative base rate or an adjusted Eurodollar rate, in each case plus an applicable margin. The applicable margin varies based upon our Leverage Ratio, as defined in the credit facility. At December 31, 2011, had there been any borrowings under our revolving credit facility, the interest rate applicable to alternate base rate borrowings would have been 4.50% and the interest rate applicable to Eurodollar rate borrowings would have been the Eurodollar margin of 2.25% plus the applicable LIBOR rate.
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Fees are charged on any outstanding letters of credit at a rate that ranges from 2.25% to 3.25%, depending on a leverage ratio specified in the credit agreement. In addition, a fronting fee of 0.25% is charged on outstanding letters of credit.
A commitment fee that ranges from 0.375% to 0.50%, depending on a leverage ratio specified in the credit agreement is charged on any unused capacity of the revolving credit facility. In addition, we are charged an annual administrative fee of $0.1 million. The credit facility also allows for the use of secured bilateral letters of credit. At December 31, 2011, we had $17.0 million of bilateral letters of credit outstanding and the interest in effect was 1.75%.
As of December 31, 2011, we were in compliance with our covenants under our credit facility.
The credit facility contains representations and warranties and affirmative and negative covenants customary for transactions of this nature. The negative covenants limit or restrict our ability (as well as the ability of our Restricted Subsidiaries, as defined in the credit facility) to:
| • | permit the ratio of our consolidated EBITDA to our consolidated cash interest expense at the end of any fiscal quarter, for the immediately preceding four quarter period, to be less than 2.50 to 1.00; |
| • | permit the ratio of our consolidated net debt to our consolidated EBITDA at the end of any fiscal quarter, for the immediately preceding four quarter period, to be greater than 4.50 to 1.00 (or 5.00 to 1.00 during a temporary period from the date of funding of the purchase price of certain acquisitions (as described in the credit facility) until the last day of the third fiscal quarter following such acquisitions); |
| • | incur additional debt, subject to customary carve outs for certain permitted additional debt, incur certain liens on assets, subject to customary carve outs for certain permitted liens, or enter into certain sale and leaseback transactions; |
| • | make investments in or make loans or advances to persons that are not Restricted Subsidiaries, subject to customary carve out for certain permitted investments, loans and advances; |
| • | make certain cash distributions, provided that we may make distributions of available cash so long as no default under the credit agreement then exists or would result therefrom; |
| • | dispose of assets in excess of an annual threshold amount; |
| • | make certain amendments, modifications or supplements to organization documents, our risk management policy, other material indebtedness documents and material contracts or enter into certain restrictive agreements or make certain payments on subordinated indebtedness; |
| • | engage in business activities other than our business as described herein, incidental or related thereto or a reasonable extension of the foregoing; |
| • | enter into hedging agreements, subject to a customary carve out for agreements entered into in the ordinary course of business for non-speculative purposes; |
| • | make changes to our fiscal year or other significant changes to our accounting treatment and reporting practices; |
| • | engage in certain mergers or consolidations and transfers of assets; and |
| • | enter into transactions with affiliates unless the terms are not less favorable, taken as a whole, than would be obtained in an arms-length transaction, subject to customary exceptions. |
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The credit agreement also contains events of default customary for transactions of this nature, including the failure by SemGroup to directly or indirectly own a majority of the equity interests of our general partner. Upon the occurrence and during the continuation of an event of default under the credit facility, the lenders may, among other things, terminate their revolving loan commitments, accelerate and declare the outstanding loans to be immediately due and payable and exercise remedies against us and the collateral as may be available to the lenders under the credit facility and other loan documents.
Credit Risk
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. We examine the creditworthiness of third party customers to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.
Customer Concentration
Gavilon L.L.C, Vitol S.A, and BP Canada Energy Marketing Corporation, each accounted for more than 10% of our total revenue for the year ended December 31, 2011, at approximately 20%, 18% and 16%, respectively. Gavilon L.L.C. accounted for more than 10% of our total revenue for the year ended December 31, 2010, at approximately 42%. Gavilon L.L.C. accounted for more than 10% of our total revenue for the eleven months ended November 30, 2009, at approximately 81%. Although we have contracts with customers of varying duration, if one or more of our major customers were to default on their contract or if we were to be unable to renew our contract with one or more of these customers on favorable terms, we might not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our revenues and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our adjusted gross margin.
Contractual Obligations
In the ordinary course of business we enter into various contractual obligations for varying terms and amounts. The following table includes our non-cancellable contractual obligations as of December 31, 2011, and our best estimate of the period in which the obligation will be settled:
| Less Than | 1-3 | 3-5 | More Than 5 | |||||||||||||||||
| Contractual Obligations |
Total | 1 Year | Years | Years | Years | |||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Operating leases |
$ | 1,483 | $ | 711 | $ | 729 | $ | 41 | $ | 2 | ||||||||||
| Purchase commitments |
3,142,986 | 1,232,138 | 868,161 | 1,042,687 | — | |||||||||||||||
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| Total |
$ | 3,144,469 | $ | 1,232,849 | $ | 868,890 | $ | 1,042,278 | $ | 2 | ||||||||||
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The bulk 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).
In addition to the items in the table above, we have entered into certain derivative instruments that are recorded at fair value on our consolidated balance sheet as of December 31, 2011.
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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 December 31, 2011 and December 31, 2010, we had outstanding letters of credit of approximately $39.6 million and $19.2 million, respectively.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
This Management’s Discussion and Analysis of Financial Condition and Results of Operation is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. The preparation of these financial statements and related disclosures requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates and judgments that affect the reported amount of assets, liabilities, revenue, expenses and related disclosures of contingent assets and liabilities. The application of these policies involves judgments regarding future events, including the likelihood of success of particular projects and legal and regulatory challenges. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.
On an on-going basis, we evaluate these estimates using historical experience, consultation with experts and other methods we consider reasonable. Actual results may differ substantially from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
Our significant accounting policies are summarized in Note 2 of our audited consolidated financial statements shown beginning on page F-1 of this Form 10-K. We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and results of operations, and that require the most difficult, subjective and complex judgments by management regarding estimates about matters that are inherently uncertain.
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| Accounting Policy |
Judgment/Uncertainty Affecting Application | |
| Fresh Start Reporting and Reorganization Value | Determination of reorganization value | |
| Allocation of the reorganization value to our assets based on their fair values | ||
| Derivative Instruments | Instruments used in valuation techniques | |
| Market maturity and economic conditions | ||
| Contract interpretation | ||
| Market conditions in the energy industry, especially the effects of price volatility on contractual commitments | ||
| Impairment of Long Lived Assets | Recoverability of investment through future operations | |
| Regulatory and political environments and requirements | ||
| Estimated useful lives of assets | ||
| Environmental obligations and operational limitations | ||
| Estimates of future cash flows | ||
| Estimates of fair value | ||
| Judgment about triggering effects | ||
| Contingencies | Estimated financial impact of event | |
| Judgment about the likelihood of event occurring | ||
| Regulatory and political environments and requirements | ||
Fresh-Start Reporting and Reorganization Value
As part of SemGroup’s emergence from bankruptcy on November 30, 2009, we implemented fresh-start reporting in accordance with ASC 852, “Reorganizations.” Accordingly, our assets were adjusted to reflect their estimated fair value as of November 30, 2009. As a result, financial data prior to November 30, 2009 is not comparable to our financial data on and after November 30, 2009.
Under fresh-start reporting, a reorganization value was determined and allocated to our net assets based on their relative fair values in a manner similar to the accounting provisions applied to business combinations under ASC 805, “Business Combinations.” Adjustments necessary to state our balance sheet accounts at fair value were made based on the work of management, financial consultants and independent appraisals. The estimates and assumptions used to derive the reorganization value and the allocation of that value to assets is inherently subject to significant business, economic and competitive uncertainties and contingencies, many of which are beyond our control. Modification to these assumptions could have significantly changed the reorganization value and the resultant fair values of our assets. The allocation of reorganization value did not result in the recognition of any goodwill or other intangible assets.
Derivative Instruments
We follow the guidance of ASC 815, “Derivatives and Hedging,” to account for derivative instruments. ASC 815 requires us to mark-to-market all derivative instruments on the balance sheet, and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings. In certain cases, we may apply hedge accounting to our derivative instruments. The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the fair value of the derivative instrument and the underlying hedged item. Changes in the fair value of derivative instruments accounted for as hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged item, or deferred and recorded as a component of other comprehensive income and subsequently recognized in earnings when the hedged transactions occur.
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Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be a normal purchase normal sale (“NPNS”). The availability of this exception is based on the assumption that we have the ability, and intent, to deliver or take delivery of the underlying item. These assumptions are based on internal forecasts of sales and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with immediate recognition through earnings.
We routinely enter into agreements to purchase and sell petroleum products at specified future dates. We establish a margin for these purchases by entering into various types of physical and financial sales and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. We account for these commitments as normal purchases and sales, and therefore we do not record assets or liabilities related to these agreements until the product is purchased or sold.
Our results of operations and cash flows are impacted by changes in market prices for petroleum products. We manage this exposure to commodity price risk, 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 are comprised of crude oil forward contracts and futures contracts. These are defined as follows:
Forward contracts – Over the counter contracts to buy or sell a commodity at an agreed upon future date. The buyer and seller agree on specific terms (price, quantity, delivery period, and location) and conditions at the inception of the contract.
Futures contracts – Exchange traded contracts to buy or sell a commodity. These contracts are standardized by the exchange in terms of quality, quantity, delivery period and location for each commodity.
We record certain commodity derivative assets and liabilities at fair value at each balance sheet date. 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. We have not designated any of our commodity derivatives as hedges.
Additional discussion of the accounting for derivative instruments at fair value is included in Note 5 to our consolidated financial statements beginning on page F-1 of this Form 10-K.
Evaluation of Assets for Impairment and Other Than Temporary Decline in Value
In accordance with ASC 360, “Property, Plant and Equipment,” we evaluate property, plant and equipment for impairment whenever indicators of impairment exist. Examples of such indicators are:
| • | significant decrease in the market price of a long-lived asset; |
| • | significant adverse change in the manner an asset is used or its physical condition; |
| • | adverse business climate; |
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| • | accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset; |
| • | current period loss combined with a history of losses or the projection of future losses; and |
| • | change in our intent about an asset from an intent to hold such asset through the end of its estimated useful life to a greater than fifty percent likelihood that such asset will be disposed of before then. |
Recoverability of assets to be held and used is measured by comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount exceeds the fair value of the assets. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. However, actual future market prices and costs could vary from the assumptions used in our estimates and the impact of such variations could be material.
To date, we have not observed any indication that impairment exists, and as a result there has been no test for impairment or negative impact on our results of operations related to impairment of long-lived assets.
Contingencies
We record a loss contingency when management determines that it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. Gain contingencies are not recorded.
While we have disclosed a number of contingencies (as described in Note 7 to our audited consolidated financial statements, which are included in this Form 10-K beginning on page F-1), we have not accrued for any contingent loss at December 31, 2011.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
This discussion on market risks represents an estimate of possible changes in future earnings that would occur assuming hypothetical future movements in commodity prices and interest rates. Our views on market risk are not necessarily indicative of actual results that may occur, and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.
We are exposed to various market risks, including volatility in crude oil prices and interest rates. We have in the past used, and expect that in the future we will continue to use, various derivative instruments to manage such exposure. Our risk management policies and procedures are designed to monitor physical and financial commodity positions and the resulting outright commodity price risk as well as basis risk resulting from differences in commodity grades, purchase and sales locations and purchase and sale timing. We have a risk management function that has responsibility and authority for our Comprehensive Risk Management Policy, which governs our enterprise-wide risks, including the market risks discussed in this item. Subject to our Comprehensive Risk Management Policy, our finance and treasury function has responsibility and authority for managing exposure to interest rates.
Commodity Price Risk
Commodity prices have historically been volatile and cyclical. For example, NYMEX West Texas Intermediate benchmark prices have ranged from an all-time high of over $145 per barrel (June/July 2008) to a low of approximately $10 per barrel (March 1986) over the last 25 years. The table below outlines the range of NYMEX prompt month daily settle prices for crude oil for the years ended December 31, 2011, 2010, 2009 and 2008.
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| Light Sweet Crude Oil Futures ($ per Barrel) |
Light Sweet Crude Oil Futures ($ per Barrel) |
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| Year Ended December 31, 2011 |
Year Ended December 31, 2010 | |||||||||
| High |
$ | 113.93 | High | $ | 91.51 | |||||
| Low |
$ | 75.67 | Low | $ | 68.01 | |||||
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| High/Low Differential |
$ | 38.26 | High/Low Differential | $ | 23.50 | |||||
| Year Ended December 31, 2009 |
Year Ended December 31, 2008 | |||||||||
| High |
$ | 81.37 | High | $ | 145.29 | |||||
| Low |
$ | 33.98 | Low | $ | 33.87 | |||||
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| High/Low Differential |
$ | 47.39 | High/Low Differential | $ | 111.42 | |||||
Revenue from our asset-based activities is dependent on throughput volume, tariff rates, the level of fees generated from our pipeline systems, capacity contracted to third parties, capacity that we use for our own operational or marketing activities and the level of other fees generated at our storage facilities. Profit from our marketing activities is dependent on our ability to sell crude oil at prices in excess of our aggregate cost. Margins may be affected during transitional periods between a backwardated market (when the prices for future deliveries are lower than the current prices) and a contango market (when the prices for future deliveries are higher than the current prices). Our crude oil marketing activities are generally not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and relative fluctuations in marked-related indices.
Based on our open derivative contracts at December 31, 2011, a 5% increase in the applicable market price or prices for each derivative contract would result in a less than $0.5 million decrease in our crude oil sales revenues. A 5% decrease in the applicable market price or prices for each derivative contract would result in a less than $0.5 million increase in 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.
Margin deposits or other credit support, including letters of credit, are generally required on derivative instruments utilized to manage our price exposure. As commodity prices increase or decrease, the fair value of our derivative instruments changes, thereby increasing or decreasing our margin deposit or other credit support requirements. Although a component of our risk-management strategy is intended to manage the margin and other credit support requirements on our derivative instruments, volatile spot and forward commodity prices, or an expectation of increased commodity price volatility, could increase the cash needed to manage our commodity price exposure and thereby increase our liquidity requirements. This may limit amounts available to us through borrowing, decrease the volume of petroleum products we purchase and sell or limit our commodity price management activities.
Interest Rate Risk
We have exposure to changes in interest rates under our new credit facility. The credit markets have recently experienced historical lows in interest rates. If the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. Interest rates on our floating rate credit facility and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly.
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Prior to our initial public offering, substantially all of our interest expense was incurred at fixed rates. As a result, an increase or decrease in interest rates would have had no material impact on our interest expense for the period during 2011 prior to our initial public offering. We recorded interest expense related to our new revolver credit facility of $57.6 thousand during December 2011. An increase in interest rates of 1% would have increased our interest expense by $12.6 thousand million during December 2011.
Impact of Seasonality
Our sales volumes in our Bakken Shale operations typically decline in the winter due to the decreased levels of drilling and completion of new wells during the winter months.
Item 8. Financial Statements and Supplementary Data
The consolidated financial statements required to be included in this Form 10-K appear immediately following the signature page to this Form 10-K, beginning on page F-1.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer of our general partner have concluded that the design and operation of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective as of December 31, 2011. This conclusion is based on an evaluation conducted under the supervision and participation of the Chief Executive Officer and Chief Financial Officer of our general partner along with our management. Disclosure controls and procedures are those controls and procedures designed to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that such information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, as appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting
This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Partnership’s registered public accounting firm due to a transition period established by the rules of the SEC for new registrants.
There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2011 that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.
None
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Item 10. Directors, Executive Officers and Corporate Governance
Board of Directors of our General Partner
We are managed under the direction of the Board of Directors of our sole general partner, Rose Rock GP, which consists of six members appointed by SemGroup Corporation, the parent corporation of our general partner. We refer to the Board of Directors of Rose Rock GP as our Board of Directors. Once a member is appointed to our Board of Directors, such member continues in office until the resignation or removal of such member or until the death of such member. Because the members of our Board of Directors are not elected by unitholders, we do not have a procedure by which unitholders may recommend nominees to our Board of Directors.
Because we are a limited partnership, certain listing standards of the NYSE are not applicable to us. Accordingly, Section 303A.01 of the NYSE Listed Company Manual, which would require that the Board of Directors of our general partner be comprised of a majority of independent directors, and Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require that the Board of Directors of our general partner maintain a nominating committee and a compensation committee, each consisting entirely of independent directors, are not applicable to us. However, our Board of Directors has affirmatively determined that two of the six members of our Board of Directors, Rodney L. Gray and Mark Monroe, have no material relationship with us and are “independent” under our Governance Guidelines and the listing standards of the NYSE.
In evaluating director candidates, SemGroup Corporation considers factors that are in the best interests of the Partnership and its unitholders, including the knowledge, experience, integrity and judgment of each candidate; the potential contribution of each candidate to the diversity of backgrounds, experience and competencies that the Board desires to have represented on the Board; each candidate’s ability to devote sufficient time and effort to his or her duties as a director; and any core competencies or technical expertise necessary to staff Board committees. In addition, SemGroup Corporation assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the Partnership.
The Audit Committee
Our Board of Directors has appointed an Audit Committee consisting of three members of our Board of Directors, two of whom (Messrs. Gray and Monroe) are independent under our Governance Guidelines and the listing standards of the NYSE. The other member, Robert N. Fitzgerald , is not independent. All three members of our Audit Committee are required to be independent within one year following the date that our common units were listed on the NYSE. Our guidelines for determining the independence of members of the Audit Committee are included in our Governance Guidelines. The Board of Directors has determined that each member of the Audit Committee qualifies as an “audit committee financial expert” as defined by the rules of the SEC.
The Audit Committee has oversight responsibility with respect to the integrity of our financial statements, the performance of our internal audit function, the independent registered public accountant’s qualifications and independence and our compliance with legal and regulatory requirements. The Audit Committee directly appoints, retains, evaluates and may terminate our independent registered public accounting firm. The Audit Committee reviews our annual audited and quarterly unaudited financial statements. The Audit Committee has all other responsibilities required by the applicable NYSE listing standards and applicable SEC rules. Our Board of Directors has adopted a written charter for our Audit Committee which is available on line and may be printed from our website at www.rrmidstream.com and is also available from the corporate secretary of our general partner.
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The Conflicts Committee
Our Board of Directors has appointed a Conflicts Committee consisting of the two members of our Board of Directors (Messrs. Gray and Monroe) who are independent under our Governance Guidelines and the listing standards of the NYSE and who are not also executive officers or members of the Board of Directors of SemGroup Corporation. The Conflicts Committee has the authority to review specific matters that may present a conflict of interest in order to determine if the resolution of such conflict is “fair and reasonable” to our unitholders. In making any such determination, the Conflicts Committee has the authority to engage advisors to assist it in carrying out its duties.
Risk Oversight
Enterprise risk management is a company-wide process that involves our Board of Directors and management in identifying, assessing and managing risks that could affect our ability to fulfill our business objectives or execute our business strategy. Our enterprise risk management activities involve the identification and assessment of a broad range of risks and the development of plans to mitigate their effects. These risks generally relate to strategic, operations, financial and regulatory compliance issues.
Not all risks can be dealt with in the same way. Some risks may be easily perceived and controllable, and other risks are unknown; some risks can be avoided or mitigated by particular behavior, and some risks are unavoidable as a practical matter. For some risks, the potential adverse impact would be minor and, as a matter of business judgment, it may not be appropriate to allocate significant resources to avoid the adverse impact; in other cases, the adverse impact could be significant, and it is prudent to expend resources to seek to avoid or mitigate the potential adverse impact. In some cases, a higher degree of risk may be acceptable because of a greater perceived potential for reward. Management is responsible for identifying risk and risk controls related to our significant business activities, mapping the risks to our partnership strategy; and developing programs and recommendations to determine the sufficiency of risk identification, the balance of potential risk to potential reward and the appropriate manner in which to control and mitigate risk.
Our Board of Directors is responsible for oversight of our enterprise-wide risk and has approved our comprehensive risk management policy. The comprehensive risk management policy is designed to ensure we: identify and communicate our risk appetite and risk tolerances; establish an organizational structure that prudently separates responsibilities for executing, valuing and reporting our business activities; value (where appropriate), report and manage all material business risks in a timely and accurate manner; effectively delegate authority for committing our resources; foster the efficient use of capital and collateral; and minimize the risk of a material adverse event.
In addition, our Board of Directors is implementing its risk oversight responsibilities by having management provide periodic briefing and informational sessions on the significant voluntary and involuntary risks that the Partnership faces and how the Partnership is seeking to control and mitigate these risks if and when appropriate. In some cases, as with risks relating to any significant acquisitions, risk oversight will be addressed as part of the full Board’s engagement with the Chief Executive Officer and management.
The Board intends to annually review a management assessment of the primary operational and regulatory risks facing the Partnership, their relative magnitude and management’s plan for mitigating these risks. The Board also intends to review risks related to the Partnership’s business strategy at its annual strategic planning meeting and at other meetings as appropriate.
Our Audit Committee oversees risk issues associated with our overall financial reporting and disclosure process and legal compliance, as well as reviews policies and procedures on risk control assessment and accounting risk exposure, including our business continuity and disaster recovery plans. The Audit Committee meets with the Chief Executive Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Accounting Officer and Director – Internal Audit as well as our independent registered public accounting firm in executive sessions, at which risk issues are discussed, at each of its in-person meetings during the year.
Directors and Executive Officers
The following table sets forth the members of our Board of Directors, Audit Committee, Conflicts Committee and the executive officers of our general partner. The persons designated as our executive officers serve in that capacity at the discretion of our Board of Directors. There are no family relationships between any of our executive officers or members of the Board of Directors, Audit Committee or the Conflicts Committee. Some of these individuals are also officers of certain of our subsidiaries and affiliates.
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| Name |
Age | Position with Rose Rock GP | ||
| Norman J. Szydlowski | 60 | President, Chief Executive Officer and Chairman | ||
| Peter L. Schwiering | 67 | Chief Operating Officer and Director | ||
| Robert N. Fitzgerald | 52 | Senior Vice President, Chief Financial Officer, Director and Audit Committee member | ||
| Timothy O'Sullivan | 55 | Vice President and Director | ||
| Rodney L. Gray | 59 | Director, Conflicts Committee Chairman and Audit Committee member | ||
| Mark E. Monroe | 57 | Director, Audit Committee Chairman and Conflicts Committee member | ||
| Candice L. Cheeseman | 56 | General Counsel and Secretary | ||
| Paul Largess | 61 | Vice President, Chief Accounting Officer and Controller |
Norman J. Szydlowski. Mr. Szydlowski is the President and Chief Executive Officer and Chairman of the Board of Directors of Rose Rock Midstream GP, LLC. Mr. Szydlowski has also served as a director and as President and Chief Executive Officer of SemGroup Corporation since November 2009. From January 2006 until January 2009, Mr. Szydlowski served as president and chief executive officer of Colonial Pipeline Company, an interstate common carrier of petroleum products. From 2004 to 2005, he served as a senior consultant to the Iraqi Ministry of Oil in Baghdad on behalf of the U.S. Department of Defense, where he led an advisory team in the rehabilitation, infrastructure security and development of future strategy of the Iraqi oil sector. From 2002 until 2004, he served as vice president of refining for Chevron Corporation (formerly ChevronTexaco), one of the world’s largest integrated energy companies. Mr. Szydlowski joined Chevron in 1981 and served in various capacities of increasing responsibility in sales, planning, supply chain management, refining and plant operations, transportation and construction engineering. Mr. Szydlowski serves on the board of directors of NGL Energy Holdings LLC, the general partner of NGL Energy Partners LP, an owner and operator in the midstream, wholesale supply and marketing and retail propane business.
As the current President and Chief Executive Officer of SemGroup Corporation, Mr. Szydlowski provides a management representative on the Board of Directors of our general partner with knowledge of the day-to-day operations of SemGroup obtained as a result of his role. Thus, he can facilitate the board’s access to timely and relevant information and its oversight of management’s strategy, planning and performance. In addition, Mr. Szydlowski brings to the board considerable management and leadership experience, most recently as president and chief executive officer of Colonial Pipeline Company, and extensive knowledge of the energy industry and of our business gained during his 30-year career in the energy business.
Peter L. Schwiering. Mr. Schwiering is the Chief Operating Officer and a director of Rose Rock Midstream GP, LLC. He also serves as Vice President of SemGroup Corporation, a position he has held since February 2012, and as President of SemCrude, L.P., a position he has held since August 2009. Mr. Schwiering joined SemCrude, L.P. in 2000 as Vice President of Operations. Prior to joining SemCrude, L.P., Mr. Schwiering worked for Dynegy Pipeline as manager of pipeline and commercial business. He also served with Sun Company for 25 years in various positions, last serving as the company’s manager of business development – Western Region, based in Oklahoma. Mr. Schwiering’s over 40 years of experience in the energy industry, along with his knowledge of our assets from his experience as president of SemCrude, L.P., provide him with the necessary skills to serve as a member of the Board of Directors of our general partner.
Robert N. Fitzgerald. Mr. Fitzgerald is the Senior Vice President and Chief Financial Officer, a director of Rose Rock Midstream GP, LLC and serves on its Audit Committee. Mr. Fitzgerald joined SemGroup Corporation in November 2009 and serves as SemGroup Corporation’s Senior Vice President and Chief Financial Officer. Prior to joining SemGroup, Mr. Fitzgerald served as chief financial officer from February 2008 to November 2009 of Windsor Energy Group, a private independent oil and gas exploration and development company. He has also served from December 2006 until February 2008 as executive vice president of LinkAmerica Corp. and from January 2003 until December 2006 as chief operating officer and chief financial officer of Arrow Trucking Company, both commodity transportation companies. From January 2000 until January 2003, he served as vice president, finance of Williams Communications Group, a global communication company. Prior to that, Mr. Fitzgerald was with BP Amoco and Amoco Corporation for 20 years, working in various financial and operations positions in Tulsa, Oklahoma; Houston, Texas; Denver, Colorado; and Chicago, Illinois. Mr. Fitzgerald is currently a member of the American Institute of
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Certified Public Accountants, the Institute of Management Accountants and the Institute of Internal Auditors. He is a certified public accountant. Mr. Fitzgerald’s 25+ years of financial and operational experience, in general, and experience in the energy industry, in particular, including his experience with SemGroup Corporation, provide him with the necessary skills to serve as a member of the Board of Directors of our general partner.
Timothy O’Sullivan. Mr. O’Sullivan is the Vice President and a director of Rose Rock Midstream GP, LLC. Mr. O’Sullivan also serves as Vice President, Corporate Planning and Strategic Initiatives of SemGroup Corporation, a position he has held since April 2010. From February 2005 until April 2010, he served as President and Chief Operating Officer of SemGas, L.P. From 2001 until joining SemGroup Corporation, Mr. O’Sullivan worked for Williams Power Company where he was director of global gas and power origination. He was previously employed with Koch Industries, Inc. for 19 years where he served in various capacities in its natural gas division, including business development, marketing and trading, and executive management. Mr. O’Sullivan began his career as a staff accountant for Main Hurdman. He is a certified public accountant. Mr. O’Sullivan was a member of the board of directors of the Gas Processors Association and served on its Executive and Finance Committee. Mr. O’Sullivan’s experience with SemGroup Corporation and its affiliates along with his over 25 years of experience in the energy industry provide him with the necessary skills to serve as a member of the Board of Directors of our general partner.
Rodney L. Gray. Mr. Gray is a director of Rose Rock Midstream GP, LLC and the Chairman of its Conflicts Committee and a member of its Audit Committee. From June 2009 until June 2010, Mr. Gray served as Chief Financial Officer and Executive Vice President of Cobalt International Energy, Inc. From 2003 to April 2009, Mr. Gray served as Chief Financial Officer of Colonial Pipeline, an interstate carrier of petroleum products. He currently serves as Chairman of both the audit and risk management committee and the conflicts committee of the board of directors of Regency Energy Partners LP. Mr. Gray received a Bachelor of Science degree in Accounting from the University of Wyoming and a Bachelor of Science degree in Mathematics and Economics from Rock Mountain College in Billings, Montana. Mr. Gray brings more than 30 years of experience in the energy industry, including as an executive with financial leadership responsibility, to the board. He also has experience serving as an independent member of the board of directors of a master limited partnership. We believe that this experience provides him with the necessary skills to serve on the Board of Directors of our general partner and its Audit Committee.
Mark E. Monroe. Mr. Monroe is a director of Rose Rock Midstream GP, LLC and Chairman of its Audit Committee and a member of its Conflicts Committee. Mr. Monroe served as President and Chief Operating Officer of Continental Resources, Inc., an NYSE-listed oil and gas exploration and production company, from October 2005 until his retirement in October 2008. Mr. Monroe has been a director of Continental Resources since November 2001, and currently serves as Chairman of its audit committee. Mr. Monroe was a consultant and served as a member of the board of directors of Unit Corporation, an NYSE-listed onshore drilling and oil and gas exploration and production company, from October 2003 through October 2005. Mr. Monroe served in various positions with Louis Dreyfus Natural Gas Corp beginning in 1980, including serving as its Chief Executive Officer and President from August 1996 until its merger with Dominion Resources, Inc. in October 2001. He currently serves on the board of directors of the Oklahoma Independent Petroleum Association. He has served as Chairman of the Oklahoma Independent Petroleum Association, and has served on the Domestic Petroleum Council and the National Petroleum Council, as well as on the boards of directors of the Independent Petroleum Association of America, the Oklahoma Energy Explorers, and the Petroleum Club of Oklahoma City. Mr. Monroe is a certified public accountant and received his B.A. in business administration from the University of Texas at Austin. Mr. Monroe brings extensive executive and financial experience to the board from his positions as Chief Executive Officer, President and Chief Financial Officer at various publicly-traded oil and gas companies and his background as a certified public accountant. We believe these experiences and skills qualify him to serve on the Board of Directors of our general partner and its Audit Committee.
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Candice L. Cheeseman. Ms. Cheeseman is the General Counsel and Secretary of Rose Rock Midstream GP, LLC. Ms. Cheeseman joined SemGroup Corporation in February 2010 and serves as SemGroup Corporation’s General Counsel and Secretary. Prior to joining SemGroup Corporation, Ms. Cheeseman served as general counsel of Global Power Equipment Group Inc., a comprehensive provider of power generation equipment and maintenance services for energy customers, since May 2004. In September 2006, Global Power Equipment Group Inc. and its domestic subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware. Global Power Equipment Group and its subsidiaries emerged from bankruptcy protection in January 2008. Prior to Global Power, she was employed by WilTel Communications Group, an internet, data, voice and video service provider, where she served in a variety of capacities, including general counsel and secretary, commencing in November 2002. Ms. Cheeseman has been a practicing attorney for two decades serving in various capacities for Williams Communications, Marriott International and law firms in the Washington D.C. area.
Paul Largess. Mr. Largess is the Vice President, Chief Accounting Officer and Controller of Rose Rock Midstream GP, LLC. He has also serves as Vice President, Chief Accounting Officer and Controller of SemGroup Corporation, a position held since November 2009. From 2007 to 2009, he worked as a consultant and at the University of Tulsa as an adjunct professor of accounting. Mr. Largess retired as controller of CITGO Petroleum Corporation in 2006, after 21 years of service in a number of positions in accounting, finance and audit. Prior to joining CITGO, Mr. Largess worked as an auditor with Texaco and in public accounting. He serves on the board of directors of ADDvantage Technologies Group, Inc., as chairman of its audit committee and as a member of its corporate governance committee and nominating committee. Mr. Largess is a certified public accountant.
Additional Governance Matters
Executive Sessions of the Board of Directors
Our Board of Directors has documented its governance practices in our Governance Guidelines. Our Board of Directors holds regular executive sessions in which non-management board members meet without any members of management present. The chairman of our Audit Committee, Mr. Monroe, presides at regular sessions of the non-management members of our Board of Directors. Meetings of the non-management board members are scheduled in connection with each in-person meeting of our Board of Directors.
Governance Guidelines
Our Board of Directors has adopted Governance Guidelines that address several Partnership governance matters, including responsibilities of our directors, the composition and responsibility of the Audit Committee, the conduct and frequency of board meetings, management succession, director access to management and outside advisors, director orientation and continuing education, and annual self-evaluation of the board. Our Board of Directors recognizes that effective governance is an ongoing process, and the Board will review our Governance Guidelines periodically as deemed necessary.
Codes of Business Conduct and Ethics
Our Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to the members of our Board of Directors, our officers and the employees of SemGroup and Rose Rock GP, who provide services to us and an additional separate Code of Ethics for CEO and Senior Financial Officers, which is applicable to the chief executive officer and all senior financial officers, including the chief financial officer, of our general partner. We intend to promptly post on our website any amendments to, or waivers (including any implicit waiver) from, any provision of our Code of Business Conduct and Ethics or Code of Ethics for CEO and Senior Financial Officers in accordance with the applicable rules of the SEC and NYSE.
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Web Access
We provide access through our website at www.rrmidstream.com to current information relating to Partnership governance, including our Audit Committee Charter, our Code of Business Conduct and Ethics, our Code of Ethics for CEO and Senior Financial Officers, our Governance Guidelines and other matters impacting our governance principles. You may access copies of each of these documents from our website. You may also contact the office of the secretary of Rose Rock GP for printed copies of these documents free of charge. Our website and any contents thereof are not incorporated by reference into this Form 10-K.
Communications with Directors
Our Board of Directors believes that it is management’s role to speak for the Partnership. Our Board of Directors also believes that any communications between members of the Board of Directors and interested parties, including unitholders, should be conducted with the knowledge of our chairman, president and chief executive officer. Interested parties, including unitholders, may contact one or more members of our Board of Directors, including non-management directors and non-management directors as a group, by writing to the director or directors in care of the secretary of Rose Rock GP at our principal executive offices. A communication received from an interested party or unitholder will be promptly forwarded to the director or directors to whom the communication is addressed. A copy of the communication will also be provided to our chairman, president and chief executive officer. We will not, however, forward sales or marketing materials or correspondence primarily commercial in nature, materials that are abusive, threatening or otherwise inappropriate, or correspondence not clearly identified as interested party or unitholder correspondence.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires executive officers, members of our Board of Directors and persons who own more than 10 percent of our common units to file reports of ownership and changes in ownership with the SEC and the NYSE and to furnish us with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms received by us during and with respect to the 2011 fiscal year or written representations from certain reporting persons that no Form 5s were required for those persons, we believe that during 2011 our reporting persons complied with all applicable filing requirements in a timely manner.
Item 11. Executive Compensation
Compensation Discussion and Analysis
All of our executive officers and other employees necessary for our business to function are employed and compensated by SemGroup, subject to reimbursement by us. We and our general partner were formed in 2011. We are managed by the executive officers of our general partner. Executive officers include our principal executive officer, Norman J. Szydlowski, our principal financial officer, Robert N. Fitzgerald, our General Counsel and Secretary, Candice L. Cheeseman, our Vice President, Tim O’Sullivan and our Chief Operating Officer, Peter L. Schwiering (collectively, our “named executive officers”). Each of our named executive officers is also a named executive officer of SemGroup and, with the exception of Mr. Schwiering, our named executive officers devote less than a majority of their total business time to our general partner. Mr. Schwiering is also an employee of SemGroup and he devotes approximately one-third of his business time to SemGroup and approximately two-thirds of his total business time to us. Compensation paid or awarded by us in 2011 with respect to the named executive officers reflects only the portion of the compensation expense that is payable by us, which is determined by the amount of time each named executive officer actually spent working for us relative to the amount of time each spent working for SemGroup.
Neither we nor our general partner have a compensation committee. The named executive officers of our general partner are compensated directly by SemGroup. All decisions as to the compensation of the named executive officers of our general partner who are involved in our management are made by the Compensation Committee of SemGroup. Therefore, we do not have any policies or programs relating to compensation of the named executive officers of our general partner and we make no decisions relating to such compensation. None of the named executive officers of our general partner have employment agreements with us or are otherwise specifically compensated for their
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service as a named executive officer of our general partner. A full discussion of the policies and programs of the Compensation Committee of SemGroup will be set forth in the proxy statement of SemGroup’s 2012 annual meeting of stockholders which will be available upon its filing on the SEC website at http://www.sec.gov and on SemGroup’s website at http://semgroupcorp.com under the heading “Investors – SEC Filings.” The compensation paid by SemGroup to our named executive officers is allocated to us and reimbursed by us to SemGroup.
Board Report on Compensation
Neither we nor our general partner has a compensation committee. The Board of Directors of our general partner has reviewed and discussed with management the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.
The Board of Directors of Rose Rock GP:
Norman J. Szydlowski
Peter L. Schwiering
Robert N. Fitzgerald
Timothy O’Sullivan
Rodney L. Gray
Mark E. Monroe
Summary Compensation Table
The following table sets forth certain information with respect to SemGroup’s compensation of our general partner’s named executive officers attributable to us during the period beginning on December 1, 2011 and ending on December 31, 2011, which is the period in 2011 for which SemGroup will seek reimbursement from us. We and our general partner were formed in 2011; therefore, we incurred no cost or liability with respect to compensation of our named executive officers, nor has our general partner accrued any liabilities for incentive compensation for our named executive officers for the period from January 1, 2011 to November 30, 2011, fiscal year ended December 31, 2010 or for any prior periods. Accordingly, we are not presenting any compensation information for such historical periods.
| Name and Principal Position |
Year | Salary ($) |
Bonus ($) |
Stock Awards ($)(1) |
Option Awards ($) |
Non-Equity Incentive Plan Compensation ($) |
Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(2) |
All Other Compensation ($)(3) |
Total ($) |
|||||||||||||||||||||||||||
| Norman J. Szydlowski |
2011 | 12,032 | — | 17,775 | — | 8,781 | — | 602 | 39,190 | |||||||||||||||||||||||||||
| Robert N. Fitzgerald |
2011 | 7,295 | — | 6,250 | — | 4,938 | — | 365 | 18,848 | |||||||||||||||||||||||||||
| Candice L. Cheeseman |
2011 | 6,319 | — | 3,959 | — | 4,333 | — | 316 | 14,927 | |||||||||||||||||||||||||||
| Timothy R. O’Sullivan |
2011 | 3,795 | — | 2,325 | — | 2,490 | — | 190 | 8,800 | |||||||||||||||||||||||||||
| Peter L. Schwiering |
2011 | 17,583 | — | 10,937 | — | 13,500 | — | 719 | 42,739 | |||||||||||||||||||||||||||
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| (1) | Represents the grant date fair value attributable to us computed in accordance with ASC 718 “Stock Compensation,” of the shares of restricted stock of SemGroup and performance share units granted under SemGroup’s equity incentive plan. The assumptions used to value the stock awards are included in Note 21 to SemGroup’s consolidated financial statements contained in SemGroup’s Annual Report on Form 10-K for the year ended December 31, 2011. The amounts shown do not represent amounts paid to such executive officers. |
The value included for the performance share units is based on 100 percent of the performance share units vesting at the end of the three-year performance period. Using the maximum number of shares of SemGroup issuable upon vesting of the performance share units (150 percent of the units granted), the aggregate grant date fair value of the performance share units attributable to us would be as follows:
| Name |
2011 | |||
| Norman J. Szydlowski |
$ | 26,662 | ||
| Robert N. Fitzgerald |
$ | 9,375 | ||
| Candice L. Cheeseman |
$ | 5,938 | ||
| Timothy R. O’Sullivan |
$ | 3,487 | ||
| Peter L. Schwiering |
$ | 16,405 | ||
| (2) | Reflects the amounts attributable to us for 2011 for awards under SemGroup’s short-term incentive program based on achievement of certain performance metrics specified therein. Amounts were based on partial achievement of the performance metrics for 2011. |
| (3) | Represents amounts attributable to us under SemGroup’s 401(k) matching contribution. |
We have not included tables with information about grants of plan-based awards, outstanding equity awards at fiscal year-end, option exercises and stock vested, pension benefits, and non-qualified deferred compensation because there is nothing to include in such tables for 2011. In addition, our named executive officers are not entitled to any compensation as a result of a change-in-control of us or the termination of their service as a named executive officer of our general partner.
Equity Incentive Plan
Our general partner has adopted the Rose Rock Midstream Equity Incentive Plan (the “EIP”) for the employees and directors of our general partner and its affiliates, including SemGroup, and any consultants who perform services for us, our general partner and any of our and our general partner’s affiliates, including SemGroup. No awards were made under the EIP in 2011. The description of the EIP set forth below is a summary of the material features of the EIP.
The EIP consists of options, unit appreciation rights, restricted units, phantom units and other unit-based awards, including any tandem distribution equivalent rights that may be granted with respect to an award, other than an award of restricted units. The EIP limits the number of common units that may be delivered pursuant to awards under the plan to 840,000 common units. If an award expires, is forfeited, canceled or otherwise terminates without the issuance of common units or if such award is otherwise settled for cash, the common units subject to such award, to the extents of such expiration, forfeiture, cancellation, termination or settlement for cash, will again be available for new awards under the EIP. Common units to be delivered pursuant to awards under the EIP may be common units acquired in the open market, from us, from any of our affiliates or from any other person, or any combination of the foregoing.
Administration. The EIP is administered by our Board of Directors. Our Board of Directors may terminate or amend the EIP at any time with respect to any common units for which a grant has not yet been made. Our Board of Directors also has the right to amend, alter, suspend, discontinue or terminate the EIP or any portion thereof at any time, including increasing the number of common units available under the EIP, subject in each case to unitholder approval as may be required under the EIP or by the exchange upon which the common units are listed at that time, if any. No change may be made in any outstanding grant that would materially reduce the benefits of the participant without the consent of the participant. Unless earlier terminated by the Board of Directors of our general partner, the EIP will terminate on the tenth anniversary of its effective date. Upon termination of the EIP, awards then outstanding will continue pursuant to the terms of their grants.
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Options. An option represents the right to purchase a stated number of common units at a specified exercise price, subject to such terms and conditions as may be established by the Board of Directors of our general partner in its sole discretion. Options may be granted to such eligible individuals and with such terms as our Board of Directors may determine that are consistent with the EIP. However, an option must have an exercise price greater than or equal to the fair market value of a common unit on the date of grant. The term of each option will be determined by our Board of Directors at the time of grant, but in no event shall such term be greater than ten years from the date of grant.
In general, an option will become exercisable over a period determined by our Board of Directors. An option may be exercised for all, or from time to time any part, of the common units for which it is then exercisable. The aggregate exercise price for the common units as to which an option is exercised must be paid in full at the time of exercise. At the participant’s election, the exercise price may be paid (i) in cash, (ii) in common units with a fair market value equal to the aggregate exercise price for the common units being purchased (to the extent permitted, and subject to conditions imposed, by the Board of Directors of our general partner), (iii) partly in cash and partly in common units (to the extent permitted, and subject to conditions imposed, by the Board of Directors of our general partner), or (iv) if there is a public market for the common units at the time of exercise, through the delivery of irrevocable instructions to a broker to sell common units obtained upon the exercise of the option and to deliver promptly an amount out of the proceeds of such sale equal to the aggregate exercise price for the common units being purchased.
Unit Appreciation Rights. A unit appreciation right represents the right to receive the appreciation in the value of a specified number of common units on the date of exercise over the grant price of such unit appreciation right, as determined by our Board of Directors on the date of grant. Payment on a unit appreciation right will be made either in cash, common units, other property or any combination thereof, as determined by our Board of Directors in its sole discretion. Unit appreciation rights may be granted to such eligible individuals and with such terms as our Board of Directors may determine that are consistent with the EIP. However, a unit appreciation right must have an exercise price greater than or equal to the fair market value of a common unit on the date of grant. The term of each unit appreciation right will be determined by our Board of Directors at the time of grant, but in no event shall such term be greater than ten years from the date of grant.
Our Board of Directors may also grant tandem unit appreciation rights, which are unit appreciation rights that are granted in tandem with an option at the same time such option is granted. A tandem unit appreciation right may be exercisable only to the extent that the related option is exercisable and will expire no later than the expiration of the related option. Upon the exercise of all or a portion of a tandem unit appreciation right, a participant will be required to forfeit the right to exercise an equivalent portion of the related option (and, when a common unit is purchased under the related option, the participant shall be required to forfeit an equivalent portion of the tandem unit appreciation right).
Restricted Units. A restricted unit is a common unit that is subject to forfeiture upon the occurrence of certain specified events. Restricted units may be granted to such eligible individuals and with such terms as our Board of Directors may determine that are consistent with the EIP. Each award agreement evidencing a restricted unit will specify the restriction period(s), the number of restricted units subject to the award, and the performance, employment or other conditions (including termination as the result of death, disability or other reason) under which the restricted units will vest or be forfeited. Our Board of Directors may condition the grant of restricted units or the expiration of the restriction period(s) upon the participant’s achievement of one or more performance goal(s) specified in the award agreement. If the participant fails to achieve the specified performance goal(s), our Board of Directors will not grant the restricted units to the participant or the participant will forfeit such restricted units, as applicable. At the end of the restriction period(s), the restrictions imposed under the EIP and the applicable award agreement will lapse and the vested common units will be delivered to the participant. Our Board of Directors will determine and set forth in the participant’s award agreement whether or not the participant shall have the right to exercise voting rights with respect to the restricted units during the restriction period(s).
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Each restricted unit will include one unit distribution right, which is a contingent right to receive a cash payment equal to the cash distributions made on each common unit subject to the award. Unless provided otherwise in the applicable award agreement, distributions made pursuant to the unit distribution rights will be paid to the holder of the restricted unit without restriction at the same time distributions are paid to our other unitholders. The applicable award agreement may provide that distributions made pursuant to the unit distribution rights with respect to the restricted units will be subject to the same forfeiture and other restrictions as the restricted units and, if so restricted, such distributions shall be held, without interest, until the restricted units vest or are forfeited, as the case may be, in which case such distributions shall similarly be paid or forfeited, as the case may be.
Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of our Board of Directors, cash equivalent to the value of a common unit. Our Board of Directors will determine the number of phantom units to be granted to a participant, the restriction period, the conditions under which the phantom units may vest or be forfeited, which conditions may include, without limitation, accelerated vesting upon the achievement of specified performance goals, and such other terms and conditions as the Board of Directors of our general partner may establish, including whether distribution equivalent rights will be granted with respect to such phantom units. If the participant fails to achieve the specified performance goal(s) set forth in applicable award agreement, our Board of Directors will not grant the phantom units to the participant or the participant will forfeit such phantom units, as applicable. Upon vesting of each phantom unit, the participant shall receive one common unit or cash equal to the fair market value of a common unit on the date of vesting, as determined by our Board of Directors in its discretion. All unvested phantom units shall be forfeited by the participant except as otherwise provided by the applicable award agreement, upon termination of a participant’s service for any reason during the applicable restriction period.
Other Unit-Based Awards. Our Board of Directors, in its sole discretion, may grant other unit-based awards, including awards of common units and awards that are valued, in whole or in part, by reference to, or are otherwise based on, the fair market value of common units. Such other unit-based awards will be independent on such conditions as our Board of Directors may determine, including the right to receive one or more common units (or the equivalent cash value of such common units) upon the completion of a specified period of service, the occurrence of an event and/or the attainment of certain performance goals. Other unit-based awards may be granted alone or in addition to any other awards granted under the EIP. Our Board of Directors will determine to whom and when other unit-based awards will be made, the number of common units to be awarded under (or otherwise related to) such other unit-based awards, whether such other unit-based awards will be settled in cash, common units or a combination of cash and common units, and all other terms and conditions of such awards.
Distribution Equivalent Rights. To the extent provided by our board of directors, an award, other than an award of restricted units, may include a tandem distribution equivalent right grant. A tandem distribution equivalent right entitles the participant to receive a cash payment equal to the cash distributions made on a common unit during the period in which the underlying award is outstanding. Distribution equivalent rights will be subject to the same vesting restrictions as the underlying award, or be subject to such other provisions or restrictions as may be determined by our board of directors in its discretion. Any grant of distribution equivalent rights will be evidenced in the award agreement for the underlying award. Unless provided otherwise in the applicable award agreement, distributions made pursuant to the tandem distribution equivalent right will be paid to the participant without restriction at the same time distributions are paid to our other unit holders. A tandem distribution equivalent right will expire upon the forfeiture, vesting or exercise (as applicable), expiration or settlement of the underlying award.
Compensation Committee Interlocks and Insider Participation
As previously discussed, our general partner’s Board of Directors is not required to maintain, and does not maintain a compensation committee. During 2011, Norman J. Szydlowski, served as our general partner’s President and Chief Executive Officer, Chairman of the Board of Directors and also served as President and Chief Executive Officer of SemGroup. Also, during 2011, Robert N. Fitzgerald and Timothy O’Sullivan, who were a directors of our general partner, also served as executive officers of SemGroup. However, all compensation decisions with respect to each of these persons are made by SemGroup and none of these individuals receive any compensation directly from us or our general partner. Please read “Certain Relationships and Related Transactions, and Director Independence” below for information about relationships among us, our general partner and SemGroup.
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Compensation Policies and Practices as They Relate to Risk Management
We do not have any employees. We are managed and operated by the directors and officers of our general partner and employees of SemGroup perform services on our behalf. We do not have any compensation policies or practices that need to be assessed or evaluated for the effect on our operations. Please read “Compensation Discussion and Analysis” and “Certain Relationships and Related Transactions, and Director Independence” for more information about this arrangement. For an analysis of any risks arising from SemGroup’s compensation policies and practices, please read SemGroup’s 2012 Proxy Statement.
Compensation of Directors
The officers or employees of our general partner or of SemGroup who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers or employees of our general partner or of SemGroup receive compensation for their service as directors consisting of a $70,300 annual cash retainer and restricted units worth $39,300, which will vest on the first anniversary of the date of grant. The chairmen of the Conflicts Committee and Audit Committee will receive additional annual cash retainers in the amount of $7,500 and $15,000, respectively. In addition, non-employee directors will be reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or its committees. Each director will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.
Director Compensation Table for 2011
The following table sets forth the compensation of our non-employee directors in 2011.
| Name |
Fees Earned or Paid in Cash ($)(1) |
Unit Awards ($) |
Option Awards ($) |
Non-Equity Incentive Plan Compensation ($) |
Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) |
All Other Compensation ($) |
Total ($) |
|||||||||||||||||||||
| Rodney L. Gray |
3,624 | — | — | — | — | — | 3,624 | |||||||||||||||||||||
| Mark E. Monroe |
3,973 | — | — | — | — | — | 3,973 | |||||||||||||||||||||
| (1) | The amounts reflected in the above table reflect pro-rated retainer amounts earned for the period beginning December 9, 2011 and ending December 31, 2011. |
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters
The following table sets forth certain information regarding the beneficial ownership of units that, as of February 28, 2012, are held by:
| • | each person who is known to us to beneficially own more than 5% of such units to be outstanding; |
| • | each of the directors and named executive officers of our general partner; and |
| • | all of the directors and executive officers of our general partner as a group. |
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All information with respect to beneficial ownership has been furnished by the respective directors, officers or more than 5% unitholders as the case may be.
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options held by that person that are currently exercisable or exercisable within 60 days of February 28, 2012, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
The percentage of units beneficially owned is based on a total of 8,428,922 common units and 8,389,709 subordinated units outstanding.
| Name of Beneficial Owner(1) |
Common Units Beneficially Owned |
Percentage of Common Units Beneficially Owned |
Subordinated Units Beneficially Owned |
Percentage of Subordinated Units Beneficially Owned |
Percentage of Total Common and Subordinated Units Beneficially Owned |
|||||||||||||||
| SemGroup Corporation (2) |
1,389,709 | 16.5 | % | 8,389,709 | 100 | % | 58.10 | % | ||||||||||||
| The Northwestern Mutual Life Insurance Company (3) |
800,000 | 9.5 | % | — | — | 4.8 | % | |||||||||||||
| Kayne Anderson Capital Advisors, L.P. (4) |
722,189 | 8.6 | % | — | — | 4.3 | % | |||||||||||||
| The Goldman Sachs Group, Inc. (5) |
794,400 | 9.4 | % | — | — | 4.7 | % | |||||||||||||
| Invesco Ltd. (6) |
823,346 | 9.8 | % | — | — | 4.9 | % | |||||||||||||
| Norman J. Szydlowski |
22,191 | * | % | — | — | * | % | |||||||||||||
| Peter L. Schwiering |
8,404 | * | % | — | — | * | % | |||||||||||||
| Robert N. Fitzgerald |
5,366 | * | % | — | — | * | % | |||||||||||||
| Timothy O’Sullivan |
4,028 | * | % | — | — | * | % | |||||||||||||
| Rodney L. Gray |
1,866 | * | % | — | — | * | % | |||||||||||||
| Mark E. Monroe |
6,866 | * | % | — | — | * | % | |||||||||||||
| Candice L. Cheeseman |
6,814 | * | % | — | — | * | % | |||||||||||||
| Paul Largess |
867 | * | % | — | — | * | % | |||||||||||||
| All directors and executive officers as a group (8 persons) |
56,402 | * | % | — | — | * | % | |||||||||||||
| * | Less than 1%. |
| (1) | Unless otherwise indicated, the address for all beneficial owners in this table is Two Warren Place, 6120 S. Yale Avenue, Suite 700, Tulsa, Oklahoma 74136-4216. |
| (2) | SemGroup Corporation may be deemed to beneficially own the 1,389,709 common units and 8,389,709 subordinated units beneficially owned by Rose Rock Midstream Holdings, LLC. |
| (3) | This information is as of December 31, 2011, as reported in a Schedule 13G filed by The Northwestern Mutual Life Insurance Company, 720 East Wisconsin Avenue, Milwaukee, Wisconsin, 53202. The Schedule 13G reports that Mason Street Advisors, LLC, a wholly owned company of The Northwestern Mutual Life Insurance Company and a registered investment advisor, serves as an investment advisor to Northwestern Mutual Life Insurance Company and shares voting and investment power with respect to the reported units. |
| (4) | This information is as of December 31, 2011, as reported in a Schedule 13G filed by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne, each with an address of 1800 Avenue of the Stars, Third Floor, Los Angeles, California 90067. The Schedule 13G reports that Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne share voting and investment power with respect to the reported units. |
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| (5) | This information is as of December 31, 2011, as reported in a Schedule 13G filed by The Goldman Sachs Group, Inc. and Goldman, Sachs & Co., each with an address of 200 West Street, New York, New York 10282. The Schedule 13G reports that The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. share voting and investment power with respect to the reported units. |
| (6) | This information is as of December 31, 2011, as reported in a Schedule 13G filed by Invesco Ltd., 1555 Peachtree Street NE, Atlanta, GA 30309. The Schedule 13G reports that Invesco Ltd. has the sole voting and investment power with respect to the reported units. |
The following table sets forth, as of February 28, 2012, the number of shares of SemGroup’s Class A common stock owned by each of the directors and executive officers of our general partner and all directors and executive officers of our general partner as a group. None of the directors or executive officers beneficially owns any of SemGroup’s Class B common stock.
| Name of Beneficial Owner(1) |
Shares of Class A Common Stock Owned Directly or Indirectly |
Shares of Class A Common Stock Underlying Options Exercisable Within 60 Days |
Total Shares of Class A Common Stock Beneficially Owned (2) |
Percentage of Total Shares of Class A Common Stock Beneficially Owned |
||||||||||||
| Norman J. Szydlowski |
146,635 | — | 146,635 | * | ||||||||||||
| Peter L. Schwiering |
13,383 | — | 13,383 | * | ||||||||||||
| Robert N. Fitzgerald |
29,451 | — | 29,451 | * | ||||||||||||
| Timothy O’Sullivan |
14,373 | — | 14,373 | * | ||||||||||||
| Rodney L. Gray |
— | — | — | — | ||||||||||||
| Mark E. Monroe |
— | — | — | — | ||||||||||||
| Candice L. Cheeseman |
23,254 | — | 25,499 | * | ||||||||||||
| Paul Largess |
9,670 | — | 9,670 | * | ||||||||||||
| All directors and executive officers as a group (8 persons) |
236,766 | — | 239,011 | * | ||||||||||||
| * | Less than 1%. |
| (1) | The address for all beneficial owners in this table is Two Warren Place, 6120 S. Yale Avenue, Suite 700, Tulsa, Oklahoma 74136-4216. |
| (2) | Shares beneficially owned include shares of restricted Class A common stock held by the directors and executive officers over which they have voting power but not investment power. |
| (3) | Of the 146,635 shares held by Mr. Szydlowski, 46,600 shares are held of record by the Szydlowski Family Trust Agreement, dated June 9, 2004, of which Mr. Szydlowski is the trustee. |
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information with respect to the securities that may be issued under the Rose Rock Midstream Equity Incentive Plan as of December 31, 2011. For more information regarding the Rose Rock Midstream Equity Incentive Plan, which did not require approval by our unitholders, please see “Item 11. Executive Compensation – Equity Incentive Plan.”
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| Plan Category |
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights |
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights |
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a) ) |
|||||||||
| (a) | — | — | ||||||||||
| Equity compensation plans approved by security holders |
— | — | — | |||||||||
| Equity compensation plans not approved by security holders (1) |
— | — | 840,000 | (2) | ||||||||
|
|
|
|
|
|
|
|||||||
| Total |
— | — | 840,000 | |||||||||
| (1) | The Board of Directors of our general partner adopted the Rose Rock Midstream Equity Incentive Plan in connection with our initial public offering. |
| (2) | Common units may be issued under the Rose Rock Midstream Equity Incentive Plan pursuant to the following type of awards: options, unit appreciation rights, restricted units, phantom units and other unit-based awards. |
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Item 13. Certain Relationships and Related Transactions, and Director Independence
Relationship with SemGroup Corporation
SemGroup Corporation owns our sole general partner, Rose Rock GP, and appoints members of our Board of Directors and/or Audit and Conflicts Committees. Other relationships with Rose Rock GP include the following:
Cash Distributions
SemGroup Corporation and its affiliates own 1,389,709 common units and 8,389,709 subordinated units, which together constitutes a 57.0% limited partnership interest in us at January 31, 2012. In addition, SemGroup owns our general partner, which owns a 2.0% general partner interest in us and all of our incentive distribution rights. Information about our cash distribution policy is included under the caption “Cash Distributions” beginning on page 51.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including SemGroup), on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders.
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, including a transaction with an affiliate, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.
Our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of, or course of action taken with respect to, a conflict is:
| • | approved by the Conflicts Committee, although our general partner is not obligated to seek such approval; |
| • | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; |
| • | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| • | fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
Our general partner may, but is not required to, seek the approval of the resolution of, or course of action taken, with respect to a conflict of interest from the Conflicts Committee. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the Conflicts Committee and its Board of Directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to have a subjective belief that he is acting in, or not opposed to, the interests of the partnership.
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Direct Employee Expenses
We do not directly employ any persons to manage or operate our business. These functions are performed by employees of SemGroup. SemGroup charged us $11.3 million during the year ended December 31, 2011, for direct employee costs.
Allocated Expenses
SemGroup incurs expenses to provide certain indirect corporate general and administrative services to us. Such expenses include employee compensation costs, professional fees and rental fees for office space, among other expenses. SemGroup charged us $4.5 million during the year ended December 31, 2011, for such allocated costs.
Liability Transfer
On December 15, 2011, we transferred a liability to SemGroup after receiving an indemnification against any loss pursuant to the terms of an omnibus agreement between Rose Rock and SemGroup. This liability related to revenue which was deferred pending resolution of a dispute which arose in connection to a sale of crude oil in June 2011. The transfer of this liability to SemGroup is a non-cash transaction which is not reflected in our consolidated statement of cash flow for the year ended December 31, 2011.
SemGroup Credit Facilities
Prior to our initial public offering, we utilized letters of credit under SemGroup’s credit facilities. Subsequent to our initial public offering, which was completed on December 14, 2011, we no longer utilize letters or credit under SemGroup’s credit facilities and our assets no longer serve as collateral under SemGroup’s credit agreement.
Agreements with SemGroup and its Affiliates
We and other parties have entered into various documents and agreements with certain of our affiliates, as described in more detail below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.
Contribution Agreement
On November 29, 2011, we entered into a contribution agreement with SemGroup and certain SemGroup subsidiaries which effected the following transactions:
| • | the distribution by SemCrude, L.P. to SemGroup of: |
| • | certain inactive assets and certain liabilities; and |
| • | all of its interests in SemCrude Pipeline, L.L.C., which holds a 51% interest in the White Cliffs Pipeline; and |
| • | the contribution by SemGroup to us of 100% of the limited and general partner interests in SemCrude, L.P. |
Omnibus Agreement
In connection with the closing of our initial public offering, we entered into an omnibus agreement with our general partner and SemGroup which addresses certain aspects of our relationship with them, including:
| • | our use of the names “Rose Rock” and “SemCrude” and related marks; and |
| • | certain indemnification obligations including, among others, the following: |
| • | SemGroup’s obligation to indemnify us for losses relating to certain environmental matters relating to our assets arising on or prior to the date we closed our initial public offering; |
| • | our obligation to indemnify SemGroup for losses relating to certain environmental matters relating to our assets arising after the closing of our initial public offering; |
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| • | SemGroup’s obligation to indemnify us for losses relating to or arising from (i) certain title and rights-of-way matters, (ii) our failure to have certain necessary governmental consents and permits, (iii) assets previously owned by SemCrude and retained by SemGroup, (iv) certain environmental liabilities retained by SemGroup, (v) certain scheduled matters and claims relating to SemGroup’s bankruptcy, (vi) certain regulatory matters and (vii) certain tax liabilities; and |
| • | our obligation to indemnify SemGroup for losses attributable to the ownership or operation of our assets and the assets of our subsidiaries after the closing of our initial public offering. |
SemGroup’s obligations to indemnify us as described in the first and third bullets above are subject to a deductible of $500,000. SemGroup’s obligations to indemnify us with respect to environmental liabilities relating to our assets, title and rights-of-way matters, failure to have certain necessary governmental consents and permits, retained assets and retained environmental liabilities terminate after 3 years, and its obligation to indemnify us with respect to certain regulatory matters terminates after 5 years. SemGroup’s indemnity related to tax matters terminates upon the expiration of the statute of limitations. SemGroup’s obligation to indemnify us with respect to environmental liabilities relating to our assets and regulatory matters is capped at $20 million. In no event will SemGroup be obligated to indemnify us for any claims, losses, expenses or liabilities to the extent any such amounts are reserved for in our financial statements as of the closing of our initial public offering. No party will be obligated to indemnify any other party for losses to the extent that such losses are recovered by the indemnified party under available insurance coverage or from a third party.
The omnibus agreement can be amended by written agreement of all parties to the agreement. However, we may not agree to any amendment or modification that would, in the determination of our general partner, be adverse in any material respect to the holders of our common units without prior approval of the Conflicts Committee. In the event of (i) a “change in control” (as defined in the omnibus agreement) of our general partner or (ii) the removal of Rose Rock GP as our general partner in circumstances where “cause” (as defined in our partnership agreement) does not exist and the common units held by SemGroup and its affiliates were not voted in favor of such removal, the omnibus agreement (other than the indemnification provisions if the triggering event is a change of control) will be terminable by SemGroup, and we will have a 90-day transition period to cease our use of the name “Rose Rock” and related marks.
SemGroup and its affiliates are not restricted, under either our partnership agreement or the omnibus agreement, from competing with us. SemGroup is permitted to compete with us and may acquire or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase those assets.
Other Transactions with SemGroup Related Persons
We engage in certain transactions with other subsidiaries of SemGroup. These transactions include:
| • | providing leased storage and management services for White Cliffs Pipeline, which generated $2.2 million of revenues in the year ended December 31, 2011; |
| • | purchasing condensate from SemStream, L.P., certain of which purchases were fixed price forward purchases, which we recorded at fair value at each balance sheet date. For the year ended December 31, 2011, we purchased $46.7 million of condensate from SemStream, L.P.; |
| • | purchasing condensate from SemGas, L.P. For the year ended December 31, 2011, we purchased $6.5 million of condensate from SemGas, L.P.; |
| • | prior to our initial public offering, we participated in SemGroup’s cash management program, pursuant to which cash we received from customers was transferred to SemGroup on a regular basis, and when we remitted payments to suppliers, SemGroup transferred cash to us to cover the payments; and |
| • | purchasing natural gasoline from NGL Energy Partners LP in the amount of $8.9 million. |
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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, our general partner’s General Counsel and Secretary. Mr. Berman does not perform any legal services for us. We paid $6,817 in legal fees and related expenses to this law firm for services rendered to us during 2011.
Procedures for Review, Approval and Ratification of Related Person Transactions
Our Board of Directors has adopted a Related Person Transaction Policy that establishes procedures for the identification, review and approval of related person transactions. Pursuant to the policy, the General Counsel of our general partner is charged with primary responsibility for determining whether, based on the facts and circumstances, a proposed transaction is a related person transaction. For the purposes of the policy, a “related person transaction” is any transaction, arrangement or relationship (or any series of similar transactions, arrangements or relationships) in which (i) we, our general partner or any of our subsidiaries participate or will participate, (ii) the amount involved exceeds $120,000, and (iii) any executive officer, director or director nominee of our general partner, any person who is the beneficial owner of more than 5% of any class of our voting securities, or any immediate family member of any of the foregoing individuals (a “related person”) has or will have a direct or indirect material interest.
To assist our General Counsel in making this determination, the policy sets forth certain categories of transactions that are deemed not to involve a direct or indirect material interest on the part of the related person. If, after applying these categorical standards and weighing all of the facts and circumstances, our General Counsel determines that a proposed transaction is a related person transaction, our General Counsel must present the proposed transaction to the Conflicts Committee of our Board of Directors for review or, if impracticable under the circumstances, to the Chairman of such committee. The conflicts committee must then either approve or reject the transaction in accordance with the terms of the policy. In the course of making this determination, the Conflicts Committee will consider all relevant information available to it and, as appropriate, take into consideration the following:
| • | whether the transaction was undertaken in our ordinary course of business; |
| • | whether the transaction was initiated by us or the related person; |
| • | whether the transaction with the related person is proposed to be entered into on terms no less favorable to us than terms that could have been reached with an unrelated third party; |
| • | the purpose, and the potential benefits to us, of the transaction; |
| • | the approximate dollar value of the amount involved in the transaction and whether such amount is material to us; |
| • | the related person’s interest in the transaction (including the approximate dollar value of the amount of the such related person’s interest in the transaction); and |
| • | any other information regarding the transaction or related person that would be material to investors in light of the circumstances of the particular transaction. |
The Conflicts Committee may approve or ratify a related person transaction only if it determines that the transaction is consistent with our best interests as a whole. Further, in approving any such transaction, the conflicts committee has the authority to impose any terms or conditions it deems appropriate on us or the related person. Absent this approval, no such related person transaction may be entered into by us.
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The related person transactions described above were entered into and/or were on-going prior to our initial public offering and prior to our adoption of the Related Person Transaction Policy, and as a result, the related person transactions described above have not been reviewed or approved under such policy.
In addition to the above, we require each executive officer and director of our general partner to annually provide us written disclosure of any transaction between the officer or director and us. Our Board of Directors reviews this disclosure in connection with its annual review of the independence of our Board of Directors and our Audit and Conflicts Committees. These procedures are not in writing but are documented through the meeting agendas of our Board of Directors.
Director Independence
The NYSE does not require a listed publicly traded partnership like us to have a majority of independent directors on the Board of Directors of our general partner. Please read “Directors, Executive Officers and Corporate Governance—Board of Directors of Our General Partner”, beginning on page 77 in Item 10 above, for information about the independence of our general partner’s Board of Directors and its committees, which information is incorporated into this Item 13 by reference.
Item 14. Principal Accountant Fees and Services
Fees of Independent Registered Public Accounting Firm
We have engaged BDO USA, LLP as our independent registered public accounting firm. The following table sets forth fees billed for professional serviced rendered by BDO USA, LLP to audit our annual financial statements and for other services in 2011 and 2010.
| 2011 | 2010 | |||||||
| Audit fees (1) |
$ | 502,302 | $ | — | ||||
| Audit-related fees |
— | — | ||||||
| Tax fees |
— | — | ||||||
| All other fees |
— | — | ||||||
|
|
|
|
|
|||||
| Total |
$ | 502,302 | $ | — | ||||
|
|
|
|
|
|||||
| (1) | Includes fees related to the initial public offering of Rose Rock. |
Audit Committee Pre-Approval Policy
The Audit Committee of our general partner pre-approves all audit and permissible non-audit services by the independent registered public accounting firm prior to the receipt of such services. All services set forth in the table above were pre-approved by the Audit Committee of SemGroup Corporation (our general partner did not yet have an Audit Committee at the time the services were approved).
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Item 15. Exhibits and Financial Statement Schedules
| (a) | (1) Financial Statements. The consolidated financial statements included in this Form 10-K are listed on page F-1, which follows the signature page to this Form 10-K. | |
| (2) Financial Statement Schedules. All financial statement schedules are omitted as inapplicable or because the required information is contained in the financial statements or the notes thereto. | ||
| (3) Exhibits. The following documents are included as exhibits to this Form 10-K. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, such exhibit is filed herewith. | ||
| Exhibit |
Description | |
| 3.1 | Certificate of Limited Partnership of Rose Rock Midstream, L.P. (filed as Exhibit 3.1 to Registrant’s registration statement on Form S-1 (File No. 333-176260) (the “Form S-1”), filed with the Commission on August 12, 2011). | |
| 3.2 | Second Amended and Restated Agreement of Limited Partnership of Rose Rock Midstream, L.P. (filed as Exhibit 3.1 to the Registrant’s current report on Form 8-K (File No. 001-35365), filed with the Commission on December 20, 2011). | |
| 3.3 | Certificate of Formation of Rose Rock Midstream GP, LLC (filed as Exhibit 3.4 to the Form S-1, filed with the Commission on August 12, 2011). | |
| 3.4 | First Amended and Restated Limited Liability Company Agreement of Rose Rock Midstream GP, LLC (filed as Exhibit 3.2 to the Registrant’s current report on Form 8-K (file No. 001-35365), filed with the Commission on December 20, 2011). | |
| 10.1 | Credit Agreement, dated November 10, 2011, among Rose Rock Midstream, L.P., as borrower, The Royal Bank of Scotland PLC, as administrative agent and collateral agent, the other agents party thereto and the lenders and issuing banks party thereto (filed as Exhibit 10.1 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 10.2 | Contribution, Conveyance and Assumption Agreement, dated November 29, 2011, by and among SemGroup Corporation, certain subsidiaries of SemGroup Corporation and Rose Rock Midstream, L.P. (filed as Exhibit 10.2 to the Form S-1, filed with the Commission on December 1, 2011). | |
| 10.3* | Rose Rock Midstream Equity Incentive Plan (filed as Exhibit 10.1 to the Registrant’s current report on Form 8-K (File No. 001-35365), filed with the Commission on December 14, 2011). | |
| 10.3.1* | Form of Restricted Unit Award Agreement (Employees) under the Rose Rock Midstream Equity Incentive Plan. | |
| 10.3.2* | Form of Restricted Unit Award Agreement (Directors) under the Rose Rock Midstream Equity Incentive Plan (filed as Exhibit 10.3.2 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 10.3.3* | Form of Phantom Unit Award Agreement under the Rose rock Midstream Equity Incentive Plan (filed as Exhibit 10.3.3 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 10.4 | Omnibus Agreement dated as of December 14, 2011, among the Registrant, SemGroup Corporation and Rose Rock Midstream GP, LLC (filed as Exhibit 10.1 to the Registrant’s current report on Form 8-K (File No. 001-35365), filed with the Commission on December 20, 2011). | |
| 10.5* | Employee Agreement, dated as of November 30, 2009, by and among SemManagement, L.L.C., SemGroup Corporation and Norman J. Szydlowski (incorporated by reference to 10.11 the Registration Statement on Form 10 of SemGroup Corporation (File No. 001-34736) filed on May 6, 2010) | |
96
| 10.6* | Letter Amendment dated March 18, 2010, by and among SemManagement, L.L.C., SemGroup Corporation and Norman J. Szydlowski, amending the Employment Agreement dated as of November 30, 2009 (incorporated by reference to Exhibit 10.12 the Registration Statement on Form 10 of SemGroup Corporation (File No. 001-34736 filed on May 6, 2010) | |
| 10.7* | Form of Severance Agreement between SemGroup Corporation and each of its executive officers other than Norman J. Szydlowski and David B. Gorte (incorporated by reference to Exhibit 10.13 of the Registration Statement on Form 10 of SemGroup (file No. 001-34736) filed on July 23, 2010) | |
| 10.8 | Crude Oil Storage Services Agreement, dated effective February 1, 2009, by and between SemCrude L.P. and Gavilon, L.L.C. (filed as Exhibit 10.8 to the Form S-1, filed with the Commission on September 30, 2011). | |
| 10.9 | First Amendment to Crude Oil Storage Services Agreement, dated effective May 1, 2009, by and between Gavilon, LLC and SemCrude, L.P. (filed as Exhibit 10.9 to the Form S-1, filed with the Commission on September 30, 2011). | |
| 10.10 | Second Amendment to Crude Oil Storage Services Agreement, dated effective October 1, 2009, by and between Gavilon, LLC and SemCrude, L.P. (filed as Exhibit 10.10 to the Form S-1, filed with the Commission on September 30, 2011). | |
| 10.11 | Third Amendment to Crude Oil Storage Services Agreement, dated May 4, 2010, by and between Gavilon, LLC and SemCrude, L.P. (filed as Exhibit 10.11 to the Form S-1, filed with the Commission on September 30, 2011). | |
| 10.12 | Fourth Amendment to Crude Oil Storage Services Agreement, dated effective as of October 7, 2011, by and between SemCrude, L.P. and Gavilon LLC (filed as Exhibit 10.12 to the Form S-1, filed with the Commission on October 11, 2011). | |
| 10.13* | Form of Rose Rock Midstream GP, LLC Board of Directors Compensation Plan (filed as Exhibit 10.13 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 10.14* | Form of Amendment to Severance Agreement between SemGroup Corporation and each of its executive officers other than Norman J. Szydlowski and David B. Gorte (filed as Exhibit 10.14 to the Form S-1, filed with the Commission on November 23, 2011). | |
| 21.1 | List of subsidiaries of Rose Rock Midstream, L.P. (filed as Exhibit 21.1 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 23.1 | Consent of BDO USA, LLP | |
| 31.1 | Rule 13a – 14(a)/15d – 14(a) Certification of Norman J. Szydlowski, Chief Executive Officer. | |
| 31.2 | Rule 13a – 14(a)/15d – 14(a) Certification of Robert N. Fitzgerald, Chief Financial Officer. | |
| 32.1 | Section 1350 Certification of Norman J. Szydlowski, Chief Executive Officer. | |
| 32.2 | Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Office. | |
| 101 | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) the Consolidated Balance Sheets as of December 31, 2011 and 2010, (ii) the Consolidated Statements of Income for the years ended December 31, 2011 and 2010, the month ended December 31, 2009 (subsequent to emergence) and the eleven months ended November 30, 2009 (prior to emergence), (iii) the Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2011 and 2010, the month ended December 31, 2009 (subsequent to emergence), and the eleven months ended November 30, 2009 (prior to emergence), (iv) the Consolidated Statements of Cash Flows for the years ended December 31, 2011 and 2010, the month ended December 31, 2009 (subsequent to emergence) and the eleven months ended November 30, 2009 (prior to emergence) and (v) the Notes to Consolidated Financial Statements. | |
| * | Management contract or compensatory plan or arrangement. |
97
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
| ROSE ROCK MIDSTREAM, L.P. | ||||||
| Date: February 29, 2012 | ||||||
| By: | /s/ Robert N. Fitzgerald | |||||
| Robert N. Fitzgerald | ||||||
| Senior Vice President and | ||||||
| Chief Financial Officer | ||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
| Signature | Title | Date | ||
| /s/ Norman J. Szydlowski |
President, Chief Executive Officer | February 29, 2012 | ||
| Norman J. Szydlowski | and Chairman (Principal Executive Officer) | |||
| /s/ Robert N. Fitzgerald |
Senior Vice President and Chief Financial Officer and |
February 29, 2012 | ||
| Robert N. Fitzgerald | Director (Principal Financial Officer) | |||
| /s/ Peter L. Schwiering |
Chief Operating Officer and Director | February 29, 2012 | ||
| Peter L. Schwiering | ||||
| /s/ Paul F. Largess |
Vice President, Chief Accounting Officer and Controller |
February 29, 2012 | ||
| Paul F. Largess | (Principal Accounting Officer) | |||
| /s/ Timothy O’Sullivan |
Vice President and Director | February 29, 2012 | ||
| Timothy O’Sullivan | ||||
| /s/ Rodney L. Gray |
Director | February 29, 2012 | ||
| Rodney L. Gray | ||||
| /s/ Mark E. Monroe |
Director | February 29, 2012 | ||
| Mark E. Monroe | ||||
98
Index to Financial Statements
Rose Rock Midstream, L.P.
| Page | ||||
| Historical audited financial statements: |
||||
| F-2 | ||||
| Consolidated Balance Sheets as of December 31, 2011 and 2010 |
F-3 | |||
| F-4 | ||||
| F-5 | ||||
| F-6 | ||||
| F-7 | ||||
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors and Unitholders
Rose Rock Midstream, L.P.
Tulsa, Oklahoma
We have audited the accompanying consolidated balance sheets of Rose Rock Midstream, L.P. (the “Company”) as of December 31, 2011 and 2010 (Successor) and the related consolidated statements of income, partners’ capital (deficit), and cash flows for the years ended December 31, 2011 and 2010, and for the one month ended December 31, 2009 (Successor), and for the eleven months ended November 30, 2009 (Predecessor). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Rose Rock Midstream, L.P. at December 31, 2011 and 2010 (Successor), and the results of its operations and its cash flows for the years ended December 31, 2011 and 2010, and the one month ended December 31, 2009 (Successor) and the eleven months ended November 30, 2009 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, effective November 30, 2009, the Company emerged from bankruptcy and applied fresh-start accounting. As a result, the consolidated statements of income and cash flows for the years ended December 31, 2011 and 2010, and the one month ended December 31, 2009, are presented on a different basis than that for periods prior to fresh-start and, therefore, are not comparable.
/s/ BDO USA, LLP
BDO USA, LLP
Dallas, Texas
February 29, 2012
F-2
ROSE ROCK MIDSTREAM, L.P.
(Dollars in thousands)
| December 31, | December 31, | |||||||
| 2011 | 2010 | |||||||
| ASSETS |
||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 9,709 | $ | 303 | ||||
| Accounts receivable |
131,655 | 73,387 | ||||||
| Receivable from affiliates |
2,210 | 80 | ||||||
| Inventories |
21,803 | 17,968 | ||||||
| Other current assets |
1,205 | 4,280 | ||||||
|
|
|
|
|
|||||
| Total current assets |
166,582 | 96,018 | ||||||
|
|
|
|
|
|||||
| Property, plant and equipment (net of accumulated depreciation of $22,611 at December 31, 2011 and $11,243 at December 31, 2010) |
276,246 | 260,048 | ||||||
| Other assets, net |
2,666 | 1,065 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 445,494 | $ | 357,131 | ||||
|
|
|
|
|
|||||
| LIABILITIES AND PARTNERS’ CAPITAL |
||||||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 125,681 | $ | 51,210 | ||||
| Payable to affiliates |
7,991 | 2 | ||||||
| Accrued liabilities |
4,708 | 10,278 | ||||||
| Other current liabilities |
2,173 | 5,653 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
140,553 | 67,143 | ||||||
|
|
|
|
|
|||||
| Long-term debt |
87 | — | ||||||
| Commitments and contingencies (Note 7) |
||||||||
| Partners’ Capital: |
||||||||
| Common units—public (7,000,000 units issued and outstanding at December 31, 2011) |
127,531 | — | ||||||
| Common units—SemGroup (1,389,709 units issued and outstanding at December 31, 2011) |
37,739 | — | ||||||
| Subordinated units—SemGroup (8,389,709 units issued and outstanding at December 31, 2011) |
133,487 | — | ||||||
| General partner units—SemGroup (342,437 units issued and outstanding at December 31, 2011) |
6,097 | — | ||||||
| Predecessor partners’ capital |
— | 289,988 | ||||||
|
|
|
|
|
|||||
| Total Partners’ Capital |
304,854 | 289,988 | ||||||
|
|
|
|
|
|||||
| Total liabilities and partners’ capital |
$ | 445,494 | $ | 357,131 | ||||
|
|
|
|
|
|||||
The accompanying notes are an integral part of these consolidated financial statements.
F-3
ROSE ROCK MIDSTREAM, L.P.
Consolidated Statements of Income
(In thousands, except per unit amounts)
| Subsequent to Emergence | Prior to Emergence | |||||||||||||||
| Year | Year | Month | Eleven Months | |||||||||||||
| Ended | Ended | Ended | Ended | |||||||||||||
| December | December | December | November | |||||||||||||
| 31, 2011 | 31, 2010 | 31, 2009 | 30, 2009 | |||||||||||||
| Revenues, including revenues from affiliates (Note 12): |
||||||||||||||||
| Product |
$ | 395,301 | $ | 158,308 | $ | 6,724 | $ | 197,203 | ||||||||
| Service |
35,801 | 49,408 | 3,891 | 40,281 | ||||||||||||
| Other |
219 | 365 | — | 3 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total revenues |
431,321 | 208,081 | 10,615 | 237,487 | ||||||||||||
| Expenses, including expenses from affiliates (Note 12): |
||||||||||||||||
| Costs of products sold, exclusive of depreciation and amortization shown below |
366,265 | 146,614 | 5,969 | 180,154 | ||||||||||||
| Operating |
18,973 | 20,398 | 1,536 | 15,614 | ||||||||||||
| General and administrative |
9,843 | 7,660 | 1,270 | 5,813 | ||||||||||||
| Depreciation and amortization |
11,379 | 10,435 | 818 | 3,193 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total expenses |
406,460 | 185,107 | 9,593 | 204,774 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating income |
24,861 | 22,974 | 1,022 | 32,713 | ||||||||||||
| Other expenses (income): |
||||||||||||||||
| Interest expense |
1,823 | 482 | 43 | 1,699 | ||||||||||||
| Other expense (income), net |
(197 | ) | (985 | ) | (306 | ) | (1,602 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total other expenses (income), net |
1,626 | (503 | ) | (263 | ) | 97 | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income before reorganization items |
23,235 | 23,477 | 1,285 | 32,616 | ||||||||||||
| Reorganization items gain, including expenses allocated from affiliates (Note 3), net |
— | — | — | 99,936 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income |
$ | 23,235 | $ | 23,477 | $ | 1,285 | $ | 132,552 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Allocation of net income used for earnings per unit calculation: |
||||||||||||||||
| Net income |
$ | 23,235 | ||||||||||||||
| Less: Net income prior to initial public offering on December 14, 2011 |
22,265 | |||||||||||||||
|
|
|
|||||||||||||||
| Net income subsequent to initial public offering on December 14, 2011 |
$ | 970 | ||||||||||||||
|
|
|
|||||||||||||||
| Allocation of net income subsequent to initial public offering: |
||||||||||||||||
| Net income allocated to general partner |
$ | 19 | ||||||||||||||
|
|
|
|||||||||||||||
| Net income allocated to common unitholders |
$ | 475.5 | ||||||||||||||
|
|
|
|||||||||||||||
| Net income allocated to subordinated unitholders |
$ | 475.5 | ||||||||||||||
|
|
|
|||||||||||||||
| Earnings per limited partner unit subsequent to initial public offering: |
||||||||||||||||
| Common unit (basic and diluted) |
$ | 0.06 | ||||||||||||||
|
|
|
|||||||||||||||
| Subordinated unit (basic and diluted) |
$ | 0.06 | ||||||||||||||
|
|
|
|||||||||||||||
| Weighted average number of limited partner units outstanding: |
||||||||||||||||
| Common units (basic and diluted) |
8,390 | |||||||||||||||
|
|
|
|||||||||||||||
| Subordinated units (basic and diluted) |
8,390 | |||||||||||||||
|
|
|
|||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
ROSE ROCK MIDSTREAM, L.P.
Consolidated Statements of Changes in Partners’ Capital (Deficit)
(Dollars in thousands)
| Common Units - Public |
Common Units - SemGroup |
Subordinated Units |
General Partner Interest |
Predecessor Net Partners’ Capital (Deficit) |
Total Partners’ Capital |
|||||||||||||||||||
| Balance at December 31, 2008 (Prior to emergence) |
$ | — | $ | — | $ | — | $ | — | $ | (1,136,417 | ) | $ | (1,136,417 | ) | ||||||||||
| Net loss, prior to implementation of Plan of Reorganization |
— | — | — | — | (20,328 | ) | (20,328 | ) | ||||||||||||||||
| Other |
— | — | — | — | (17 | ) | (17 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Balance prior to implementation of Plan of Reorganization |
— | — | — | — | (1,156,762 | ) | (1,156,762 | ) | ||||||||||||||||
| Implementation of Plan of Reorganization |
— | — | — | — | 1,437,132 | 1,437,132 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Balance at November 30, 2009 (Subsequent to emergence) |
280,370 | 280,370 | ||||||||||||||||||||||
| Net income |
— | — | — | — | 1,285 | 1,285 | ||||||||||||||||||
| Net distributions to SemGroup |
— | — | — | — | (1,441 | ) | (1,441 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Balance at December 31, 2009 (Subsequent to emergence) |
— | — | — | — | 280,214 | 280,214 | ||||||||||||||||||
| Net income |
— | — | — | — | 23,477 | 23,477 | ||||||||||||||||||
| Net distributions to SemGroup |
— | — | — | — | (13,703 | ) | (13,703 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Balance at December 31, 2010 (Subsequent to emergence) |
— | — | — | — | 289,988 | 289,988 | ||||||||||||||||||
| Net income attributable to the period from January 1, 2011 through November 29, 2011 |
— | — | — | — | 21,087 | 21,087 | ||||||||||||||||||
| Net distributions to SemGroup |
— | — | — | — | (20,349 | ) | (20,349 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Balance at November 29, 2011, prior to contribution of assets |
— | — | — | — | 290,726 | 290,726 | ||||||||||||||||||
| Contribution of deferred organizational costs |
— | — | — | — | 3,065 | 3,065 | ||||||||||||||||||
| Net liabilities of predecessor not contributed to Rose Rock Midstream, L.P. |
— | — | — | — | 3,073 | 3,073 | ||||||||||||||||||
| Contribution of net assets to Rose Rock Midstream, L.P. in exchange for common units, subordinated units, incentive distribution rights, and a 2% general partner interest |
— | 35,843 | 124,945 | 5,876 | (166,664 | ) | — | |||||||||||||||||
| Net income attributable to the period from November 29, 2011 to December 14, 2011 |
— | 577 | 577 | 24 | — | 1,178 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Balance at December 14, 2011, prior to initial public offering |
— | 36,420 | 125,522 | 5,900 | 130,200 | 298,042 | ||||||||||||||||||
| Issuance of common units to the public, net of underwriters’ discount and fees |
127,134 | — | — | — | — | 127,134 | ||||||||||||||||||
| Net distributions to SemGroup |
— | — | — | — | (130,200 | ) | (130,200 | ) | ||||||||||||||||
| Transfer liability to SemGroup on December 15, 2011 |
— | 1,241 | 7,489 | 178 | — | 8,908 | ||||||||||||||||||
| Net income attributable to the period from December 15, 2011 to December 31, 2011 |
397 | 78 | 476 | 19 | — | 970 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Balance at December 31, 2011 |
$ | 127,531 | $ | 37,739 | $ | 133,487 | $ | 6,097 | $ | — | $ | 304,854 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
ROSE ROCK MIDSTREAM, L.P.
Consolidated Statements of Cash Flows
(Dollars in thousands)
| Subsequent to Emergence | Prior to Emergence | |||||||||||||||
| Year | Year | Month | Eleven Months | |||||||||||||
| Ended | Ended | Ended | Ended | |||||||||||||
| December 31, | December 31, | December 31, | November 30, | |||||||||||||
| 2011 | 2010 | 2009 | 2009 | |||||||||||||
| Cash flows from operating activities: |
||||||||||||||||
| Net income |
$ | 23,235 | $ | 23,477 | $ | 1,285 | $ | 132,552 | ||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||||||
| Depreciation and amortization |
11,379 | 10,435 | 818 | 3,193 | ||||||||||||
| Loss (gain) on disposal of long-lived assets, net |
64 | 67 | — | (40 | ) | |||||||||||
| Non-cash reorganization items |
— | — | — | (24,682 | ) | |||||||||||
| Provision for (recovery of) uncollectible accounts receivable |
(916 | ) | 3,340 | — | — | |||||||||||
| Gain on fresh start reporting |
— | — | — | (152,880 | ) | |||||||||||
| Changes in assets and liabilities: |
||||||||||||||||
| Decrease (increase) in restricted cash |
— | 16,681 | (3,022 | ) | (13,659 | ) | ||||||||||
| Decrease (increase) in accounts receivable |
(57,352 | ) | (69,904 | ) | 5,277 | 630,706 | ||||||||||
| Decrease (increase) in receivable from affiliates |
(2,130 | ) | (80 | ) | — | — | ||||||||||
| Decrease (increase) in inventories |
44 | (3,210 | ) | (2,161 | ) | 12,105 | ||||||||||
| Decrease (increase) in margin deposits |
1,410 | (2,006 | ) | — | — | |||||||||||
| Decrease (increase) in other current assets |
208 | 3,801 | (399 | ) | (2,608 | ) | ||||||||||
| Decrease (increase) in other assets |
(368 | ) | 121 | 1,587 | 3,231 | |||||||||||
| Increase (decrease) in accounts payable and accrued liabilities |
66,643 | 48,005 | (1,015 | ) | (528,733 | ) | ||||||||||
| Increase (decrease) in payable to affiliates |
7,989 | 2 | — | — | ||||||||||||
| Change in net derivative asset / liability |
(787 | ) | 763 | (282 | ) | (254 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net cash provided by operating activities |
49,419 | 31,492 | 2,088 | 58,931 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash flows from investing activities: |
||||||||||||||||
| Capital expenditures |
(31,635 | ) | (16,732 | ) | (2,047 | ) | (34,530 | ) | ||||||||
| Proceeds from sale of long-lived assets |
4 | 9 | — | 40 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net cash used in investing activities |
(31,631 | ) | (16,723 | ) | (2,047 | ) | (34,490 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash flows from financing activities: |
||||||||||||||||
| Net proceeds from initial public offering |
127,134 | — | — | — | ||||||||||||
| Change in book overdrafts |
— | (425 | ) | 425 | (807 | ) | ||||||||||
| Principal payments on capital lease obligations |
(13 | ) | (338 | ) | (40 | ) | (450 | ) | ||||||||
| Net distributions to SemGroup |
(135,503 | ) | (13,703 | ) | (1,441 | ) | (22,169 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net cash used in financing activities |
(8,382 | ) | (14,466 | ) | (1,056 | ) | (23,426 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net increase (decrease) in cash and cash equivalents |
9,406 | 303 | (1,015 | ) | 1,015 | |||||||||||
| Cash and cash equivalents at beginning of period |
303 | — | 1,015 | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Cash and cash equivalents at end of period |
$ | 9,709 | $ | 303 | $ | — | $ | 1,015 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 1. | OVERVIEW |
Rose Rock Midstream, L.P. is a Delaware limited partnership. Its operations include the following:
| • | a storage terminal in Cushing, Oklahoma with over 5.0 million barrels of crude oil storage capacity; |
| • | an approximate 640-mile crude oil gathering and transportation pipeline system and over 530,000 barrels of associated storage in Kansas and northern Oklahoma, and an additional 130,000 barrels currently under construction; |
| • | a crude oil gathering, storage, transportation and marketing business in the Bakken Shale area in western North Dakota and eastern Montana; and |
| • | a modern, ten-lane crude oil truck unloading facility in Platteville, Colorado, which connects to the origination point of White Cliffs Pipeline. |
The general partner of Rose Rock Midstream, L.P. is Rose Rock Midstream GP, LLC, which is a wholly-owned subsidiary of SemGroup Corporation. SemGroup Corporation is a Delaware corporation headquartered in Tulsa, Oklahoma that provides diversified midstream services to the energy industry. SemGroup Corporation is the successor entity of SemGroup, L.P., which was an Oklahoma limited partnership.
Rose Rock Midstream, L.P. was formed in August 2011. On November 29, 2011, SemGroup Corporation contributed a wholly-owned subsidiary, SemCrude, L.P., to Rose Rock Midstream, L.P., in return for limited partner interests, general partner interests, and certain incentive distribution rights in Rose Rock Midstream, L.P. On December 14, 2011, Rose Rock Midstream, L.P. completed an initial public offering in which it sold 7,000,000 common units representing limited partner interests.
Basis of presentation
These consolidated financial statements of Rose Rock Midstream, L.P. include the activity of its predecessor prior to November 29, 2011. The predecessor included SemCrude, L.P. (“SemCrude”), a wholly-owned subsidiary of SemGroup Corporation (exclusive of SemCrude’s ownership interests in SemCrude Pipeline, L.L.C., which holds a 51% ownership interest in the White Cliffs Pipeline), and Eaglwing, L.P. (“Eaglwing”), which is also a wholly-owned subsidiary of SemGroup Corporation. Although Eaglwing is not currently conducting any revenue-generating operations and was not contributed to Rose Rock Midstream, L.P., it was included in the financial statements of the predecessor because it previously conducted operations that were similar to those of SemCrude. Eaglwing did not have a significant impact on these financial statements during the periods from 2009 through 2011, other than a $3.4 million reorganization items loss recorded to the statement of income for the eleven months ended November 30, 2009. Subsequent to November 29, 2011, these consolidated financial statements include the accounts of Rose Rock Midstream, L.P. and its controlled subsidiaries, which include SemCrude, L.P.
These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. All significant transactions between Rose Rock Midstream, L.P. and its consolidated subsidiaries have been eliminated. All significant transactions between SemCrude and Eaglwing have been eliminated.
The terms “we”, “our”, “us”, “Rose Rock”, the “Partnership” and similar language used in these notes to the consolidated financial statements refer to Rose Rock Midstream, L.P, its subsidiaries, and its predecessor. The term “SemGroup” refers to SemGroup Corporation, SemGroup, L.P., and their other controlled subsidiaries, including Rose Rock Midstream GP, LLC.
F-7
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 1. | OVERVIEW, Continued |
SemGroup bankruptcy
On July 22, 2008 (the “Petition Date”), SemGroup, L.P., SemCrude, and Eaglwing filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. While in bankruptcy, SemGroup, L.P. filed a plan of reorganization with the court, which was confirmed on October 28, 2009 (the “Plan of Reorganization”). The Plan of Reorganization determined, among other things, how pre-Petition Date obligations would be settled, the equity structure of the reorganized company upon emergence, and the financing arrangements upon emergence. SemGroup Corporation, SemCrude, and Eaglwing emerged from bankruptcy protection on November 30, 2009 (the “Emergence Date”).
These consolidated financial statements of Rose Rock Midstream, L.P. and its predecessor include activity prior to emergence from bankruptcy and activity subsequent to emergence from bankruptcy. As described in Note 3, Rose Rock’s predecessor applied fresh-start reporting on the Emergence Date. As a result, the consolidated financial statements subsequent to the Emergence Date are not comparable to the consolidated financial statements prior to the Emergence Date.
Ownership
Our partnership interests include the following at December 31, 2011:
| • | 8,389,709 common units representing limited partner interests (of which 1,389,709 units are held by SemGroup) |
| • | 8,389,709 subordinated units representing limited partner interests (all of which are held by SemGroup); and |
| • | a 2% general partner interest (which is held by SemGroup). |
On December 14, 2011, we sold 7,000,000 common units in an initial public offering. We received net proceeds of $127.1 million, which we distributed to SemGroup (related to assets contributed at formation of Rose Rock).
| 2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
USE OF ESTIMATES – 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. Our significant estimates include, but are not limited to: (1) allowances for doubtful accounts receivable; (2) estimated useful lives of assets, which impacts depreciation; (3) estimated fair values of long-lived assets recorded in fresh-start reporting; (4) estimated fair values of long-lived assets used in impairment tests; (5) fair values of derivative instruments; and (6) accrual and disclosure of contingent losses. Although management believes these estimates are reasonable, actual results could differ materially from these estimates.
FRESH-START REPORTING – We adopted fresh-start reporting on the Emergence Date. In connection with fresh-start reporting, we recorded our assets and liabilities at fair value at the Emergence Date.
CASH AND CASH EQUIVALENTS – Cash includes currency on hand and demand and time deposits with banks or other financial institutions. Cash equivalents include highly liquid investments with maturities of three months or less at the date of purchase. Balances at financial institutions may exceed federally insured limits.
F-8
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, Continued |
ACCOUNTS RECEIVABLE – Accounts receivable are reported net of the allowance for doubtful accounts. Our assessment of the allowance for doubtful accounts is based on several factors, including the overall creditworthiness of our customers, existing economic conditions, and the amount and age of past due accounts. We enter into netting arrangements with certain counterparties to help mitigate credit risk. Receivables subject to netting are presented as gross receivables (with the related accounts payable also presented gross) until such time as the balances are settled. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.
The allowance for doubtful accounts is $0.2 million at December 31, 2011 and $3.3 million at December 31, 2010. At December 31, 2010, our predecessor had a receivable from a customer in the amount of $3.3 million, on which a full valuation allowance had been recorded. During 2011, our predecessor collected $1.1 million of this receivable, which was recorded as a reduction to operating expense in the consolidated statement of income. SemGroup did not contribute the receivable to Rose Rock, so we are not entitled to the benefit of any additional collections SemGroup may receive on this receivable.
At the Emergence Date, as part of fresh-start reporting, we recorded accounts receivable at fair value. This was accomplished by reducing the allowance for doubtful accounts to zero and recording a corresponding reduction to accounts receivable. We report any amounts we have collected in excess of the estimated Emergence Date fair value as reductions to operating expenses in the consolidated statements of income.
INVENTORIES – Inventories primarily consist of crude oil. Inventories are valued at the lower of cost or market, with cost generally determined using the weighted-average method. The cost of inventory includes applicable transportation costs.
We enter into exchanges with third parties whereby we acquire products that differ in location, grade, or delivery date from products we have available for sale. These exchanges are valued at cost, and although a transportation, location or product differential may be recorded, generally no gain or loss is recognized.
PROPERTY, PLANT AND EQUIPMENT – Property, plant and equipment is recorded at cost (although, as described above, property, plant and equipment was adjusted to fair value at November 30, 2009 upon adoption of fresh-start reporting). We capitalize costs that extend or increase the future economic benefits of property, plant and equipment, and expense maintenance costs that do not. When assets are disposed of, their cost and related accumulated depreciation are removed from the balance sheet, and any resulting gain or loss is recorded within operating expenses in the consolidated statements of income.
Depreciation is calculated primarily on the straight-line method over the following estimated useful lives:
| Pipelines and related facilities |
20 years | |||
| Storage and terminal facilities |
10 –25 years | |||
| Office and other property and equipment |
3 – 7 years |
LINEFILL – Pipelines and storage facilities generally require a minimum volume of product in the system to enable the system to operate. Such product, known as linefill, is generally not available to be withdrawn from the system. Linefill owned by us in facilities operated by us is recorded at historical cost, is included in property, plant and equipment in the consolidated balance sheets, and is not depreciated. We also own linefill in third party facilities, which is included in inventory on the consolidated balance sheets.
F-9
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, Continued |
IMPAIRMENT OF LONG-LIVED ASSETS – We test long-lived asset groups for impairment when events or circumstances indicate that the net book value of the asset group may not be recoverable. We test an asset group for impairment by estimating the undiscounted cash flows expected to result from its use and eventual disposition. If the estimated undiscounted cash flows are lower than the net book value of the asset group, we then estimate the fair value of the asset group and record a reduction to the net book value of the assets and a corresponding impairment loss.
COMMODITY DERIVATIVE INSTRUMENTS – We generally record the fair value of derivative instruments on the consolidated balance sheets and the change in fair value as an increase or decrease to product revenue. As shown in Note 5, the fair value of derivatives at December 31, 2011 and 2010 are recorded to other current assets or other current liabilities on the consolidated balance sheets. Related margin deposits are recorded to other current assets or other current liabilities on the consolidated balance sheets. Margin deposits have not generally been netted against derivative assets or liabilities at December 31, 2011 and 2010.
The fair value of a derivative contract is determined based on the nature of the transaction and the market in which the transaction was executed. Quoted market prices, when available, are used to value derivative transactions. In situations where quoted market prices are not readily available, we estimate the fair value using other valuation techniques that reflect the best information available under the circumstances. Fair value measurements of derivative assets include consideration of counterparty credit risk. Fair value measurements of derivative liabilities include consideration of our creditworthiness.
We have elected “normal purchase” and “normal sale” treatment for certain commitments to purchase or sell petroleum products at future dates. This election is only available when a transaction is expected to result in physical delivery of product over a reasonable period in the normal course of business and is not expected to be net settled. Agreements accounted for under this election are not recorded at fair value; instead, the transaction is recorded when the product is delivered.
INTERCOMPANY ACCOUNTS – Prior to our initial public offering, we participated in SemGroup’s cash management program. Under this program, cash we received from customers was transferred to SemGroup on a regular basis; when we remitted payments to suppliers, SemGroup transferred cash to us to cover the payments. In addition, SemGroup incurred certain expenses on our behalf that are reported within our consolidated statements of income.
Prior to our initial public offering, we recorded transactions with SemGroup and its other controlled subsidiaries to intercompany accounts. When our intercompany accounts were in a net receivable position, we reported the balance as a reduction to partners’ capital on our consolidated balance sheet. In our consolidated statements of cash flows, we have reported the net change in the intercompany accounts as a financing cash flow within “net distributions to SemGroup”. We have reported the net change in partners’ capital associated with these transactions with SemGroup as “net distributions to SemGroup” in our consolidated statements of changes in partners’ capital (deficit).
CONTINGENT LOSSES – We record a liability for a contingent loss when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. We record attorneys’ fees incurred in connection with a contingent loss at the time the fees are incurred. We do not record liabilities for attorneys’ fees that are expected to be incurred in the future.
ASSET RETIREMENT OBLIGATIONS – Asset retirement obligations include legal or contractual obligations associated with the retirement of long-lived assets, such as requirements to incur costs to dispose of equipment or to remediate the environmental impacts of the normal operation of the assets. We record liabilities for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made.
F-10
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, Continued |
REVENUE RECOGNITION – Under our current operations, product revenues relate primarily to our marketing business in the Bakken Shale area and to certain fixed-margin transactions related to our pipeline system in Kansas and Oklahoma. The fixed-margin transactions are structured such that 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 a fixed margin that is, in effect, economically equivalent to a transportation fee. Sales of product are recognized at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. Any transportation costs we incur to ship product on third-party infrastructure are included in the price of product sold to customers, and are included within product revenues and costs of goods sold. Taxes collected from customers and remitted to governmental authorities are recorded on a net basis (excluded from revenue). As described in Note 5, product revenues include realized and unrealized gains and losses on commodity derivatives.
Under our current operations, fixed-fee service revenues relate primarily to our storage terminal in Cushing, our pipeline system in Kansas and Oklahoma (excluding transactions whereby we take title to the product while it is in our pipeline system, as described above), and our crude oil truck unloading facility in Platteville, Colorado. Service revenues are recognized at the time the service is performed.
PURCHASES AND SALES OF INVENTORY WITH THE SAME COUNTERPARTY – We routinely enter into transactions to purchase inventory from, and sell inventory to, the same counterparty. Such transactions that are entered into in contemplation of one another are recorded on a net basis.
PREDECESSOR INTEREST EXPENSE – The interest expense reported in our consolidated statements of income prior to our initial public offering consisted of letter of credit fees. SemGroup has been a borrower on several corporate credit agreements (and our assets previously served as collateral under these agreements), but SemGroup did not allocate this debt to its subsidiaries. SemGroup did not charge us interest on the balances in our intercompany accounts.
INCOME TAXES – We are a partnership for income tax purposes and therefore are not subject to federal or state income taxes. The tax on our net income is borne by the individual partners through the allocation of taxable income. Net income for financial statement purposes may differ significantly from taxable income allocated to our partners because of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements of our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes is not available to us.
REORGANIZATION ITEMS – As described in Note 1, SemGroup, SemCrude and Eaglwing operated as debtors-in-possession subject to the jurisdiction of the bankruptcy court during the eleven months ended November 30, 2009. Revenues, expenses, realized gains and losses, and provisions for losses resulting from the reorganization and restructuring of the business are reported as reorganization items in the consolidated statement of income for the eleven months ended November 30, 2009. The effects of the adjustments to the reported amounts of assets resulting from the adoption of fresh-start reporting are also reported within reorganization items in the consolidated statement of income for the eleven months ended November 30, 2009.
OPERATING SEGMENT – Our operations are similar in geography, nature of the services we provide, and type of customers we serve. We are managed by SemGroup as one operating segment.
COMPREHENSIVE INCOME – Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Rose Rock has no items of comprehensive income in any period presented. Therefore, net income as presented in the consolidated statements of income equals comprehensive income.
F-11
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 3. | REORGANIZATION |
On July 22, 2008, SemGroup and many of its affiliates (including SemCrude and Eaglwing), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Certain claims against us in existence prior to the filing of the petitions for relief under the federal bankruptcy laws were stayed while SemGroup continued business operations as a debtor-in-possession. We received approval from the court to pay or otherwise honor certain of our obligations incurred before the Petition Date. The court also approved our use of cash to meet our post Petition Date obligations.
While in bankruptcy, SemGroup filed a Plan of Reorganization with the court, which was confirmed on October 28, 2009. The Plan of Reorganization determined, among other things, how pre-Petition Date obligations would be settled, SemGroup’s equity structure upon emergence, and SemGroup’s financing arrangements upon emergence.
Determination of reorganization value
An essential element in negotiating a reorganization plan with the various classes of creditors is the determination of reorganization value by the parties in interest. In the event that the parties in interest cannot agree on the reorganization value, the court may be called upon to determine the reorganization value of the entity before a plan of reorganization can be confirmed.
During the reorganization process, a reorganization value was proposed. This reorganization value was ultimately agreed to by the creditors and confirmed by the court. The proposed reorganization value was determined by applying the following valuation methods:
| • | a “guideline company” approach, in which valuation multiples observed from industry participants were considered and comparisons were made between SemGroup’s expected performance relative to other industry participants to determine appropriate multiples to apply; |
| • | analysis of recent transactions involving companies determined to be similar to SemGroup; and |
| • | a calculation of the present value of SemGroup’s estimated future cash flows. |
After completing this analysis, the reorganization value of SemGroup was determined to be $1.5 billion. This proposed reorganization value was determined using numerous projections and assumptions. These estimates are subject to significant uncertainties, many of which are beyond SemGroup’s control, including, but not limited to, the following:
| • | changes in the economic environment; |
| • | changes in supply or demand for petroleum products; |
| • | changes in prices of petroleum products; |
| • | the ability to successfully implement expansion projects; |
| • | the ability to improve relationships with customers and suppliers, as these relationships were adversely impacted by the bankruptcy filing; |
| • | the ability to renew certain business operations that were limited during the bankruptcy due to limitations on access to capital; and |
| • | the ability to manage the additional costs associated with being a public company. |
F-12
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 3. | REORGANIZATION, Continued |
The use of different estimates could have resulted in a materially different proposed reorganization value, and there can be no assurance that actual results will be consistent with the estimates that were used to determine the proposed reorganization value. The reorganization value confirmed by the court was utilized in the application of fresh-start reporting.
Valuation of our assets and liabilities
SemGroup determined that $280 million of its reorganization value was attributable to us. We recorded individual assets and liabilities based on their estimated fair values at the Emergence Date.
November 30, 2009 balance sheet
The following table shows the effects of the emergence from bankruptcy on our November 30, 2009 consolidated balance sheet (in thousands):
| Prior to Emergence |
Reorganization Adjustments |
Fresh Start Adjustments |
Subsequent to Emergence |
|||||||||||||
| ASSETS |
||||||||||||||||
| Current assets: |
||||||||||||||||
| Cash and cash equivalents |
$ | 1,015 | $ | — | $ | — | $ | 1,015 | ||||||||
| Restricted cash |
13,659 | — | — | 13,659 | ||||||||||||
| Accounts receivable |
12,100 | — | — | 12,100 | ||||||||||||
| Receivable from affiliates |
13,443 | (13,443 | )(a) | — | — | |||||||||||
| Inventories |
12,718 | — | — | 12,718 | ||||||||||||
| Other current assets |
4,466 | (409 | )(b) | — | 4,057 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total current assets |
57,401 | (13,852 | ) | — | 43,549 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Property, plant and equipment |
95,347 | — | 157,130 | (h) | 252,477 | |||||||||||
| Goodwill |
2,296 | — | (2,296 | )(h) | — | |||||||||||
| Other intangible assets |
1,954 | — | (1,954 | )(h) | — | |||||||||||
| Other assets, net |
2,773 | — | — | 2,773 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total assets |
$ | 159,771 | $ | (13,852 | ) | $ | 152,880 | $ | 298,799 | |||||||
|
|
|
|
|
|
|
|
|
|||||||||
| LIABILITIES AND NET PARTNERS’ CAPITAL (DEFICIT) |
||||||||||||||||
| Current liabilities: |
||||||||||||||||
| Accounts payable |
$ | 11,726 | $ | (665 | )(c) | $ | — | $ | 11,061 | |||||||
| Advances from parent |
34,942 | (34,942 | )(d) | — | — | |||||||||||
| Accrued liabilities |
2,355 | — | — | 2,355 | ||||||||||||
| Payable to affiliates |
4,587 | (4,587 | )(e) | — | — | |||||||||||
| Other current liabilities |
5,013 | — | — | 5,013 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total current liabilities |
58,623 | (40,194 | ) | — | 18,429 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Liabilities subject to compromise |
1,257,910 | (1,257,910 | )(f) | — | — | |||||||||||
| Net partners’ capital (deficit): |
||||||||||||||||
| Partners’ capital (deficit)—Predecessor |
(1,156,762 | ) | 1,156,762 | (g) | — | — | ||||||||||
| Partners’ capital—Successor |
— | 127,490 | (g) | 152,880 | (i) | 280,370 | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net partners’ capital (deficit) |
(1,156,762 | ) | 1,284,252 | 152,880 | 280,370 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total liabilities and net parent capital (deficit) |
$ | 159,771 | $ | (13,852 | ) | $ | 152,880 | $ | 298,799 | |||||||
|
|
|
|
|
|
|
|
|
|||||||||
F-13
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 3. | REORGANIZATION, Continued |
| (a) | Prior to emergence from bankruptcy, we had a receivable from SemCanada Crude Company (“SemCanada Crude”). SemCanada Crude is a wholly-owned subsidiary of SemGroup that applied for bankruptcy protection in Canada in July 2008 and emerged from bankruptcy on November 30, 2009, concurrent with the emergence of SemGroup and SemCrude. Pursuant to the Plan of Reorganization, SemCanada Crude made payments to creditors of SemGroup’s U.S. subsidiaries, and accordingly our receivable from SemCanada Crude was extinguished. |
| (b) | Reflects the transfer to SemGroup of a commodity derivative contract. |
| (c) | We elected not to cancel certain contracts that were in effect prior to the Petition Date. For these contracts, we were required to make payments to the counterparties to cure defaults on the contracts. These payments were made by SemGroup upon emergence from bankruptcy. |
| (d) | Our liabilities to SemGroup and its controlled subsidiaries were extinguished pursuant to the Plan of Reorganization. |
| (e) | Our liability to Blueknight Energy Partners, L.P. (formerly SemGroup Energy Partners, L.P.), which was formerly a subsidiary of SemGroup, was extinguished in the reorganization process. |
| (f) | Represents the transfer to SemGroup of liabilities subject to compromise, pursuant to the Plan of Reorganization. |
| (g) | Reflects the cancellation of predecessor capital and the issuance of successor capital. |
| (h) | Reflects the adjustments to the recorded values of assets resulting from fresh-start reporting. |
| (i) | Reflects the reorganization items gain resulting from fresh-start reporting. |
Reorganization items
The net reorganization items gain shown in the consolidated statement of income for the eleven months ended November 30, 2009 consists of the following (in thousands):
| Gain on asset revaluation in fresh-start reporting (a) |
$ | 152,880 | ||
| Professional fees (b) |
(74,705 | ) | ||
| Adjustment to liabilities subject to compromise (c) |
39,780 | |||
| Loss on disposal or impairment of long-lived assets (d) |
(11,677 | ) | ||
| Uncollectable accounts expense (e) |
(3,329 | ) | ||
| Employment costs (f) |
(2,921 | ) | ||
| Other |
(92 | ) | ||
|
|
|
|||
| Total reorganization items gain, net |
$ | 99,936 | ||
|
|
|
| (a) | We revalued our assets and liabilities in fresh-start reporting, and recorded a reorganization gain for the increase in fair value of the net assets over the previously recorded values. |
| (b) | SemGroup incurred a variety of professional fees related to the restructuring of the business, including, among others: |
| • | legal fees related to the reorganization process, including those related to bankruptcy court filings and hearings, negotiation of credit agreements, settlements of disputes with claimants, and other matters; |
F-14
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 3. | REORGANIZATION, Continued |
| • | general management consulting services related to the disposal of assets, the reconciliation and negotiation of pre-petition claims, preparation for emergence from bankruptcy, and other matters; |
| • | valuation advisory fees for the determination of the reorganization value of the business required for the Plan of Reorganization and the valuation of long-lived assets required by fresh-start reporting; |
| • | accounting fees for assistance with fresh-start reporting and preparation for public company financial reporting obligations; and |
| • | fees paid to the United States Trustee. |
SemGroup allocated a portion of these fees to us, based on our reorganization value relative to the total reorganization value of SemGroup’s United States subsidiaries that emerged from bankruptcy.
| (c) | Represents refinements to the estimated amount of valid claims by pre-petition creditors. During 2008, we recorded an estimated loss for the total amount of valid claims subject to compromise, reported within revenues, costs of products sold, and reorganization items in the consolidated statements of income. During 2009, we refined this estimate as we reviewed the claims, and reversed some of the amounts that had been accrued in 2008. This amount also includes the return to us of $10 million of cash that had been seized by a creditor. We recorded a loss during 2008 when the cash was seized, and we recorded a gain in 2009 when it was recovered. |
| (d) | During the eleven months ended November 30, 2009, we reached an agreement with Blueknight to settle a variety of outstanding matters. As part of this settlement, we surrendered property, plant and equipment and recorded a loss of $11.7 million. |
| (e) | Represents the write-off of receivables in situations where we believe the customer non-payment was related to our bankruptcy. The amounts include recovery of certain receivables from Blueknight Energy Partners, L.P. |
| (f) | Employment costs include severance related to the termination of employment relationships and bonuses paid to retain personnel during the reorganization. |
| 4. | PROPERTY, PLANT AND EQUIPMENT |
Property, plant and equipment consists of the following (in thousands):
| Subsequent to Emergence | ||||||||
| December 31, | December 31, | |||||||
| 2011 | 2010 | |||||||
| Land |
$ | 15,759 | $ | 16,786 | ||||
| Pipelines and related facilities |
156,263 | 147,213 | ||||||
| Storage and terminal facilities |
77,036 | 70,170 | ||||||
| Linefill |
12,126 | 16,004 | ||||||
| Office and other property and equipment |
2,716 | 2,540 | ||||||
| Construction-in-progress |
34,957 | 18,578 | ||||||
|
|
|
|
|
|||||
| Property, plant and equipment, gross |
298,857 | 271,291 | ||||||
| Accumulated depreciation |
(22,611 | ) | (11,243 | ) | ||||
|
|
|
|
|
|||||
| Property, plant and equipment, net |
$ | 276,246 | $ | 260,048 | ||||
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|
|||||
F-15
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 4. | PROPERTY, PLANT AND EQUIPMENT, Continued |
We recorded depreciation expense of $11.4 million for the year ended December 31, 2011, $10.4 million for the year ended December 31, 2010, $0.8 million for the month ended December 31, 2009, and $2.8 million for the eleven months ended November 30, 2009.
| 5. | FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK |
Commodity derivative contracts
Our results of operations and cash flows are impacted by changes in market prices for petroleum products. This exposure to commodity price risk is managed, in part, by entering into various commodity derivatives.
We seek to manage the price risk associated with our marketing operations by limiting our net open positions through (i) the concurrent purchase and sale of like quantities of crude oil to create back-to-back transactions that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered or (ii) derivative contracts. Our storage and transportation assets also can be used to mitigate location and time basis risk. All marketing activities are subject to our comprehensive risk management policy, which establishes limits in order to manage risk and mitigate financial exposure.
Our commodity derivatives were comprised of crude oil and natural gas liquids forward contracts and futures contracts. These are defined as follows:
Forward contracts – Over the counter contracts to buy or sell a commodity at an agreed upon future date. The buyer and seller agree on specific terms (price, quantity, delivery period, and location) and conditions at the inception of the contract.
Futures contracts – Exchange traded contracts to buy or sell a commodity. These contracts are standardized by the exchange in terms of quality, quantity, delivery period and location for each commodity.
We record certain commodity derivative assets and liabilities at fair value at each balance sheet date. The table below summarizes the balances of these assets and liabilities at December 31, 2011 and 2010 (in thousands):
| December 31, 2011 | December 31, 2010 | |||||||||||||||||||||||||||||||
| Level 1 | Netting* | Total | Level 1 | Level 2 | Level 3 | Netting* | Total | |||||||||||||||||||||||||
| Assets |
$ | 393 | $ | (231 | ) | $ | 162 | $ | 97,773 | $ | 208 | $ | 1,619 | $ | (97,981 | ) | $ | 1,619 | ||||||||||||||
| Liabilities |
231 | (231 | ) | — | 99,362 | 863 | — | (97,981 | ) | 2,244 | ||||||||||||||||||||||
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|||||||||||||||||
| Net assets (liabilities) at fair value |
$ | 162 | $ | — | $ | 162 | $ | (1,589 | ) | $ | (655 | ) | $ | 1,619 | $ | — | $ | (625 | ) | |||||||||||||
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| * | Relates primarily to exchange traded futures. Gain and loss positions on multiple contracts are settled net on a daily basis with the exchange. |
“Level 1” measurements were obtained using unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. These include futures contracts that are traded on an exchange.
“Level 2” measurements use as inputs market observable and corroborated prices for similar derivative contracts. Assets and liabilities classified as Level 2 include over-the-counter (OTC) traded physical fixed priced purchases and sales forward contracts.
F-16
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 5. | FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK, Continued |
“Level 3” measurements were obtained using information from a pricing service and internal valuation models incorporating observable and unobservable market data. These include physical fixed price purchases and sales forward contracts with an affiliate for which there is not a highly liquid OTC market, and therefore are not included in Level 1 or Level 2 above.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the measurement requires judgment, and may affect the valuation of assets and liabilities and their placement within the fair value levels. At December 31, 2011 all of our physical fixed price forward purchases and sales contracts were being accounted for as normal purchases and normal sales.
The following table reconciles changes in the fair value of commodity derivatives classified as Level 3 in the fair value hierarchy (in thousands):
| Subsequent to Emergence | Prior to Emergence | |||||||||||||||
| Year Ended December 31, 2011 |
Year Ended December 31, 2010 |
Month Ended December 31, 2009 |
Eleven Months Ended November 30, 2009 |
|||||||||||||
| Beginning balance |
$ | 1,619 | $ | 218 | $ | 408 | $ | (11 | ) | |||||||
| Total gain or loss (realized and unrealized) included in product revenues |
— | 919 | 4 | 2,013 | ||||||||||||
| Settlements |
(1,619 | ) | 482 | (194 | ) | (1,594 | ) | |||||||||
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| Ending balance |
$ | — | $ | 1,619 | $ | 218 | $ | 408 | ||||||||
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| Amount of total gain or loss included in earnings for the period attributable to the change in unrealized gain or loss relating to assets and liabilities still held at the reporting date |
$ | — | $ | 1,619 | $ | 218 | $ | 408 | ||||||||
The following table sets forth the notional quantities for derivative instruments entered into during the periods indicated (amounts in thousands of barrels):
| Subsequent to Emergence | Prior to Emergence | |||||||||||||||
| Year Ended December 31, 2011 |
Year Ended December 31, 2010 |
Month Ended December 31, 2009 |
Eleven Months Ended November 30, 2009 |
|||||||||||||
| Sales |
6,309 | 6,313 | 69 | 2,766 | ||||||||||||
| Purchases |
6,457 | 6,168 | 49 | 2,426 | ||||||||||||
We have not designated any of our commodity derivative instruments as accounting hedges. We record the fair value of the derivative instruments on our 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):
F-17
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 5. | FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK, Continued |
| December 31, 2011 | December 31, 2010 | |||||||||||||||
| Assets |
Liabilities | Assets | Liabilities | |||||||||||||
| $ | 162 | $ | — | $ | 1,619 | $ | 2,244 | |||||||||
Realized and unrealized gains (losses) from our commodity derivatives were recorded to product revenue in the following amounts (in thousands):
| Subsequent to Emergence |
Prior to Emergence | |||||||||||
| Year Ended | Year Ended |
Month Ended |
Eleven Months Ended |
|||||||||
| December 31, 2011 |
December 31, 2010 | December 31, 2009 | November 30, 2009 | |||||||||
| $ (386) | $ | (1,929 | ) | $ | 282 | $ | 351 | |||||
Concentrations of risk
During the year ended December 31, 2011, we generated approximately $334 million of revenue from five third party customers, which represented approximately 78% of our consolidated revenue. We purchased approximately $35 million of product from one third party supplier, which represented approximately 10% of our costs of products sold. At December 31, 2011, four third party customers accounted for 62% of our consolidated accounts receivable.
During the year ended December 31, 2010, we generated approximately $88 million of revenue from a third party, which represented approximately 42% of our consolidated revenue. We purchased approximately $18 million of product from one third party supplier, which represented approximately 12% of our costs of products sold. At December 31, 2010, two third party customers accounted for 41% of our consolidated accounts receivable.
During the month ended December 31, 2009, we generated approximately $4 million of revenue from a third party, which represented approximately 38% of our consolidated revenue.
During the eleven months ended November 30, 2009, we generated approximately $193 million in revenue from one customer, which represented approximately 80% of our consolidated revenue. We purchased approximately $125 million of product from one supplier, which represented approximately 69% of our costs of products sold.
As described in Note 12, we also generated significant revenues and expenses during the periods from 2009 through 2011 from other subsidiaries of SemGroup.
| 6. | LONG-TERM DEBT |
On November 10, 2011, we entered into a five-year senior secured revolving credit facility agreement. The credit facility under this agreement became effective upon completion of our initial public offering on December 14, 2011.
F-18
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 6. | LONG-TERM DEBT, Continued |
The credit agreement provides for a revolving credit facility of $150 million. The agreement also provides that the revolving credit facility may, under certain conditions, be increased by up to an additional $200 million. The credit facility includes a $75 million sub-limit for the issuance of letters of credit. All amounts outstanding under the agreement will be due and payable on December 14, 2016.
At our option, amounts borrowed under the credit agreement will bear interest at either the Eurodollar rate or an alternate base rate (“ABR”), plus, in each case, an applicable margin. Until the date the financial statements relating to the quarter ending March 31, 2012 have been delivered, the applicable margin relating to any Eurodollar loan will be 2.25% and with respect to any ABR loan will be 1.25%. After such financial statements have been delivered, the applicable margin will range from 2.25% to 3.25% in the case of a Eurodollar rate loan, and from 1.25% to 2.25% in the case of an ABR loan, in each case, based on a leverage ratio. At December 31, 2011, we did not have any outstanding borrowings on this facility.
Fees are charged on any outstanding letters of credit at a rate that ranges from 2.25% to 3.25%, depending on a leverage ratio specified in the credit agreement. At December 31, 2011, there were $22.6 million in outstanding letters of credit, and the rate in effect was 2.25%. In addition, a fronting fee of 0.25% is charged on outstanding letters of credit.
A commitment fee that ranges from 0.375% to 0.50%, depending on a leverage ratio specified in the credit agreement is charged on any unused capacity of the revolving credit facility. In addition, we are charged an annual administrative fee of $0.1 million. The credit facility also allows for the use of Secured Bilateral Letters of Credit, which are issued external to the credit facility and do not reduce revolver availability. At December 31, 2011, we had $17.0 million of Bilateral Letters of Credit outstanding and the interest rate in effect was 1.75%.
We paid $1.7 million of fees to lenders and advisors which was recorded in other noncurrent assets and is being amortized over the life of the agreement. We recorded $0.1 million of interest expense during December 2011 related to this facility, including amortization of debt issuance costs.
The credit agreement includes customary representations and warranties and affirmative and negative covenants. The covenants in the agreement include limitations on creation of new indebtedness and liens, entry into sale and lease-back transactions, investments, and fundamental changes including mergers and consolidations, dividends and other distributions, material changes in our business and modifying certain documents. The agreement also requires the maintenance of a specified consolidated leverage ratio and an interest coverage ratio. In addition, the agreement prohibits any commodity transactions that are not permitted by our Comprehensive Risk Management Policy.
The credit agreement includes customary events of default, including events of default relating to non-payment of principal and other amounts owing under the agreement from time to time, including in respect of letter of credit disbursement obligations, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults of us and our restricted subsidiaries to any material indebtedness, cross acceleration to any material indebtedness, bankruptcy and insolvency events, the occurrence of a change of control, certain unsatisfied judgments, certain ERISA events, certain environmental matters and certain assertions of or actual invalidity of certain loan documents. A default under the credit agreement would permit the participating banks to terminate commitments, require immediate repayment of any outstanding loans with interest and any unpaid accrued fees, and require the cash collateralization of outstanding letter of credit obligations.
F-19
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 6. | LONG-TERM DEBT, Continued |
The credit agreement restricts our ability to make certain types of payments relating to our units, including the declaration or payment of cash distributions; provided that we may make quarterly distributions of available cash so long as no default under the agreement then exists or would result therefrom. The agreement is guaranteed by all of our material domestic subsidiaries and secured by a lien on substantially all of our property and assets, subject to customary exceptions. At December 31, 2011, we were in compliance with the terms of the credit agreement.
At December 31, 2011, we had $87 thousand of capital lease obligations reported as long-term debt on the consolidated balance sheet.
| 7. | COMMITMENTS AND CONTINGENCIES |
Bankruptcy matters
| (a) | Confirmation order appeals |
Manchester Securities appeal. On October 21, 2009, Manchester Securities Corporation, a creditor of SemGroup Holdings, L.P. (a subsidiary of SemGroup), filed an objection to the Plan of Reorganization. In the objection, Manchester argued that the Plan of Reorganization should not be confirmed because it did not provide for an alleged $50 million claim of SemGroup Holdings, L.P. against SemCrude Pipeline, L.L.C. On October 28, 2009, the bankruptcy court overruled the objection and entered the confirmation order approving the Plan of Reorganization. On November 4, 2009, Manchester filed a notice of appeal of the confirmation order. On December 4, 2009, Manchester’s appeal was docketed in the United States District Court for the District of Delaware. SemGroup filed a motion to dismiss the appeal as equitably moot. On February 18, 2011, the District Court granted SemGroup’s motion to dismiss the appeal. On March 22, 2011, Manchester filed a notice to appeal this order. On January 2, 2012, the United States Court of Appeals affirmed the judgment of the District Court to dismiss the appeal. Manchester has not filed a petition for rehearing or a petition for a writ of certiorari with the United States Supreme Court. The deadline for filing a petition for rehearing has passed. The deadline for filing a petition for a writ of certiorari with the Supreme Court is March 2, 2012. Rose Rock is indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement.
Luke Oil appeal. On October 21, 2009, Luke Oil Company, C&S Oil/Cross Properties, Inc., Wayne Thomas Oil and Gas and William R. Earnhardt Company (collectively, “Luke Oil”) filed an objection to the Plan of Reorganization "to the extent that the Plan of Reorganization may alter, impair, or otherwise adversely affect Luke Oil’s legal rights or other interests.” On October 28, 2009, the bankruptcy court overruled the Luke Oil objection and entered the confirmation order. On November 6, 2009, Luke Oil filed a notice of appeal. On December 23, 2009, Luke Oil’s appeal was docketed in the United States District Court for the District of Delaware. SemGroup filed a motion to dismiss the appeal as equitably moot. Briefing on this matter is complete but the motion to dismiss has not been ruled upon by the District Court. While SemGroup believes that this action is without merit and is vigorously defending this matter on appeal, an adverse ruling on this action could have a material adverse impact on us.
| (b) | Claims reconciliation process |
A large number of parties have made claims against us for obligations alleged to have been incurred prior to the Petition Date. On September 15, 2010, the bankruptcy court entered an order estimating the contingent, unliquidated and disputed claims and authorizing distributions to holders of allowed claims. Pursuant to that order SemGroup has begun making distributions to the claimants. SemGroup continues to attempt to settle unresolved claims.
F-20
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 7. | COMMITMENTS AND CONTINGENCIES, Continued |
Pursuant to the Plan of Reorganization, SemGroup committed to settle all pre-petition claims by paying a specified amount of cash, issuing a specified number of warrants, and issuing a specified number of shares of SemGroup Corporation common stock. The resolution of most of the outstanding claims will not impact the total amount of consideration SemGroup will give to the claimants; instead, the resolution of the claims will impact the relative share of the total consideration that each claimant receives.
However, there is a specified group of claims for which SemGroup could be required to pay additional funds to settle. Pursuant to the Plan of Reorganization, SemGroup set aside a specified amount of restricted cash at the Emergence Date, which SemGroup expected to be sufficient to settle this group of claims. Since the Emergence Date, SemGroup has made significant progress in resolving these claims, and continues to believe that the cash set aside at the Emergence Date will be sufficient to pay these claims. However, SemGroup has not yet reached a resolution of all of these claims, and if the total settlement amount of these claims exceeds the specified amount, SemGroup will be required to pay additional funds to these claimants, and we could be required to share in this expense. Rose Rock is indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement.
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 adverse 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.
Environmental
We may from time to time experience leaks of petroleum products from our facilities, 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 our bankruptcy proceeding regarding five of our sites in Kansas that KDHE believed, based on their historical use, may have soil or groundwater contamination in excess of state standards. KDHE sought our agreement to undertake assessments of these sites to determine whether they are contaminated. We entered into a Consent Agreement and Final Order with KDHE to conduct environmental assessments on the sites and to pay KDHE’s costs associated with their oversight of this matter. We have conducted phase II investigations at all sites. Three of the five sites have limited amounts of soil contamination that will be excavated and/or remediated on site. Three of the five sites appear to have ground water contamination that may require further delineation and/or on-going monitoring. We are preparing work plans to submit to the State of Kansas for approval. We do not anticipate any penalties or fines for these historical sites. Rose Rock is indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement.
F-21
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 7. | COMMITMENTS AND CONTINGENCIES, Continued |
Blueknight claim
Blueknight Energy Partners, L.P. (“Blueknight”), which was formerly a subsidiary of SemGroup, together with other entities related to Blueknight, entered into a Shared Services Agreement on April 7, 2009, with SemCrude, L.P. and SemManagement, L.L.C. (which are currently subsidiaries of SemGroup). The services provided by SemCrude to Blueknight under this agreement included the coordination of movement of crude oil belonging to Blueknight’s customers and the operation of Blueknight’s Oklahoma pipeline system and its Cushing, Oklahoma terminal. Under the subsequent amendments to the agreements beginning in May 2010, certain of these services were phased out, and Blueknight began to manage the movement of its crude oil and the operation of its Cushing terminal.
In a letter dated August 18, 2011, Blueknight claimed that SemCrude owes Blueknight approximately 141,000 barrels of crude oil. We responded to Blueknight’s letter denying their charges and requesting documentation from Blueknight of its claim. We continued to respond to requests for information and to review documentation provided by Blueknight; however, on February 14, 2012, Blueknight filed suit against us in the District Court of Oklahoma County, Oklahoma in connection with this claim; however, we cannot reliably predict the outcome. Rose Rock is indemnified by SemGroup against any loss in this matter pursuant to the terms of the omnibus agreement.
Asset retirement obligations
We may be subject to removal and restoration costs upon retirement of our facilities. However, we do not believe the present value of such obligations under current laws and regulations, after taking into account the estimated lives of our facilities, is material to our financial position or results of operations.
Leases
We have entered into operating lease agreements for office space, office equipment, land, trucks and tank storage. Future minimum payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year at December 31, 2011 are as follows (in thousands):
| For twelve months ending: | ||||
| December 31, 2012 |
$ | 711 | ||
| December 31, 2013 |
538 | |||
| December 31, 2014 |
191 | |||
| December 31, 2015 |
35 | |||
| December 31, 2016 |
6 | |||
| Thereafter |
2 | |||
|
|
|
|||
| Total future minimum lease payments |
$ | 1,483 | ||
|
|
|
|||
We recorded lease and rental expenses of $1.0 million for the year ended December 31, 2011, $0.7 million for the year ended December 31, 2010, $0.1 million for the month ended December 31, 2009, and $0.7 million for the eleven months ended November 30, 2009.
F-22
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 7. | COMMITMENTS AND CONTINGENCIES, Continued |
Purchase and sale commitments
We routinely enter into agreements to purchase and sell petroleum products at specified future dates. We establish a margin for these purchases by entering into various types of physical and financial sales and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. We account for these commitments as normal purchases and sales, and therefore we do not record assets or liabilities related to these agreements until the product is purchased or sold. At December 31, 2011, such commitments included the following (in thousands):
| Volume | ||||||||
| (barrels) | Value ($) | |||||||
| Fixed price purchases |
150 | $ | 13,442 | |||||
| Fixed price sales |
150 | $ | 14,496 | |||||
| Floating price purchases |
32,244 | $ | 3,129,544 | |||||
| Floating price sales |
32,556 | $ | 3,135,741 | |||||
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).
| 8. | EMPLOYEE BENEFITS AND EQUITY-BASED COMPENSATION |
We do not directly employ any persons to manage or operate our business, as these functions are performed by employees of SemGroup. At December 31, 2011, SemGroup had approximately 80 employees who were dedicated primarily to the management and operation of our business. None of these employees are represented by labor unions, and none are subject to collective bargaining agreements.
Equity incentive plan
On December 8, 2011, the board of directors of our general partner adopted the Rose Rock Midstream Equity Incentive Plan (the “Incentive Plan”). During first quarter 2012, we granted 39,213 awards of restricted units that will vest on January 19, 2015, contingent upon the continued service of the recipients. The awards may be subject to accelerated vesting in the event of involuntary terminations.
SemGroup stock-based compensation
Certain of SemGroup’s employees who support us participate in SemGroup’s equity-based compensation program. Awards under this program generally represent awards of restricted stock of SemGroup, which are subject to specified vesting periods. SemGroup charged us $0.5 million during the year ended December 31, 2011 and $0.4 million during the year ended December 31, 2010 related to such equity-based compensation. We estimate that we will record expense of $0.5 million during the year ended December 31, 2012, $0.1 million during the year ended December 31, 2013, and $0.1 million during the year ended December 31, 2014, related to such awards that had been granted as of December 31, 2011.
Certain of SemGroup’s employees who support us were granted retention awards by SemGroup. These awards vested in December 2011 and were paid in SemGroup stock. SemGroup charged us $0.4 million during the year ended December 31, 2011 and $0.3 million during the year ended December 31, 2010 related to these awards.
F-23
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 8. | EMPLOYEE BENEFITS AND EQUITY-BASED COMPENSATION, Continued |
Defined contribution plan
Most of the employees of SemGroup who support us participate in one of SemGroup’s defined contribution plans. SemGroup charged us $0.3 million during each of the years ended December 31, 2011 and December 31, 2010 for contributions made by SemGroup to this plan.
Allocated employee compensation expenses
As described in Note 12, SemGroup allocated certain corporate general and administrative expenses to us. These allocated expenses included equity-based compensation, retention awards, and defined contribution plan benefits for corporate employees, and such expenses are in addition to the expenses described above for employees who directly support our operations.
| 9. | PARTNERS’ CAPITAL AND DISTRIBUTIONS |
General partner
SemGroup owns the 2% general partner interest in us, and, through this general partner interest, has the right to manage and operate us. SemGroup may not be removed as general partner except by a vote of the holders of at least 66 2/3% of the outstanding limited partner units voting together as a single class, including any limited partner units owned by our general partner and its affiliates, including SemGroup.
Limited partner interests—common units
Limited partners have the right to vote on certain matters. For example, a unit majority is required to make certain types of amendments to the partnership agreement, to allow the sale substantially all of our assets, or to dissolve the Partnership. Limited partners also have certain distribution rights, as summarized below.
Limited partner interests – subordinated units
The holders of subordinated limited partner units have similar voting rights to holders of common limited partner units. However, as described below, the distribution rights for holders of subordinated units are different than those of common units. The subordinated units will be converted to common units upon the achievement of certain targets specified in our partnership agreement.
Distribution rights
We intend to pay a minimum quarterly distribution of $0.3625 per unit to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors.
Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:
| • | first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.3625, plus any arrearages from prior quarters; |
| • | second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.3625; and |
| • | third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.416875. |
F-24
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 9. | PARTNERS’ CAPITAL AND DISTRIBUTIONS, Continued |
If cash distributions to our unitholders exceed $0.416875 per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” The following table summarizes the incentive distribution levels:
| Marginal Percentage Interest in Distributions |
||||||||||||||||
| Total Quarterly Distribution Per Unit Target Amount |
Unitholders | General Partner Interest |
Incentive Distribution Rights |
|||||||||||||
| Minimum Quarterly Distribution |
$ | 0.3625 | 98.0% | 2.0% | — | |||||||||||
| First Target Distribution |
above $ | 0.3625 | up to $ | 0.416875 | 98.0% | 2.0% | — | |||||||||
| Second Target Distribution |
above $ | 0.416875 | up to $ | 0.453125 | 85.0% | 2.0% | 13.0 | % | ||||||||
| Third Target Distribution |
above $ | 0.453125 | up to $ | 0.54375 | 75.0% | 2.0% | 23.0 | % | ||||||||
| Thereafter |
above $ | 0.54375 | 50.0% | 2.0% | 48.0 | % | ||||||||||
Distribution declared in January 2012
On January 23, 2012, we declared a distribution of $0.0670 per unit (calculated as the $0.3625 minimum quarterly distribution, prorated based on the length of time during the three months ended December 31, 2011, that was subsequent to our initial public offering). This distribution was paid on February 13, 2012 to unitholders of record on February 3, 2012. For this distribution, $0.6 million was paid to our common unitholders, $0.6 million was paid to our subordinated unitholders, and less than $0.1 million was paid to our general partner.
| 10. | EARNINGS PER LIMITED PARTNER UNIT |
Net income is allocated to the general partner and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated to the general partner.
Basic and diluted earnings per limited partner unit is determined by dividing net income allocated to the limited partners, by the weighted average number of limited partner units for such class outstanding during the period. Diluted earnings per limited partner unit reflects, where applicable, the potential dilution that could occur if securities or other agreements to issue additional units of a limited partner class, such as restricted unit awards, were exercised, settled or converted into such units. At December 31, 2011, we have none of these types of awards outstanding.
The following table sets forth the computation of basic and diluted earnings per limited partner unit for the period from December 15, 2011 (the day following the closing of our IPO) through December 31, 2011 (amounts in thousands, except per unit data):
F-25
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 10. | EARNINGS PER LIMITED PARTNER UNIT, Continued |
| December 15,
2011 through December 31, 2011 |
||||
| Net income |
$ | 970 | (2) | |
| Less: General partner’s incentive distribution earned (1) |
— | |||
| Less: General partner’s 2.0% ownership |
19 | |||
|
|
|
|||
| Net income allocated to limited partners |
$ | 951 | ||
|
|
|
|||
| Numerator for basic and diluted earnings per limited partner unit: |
||||
| Allocation of net income among limited partner interests: |
||||
| Net income allocable to common units |
$ | 475.5 | ||
| Net income allocable to subordinated units |
475.5 | |||
|
|
|
|||
| Net income allocated to limited partners |
$ | 951 | ||
|
|
|
|||
| Denominator |
||||
| Basic and diluted weighted average number of limited partner units outstanding: |
||||
| Common units |
8,390 | |||
|
|
|
|||
| Subordinated units |
8,390 | |||
|
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| Basic and diluted net income per limited partner unit: |
||||
| Common units |
$ | 0.06 | ||
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| Subordinated units |
$ | 0.06 | ||
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| (1) | Based on the amount of the distribution declared per common and subordinated unit related to earnings for the period from December 15, 2011 through December 31, 2011, our general partner was not entitled to receive any incentive distribution for this period. |
| (2) | Represents December net income adjusted for the impact of certain accruals and prorated for 17 days. |
| 11. | SUPPLEMENTAL INFORMATION —STATEMENTS OF CASH FLOWS |
The non-cash reorganization items shown on the consolidated statement of cash flows for the eleven months ended November 30, 2009 includes a $3.3 million allowance for uncollectable accounts, an $11.7 million loss on disposal of property, plant and equipment, and a $39.8 million gain on adjustments to liabilities subject to compromise.
As described in Note 3, we transferred certain assets and liabilities to SemGroup on November 30, 2009, pursuant to SemGroup’s Plan of Reorganization. This non-cash activity is not reflected in our consolidated statement of cash flows for the eleven months ended November 30, 2009.
On December 15, 2011, we transferred a liability to SemGroup after receiving an indemnification against any loss pursuant to the terms of an omnibus agreement between Rose Rock and SemGroup. This liability related to revenue which was deferred pending resolution of a dispute which arose in connection to a sale of crude oil in June 2011. The transfer of this liability to SemGroup is a non-cash transaction which is not reflected in our consolidated statement of cash flow for the year ended December 31, 2011.
F-26
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 12. | RELATED PARTY TRANSACTIONS |
Direct employee expenses
We do not directly employ any persons to manage or operate our business. These functions are performed by employees of SemGroup. SemGroup charged us $11.3 million during the year ended December 31, 2011, $8.2 million during the year ended December 31, 2010, $0.8 million during the month ended December 31, 2009, and $7.7 million during the eleven months ended November 30, 2009, for direct employee costs. These expenses were recorded to operating expenses and general and administrative expenses in our consolidated statements of income.
Allocated expenses
SemGroup incurs expenses to provide certain indirect corporate general and administrative services to its subsidiaries. Such expenses include employee compensation costs, professional fees and rental fees for office space, among other expenses.
For the eleven months ended November 30, 2009, SemGroup’s corporate general and administrative expenses were allocated to its subsidiaries based on percentages established by SemGroup management. At the beginning of each year, management estimated corporate general and administrative costs and assigned the subsidiaries a flat monthly charge of that amount. From time to time, the monthly charges were reviewed and adjusted. In addition to the flat monthly charge, the subsidiaries would also be allocated a portion of the over or under allocation of actual corporate general and administrative expense from the prior month. This monthly “true up” was based on each subsidiary’s year to date allocation as a percentage of the total year to date corporate general and administrative expense.
Beginning in December 2009, the general and administrative expenses of each corporate department have been allocated to the subsidiaries based on criteria such as actual usage, headcount, and estimates of effort or benefit. The method for allocating cost is based on the type of service being provided. For example, internal audit costs are based on an estimate of effort attributable to a subsidiary. In contrast, certain accounting department costs are allocated based on the number of transactions processed for a given segment compared to the total number processed.
SemGroup charged us $4.5 million during the year ended December 31, 2011, $4.9 million during the year ended December 31, 2010, $1.0 million during the month ended December 31, 2009, and $4.1 million during the eleven months ended November 30, 2009 for such allocated costs. These expenses were recorded to general and administrative expenses in our consolidated statements of income.
Allocated reorganization expenses
As described in Note 3, the reorganization items in our consolidated statement of income for the eleven months ended November 30, 2009 include $74.7 million of professional fees and $2.9 million of employee expenses allocated from SemGroup.
SemGroup credit facilities
SemGroup was a borrower under various credit agreements during the periods included in these financial statements. Prior to our initial public offering, SemCrude and Eaglwing, along with other subsidiaries of SemGroup, served as subsidiary guarantors under certain of these agreements. SemGroup did not allocate this debt to its subsidiaries, and our statements of income do not include any allocated interest expense, prior to our initial public offering. SemGroup did not charge us interest expense on intercompany payables.
Prior to our initial public offering, we utilized letters of credit under SemGroup’s credit facilities. Our statements of income include direct charges from SemGroup for letter of credit usage, which is reported within interest expense.
Subsequent to our initial public offering, which was completed on December 14, 2011, our assets no longer serve as collateral under SemGroup’s credit agreement.
F-27
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 12. | RELATED PARTY TRANSACTIONS, Continued |
Predecessor cash management
Prior to our initial public offering, we participated in SemGroup’s cash management program. Under this program, cash we received from customers was transferred to SemGroup on a regular basis; when we remitted payments to suppliers, SemGroup transferred cash to us to cover the payments. As described Note 2, such cash transfers were recorded to intercompany accounts.
NGL Energy
SemGroup acquired certain ownership interests in NGL Energy Partners LP (“NGL Energy”) and its general partner on November 1, 2011. Subsequent to that date, we made purchases of natural gasoline from NGL Energy in the amount of $8.9 million.
SemStream
We purchased condensate from SemStream, L.P. (“SemStream”), which is also a wholly-owned subsidiary of SemGroup. Certain of these purchases were fixed price forward purchases, which we recorded at fair value at each balance sheet date, with the unrealized gains being recorded to revenue. Our transactions with SemStream consisted of the following (amounts in thousands):
| Subsequent to Emergence | Prior to Emergence | |||||||||||||||
| Year Ended December 31, 2011 |
Year Ended December 31, 2010 |
Month Ended December 31, 2009 |
Eleven
Months Ended November 30, 2009 |
|||||||||||||
| Revenues |
$ | — | $ | 1,401 | $ | — | $ | — | ||||||||
| Purchases |
$ | 46,738 | $ | 36,811 | $ | 2,952 | $ | 26,306 | ||||||||
SemGas
We purchase condensate from SemGas, L.P. (“SemGas”), which is also a wholly-owned subsidiary of SemGroup. Our purchases from SemGas included the following (amounts in thousands):
| Subsequent to Emergence | Prior to Emergence | |||||||||||||||
| Year Ended December 31, 2011 |
Year Ended December 31, 2010 |
Month Ended December 31, 2009 |
Eleven
Months Ended November 30, 2009 |
|||||||||||||
| Purchases |
$ | 6,547 | $ | 4,427 | $ | 441 | $ | 3,239 | ||||||||
White Cliffs
SemGroup owned 99% of White Cliffs and controlled it until September 30, 2010. Subsequent to that date, SemGroup owns 51% of White Cliffs and exercises significant influence over it. We generated revenues from White Cliffs of $2.2 million for the year ended December 31, 2011, $1.9 million for the year ended December 31, 2010, $0.1 million for the month ended December 31, 2009, and $0.8 million for the eleven months ended November 30, 2009.
F-28
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 12. | RELATED PARTY TRANSACTIONS, Continued |
SemCanada Crude
We conduct a crude oil marketing business in the Northern United States. For most of the time during the years 2009 and 2010, we conducted this business along with SemCanada Crude Company (“SemCanada Crude”), which is also wholly-owned by SemGroup. SemCanada Crude would purchase crude oil and sell it to us; we would transport the product and sell it back to SemCanada Crude, which would sell the crude to third parties. Sales to and purchases from SemCanada Crude were recorded within product revenues and costs of goods sold in our consolidated statements of income. The amounts were as follows (amounts in thousands):
| Subsequent to Emergence | Prior to Emergence | |||||||||||||||
| Year Ended December 31, 2011 |
Year Ended December 31, 2010 |
Month Ended December 31, 2009 |
Eleven
Months Ended November 30, 2009 |
|||||||||||||
| Sales |
$ | — | $ | 21,526 | $ | 1,799 | $ | 141,651 | ||||||||
| Purchases |
$ | 45 | $ | 11,587 | $ | — | $ | 136,623 | ||||||||
During 2010, SemGroup began winding down the operations of SemCanada Crude. We have continued this marketing operation without the participation of SemCanada Crude.
Blueknight
Blueknight (formerly SemGroup Energy Partners, L.P.) was a controlled subsidiary of SemGroup until July 2008, when certain creditors exercised their option to take control of the Board of Directors of Blueknight’s general partner. These creditors also seized all of SemGroup’s ownership interests in Blueknight prior to SemGroup’s emergence from bankruptcy.
During the eleven months ended November 30, 2009 we purchased crude oil transportation, terminalling, and storage services from Blueknight. During the eleven months ended November 30, 2009, we received payments from Blueknight for transition services. The amounts were as follows for the eleven months ended November 30, 2009 (in thousands):
| Revenues |
$ | 1,358 | ||
| Purchases |
$ | 3,045 |
On April 7, 2009, SemGroup and Blueknight executed definitive documentation related to the settlement of certain matters and entered into a settlement of a shared services agreement. As part of the settlement, we transferred certain property, plant and equipment and inventory to Blueknight, and Blueknight transferred certain property, plant and equipment to us. We recorded a loss of $11.7 million to reorganization items in our consolidated statement of income for the eleven months ended November 30, 2009 related to these transfers.
F-29
ROSE ROCK MIDSTREAM, L.P.
Notes to Consolidated Financial Statements
| 13. | QUARTERLY FINANCIAL DATA (UNAUDITED) |
Summarized information on the consolidated results of income of Rose Rock Midstream, L.P. for the quarters during the year ended December 31, 2011, is shown below (in thousands):
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Total | ||||||||||||||||
| Total revenues |
$ | 83,791 | $ | 110,714 | $ | 104,616 | $ | 132,200 | $ | 431,321 | ||||||||||
| Total expenses |
75,704 | 105,455 | 100,352 | 124,949 | 406,460 | |||||||||||||||
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| Operating income |
8,087 | 5,259 | 4,264 | 7,251 | 24,861 | |||||||||||||||
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| Other expenses (income), net |
483 | 286 | 434 | 423 | 1,626 | |||||||||||||||
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| Net income |
$ | 7,604 | $ | 4,973 | $ | 3,830 | $ | 6,828 | $ | 23,235 | ||||||||||
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Summarized information on the consolidated results of income of Rose Rock Midstream, L.P. for the quarters during the year ended December 31, 2010, is shown below (in thousands):
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Total | ||||||||||||||||
| Total revenues |
$ | 53,182 | $ | 21,635 | $ | 58,629 | $ | 74,635 | $ | 208,081 | ||||||||||
| Total expenses |
48,521 | 21,135 | 50,435 | 65,016 | 185,107 | |||||||||||||||
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| Operating income |
4,661 | 500 | 8,194 | 9,619 | 22,974 | |||||||||||||||
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| Other (income) expenses, net |
(654 | ) | 742 | 74 | (665 | ) | (503 | ) | ||||||||||||
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| Net income (loss) |
$ | 5,315 | $ | (242 | ) | $ | 8,120 | $ | 10,284 | $ | 23,477 | |||||||||
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Second quarter 2010 total revenues and total expenses were impacted by fluctuations related to nonmonetary transactions which are reported net in accordance with ASC 845-10-15. While changes in the level of such purchase and sale activity between periods can have an effect on the comparability between those periods, there is not an effect on operating income. Second quarter results were also impacted by reduced transportation activity as a subsidiary of our predecessor’s parent company took over responsibility for their own trucking April through July of 2010.
F-30
Index to Exhibits
The following documents are included as exhibits to this Form 10-K. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, such exhibit is filed herewith.
| Exhibit Number |
Description | |
| 3.1 | Certificate of Limited Partnership of Rose Rock Midstream, L.P. (filed as Exhibit 3.1 to Registrant’s registration statement on Form S-1 (File No. 333-176260) (the “Form S-1”), filed with the Commission on August 12, 2011). | |
| 3.2 | Second Amended and Restated Agreement of Limited Partnership of Rose Rock Midstream, L.P. (filed as Exhibit 3.1 to the Registrant’s current report on Form 8-K (File No. 001-35365), filed with the Commission on December 20, 2011). | |
| 3.3 | Certificate of Formation of Rose Rock Midstream GP, LLC (filed as Exhibit 3.4 to the Form S-1, filed with the Commission on August 12, 2011). | |
| 3.4 | First Amended and Restated Limited Liability Company Agreement of Rose Rock Midstream GP, LLC (filed as Exhibit 3.2 to the Registrant’s current report on Form 8-K (file No. 001-35365), filed with the Commission on December 20, 2011). | |
| 10.1 | Credit Agreement, dated November 10, 2011, among Rose Rock Midstream, L.P., as borrower, The Royal Bank of Scotland PLC, as administrative agent and collateral agent, the other agents party thereto and the lenders and issuing banks party thereto (filed as Exhibit 10.1 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 10.2 | Contribution, Conveyance and Assumption Agreement, dated November 29, 2011, by and among SemGroup Corporation, certain subsidiaries of SemGroup Corporation and Rose Rock Midstream, L.P. (filed as Exhibit 10.2 to the Form S-1, filed with the Commission on December 1, 2011). | |
| 10.3* | Rose Rock Midstream Equity Incentive Plan (filed as Exhibit 10.1 to the Registrant’s current report on Form 8-K (File No. 001-35365), filed with the Commission on December 14, 2011). | |
| 10.3.1* | Form of Restricted Unit Award Agreement (Employees) under the Rose Rock Midstream Equity Incentive Plan. | |
| 10.3.2* | Form of Restricted Unit Award Agreement (Directors) under the Rose Rock Midstream Equity Incentive Plan (filed as Exhibit 10.3.2 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 10.3.3* | Form of Phantom Unit Award Agreement under the Rose rock Midstream Equity Incentive Plan (filed as Exhibit 10.3.3 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 10.4 | Omnibus Agreement dated as of December 14, 2011, among the Registrant, SemGroup Corporation and Rose Rock Midstream GP, LLC (filed as Exhibit 10.1 to the Registrant’s current report on Form 8-K (File No. 001-35365), filed with the Commission on December 20, 2011). | |
| 10.5* | Employee Agreement, dated as of November 30, 2009, by and among SemManagement, L.L.C., SemGroup Corporation and Norman J. Szydlowski (incorporated by reference to 10.11 the Registration Statement on Form 10 of SemGroup Corporation (File No. 001-34736) filed on May 6, 2010) | |
| 10.6* | Letter Amendment dated March 18, 2010, by and among SemManagement, L.L.C., SemGroup Corporation and Norman J. Szydlowski, amending the Employment Agreement dated as of November 30, 2009 (incorporated by reference to Exhibit 10.12 the Registration Statement on Form 10 of SemGroup Corporation (File No. 001-34736 filed on May 6, 2010) | |
| 10.7* | Form of Severance Agreement between SemGroup Corporation and each of its executive officers other than Norman J. Szydlowski and David B. Gorte (incorporated by reference to Exhibit 10.13 of the Registration Statement on Form 10 of SemGroup (file No. 001-34736) filed on July 23, 2010) | |
| 10.8 | Crude Oil Storage Services Agreement, dated effective February 1, 2009, by and between SemCrude L.P. and Gavilon, L.L.C. (filed as Exhibit 10.8 to the Form S-1, filed with the Commission on September 30, 2011). | |
| 10.9 | First Amendment to Crude Oil Storage Services Agreement, dated effective May 1, 2009, by and between Gavilon, LLC and SemCrude, L.P. (filed as Exhibit 10.9 to the Form S-1, filed with the Commission on September 30, 2011). | |
| 10.10 | Second Amendment to Crude Oil Storage Services Agreement, dated effective October 1, 2009, by and between Gavilon, LLC and SemCrude, L.P. (filed as Exhibit 10.10 to the Form S-1, filed with the Commission on September 30, 2011). | |
| 10.11 | Third Amendment to Crude Oil Storage Services Agreement, dated May 4, 2010, by and between Gavilon, LLC and SemCrude, L.P. (filed as Exhibit 10.11 to the Form S-1, filed with the Commission on September 30, 2011). | |
| 10.12 | Fourth Amendment to Crude Oil Storage Services Agreement, dated effective as of October 7, 2011, by and between SemCrude, L.P. and Gavilon LLC (filed as Exhibit 10.12 to the Form S-1, filed with the Commission on October 11, 2011). | |
| 10.13* | Form of Rose Rock Midstream GP, LLC Board of Directors Compensation Plan (filed as Exhibit 10.13 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 10.14* | Form of Amendment to Severance Agreement between SemGroup Corporation and each of its executive officers other than Norman J. Szydlowski and David B. Gorte (filed as Exhibit 10.14 to the Form S-1, filed with the Commission on November 23, 2011). | |
| 21.1 | List of subsidiaries of Rose Rock Midstream, L.P. (filed as Exhibit 21.1 to the Form S-1, filed with the Commission on November 18, 2011). | |
| 23.1 | Consent of BDO USA, LLP | |
| 31.1 | Rule 13a—14(a)/15d—14(a) Certification of Norman J. Szydlowski, Chief Executive Officer. | |
| 31.2 | Rule 13a—14(a)/15d—14(a) Certification of Robert N. Fitzgerald, Chief Financial Officer. | |
| 32.1 | Section 1350 Certification of Norman J. Szydlowski, Chief Executive Officer. | |
| 32.2 | Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer. | |
| 101 | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) the Consolidated Balance Sheets as of December 31, 2011 and 2010, (ii) the Consolidated Statements of Income for the years ended December 31, 2011 and 2010, the month ended December 31, 2009 (subsequent to emergence) and the eleven months ended November 30, 2009 (prior to emergence), (iii) the Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2011 and 2010, the month ended December 31, 2009 (subsequent to emergence), and the eleven months ended November 30, 2009 (prior to emergence), (iv) the Consolidated Statements of Cash Flows for the years ended December 31, 2011 and 2010, the month ended December 31, 2009 (subsequent to emergence) and the eleven months ended November 30, 2009 (prior to emergence) and (v) the Notes to Consolidated Financial Statements. | |
| * | Management contract or compensatory plan or arrangement. |