Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10

GENERAL FORM FOR REGISTRATION OF SECURITIES

Pursuant to Section 12(b) or 12(g) of the Securities Exchange Act of 1934

Two Warren Place

6120 S. Yale Avenue, Suite 700

Tulsa, OK 74136-4216

(918) 524-8100

(Address, including zip code, and telephone number,

including area code, of registrant’s principal executive offices)

Securities to be registered pursuant to Section 12(b) of the Act:

Securities to be registered pursuant to Section 12(g) of the Act: None.

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):

Table of Contents

Table of Contents

i

Table of Contents

Cautionary Note Regarding Forward-Looking Statements

This registration statement contains statements that we believe are, or may be considered to be, “forward-looking statements.” All statements, other than statements of historical fact, included in this registration statement regarding the prospects of our industry or our prospects, plans, financial position or business strategy may constitute forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking words such as “may,” “will,” “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. Furthermore, forward-looking statements may be included in various filings that we make with the Securities and Exchange Commission (the “SEC”) or press releases or oral statements made by or with the approval of one of our authorized executive officers. 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 the section entitled “Risk Factors” beginning on page 30 of this registration statement. Readers are cautioned not to place undue reliance on any forward-looking statements contained in this registration statement, 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. You are advised, however, to consult any additional disclosures we make in our reports to the SEC. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained in this registration statement.

Unless otherwise indicated, the terms the “Company,” “our company,” “our,” “we,” “us” and similar language refer to SemGroup ^® Corporation, a Delaware corporation, and our consolidated subsidiaries and their predecessors. We sometimes refer to crude oil, natural gas, natural gas liquids (natural gas liquids, or “NGLs,” include ethane, propane, normal butane, iso-butane, and natural gasoline), refined petroleum products and liquid asphalt cement, collectively, as “petroleum products” or “products.”

ii

Table of Contents

Items 1. and 3. Business and Properties

Overview

Our business is to provide gathering, transportation, storage, distribution, blending, marketing and other midstream services primarily to independent producers, refiners of petroleum products and other market participants located in the Midwest and Rocky Mountain regions of the United States of America (the “U.S.”), Canada and the West Coast of the United Kingdom (the “U.K.”). We have an owned, contracted and leased asset base consisting of pipelines, gathering systems, storage facilities, terminals, processing plants, blending facilities and other distribution assets located between North American production and supply areas, including the Gulf Coast, Midwest, Rocky Mountain and Western Canadian regions. We also maintain and operate storage, terminal and marine facilities at Milford Haven in the U.K. that enable customers to supply petroleum products to markets in the Atlantic Basin. We also operate a network of liquid asphalt cement terminals throughout Mexico.

Our History

We were founded in February 2000 and are based in Tulsa, Oklahoma. During the period from February 2000 through July 2008, our asset and revenue base grew through a series of strategic acquisitions and capital expansion projects. During this time period, we made 64 acquisitions at an aggregate purchase price of approximately $1.1 billion, excluding amounts paid for working capital, and spent approximately $732 million on capital expansion projects.

Historically, we conducted significant physical and financial marketing and trading activities to take advantage of price differences related to time, location and quality of various energy commodity products and to utilize our transportation and storage assets. We also provided midstream energy related services such as gathering, storage, transportation, processing and distribution of petroleum products, both to third party customers and to ourselves.

As a result of trading losses incurred and other economic conditions, we faced a liquidity crisis and on July 22, 2008, we filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code, as well as applications for creditor protection under the Companies’ Creditors Arrangement Act in Canada (collectively, the “Bankruptcy”). During the Bankruptcy, we continued to operate our midstream energy-related businesses, exited certain non-core businesses and activities, disposed of certain assets, and continued certain energy infrastructure construction projects. Certain of our business units also continued marketing activities to fulfill contractual obligations and to utilize their asset base.

During the Bankruptcy, we took steps to restructure our business portfolio and to rebalance to a business heavily weighted toward fee-based asset activities and away from trading activities. Included in these steps, and subject to the terms of our debtor in possession credit facility, we attempted to sell our assets. Due to the economic environment and a lack of available financing, bids for various assets came in below valuation expectations. In some cases, assets were not sold for strategic reasons. However, the assets of two business units, SemFuel and SemMaterials, were sold in a series of transactions during the divestiture process. For additional information relating to our recent divestitures, refer to Note 7 of our consolidated financial statements beginning on page F-1 of this registration statement. Additionally, we ceased the operations of two other businesses, SemCanada Energy and SemEuro Supply. Also during the Bankruptcy, certain creditors foreclosed on our ownership interests in SemGroup Energy Partners G.P., L.L.C., the general partner of Blueknight Energy Partners, L.P., formerly known as SemGroup Energy Partners, L.P. (“Blueknight”), and also on our subordinated units in Blueknight. As a result, we no longer had, and we no longer have, any direct or indirect ownership interest in Blueknight. For additional information relating to our relationship with Blueknight, refer to “Item 7. Certain Relationships and Related Transactions, and Director Independence— Transactions with Related Persons.”

1

Table of Contents

On November 30, 2009, we emerged from the Bankruptcy as a newly reorganized company. We continue to provide midstream energy services in North America and the U.K. from an owned, contracted and leased asset base consisting of pipelines, gathering systems, storage facilities, terminals, processing plants, blending facilities, railcars, trucks and other distribution assets. Midstream services are provided to independent producers, refiners of petroleum products and other market participants. We also selectively engage in marketing activities geared toward serving our customers and maximizing the value of our asset base.

As part of the reorganization, and in conjunction with approval from our creditors and the U.S. Bankruptcy Court, we appointed a new Board of Directors and senior management team. Norman Szydlowski was hired as Chief Executive Officer and brings considerable industry experience, management and leadership skills. Additionally, Robert Fitzgerald was hired as Senior Vice President and Chief Financial Officer, David Gorte was hired as Chief Risk Officer and Candice Cheeseman was hired as General Counsel. For information relating to our executive officers, refer to “Item 5. Directors and Executive Officers.”

We conduct our operations through seven primary business segments: SemCrude ^® , SemStream ^® , SemLogistics, SemCAMS, SemMexico, SemCanada Crude and SemGas ^® . The following diagram is a simplified organizational chart of our business segments:

Industry Overview

We move petroleum products throughout the U.S., Canada, Mexico and the U.K. We provide gathering, transportation, storage, distribution, blending, marketing and other midstream services to independent producers and refiners of petroleum products. 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.

2

Table of Contents

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 II is the Midwest region of the U.S. PADD II is the second largest PADD in terms of refinery production. As a result of the flow of petroleum products across and throughout the Midwest region, we believe PADD II is an important crude oil production, logistics, and refining center.

According to the Energy Information Administration (the “EIA”) data, in 2008, approximately 21%, or 3.7 million barrels per day (“Bpd”), of total U.S. daily refining capacity was in PADD II. Also according to EIA, PADD II produces approximately 11%, or 0.5 million Bpd, of total U.S. daily crude oil production and imports approximately 11%, or 1.3 million Bpd, of total U.S. daily imports.

PADD II 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 II 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. The chart below illustrates the flow of petroleum products across and throughout PADD II.

3

Table of Contents

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.

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 2008 data compiled by the EIA, petroleum currently accounts for about 37% of the nation’s total annual energy consumption of 99.3 quadrillion British thermal units (“Btu”). 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 2.6% from 38.35 quadrillion Btu in 2008 to 39.36 quadrillion Btu in 2020, with an additional 4.2% increase in 2030 to 41.08 quadrillion Btu. The diagram below depicts the segments of the crude oil value chain and our participation in the crude oil industry.

Our U.S. crude oil business operates primarily in Colorado, Kansas, North Dakota, Oklahoma and Texas where there are extensive crude oil production operations and our assets extend from gathering systems in and around producing fields to transportation pipelines carrying crude oil to logistics hubs, such as the Cushing Interchange, where we have terminalling and storage facilities that aid our customers in managing the delivery of crude oil. Our Canadian crude business purchases, gathers and blends crude oil in Western Canada and North Dakota. We aggregate and ship volumes on major Canadian feeder and trunkline pipeline systems and a northern U.S. trunkline system.

4

Table of Contents

Gathering and Transportation

Pipeline transportation is generally the lowest cost method for shipping crude oil. Crude oil pipelines transport oil from the wellhead to logistics hubs and/or refineries. Logistic hubs like the Cushing Interchange 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.

Terminalling, Storage and Supply

Terminalling and storage facilities complement the crude oil pipeline gathering and transportation systems. Terminals are facilities where 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:

Overview of the Cushing Interchange

The Cushing Interchange is one of the largest crude oil marketing hubs in the U.S. 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, the Cushing Interchange serves as a significant source of refinery feedstock for Midwest refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil.

Natural Gas Industry Overview

Natural gas is the third largest source of primary energy, and according to EIA data, accounted for 24% of total U.S. energy use in 2008. While the primary use for natural gas in the U.S. is for residential heating, it also has a number of commercial, industrial and electric generation uses across several different customer bases. The EIA forecasts that natural gas consumption will decrease from 23.9 trillion cubic feet (“Tcf”) in 2008 to 23.3 Tcf in 2020, followed by a gradual increase to 25.0 Tcf in 2030.

Since mid-2008, North American natural gas prices have declined significantly. This price decline, along with drilling technology improvements and the recent development of shale plays in the U.S., has resulted in reduced conventional natural gas drilling activity. Demand for natural gas and NGLs has historically been highest during the winter and lowest during the summer, as gas is used primarily for heating and the need for it increases in cold months.

5

Table of Contents

Natural gas passes through many stages before reaching end-users. First, exploration and production companies locate and produce natural gas. Second, gathering companies collect the natural gas, sometimes sending it to processing plants where liquids and other substances are removed. Third, transmission companies transport the gas through pipelines to storage units or areas of high demand. Finally, distributors deliver the gas to customers. The midstream natural gas industry is the link between upstream exploration and production activities and downstream end-use markets. The diagram below depicts the segments of the natural gas value chain and our participation in the natural gas industry.

We operate in the pipeline gathering and processing segments of the natural gas midstream industry in the U.S. and Canada. The operating fundamentals of Canadian natural gas processing operations differ somewhat from those in the U.S. The most significant difference is that, unlike U.S. natural gas processing facilities where the purchaser often purchases and owns the natural gas that it gathers and processes, in Canadian natural gas processing operations, the processor typically does not take title to the natural gas it gathers and processes. The processor instead receives fee income from transporting and processing natural gas owned by others.

As natural gas is processed to remove unwanted elements that interfere with pipeline transportation, higher value hydrocarbon liquids such as NGLs and condensate are separated from the raw natural gas stream. NGLs are obtained during the production and processing of natural gas or are a by-product from the crude oil distillation process within refineries. Supplies of NGLs are determined by the level of natural gas production, the amount of liquids in the gas, refining capacity utilization and by imports of NGLs. Condensate is a mixture of petroleum products consisting primarily of pentanes and heavier liquids extracted from natural gas. It is used to make gasoline, jet fuel and as a diluent used to dilute crude bitumen so that it can be transported by pipeline. We are engaged in the transportation, storage and distribution of NGLs, primarily propane, butane and natural gasoline.

6

Table of Contents

Gas Gathering

The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.

Gas Dehydration

Wellhead gas is generally fully saturated with water vapor. This water vapor must be removed from the gas stream to prevent formation of hydrates and condensation of free water in downstream facilities, to prevent corrosion and to meet downstream pipeline quality specifications. Dehydration is generally performed at central points along an upstream gathering system utilizing either a glycol absorption process or a solid desiccant adsorption process.

Gas Treating

In addition to water vapor, wellhead gas contains impurities such as carbon dioxide, nitrogen, hydrogen sulfide, helium, oxygen and other inert components. These impurities must be removed from the gas stream to protect downstream equipment, prevent corrosion and meet downstream pipeline quality specifications. They are removed through a variety of processes utilizing chemical reaction, absorption, adsorption or permeation.

Gas Processing

Natural gas delivered to the burner tip is almost pure methane. However, natural gas is produced from the reservoir containing impurities and heavier hydrocarbons entrained in the gas stream. The heavier hydrocarbons of NGLs must be removed from the wellhead gas stream before the gas is transported to market. These heavier hydrocarbons are removed by “processing” the gas at plants, either through temperature and pressure manipulation or absorption. The extracted heavier hydrocarbons have a high value and are sold separately to petrochemical manufacturers or wholesale marketers.

NGL Terminalling, Storage and Supply

The production of NGLs by gas processing plants and refineries is fairly constant throughout the year, whereas demand is seasonal. NGL terminalling and storage serves to balance this constant production or supply with the seasonal demand. Supply and marketing agreements are entered into with gas processors and refiners to market production on the supply side. This supply is then marketed to petrochemical plants and retail customers, as well as other consumers of NGLs.

Overview of North American NGL Hubs

There are three major North American NGL trading centers located at Edmonton, Alberta; Conway, Kansas and Mont Belvieu, Texas. These locations have substantial underground storage and are connected to NGL supply, transmission and distribution systems. Edmonton and Conway serve the U.S. midwest market while Sarnia, which is located in Ontario, and Mont Belvieu serve the U.S. northeast market. Mont Belvieu is the price reference point for North American NGL markets as it is the largest consuming region. Its strategic location on the Gulf Coast allows access to supplies from Europe, Africa and the Middle East. Mont Belvieu also

7

Table of Contents

has significant storage and pipelines to transport liquids to market and is close to large crude oil refineries. Petrochemical demand is approximately 42% of NGL demand and is the main factor affecting Mont Belvieu NGL prices. The two largest contributors to overall demand are weather, since propane is used in home heating and crop drying, and the petrochemical industry’s requirement for ethane. In general, NGLs are priced higher than natural gas to cover the cost for extraction.

Mexico Asphalt Industry

Mexico is the 14th largest country in the world based on land area and the 11th largest country in terms of population. Although its land area is only one-fifth the size of the U.S., Mexico has a population of roughly one-third that of the U.S. Mexico has a large and diverse road network in place. Of Mexico’s approximately 206,000 miles of roads, over one-third are paved, making it the largest paved-road network in Latin America. Roads are a critically important component of Mexico’s transportation infrastructure, with 99% of its passengers and 59% of its cargo being transported over road surfaces. The use of rail and water transportation in Mexico, in most cases, is either not practical or not available. As a result, roads are a high priority item of the country. The total current demand for road asphalt products in Mexico is roughly 2.1 million metric tons per year, requiring approximately 1.8 million metric tons of asphalt, either as a raw material or for end-use.

Mexico spends, on average, between U.S. $2.5 and $3.0 billion on roads per year, a level which has remained fairly constant over the past several years. Most of Mexico’s funding for roads comes from the Secretaria de Comunicaciones y Transportes (“SCT”). In 2009, the total SCT budget for roads was U.S. $3.1 billion. The 2009 budget included approximately U.S. $1.4 billion for federal new roads, approximately U.S. $0.7 billion for federal maintenance and secondary roads and approximately U.S. $1.0 billion for state and municipal road systems. Another U.S. $0.35 billion was budgeted by the federal toll-road operator.

Global Petroleum Products Storage Industry

Storage for refined products and crude oil is critical to the global economy. Fluctuations in demand for crude oil and transportation fuels, combined with changing flows of petroleum product production and refining capacity, means storage is necessary to balance demand. Additionally, supply and demand disruptions due to weather, industry upsets, political tensions and terrorism have forced all industry participants to understand the significance that access to and availability of storage will have over the future years.

The independent storage industry is experiencing particularly strong demand for its services from major oil companies, oil traders and strategic storage agencies (government entities that store fuel to protect against significant fluctuations in supply or demand as mandated by the European Union and the International Energy Agency). The construction of new tank storage facilities has historically been restricted, resulting in a supply shortage. Historically, in the main trading and supply locations, such as the ARA Region (Antwerp, Rotterdam, Amsterdam), capacity has been quickly filled by demand growth.

The global product imbalance between oil producing regions and oil consuming regions continues to grow. Such varied regional demand growth for oil products is driving altered trade patterns and increased business opportunities for independent storage operators, especially those geographically situated to service numerous markets.

8

Table of Contents

Our Business

We provide gathering, transportation, storage, distribution, blending, marketing and other midstream services primarily to independent producers, refiners of petroleum products and other market participants located in the Midwest and Rocky Mountain regions of the U.S., Canada and the West Coast of the U.K. We have an owned, contracted and leased asset base consisting of pipelines, gathering systems, storage facilities, terminals, processing plants, blending facilities and other distribution assets located between North American production and supply areas, including the Gulf Coast, Midwest, Rocky Mountain and Western Canadian regions. We also maintain and operate storage, terminal and marine facilities at Milford Haven in the U.K. that enable customers to supply product to markets in the Atlantic Basin. We also operate a network of liquid asphalt terminals throughout Mexico.

We gather, purchase, transport, store, distribute, blend and market petroleum products 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.

Our Property, Plant and Equipment

Our property, plant and equipment assets include:

We believe that the variety of our petroleum product assets creates opportunities for us and our customers year round.

9

Table of Contents

Business Strategy

Our principal business strategy is to utilize our assets and operational expertise to:

Our Business Segments

We conduct our business through seven business segments:

For information relating to revenue and total assets for each segment, refer to Note 10 of our consolidated financial statements beginning on page F-1 of this registration statement.

The following sections present an overview of our business segments, including information regarding the principal business and services rendered, assets and operations and markets and competitive strengths. Our results of operations and financial condition are subject to a variety of risks. For information regarding our key risk factors, see “Item 1A. Risk Factors.”

SemCrude

SemCrude conducts crude oil transportation, storage, terminalling, gathering, blending and marketing in Colorado, Kansas, Montana, North Dakota, Oklahoma and Texas for third party customers as well as for itself. The SemCrude business unit consists of three primary operations: (i) the White Cliffs pipeline; (ii) Kansas and Oklahoma pipelines; and (iii) Cushing storage. A majority of SemCrude’s revenue is generated from fee-based contractual arrangements that, in some instances, are fixed and not dependent on usage.

Assets and Operations

White Cliffs Pipeline. We majority own and operate a 527-mile common carrier, crude oil pipeline system that originates in Colorado and terminates in Cushing, Oklahoma (the “White Cliffs Pipeline”). The White Cliffs Pipeline provides DJ Basin producers in Colorado direct access to the Cushing market and to refiners in the Midwest area. The White Cliffs Pipeline also includes a

10

Table of Contents

100,000 barrel crude oil storage tank and a truck unloading facility owned and operated by SemCrude and located and connected at the White Cliffs Pipeline’s origination point at Platteville, Colorado. The White Cliffs Pipeline’s initial design capacity is 29,700 barrels of crude oil per day with one pump station. The White Cliffs Pipeline system can be expanded to 50,000 Bpd, if additional existing pump stations are brought on line, or 70,000 barrels per day if additional pump stations are constructed. The White Cliffs Pipeline became fully operational on June 1, 2009. We currently own 99.17% of the White Cliffs Pipeline. The other 0.83% is owned by the two shippers that entered into throughput agreements. Each shipper has a purchase option to increase its ownership of the White Cliffs Pipeline to a maximum of 24.5%, which options expire no later than June 1, 2010. If the options are fully exercised, our ownership of the White Cliffs Pipeline would be reduced to 51%. To exercise the options, the shippers must pay SemCrude a proportionate share of the White Cliffs Pipeline construction costs associated with the option ownership percentage together with a specified premium.

Kansas and Oklahoma Pipeline.  We own and operate approximately 620 miles of crude oil gathering and transportation pipeline systems and related pipeline storage tanks in Kansas and northern Oklahoma. The pipeline systems connect to several third party trunk pipelines in Kansas, several refineries and storage terminals located at Cushing, Oklahoma. The Kansas and Oklahoma pipeline systems can currently transport approximately 32,700 barrels of crude oil per day.

Cushing Storage . We own and operate 4.2 million barrels of crude oil storage in Cushing, Oklahoma. We also have 0.5 million barrels of crude oil storage under construction in Cushing. SemCrude directly utilizes, and provides to customers, fee-based storage and terminal services from owned assets in Cushing. Currently, most of SemCrude’s owned operating storage capacity at Cushing is leased to third-party customers. SemCrude also owns and operates a delivery/receipt pipeline to connect its storage operations to TEPPCO’s facility in Cushing, which is the hub where all NYMEX barrels are delivered. We have additional acreage and infrastructure in place to significantly expand storage capacity at Cushing.

Revenue and Marketing

A majority of SemCrude’s revenue is derived from fee-based contractual arrangements with third party customers. The White Cliffs Pipeline has two throughput contracts that require each shipper to pay a minimum fixed monthly payment for the capacity allocated to it on the pipeline, regardless of the capacity actually utilized. The agreements run through May 2014. The Kansas and Oklahoma pipeline system provides transportation and storage services to customers on fee-based arrangements, typically based on usage with varying term lengths. Cushing storage capacity is provided to customers under fixed fee contractual arrangements, typically based on the amount of storage capacity reserved for each customer.

In addition to third party customer revenue, SemCrude generates revenue from limited marketing activities. SemCrude’s U.S. marketing includes purchasing crude oil for its own account from producers and aggregators and selling crude oil to traders and/or refiners.

SemCrude manages marketing price risk by limiting its net open positions subject to outright price risk and basis risk resulting from grade, location or time differences. SemCrude does so by selling and purchasing like quantities of crude oil with purchase and sale transactions, or by entering into future delivery and purchase obligations with futures contracts or other derivative instruments at locations along its pipeline and Cushing storage systems, with the effect that many of these purchases and sales become “back-to-back” transactions (purchases and sales of crude oil are predominantly matched). SemCrude’s storage and transportation assets can also be used to mitigate location and time basis risk. In addition, when SemCrude engages in back-to-back purchases and sales, the sales and purchase prices are intended to lock in positive margins for SemCrude, e.g., the sales price is intended to exceed purchase costs and all other fixed and variable costs. All marketing activities are subject to our Comprehensive Risk Management Policy which establishes limits, both at SemCrude and SemGroup Corporation levels, to manage risk and mitigate financial exposure.

11

Table of Contents

Market and Competitive Strengths

SemCrude’s pipelines are located in areas where they have the ability to move crude oil to Cushing. The Cushing Interchange is one of the largest crude oil marketing hubs in the U.S. and the designated point of delivery specified in all NYMEX crude oil futures contracts. As the NYMEX delivery point and a cash market hub, the Cushing Interchange serves as a significant source of refinery feedstock for PADD II refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil. The White Cliffs Pipeline is the only direct route out of the DJ Basin in Colorado to Cushing. The Kansas/Oklahoma pipeline system allows Kansas producers and purchasers access to local refineries and Cushing.

SemStream

SemStream is engaged in the terminalling, storage, marketing and distribution of NGLs, primarily propane, and to a certain extent, butane and natural gasoline. SemStream owns assets that are located in some of the key areas of high propane demand in the U.S., with operations in over 40 states. SemStream’s operations include sales to retail, wholesale and commercial customers linked to purchases from suppliers, and encompass three primary focus areas: (i) wholesale marketing at both private and common carrier terminals; (ii) NGL supply to retail, petrochemical and commercial customers; and (iii) residential propane supply through SemStream’s wholly-owned subsidiary, SemStream Arizona Propane, L.L.C. (“SemStream Arizona”).

Assets and Operations

SemStream owns eleven NGL terminals and leases one NGL terminal. The terminals are located in Arkansas, Indiana, Minnesota, Missouri, Montana, Washington and Wisconsin. These terminals have an aggregate throughput capacity of over 325 million gallons of propane and normal butane per year. We also have one NGL terminal under construction in Arizona which is scheduled for completion in the third quarter of 2010. We also market out of several other third party owned facilities in strategic locations throughout North America. In support of the terminal operations and marketing business, SemStream has access to approximately 4.4 million barrels of storage for NGL products, some owned and some held through lease arrangements; 15 miles of underground pipeline that connect various terminals to supply sources; and a rail fleet of approximately 350 leased and 12 owned railcars.

SemStream Arizona is engaged in retail sales and downstream distribution of propane. It includes a regulated underground utility business and a non-regulated propane bulk business, serving approximately 12,000 residential customers in Arizona. The regulated business serves approximately 10,000 customers through two regulated utilities operating underground vapor systems in and around Payson and Page, Arizona. The non-regulated operations include the retail distribution of bulk propane to approximately 2,000 customers in these same Arizona communities and in certain Utah/Arizona border communities. SemStream Arizona’s assets include over 200 miles of underground pipelines, propane storage and other equipment.

12

Table of Contents

Revenue and Marketing

SemStream’s role in the NGL marketplace is to help our suppliers, typically refineries and gas processing plants, manage and market their constant production of NGLs in a seasonal demand market. Our focus for sales of product is connected to retail propane marketing companies, petrochemical plants, wholesalers and industrial customers by providing value in our network of transportation (rail/truck/pipeline), storage and truck and rail terminal assets. Additionally, the wholesale marketing business sells propane from owned terminals and conducts wholesale marketing on several common carrier pipelines serving customers in the Southeast, Northeast and the upper Midwest regions of the U.S. SemStream has exclusive product marketing agreements representing key suppliers from third party facilities, which include two refineries, a propane terminal and a group of gas plants.

The marketing business focuses on propane, but also includes the sale of normal butane, iso-butane and natural gasoline. Propane sales are typically seasonal in nature, with most sales occurring in the winter heating season. Although the other NGLs have some seasonality, they tend to be less seasonal than propane. We also generate revenue from private terminal operations by charging throughput fees on all products moving through our owned terminals.

Through our regulated utility in Arizona, we market propane directly to approximately 10,000 residential customers connected through a low pressure pipeline delivery system.

Market and Competitive Strengths

Although commodity prices could impact demand for SemStream’s services, the diversity of customers and assets allows SemStream flexibility to adjust its customer and product mix in response to changes in demand. Our assets generally have the capability to handle multiple NGL products. We operate in markets where propane serves more than 10% of the heating demand. In these markets, propane is a primary heating source and demand for our propane services is fairly stable. In addition to providing propane for heating needs, we provide propane and other NGLs to commercial, industrial and refining customers who use the products in a variety of applications from petrochemical feedstocks to refrigeration and fuel use in transportation.

NGL commodity prices tend to have some correlation to crude oil commodity prices and can experience the same volatility. While this price volatility can have an effect on SemStream, we typically structure marketing transactions index-to-index, with a negotiated differential to manage a portion of fee based margin and terminal throughput fees. SemStream’s other operations are fixed-fee arrangements in which SemStream receives a fee for marketing the NGL products for the producer. The fee is a fixed percentage of the sales price and the producer retains the commodity price risk.

SemStream manages marketing price risk by limiting its net open positions subject to outright price risk and basis risk resulting from grade, location or time differences. SemStream does so by selling and purchasing similar quantities of NGLs with purchase and sale transactions for current or future delivery, by entering into future delivery and purchase financial obligations with futures contracts or other derivative instruments, and employing its storage and transportation assets. SemStream may hedge its NGL commodity price exposure with derivatives on commodities other than NGLs due to the limited size of the market for NGL derivatives. In addition, physical transaction sale and purchase strategies are intended to lock in positive margins for SemStream, e.g., the sales price is sufficient to cover purchase costs, any other fixed and variable costs and SemStream’s profit. All marketing activities are subject to our Comprehensive Risk Management Policy which establishes limits, both at the SemStream and SemGroup Corporation levels, to manage risk and mitigate financial exposure.

13

Table of Contents

SemLogistics

SemLogistics owns the largest independent petroleum products storage facility in the U.K. The main activities of SemLogistics are the receipt, storage and redelivery of clean petroleum products and crude oil via sea-going vessels at the Milford Haven site.

Assets and Operations

SemLogistics operates a tank storage business and offers build-bulk (importing small cargos, building volume and exporting larger cargos) and break-bulk (importing larger cargos and exporting smaller cargos) operations to its customers that transport products from the Middle East to Europe, the east coast of the U.S. and the west coast of Africa. SemLogistics also provides compulsory strategic storage (storage of product within the European Union as a result of the International Energy Agency rules requiring member states to hold oil stocks in reserve) for European National Agencies. The terminal is strategically located to access the U.K. market and to service numerous global markets.

SemLogistics’ storage facility includes approximately 8.7 million barrels of above ground storage tanks. SemLogistics has also received approval from Pembrokeshire County Council to build nine new tanks with total storage capacity of 1.5 million barrels. The approval is valid through October 2013, and construction must begin by this time for the approval to remain valid. The terminal has two deep water jetties, one of which can accommodate vessels of up to 165,000 dead weight tons. It also has access to Mainline Pipeline Limited (pipeline from Milford Haven to Manchester and Nottingham), which is owned by four major oil companies.

Over 40% of SemLogistics’ storage capacity is multi-product, providing customers with tank storage for clean petroleum products, including gasoline, gasoline blendstocks, jet fuel, gas oil and diesel. The remaining tankage is either dedicated to crude oil or dual-purpose tankage for at least two clean petroleum products (gasoline/jet fuel or gasoline/gas oil or jet fuel/gas oil). SemLogistics also provides related services, e.g., tank-to-tank transfers, mixing of gasoline blendstocks and kerosene marking.

Revenue and Marketing

SemLogistics generates revenue from fixed-fee storage tank leasing and related services. All of SemLogistics’ storage capacity is leased to third parties who use the facility as an intermediate storage terminal for crude oil and refined products produced at the refineries prior to shipment to customers. Customers fall into three broad categories: trading, structural marketing storage and compulsory strategic storage. SemLogistics’ customers typically enter into contracts with terms of between six months and five years, with most of the existing customers having been in place for multiple season contract cycles.

Markets and Competitive Strength

SemLogistics’ ability to handle multiple products provides flexibility to change its operations in response to market conditions. Demand for independent storage terminals can be impacted by a wide range of influences such as the forward price curve, expanding oil production, security of supply concerns, European compulsory stock holding requirements and mismatches in regional production and consumption of oil and liquid petroleum products. Current market factors have resulted in increased demand for storage due to worldwide demand for clean products and crude oil, concerns over supply security, instability in several of the world’s largest crude oil producing countries, unprecedented fluctuations in energy commodities and the U.K.’s structural shortage of jet fuel. SemLogistics has been resilient through these changing markets due to its flexibility and location.

14

Table of Contents

SemLogistics’ terminal size (approximately 23% of the total independent storage in the U.K.) and its vessel handling capabilities make it unique compared with other terminals. In addition to being the only independent U.K. facility that serves the bulk trans-shipment sector, it is also the only facility capable of handling crude oil, with the only other comparable facility in the British Isles being a terminal in Ireland. However, the owner of this other facility, a major oil company, uses its terminal exclusively for proprietary storage and storage of Irish strategic stocks.

SemCAMS

We own and operate sour natural gas processing and gathering facilities in Alberta, Canada. The principal process performed at the processing plants is to “sweeten” sour natural gas by removing sulfur. Approximately two-thirds of the total natural gas throughput at our processing plants is sour gas. All of SemCAMS’ assets are located in West-Central Alberta, in the heart of the Western Canadian Sedimentary Basin, which accounts for approximately 80% of Canada’s sour natural gas production.

Assets and Operations

SemCAMS owns and operates varying working interests in (i) two sour natural gas processing plants known as the Kaybob South No. 3 plant (the “K3 Plant”), and the Kaybob Amalgamated plant (the “KA Plant”); (ii) two sweet gas plants known as the West Fox Creek plant and the West Whitecourt plant (the “WW Plant”), and (iii) a network of more than 600 miles of natural gas gathering and transportation pipelines. The sour gas plants are dually connected to two major long-haul natural gas pipelines that serve Canada and the U.S. The plants also have the ability to load product for transportation by truck and railcar. Prior to February 2010, the WW Plant processed both sweet and sour gas supply. In late December 2009, the working interest owners of a large gas field feeding the WW Plant voted to re-route the sour gas production away from the WW Plant to the K3 Plant. The WW Plant is presently processing only sweet natural gas.

Revenue and Marketing

SemCAMS generates revenue from the processing plants through volumetric fees for services under contractual arrangements with working interest owners and third party customers. SemCAMS does not have direct exposure to commodity prices. In addition, SemCAMS generates fee-based revenue from volume throughput on its pipelines. SemCAMS’ customers include producers of varying sizes.

SemCAMS also derives revenue as the operator of pipeline gathering systems that gather gas from multiple wells located in the same production unit and as the operator of pipeline transportation systems that deliver the gathered gas to each plant.

To support operations at our plants, several producers have committed to process all of their current and future natural gas production from lands owned by them, or their subsequent assignees, within a “dedicated area” comprised of approximately 180 townships located in and around our plants. The “dedicated area” covers approximately 27% of the volumes in the area surrounding our plants. This dedication continues until field depletion.

15

Table of Contents

Market and Competitive Strengths

SemCAMS’ natural gas gathering and processing operations are located in an area that generates more than 95% of Canada’s total natural gas production and approximately 80% of Canada’s total sour gas production. Natural gas is used for a variety of purposes in Canada including heating, electricity production and other industrial processes.

SemMexico

SemMexico provides asphalt emulsions and polymer modified liquid asphalt cement products and services to the Mexico market. SemMexico purchases, produces, stores and distributes liquid asphalt cement products in Mexico. SemMexico purchases liquid asphalt cement from local refineries in Mexico and further processes the materials, in combination with other raw materials, to produce products that are sold to road contractors and government agencies.

Assets and Operations

SemMexico operates a network of 11 in-country liquid asphalt cement terminals and modification facilities (ten are owned and one is leased) and two emulsion distribution terminals. SemMexico’s national technical center and headquarters are located in Puebla, Mexico. SemMexico purchases liquid asphalt cement from five local refineries in Mexico, which are owned and operated by Pemex.

Revenue and Marketing

SemMexico generates revenue from liquid asphalt cement product sales to customers. In general, SemMexico’s sales and purchases of liquid asphalt cement are matched as SemMexico procures product on an as-needed basis, thereby limiting price exposure to price movements on inventory. SemMexico focuses on increasing production capacity and product outlets and also in bringing technologically advanced products and solutions to Mexico’s asphalt market.

Market and Competitive Strengths

SemMexico is a leader in asphalt pavement technologies and capabilities. It is the only liquid asphalt cement company with a national footprint in Mexico. These factors have resulted in a long-term supply relationship with Pemex and continual business transactions with the same customers. SemMexico is exposed to market risk such as the sustainability of road construction and maintenance funds from the Mexican government. However, we believe that SemMexico’s significant market position, technology and long-term relationships with suppliers and customers are strategic strengths that would benefit SemMexico if funding or demand were to increase.

SemCanada Crude

SemCanada Crude purchases, aggregates and blends crude oil in Western Canada, North Dakota and Montana. SemCanada Crude purchases various grades of crude oil, primarily at pipeline and facility receipt locations, from small to medium-sized producers and energy trusts. It then aggregates the purchases for sale to independent refiners in Eastern Canada and the northern tier of the U.S., as well as to other crude oil aggregators at various aggregation points in Canada and the U.S.

16

Table of Contents

Assets and Operations

SemCanada Crude currently markets approximately 16,000 Bpd of crude oil and is a shipper on major Canadian feeder pipelines and on a number of trunkline pipelines in Canada. In addition to the aggregation of crude oil, SemCanada Crude manages and provides marketing for five company owned blending facilities located throughout Alberta and Saskatchewan, as well as two facilities in North Dakota owned by SemCrude. In relation to these facilities, SemCanada Crude purchases various grades of crude oil and diluents and, through its blending process, upgrades the product quality of purchased barrels to sell them at higher margins. In addition, SemCanada Crude has a long-term storage lease of 250,000 barrels at Edmonton, the main market hub for Canadian crude oil.

SemCanada Crude’s North Dakota/Montana aggregation and blending business is supported by assets owned by SemCrude. While SemCrude owns the assets, SemCanada Crude provides management and marketing for the area, including the purchase and sale of crude oil which is transported on SemCrude trucks and onto Enbridge Pipelines (North Dakota), where SemCrude has a historical pipeline allocation.

Revenue and Marketing

SemCanada Crude generates revenue by aggregating crude oil purchases and then selling crude oil in bulk to independent refiners and other crude oil aggregators at a margin. Crude oil is purchased and sold predominantly on 30-day evergreen contracts. SemCanada Crude also moves purchased crude oil through its owned facilities where its quality and product can be upgraded. The blending business earns profit by optimizing the crude oil grade and quality to be delivered to the pipeline via the purchase of various types of crude oil and other diluents. SemCanada Crude currently subleases its leased 250,000 barrel storage tank at Edmonton at a fixed margin.

Market and Competitive Strengths

SemCanada Crude’s blending facilities are strategically located where crude oil optimization opportunities exist through access to local pipelines and a diverse supply of crude oil produced in the area. The aggregation business supports the blending business as it provides access to requisite supply and fosters strong relationships with key partners and potential suppliers.

SemCanada Crude earns a relatively consistent margin per barrel on aggregated volumes, while blending facility profits fluctuate each month. Blending profits are driven by differential pricing of various crude oil and diluent streams, equalization penalties and the ability to access suitable supplies. SemCanada Crude structures transactions to maintain margins and hedges inventory volumes so as to minimize exposure to outright price movements.

SemCanada Crude manages marketing price risk by limiting its net open positions subject to outright price risk and basis risk resulting from grade, location or time differences. All marketing activities are subject to our Comprehensive Risk Management Policy which establishes limits, both at SemCanada Crude and SemGroup Corporation levels, to manage risk and mitigate financial exposure.

SemGas

SemGas provides natural gas gathering and processing services. It has gathering and processing plants and assets in Kansas, Oklahoma and Texas. SemGas aggregates gas supplies from the wellhead and provides various services to producers that condition the wellhead gas production for downstream markets.

17

Table of Contents

Assets and Operations

SemGas currently owns and operates over 800 miles of gathering pipelines in Kansas, Oklahoma and Texas, and three processing plants with 53 million cubic feet per day of capacity.

SemGas’ key assets include the Sherman processing plant in north-central Texas with over 400 miles of low pressure gathering lines; the Nash and Hopeton processing plants and gathering systems in northern Oklahoma; the Eufaula gathering system which gathers, dehydrates and compresses gas in eastern Oklahoma; and a gathering system and treating plant in Kansas.

Revenue and Marketing

SemGas generates revenue from a portfolio of contracts. Initial contract terms can range from two years to the life of the reserves and, upon expiration, continue to renew on a month-to-month or year-to-year evergreen basis. The majority of the contracts provide upside potential by providing SemGas participation in commodity price and processing margin upswings through percent-of-proceeds and percent-of-index contracts. On these contracts, SemGas is generally responsible for marketing the gas and NGLs for both its and the producers’ share of the products. Percent-of-proceeds contracts are based on SemGas paying the producers a percentage of the sale proceeds from the products and percent-of-index contracts are based on SemGas paying the producers a percentage of the sale proceeds based on an index price. SemGas also has fee-based contracts for processing and gathering services. SemGas’ customers include producers, operators, marketers and traders.

Market and Competitive Strengths

SemGas’ gathering and processing volumes can be impacted by market demand for the products it handles. Gathering and processing activities are also reliant on continued drilling and production activity by producers in our areas of operation. While price increases in natural gas might lead to increased drilling and supply, price increases can also adversely affect demand.

We face competition in acquiring new natural gas supplies. The natural gas gathering and processing industry is generally characterized by regional competition, based on the proximity of gathering systems and processing plants to natural gas producing wells. SemGas’ gathering and processing assets tend to have relatively long-term contracts and, in some instances, are the only assets that can provide the offered services to the customers.

SemGas generally sells all natural gas and NGLs it obtains under its percentage-of-proceeds and percentage-of-index contracts immediately in the spot market and, therefore, has little commodity price risk with respect to inventory or other physical commodity positions. SemGas’ percentage-of-proceeds and percentage-of-index processing contracts intrinsically have commodity price risk since SemGas’ fees, with respect to these contracts, vary with the level of natural gas and commodity prices. SemGas may elect to use financial derivatives to hedge this risk. SemGas is limited in the amount, and in the time period, for which it may hedge its commodity price risk associated with its contracts pursuant to our Comprehensive Risk Management Policy. More generally, all of our marketing and hedging activities are subject to our Comprehensive Risk Management Policy which establishes a set of limits, both at the SemGas and the SemGroup Corporation levels, to manage risk and mitigate financial exposure.

18

Table of Contents

Risk Governance and Comprehensive Risk Management Policy

We expect to generate the majority of our earnings from owning and operating strategic assets while endeavoring to prudently manage all risks, including commodity price risk, associated with the ownership and operations of our assets. We have a Comprehensive Risk Management Policy that reflects an enterprise-wide approach to risk management and considers both financial and non-financial risks.

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. The Audit Committee of our Board of Directors has oversight responsibilities for the implementation of, and compliance with, our Comprehensive Risk Management Policy.

Our Risk Management Committee, comprised of 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 at SemCanada Crude, SemCrude, SemGas and SemStream, our Comprehensive Risk Management Policy provides a set of limits for each of these segments individually, in addition to limits applicable on a consolidated basis. Our Comprehensive Risk Management Policy also specifies the types of transactions that may be executed by incumbents of named positions without specific approval of our Board of Directors or our Risk Management Committee. It also restricts proprietary trading activities to those proprietary trading strategies specifically approved by our Risk Management Committee and within limits significantly more restrictive than the corporate market risk management limits.

Competition

We face intense competition in each of our operations. Our competitors include other midstream companies, major integrated oil companies and their marketing affiliates, crude oil pipeline companies and independent gatherers, brokers and marketers of petroleum products of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control greater supplies of crude oil and petroleum products. Competition for customers of petroleum products 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.

19

Table of Contents

Operational Hazards and Insurance

Pipelines, terminals, storage tanks, processing plants or 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 have maintained 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. However, such insurance does not cover every potential risk associated with operating 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. We will continue to monitor the appropriateness of our deductibles and retentions as they relate to the overall cost and scope of our risk and insurance program.

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, provincial, foreign and local regulations that may affect our business.

Regulation of U.S. Pipeline and Storage Operations

Interstate Storage and Transportation

White Cliffs Pipeline is subject to regulation by the Federal Energy Regulatory Commission (“FERC”) because the rates charged to shippers on the pipeline system are required to be filed with, and accepted by, FERC. Under the Interstate Commerce Act (the “ICA”), FERC has authority to regulate companies that provide interstate petroleum based products pipeline transportation services, including pipeline operational transportation related storage services. FERC’s authority to regulate those interstate services includes the rates charged for services, terms and conditions of service, maintenance of accounts and records and various related ancillary matters. Regulated companies may not charge rates that have been determined not to be “just and reasonable” by FERC. The rates, terms and conditions for our service will be found in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. In addition, FERC prohibits petroleum and NGL based products transportation from unduly preferring, or unreasonably discriminating against, any person with respect to pipeline rates or terms and conditions of service.

20

Table of Contents

Gathering and Intrastate Pipeline Regulation

The ICA, the Natural Gas Act (the “NGA”) and the Natural Gas Policy Act of 1978 do not apply to intrastate petroleum and natural gas based products facilities and activities, i.e., those that are not used or usable in the conduct of interstate commerce. FERC has ruled that interstate petroleum and natural gas gathering systems are exempt from regulation by the Commission. We own a number of natural gas pipelines that we believe operate wholly intrastate and are, therefore, exempt from FERC regulation. We also own a number of intrastate crude gathering systems that are subject to state and local, but not federal regulation. These gathering systems are currently operated as proprietary systems and may be subject to regulation by FERC in the future.

In the states in which we operate, regulation of intrastate natural gas and crude gathering facilities and intrastate crude pipeline service generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. For example, our natural gas gathering facilities are, in some cases, subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right, as an owner of gathering facilities, to decide with whom we contract to purchase or transport natural gas.

Department of Transportation

All crude oil and liquefied petroleum gases interstate pipelines, and certain intrastate crude oil and liquefied petroleum gases pipelines and storage facilities, are subject to regulation by the Department of Transportation (the “DOT”) with respect to the design, construction, operation and maintenance of the pipeline systems and storage facilities. The DOT routinely conducts audits of the 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.

Regulation of NGL Terminals, Distribution and Utility Operations

Most of SemStream’s terminal operations, and its Arizona non-regulated and regulated propane distribution operations, are subject to the code set forth in the National Fire Protection Association Standard #58 (“NFPA 58”), Standard for the Storage and Handling of Liquefied Petroleum Gases. All of the states in which SemStream has operations have adopted some form of NFPA 58, and state agencies routinely conduct physical audits to insure compliance with such regulations.

SemStream Arizona’s utility operations are subject to regulation by the Arizona Corporation Commission (“ACC”). The ACC regulates the sale price of propane gas to customers connected to our underground propane gas systems in Payson and Page, Arizona. The ACC also conducts annual inspections of the Payson and Page utility underground pipeline systems under authority delegated to it from the DOT.

21

Table of Contents

Trucking Regulation

We 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 regulations with respect to our trucking operations.

Cross-Border Regulation

We are subject to regulatory matters specific to border crossing, which include export licenses, tariffs, customs and tax issues and toxic substance certifications. Regulations include the Short Supply Controls of the Export Administration Act, the North American Free Trade Agreement, National Energy Board Reporting and Certification and the Toxic Substances Control Act. Violations of license, tariff and tax reporting requirements under these regulations could result in the imposition of significant administrative, civil and criminal penalties. Furthermore, the failure to materially comply with applicable tax requirements could lead to the imposition of additional taxes, interest and penalties.

Regulation of Canadian Gathering, Processing, Transportation and Marketing Businesses

National Energy Board (“NEB”)

Our Canadian assets are not currently regulated by the NEB. The importation and exportation of natural gas and crude oil to and from Canada, however, are regulated by the NEB. The Government of Alberta tracks volumes exported from Alberta and, although it has not previously done so, reserves the right to limit the volume of natural gas that may be removed from Alberta in the event of domestic supply constraint.

Energy Resources Conservation Board (“ERCB”)

The ERCB’s purpose is to ensure that the discovery, development and delivery of Alberta’s resources take place in an orderly and efficient manner and in the public interest.

Among other matters, the ERCB has the authority to regulate the exploration, production, gathering, processing, transmission and distribution of natural gas within the province. With respect to natural gas gathering and processing activities, the ERCB’s primary role is to serve as a licensing authority for the construction and operation of the facilities used in those activities.

While the ERCB has jurisdiction to regulate the rates and fees charged for services provided by these types of facilities using a public complaint process, this authority is discretionary and has not commonly been exercised. Generally, the complaint-based method of regulation has meant that parties have had the opportunity to use alternative means to resolve disputes without resorting to the ERCB.

Sulphur Recovery Standards

In 2001, the ERCB set more stringent sulphur recovery standards for older sour gas processing plants, as set out in ID 2001-3. This interim directive directed older, “grandfathered” plants to either gradually increase their sulphur recovery to current standards or accept a reduction in their licensed capacity.

The K3 Plant and the KA Plant are capable of meeting “de-grandfathered” recovery requirements. The K3 Plant was “de-grandfathered” in 2006 after installation of a new Super Claus Sulphur recovery process. The KA Plant can be “de-grandfathered” via simple administrative application.

22

Table of Contents

Other Provincial Regulatory Agencies

The Alberta Boilers Safety Association (“ABSA”) is the regulatory agency in Alberta of pressure systems with a mandate to ensure that pressure equipment is constructed and operated in a manner that protects public safety. SemCAMS maintains an approved program to meet all requirements.

Regulation of U.K. Operations

In the U.K., the Department of Energy and Climate Change’s Energy Resources Development Unit is responsible for the regulation of a number of relevant areas, including licensing, fiscal policy, national oil stocks policy (including their compulsory oil stocking obligations as a member of the European Union and International Energy Agency), policy on oil disposal, offshore environmental policy, oil sharing arrangements and decommissioning. Other regulatory bodies include the Health and Safety Executive, which regulates health and safety in the upstream and downstream oil industry (among others) and the Hazardous Installations Directorate, which is responsible for inspection and enforcement of health and safety regulation with respect to the downstream oil industry (among others). There is no regulator dedicated specifically to the oil industry. The activities of SemLogistics may also be regulated as a result of the European Union’s participation in the International Carriage of Dangerous Goods by Road and Rail agreements, as well as the International Maritime Dangerous Goods Code, which governs the safe transport of dangerous goods (including oil) by sea and, in due course, by the Marine Management Organization when it comes into being pursuant to the Marine and Coastal Access Bill.

The Department for Environment Food and Rural Affairs is responsible for setting legislation, policy, regulations and guidance for a number of environmental issues. There are also several European and international laws and policies that apply. SemLogistics’ activities are regulated by the Environment Agency Wales (“EAW”). EAW also oversees spills and their cleanup, as well as new construction of tanks, bunds (spill prevention berms in the U.S.) and other improvements, and whose regulations require us to maintain a Pollution Prevention and Control permit.

At a local level, SemLogistics’ storage facility falls within the jurisdiction of the Milford Haven Port Authority (the “MHPA”). Under the Milford Haven Port Authority Act 2002, the MHPA has the power to publish directions for the purpose of promoting or securing conditions conducive to the ease, convenience or safety of navigation in Milford Haven and the approaches to it. MHPA is currently consulting on the Milford Haven Port Authority General Directions (2006). MHPA also has powers and obligations under various regulations, including, among others, the Dangerous Substances in Harbour Areas Regulations 1987 and the Harbour Docks and Piers Clauses Act 1847, as well as responsibility for the enforcement of the Port Marine Safety Code.

Regulation of Mexican Operations

SemMexico is primarily engaged in the purchasing, production, modification, storage and distribution of liquid asphalt cement products throughout Mexico. These activities are subject to compliance with environmental laws and regulations under Mexican technical “Official Standards” and other provisions that establish minimum technical requirements. Companies are required to obtain, from the corresponding federal, local and/or municipal authorities, the relevant permits and authorizations to construct and operate asphalt modification plants and carry out the activities described above.

Mexico’s Ministry of Communications and Transportation has published several construction standards establishing the specifications required for asphalt surfaces in connection with infrastructure projects, as well as certain manuals identifying the procedures for verifying compliance therewith.

23

Table of Contents

Asphalt treatment, storage and distribution activities are considered hazardous under applicable environmental laws and regulations and are subject to the scrutiny of the Ministry of the Environment and Natural Resources, which is the governmental agency in charge of granting the authorization for the handling, transportation, treatment, storage, importation, exportation and final disposal of asphalt, among others. These authorizations are essential for SemMexico to be able to perform its activities in Mexico.

Coupled with the authorizations and permits that may be granted by the Ministry of the Environment and Natural Resources, asphalt transportation activities within Mexico are subject to having obtained a number of other federal and local permits, including federal licenses for the operators of transportation units mobilizing SemMexico’s liquid asphalt cement products.

Environmental, Health and Safety Regulation

General

Our operations, including Canada, U.K. and Mexico 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 petroleum and natural gas 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 petroleum product 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, 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 would not have a material adverse effect on us, there is 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 (“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, provincial 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

24

Table of Contents

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 soils, surface waters 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 U.S. 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.

Similar measures are in place in Canada at both a federal and provincial level.

In addition, national, local and European Union regulations and directives in the U.K., and federal, state and local laws in Mexico, impose similar, but not necessarily always as stringent and detailed, requirements as in the U.S. concerning water resources and the protection of water quality, including those that regulate the discharge of pollutants and other harmful substances into water, require permits, impose clean-up obligations for spills and releases and impose fines and penalties for non-compliance. However, these countries continue to implement stricter requirements that approach the requirements in the U.S.

Air Emissions

Our operations are subject to the federal Clean Air Act, as amended, and comparable state and local laws, as well as the federal, provincial and local Canadian, U.K., European Union and Mexican laws applicable to our Canadian, U.K. and Mexican operations, although not necessarily always as stringent as found in the U.S., at least not presently. These laws and regulations regulate emissions of air pollutants from various sources, including certain of our plants, compression stations and other 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.

SemCAMS conducts on-going air, soil and ground water monitoring in accordance with license requirements. SemCAMS is required to annually report all specified emissions from its major facilities to a publically accessible National Pollutant Release Inventory database.

Sour Gas

SemCAMS operates facilities which process and transport sour gas (gas containing hydrogen sulfide, generally at concentrations of 10 parts per million or more). Due to the highly toxic and corrosive nature of sour gas, sour gas handling is regulated in Canada, at both the provincial and federal level, from the wellhead to the point of disposal of the sulfur content removed from processing the sour gas. Environmental legislation can also affect the operations of facilities and limit the extent to which facility expansion is

25

Table of Contents

permitted. Proposed facilities are facing increased resistance from community groups which is, in turn, increasing demand for alternate sources of sweetening. In addition, legislation requires that facility sites be abandoned and reclaimed to the satisfaction of provincial authorities and local landowners. A breach of such legislation may result in the imposition of fines and the issuance of clean-up orders. In all practicality, the construction of new sour gas processing facilities in Alberta has been non-existent for nearly a decade due, not only to the under-utilization of existing plants, but also owing to public safety and environmental concerns. Instead, existing plants have been better utilized by extending the reach of the relevant gathering pipeline systems.

To protect the public, pipelines transporting sour gas are required to be equipped with monitoring stations and valves that automatically shut down the flow of the pipeline in response to sudden changes in pressure or detection of sour gas in the atmosphere. SemCAMS’ sour gas pipelines are monitored 24 hours per day from a centralized pipeline control center and can be shut down by the attending operators. The distance between automatic pipeline valves is determined, based on regulated sour gas dispersion modeling, to meet approved emergency protection zone size and public exposure requirements. The integrity of the sour gas pipelines is maintained through the injection of corrosion inhibition chemicals on an on-going basis. SemCAMS’ sour gas pipelines are inspected on a regular basis to ensure the integrity of the pipelines and associated facilities.

SemCAMS’ sour gas plants have continuous sour gas detection equipment, as well as other safety systems which can automatically shut down and depressure the full plant to a controlled flare system. The plants are attended 24 hours per day and can also be shut down by attending operators.

At SemCAMS’ sour gas processing plants, sulfur recovery and air quality are constantly monitored to ensure required sulfur recovery and emission standards are met. Existing regulations require a sliding range of recovery depending on throughput. SemCAMS’ required sulfur recovery ranges vary from 98.3% to 98.8%; operational history has shown actual recovery above license requirements at 98.7% to 99.2%. Residual sulfur that cannot be removed by processing is incinerated to meet a minimum stack top temperature based on a regulator approved dispersion model.

Climate Change

In response to concerns suggesting that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”) (including carbon dioxide (“CO ₂ ”) and methane), are contributing to the warming of the Earth’s atmosphere and other climatic changes, the United States Congress has been considering legislation to reduce such emissions. In addition, more than one-third 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. As an alternative to cap and trade programs, Congress may consider the implementation of a carbon tax program. The cap and trade programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or NGL fractionation plants, to acquire and surrender emission allowances. Depending on the particular program and scope thereof, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations. Depending on the design and implementation of carbon tax programs, our operations could face additional taxes and 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 the natural gas and NGLs we gather and process.

26

Table of Contents

On December 15, 2009, the U.S. Environmental Protection Agency (the “EPA”), issued a notice of its final finding and determination that emissions of CO ₂ , methane, and other GHGs 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. Consequently, the EPA has proposed regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain 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. In March 2010, the EPA proposed revisions to these reporting requirements to apply to all oil and gas production, transmission, processing and other facilities exceeding certain emission thresholds. 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 CO ₂ 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 the petroleum products we gather, process, transport, store, distribute and market.

SemCAMS has been required to file provincial GHG emissions reports annually since 2003 for its three large gas plants. GHG baselines were set based on 2003 through 2005 data. Alberta facilities that emit more than 100,000 tonnes of GHG per year have to reduce emissions intensity by 12 percent. Companies can meet this obligation through improvements to their operations, by purchasing Alberta-based credits, by contributing to the Climate Change and Emissions Management Fund or any combination thereof. Beginning with the last half of the 2007 reporting year, penalties (U.S. $15 per tonne) are paid to the provincial government when the GHG intensity (GHG emissions per unit of production) are greater than 88% of the intensity established in the baseline data. All GHG costs paid by SemCAMS are recovered by allocation to the producers based on fuel gas use and CO ₂ composition in the inlet gas. Failure to comply with the regulation will result in a fine of $200 for every tonne of CO ₂ by which the total release of specified gases exceeds the net emissions intensity limit for the facility. Legislation to further lower the current reporting limit is pending which, if enacted, would require additional SemCAMS facilities to file provincial GHG emissions reports annually.

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 (“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 a release of “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

27

Table of Contents

by hazardous substances or other wastes released into the environment. Although “petroleum,” as well as natural gas and NGLs, have been for the most part excluded from CERCLA’s definition of a “hazardous substance,” 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, natural gas or NGLs. 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 have received notification that we are one of four companies that may be potentially responsible for any cleanup costs required under the State of Washington’s CERCLA equivalent statute with respect to a site in Spokane, Washington as result of the our having leased the site after the contamination occurred. No clean-up has yet been ordered. Our position is that, as a result of our emergence from the Bankruptcy, any potential claims against us for regulatory agency oversight costs were converted to administrative priority claims and any potential claims against us for investigation and clean-up costs were converted to unsecured claims (as they relate to other potentially responsible persons) and to administrative priority claims (as they relate to any regulatory agency).

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 (“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.

National, provincial and local laws of Canada, Mexico, the U.K. and the European Union that are applicable to our operations also regulate the release of hazardous substances or solid wastes into soils, groundwater and surface water, and include measures to prevent and control pollution as well as the handling of hazardous waste. Some of the requirements are similar to those found under CERCLA and RCRA and some are not yet as stringent, but are becoming more so as the focus on these issues increases.

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 wastes disposed 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. In some instances, any such requirements may have been dealt with in the Bankruptcy proceeding.

28

Table of Contents

Employee Safety

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”), as well as to comparable national, state, provincial and local, Canadian, Mexican, U.K. and European Union laws that are applicable to our Canadian, Mexican and U.K. operations, the purposes of which are to protect the health and safety of workers. In addition, the OSHA hazard communication standard and comparable state, Canadian federal and provincial 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.

SemCAMS facilities are also subject to regulation by ABSA. SemCAMS maintains its own compliance program, audited by ABSA, which addresses integrity, inspection and process safety management elements as required by legislation.

Hazardous Materials Transportation Requirements

The 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, the DOT regulations contain detailed specifications for pipeline operation and maintenance.

Similar requirements are in effect in Canada.

Anti-Terrorism Measures

The federal Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security (“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 processing plants and terminals are on real property owned or leased 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.

29

Table of Contents

Office Facilities

In addition to our gathering, storage, terminalling and processing facilities discussed above, we maintain corporate office headquarters located in Tulsa, Oklahoma. All of the U.S. business segments utilize Tulsa as their center of operations, except for SemCrude, whose primary operations are located in Oklahoma City. Foreign business segments utilize their centers of operations, which are Calgary, Alberta for SemCanada Crude and SemCAMS; Puebla, Mexico for SemMexico; and Milford Haven, Wales for SemLogistics. Many of our business segments also have satellite offices located throughout North America. The current lease for our Tulsa headquarters expires in May 2019, and the other office leases have varying expiration dates. 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

As of December 31, 2009, we had approximately 890 employees, including approximately 600 employees outside the U.S. in Canada, Mexico and the U.K. Approximately 540 of our employees in Canada and Mexico are represented by labor unions and subject to collective bargaining agreements governing their employment with us. We have never had a labor related work stoppage and believe our employee relations are good.

Our business faces many risks. We believe the risks described below are the material risks we face. However, the risks described below may not be the only risks we face. Additional unknown risks or risks that we currently consider immaterial may also impair our business operations. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer, and the trading price of our shares of Class A Common Stock and warrants could decline significantly. Investors should consider the specific risk factors discussed below, together with the “Cautionary Note Regarding Forward-Looking Information” and the other information contained in this registration statement and the other documents that we will file from time to time with the SEC.

Risks Related to Our Business

We have substantial indebtedness.

As of December 31, 2009, on a consolidated basis we had approximately $519.9 million in long-term debt outstanding and $117.3 million in outstanding letters of credit. In addition, we had the ability to borrow up to an additional $101.5 million in cash loans under our revolving credit facility. Significant amounts of cash flows will be necessary to make payments of interest and repay the principal amount of such indebtedness.

The degree to which we are leveraged could have important consequences because:

30

Table of Contents

There can be no assurance that we will be able to generate sufficient cash flows from operations, or that future borrowings will be available under credit facilities in an amount sufficient, to enable us to pay our debt obligations or to fund our other liquidity needs. We may need to refinance all or a portion of our debt on or before maturity. We may not be able to refinance any of our debt on commercially reasonable terms or at all.

Our credit facilities contain covenants which require us to satisfy and maintain certain financial ratios and place certain other restrictions on us.

Our credit facilities contain covenants which require us to satisfy and maintain certain financial ratios and place certain other restrictions on us. These covenants and restrictions limit our ability to respond to changing business and economic conditions and we may be prevented from engaging in transactions that might otherwise be considered beneficial to us. For example, our credit facilities limit our ability to:

Any failure to comply with the restrictions of our credit facilities, or any other such subsequent financing agreements, may result in an event of default. An event of default may allow the creditors to accelerate the related debt, as well as any other debt to which a cross-acceleration or cross-default provision applies. If we are unable to repay amounts outstanding under our credit facilities when due, the lenders thereunder could, subject to the terms of the relevant agreements, seek to sell or otherwise transfer our assets granted to them as collateral to secure the indebtedness outstanding under those facilities. Substantially all of our assets have been pledged as collateral to secure our credit facilities. In addition, the lenders under our revolving credit facility may choose to terminate any commitments they then have made to supply us with further funds.

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, and the cost of such capital, is dependent on numerous factors, including:

31

Table of Contents

In addition, volatility in the capital markets may adversely affect our ability to access any available borrowing capacity under our revolving credit facility. Our access to funds under our revolving credit facility is dependent on the ability of the lenders under the revolving credit facility to meet their funding obligations. Those lenders may not be able to meet their funding commitments if they experience shortages of capital and liquidity, resulting in a reduction in available borrowings.

Our risk management policy governing our internal trading and marketing activities cannot eliminate all risks associated with the trading and marketing of commodities, nor can we ensure compliance with the risk management policy by our employees, both of which could impact our financial and operational results.

We have in place a risk management policy that establishes authorized commodities and transaction types, delegations of authority, and limits for trading and marketing exposures and requires that we restrict net open positions (e.g., positions that are not fully hedged as to commodity price risk) to specified levels at each of the consolidated and, in certain cases, subsidiary level. Our risk management policy has restrictive terms with respect to acquiring and holding physical inventory, futures contracts or derivative products for the purpose of proprietary trading activity. These policies and practices, however, cannot eliminate all risks. If we enter into derivatives contracts or sale contracts for the delivery of products at a future date, we are subject to the risk of non-delivery under product purchase contracts or the failure of gathering and transportation systems. For example, any event that disrupts our anticipated physical supply of products 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 pipeline and gathering lines. 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 our purchase or sales contracts call for delivery of a petroleum product of a grade, at a location, or at a time that differs from the specific delivery terms of offsetting purchase and sales agreements or derivative instruments. If this occurs, we may not be able to use the physical or derivative commodity markets to fully hedge our price risk. Even though we expect to maintain only limited net open positions, as permitted under the risk management policy, we will be exposed to price risks within predefined limits and authorizations which could impact our operational and financial results.

We also have a risk that employees involved in our trading and marketing operations may not comply with the risk management policy. We cannot ensure with certainty 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.

32

Table of Contents

Our operating results and financial condition may be adversely affected by unfavorable general economic conditions.

Unfavorable economic conditions worldwide contribute to slowdowns in the oil and gas industry including the specific segments and markets in which we operate. If global economic conditions or economic conditions in the U.S. remain uncertain or persist, spread or deteriorate further, we may experience material adverse impacts on our results of operations, cash flows and financial condition.

Our profitability depends on the demand for the products we gather, transport, process and store in the markets we serve.

Any sustained reduction in demand for petroleum products in markets served by our midstream assets could result in a significant reduction in the volume of petroleum products that we gather, transport, process and store, thereby adversely affecting our results of operations, cash flows and financial condition. Factors that could lead to a reduction in demand include:

Because of the natural decline in production from existing wells in our areas of operation, our success depends on our ability to obtain new sources of supply of petroleum products, which is dependent on factors beyond our control. Any decrease in the volumes of these products that we gather could adversely affect our business and operating results.

The volumes that support our business are dependent on the level of production from wells connected to our gathering systems, the production from which may be less than we expect as a result of a natural decline of producing wells over time and the shut-in of wells for economic or other reasons. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of petroleum products. The primary factors affecting our ability to obtain sources of these products include the level of successful drilling activity near our systems and our ability to compete for volumes from successful new wells.

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering systems or the rate at which production from a well declines. 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 petroleum products, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other drilling, production and development costs.

33

Table of Contents

Fluctuations in energy prices can also greatly affect the development of new petroleum product reserves and, to a lesser extent, production from existing wells. In general terms, energy prices fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Declines in energy 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 gathering and treating assets. Because of these factors, even if new reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain levels of throughput on our systems, it could have a material adverse effect on our business, results of operations and financial condition.

Our construction of new assets may not result in the anticipated revenue increases and is subject to unanticipated regulatory, environmental, political, legal and economic risks which could adversely affect our business.

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 and may require the expenditure of significant amounts of capital. If we undertake such projects, they may not be completed on schedule or at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction may occur over an extended period of time and we will not receive any material increases in revenue until the project is completed. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for, and the development of, natural gas and crude oil reserves, we do not possess reserve expertise and we often do not have access to third party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct additions to our system, such estimates may prove to be inaccurate because of numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return which could adversely affect our results of operations, cash flows and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new petroleum product supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, or if we lose our existing rights-of-way through our inability to renew right-of-way contracts or otherwise, our results of operations, cash flows and financial condition could be adversely affected.

We may be unable to generate sufficient or positive cash flows from the purchase, transportation, storage, distribution and sale of petroleum products to adequately support our financial or operational results.

Our marketing results depend upon our ability to generate sufficient or positive cash flows from the purchase, sale and cost to carry of petroleum products. Our cash flows are affected by many factors beyond our control, including:

34

Table of Contents

Actual results may vary significantly from the projections filed with the U.S. Bankruptcy Court.

In connection with our plan of reorganization, we were required to prepare projected financial information to demonstrate to the U.S. Bankruptcy Court the feasibility of our plan of reorganization and our ability to continue operations upon our emergence from the Bankruptcy. Those projections are included in the Disclosure Statement filed with the U.S. Bankruptcy Court on September 25, 2009. Those projections are not included in this registration statement, are not incorporated by reference into this registration statement and they should not be relied upon. Those projections were based on numerous assumptions about our anticipated future performance and were based on anticipated market and economic conditions that were, and remain, beyond our control and may not materialize. Projections are inherently subject to many uncertainties and a wide variety of significant business, economic and competitive risks. Our actual results of operations and financial condition will vary from those contemplated by the projections and the variations may be material.

We cannot be certain that the Bankruptcy proceedings will not adversely affect our operations going forward.

Although we emerged from the Bankruptcy on November 30, 2009, we cannot assure you that the Bankruptcy proceedings will not adversely affect our operations going forward. Having filed for bankruptcy protection may adversely affect our ability to negotiate favorable terms from suppliers and lenders and to attract and retain customers. The failure to obtain such favorable terms and attract and retain customers would adversely affect our financial performance.

We operate in a highly competitive business environment, and competitive pressures could adversely affect our business.

We compete with similar enterprises in our areas of operation. Some of our competitors are large petroleum companies that have greater financial resources and access to supplies of petroleum products than we do. Our competitors may expand or construct gathering systems and associated infrastructure that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of petroleum products may develop their own gathering, processing and transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors and our customers. Uncertainty and possible adverse publicity resulting from our Bankruptcy reorganization may make us more susceptible to the loss of customers to our competitors. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.

35

Table of Contents

Because our consolidated financial statements reflect fresh-start reporting adjustments made upon emergence from our Bankruptcy reorganization, and because of the effects of the transactions that became effective pursuant to our plan of reorganization, financial information in our current and future financial statements will not be comparable to our financial information from prior periods.

In connection with our Bankruptcy reorganization, we adopted fresh-start reporting effective as of the close of business on November 30, 2009, in accordance with ASC 852, “ Reorganizations .” Our adoption of fresh-start reporting resulted in our becoming a new entity for financial reporting purposes. As required by fresh-start reporting, our assets and liabilities have been adjusted to reflect fair value. In addition to fresh-start reporting, our financial statements reflect the effects of all of the transactions implemented by our 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.

An impairment of goodwill could reduce our earnings.

At December 31, 2009, we had $186.8 million of goodwill which was recorded on November 30, 2009, in connection with fresh-start reporting. Goodwill was recorded to the extent that the Company’s reorganization value exceeded amounts attributed to specific tangible or identified intangible assets. Accounting principles generally accepted in the U.S. (“GAAP”) require us to test goodwill for impairment on an annual basis, or when events or circumstances occur indicating that goodwill might be impaired. If we were to determine that any of our goodwill was impaired, we would be required to take an immediate charge to earnings.

Changes in currency exchange rates could adversely affect our operating results.

A portion of our revenue is generated from our operations in Canada, the U.K. and Mexico, which use the Canadian dollar, British pound and Mexican peso, respectively, as the functional currency. Therefore, changes in the exchange rate between the U.S. dollar, on the one hand, and any of such foreign currencies, on the other hand, could adversely affect our financial and operational results.

We are subject to the risks of doing business outside of the U.S.

The success of our business depends, in part, on continued performance in our non-U.S. operations. We currently have operations in Canada, Mexico and the U.K. In addition to the other risks described in this registration statement, there are numerous risks and uncertainties that specifically affect our non-U.S. operations. These risks and uncertainties include political and economic instability, changes in local governmental laws, regulations and policies, including those related to tariffs, investments, taxation, exchange controls, employment regulations and repatriation of earnings, and enforcement of contract and intellectual property rights. International transactions may also involve increased financial and legal risks due to differing legal systems and customs, including risks of non-compliance with U.S. and local laws affecting our activities abroad, including compliance with the U.S. Foreign Corrupt Practices Act. While these factors and the impact of these factors are difficult to predict, any one or more of them could adversely affect our financial and operational results.

36

Table of Contents

Some of our operations cross the U.S./Canada border and are subject to cross border regulation.

Our cross border activities with our Canadian subsidiaries subject us to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Such regulations include the Short Supply Controls of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties.

Adverse developments in our existing areas of operation could adversely impact our results of operations, cash flows and financial condition.

Our operations are focused on gathering, transporting, storing, processing and treating petroleum products utilizing our assets which are principally located in the Midwest and Rocky Mountain supply region of the U.S. and in Alberta, Canada. As a result, our results of operations, cash flows and financial condition depend upon the demand for our services in these regions. Due to our current lack of broad 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 results of operations, cash flows and financial condition than 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, or if the volumes we gather do not meet the quality requirements of such pipelines or facilities.

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 because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, curtailments of receipt or deliveries due to insufficient capacity or for any other reason. If any of these pipelines or facilities becomes unable to transport the products we gather, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our results of operations and cash flows could be adversely affected.

As a public company, we will be subject to additional financial and other reporting and corporate governance requirements that may be difficult for us to satisfy, will raise our costs and may divert resources and management attention from operating our business.

We have historically operated as a private company. Following the effectiveness of this registration statement, we will need to file with the SEC annual and quarterly information and other reports that are specified in the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and SEC regulations. Thus, we will need to ensure that we have the ability to prepare, on a timely basis, financial statements that comply with SEC reporting requirements. We will also become subject to other reporting and corporate governance requirements, including the listing standards of the national securities exchange upon which we list our Class A Common Stock and warrants, and the provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), and the regulations promulgated thereunder, which will impose significant new compliance obligations upon us. As a public company, we will be required, among other things, to:

37

Table of Contents

The adequacy of our internal control over financial reporting must be assessed by management for each year commencing with the year ending December 31, 2011. Our internal control over financial reporting may not currently meet the standards required by Section 404 of the Sarbanes-Oxley Act. We have hired an independent consulting firm to assist us in implementing effective internal control over financial reporting. We will incur additional costs in order to improve our internal control over financial reporting and comply with Section 404, including increased auditing and legal fees and costs associated with hiring additional accounting and administrative staff. Ultimately, our efforts may not be adequate to comply with the requirements of Section 404. If we are unable to implement and maintain adequate internal control over financial reporting or otherwise to comply with Section 404, we may be unable to report financial information on a timely basis, may suffer adverse regulatory consequences, may have violations of the applicable national securities exchange listing rules and may breach covenants under our credit facilities. There could also be a negative reaction in the financial markets due to a loss of investor confidence in us and the reliability of our financial statements.

The changes necessitated by becoming a public company will require a significant commitment of additional resources and management oversight that will increase our costs and might place a strain on our systems and resources. As a result, our management’s attention might be diverted from other business concerns. In addition, we might not be successful in implementing and maintaining controls and procedures that comply with these requirements. If we fail to maintain an effective internal control environment or to comply with the numerous legal and regulatory requirements imposed on public companies, we could make material errors in, and be required to restate, our financial statements. Any such restatement could result in a loss of public confidence in the reliability of our financial statements and sanctions imposed on us by the SEC.

We are exposed to the creditworthiness and performance of our customers, suppliers and transactional counterparties, and any material nonpayment or nonperformance by one or more of these parties could adversely affect our financial and operational results.

There can be no assurance we have adequately assessed the creditworthiness of each of our existing or future customers, suppliers or transactional counterparties or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our financial condition and results of operations. Nor is there certainty that our counterparties will perform or adhere to existing or future contractual arrangements.

We manage our exposure to credit risk through credit analysis and credit monitoring procedures and policies, including credit support requirements for customers and counterparties to which we extend no or limited unsecured credit, such as letters of credit, prepayments, and guarantees. However, these procedures and policies cannot fully eliminate counterparty credit risks, and to the extent our procedures and policies prove to be inadequate, our financial and operational results may be negatively impacted.

38

Table of Contents

Some of our counterparties may be highly leveraged or have limited financial resources and will be subject to their own operating and regulatory risks and, even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. 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 business involves many hazards and operational risks, some of which may not be covered by insurance.

Sudden leaks are possible in operations involving pipelines and tanks. 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, construction or manufacturing defects); failure to maintain adequate supplies of spare parts; operator error; labor disputes; disputes with interconnected facilities and carriers; and catastrophic events such as natural disasters, fires, explosions, fractures, 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 results of operations, cash flows and financial condition. 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.

Any acquisition involves risks that may adversely affect our business.

Any acquisition involves potential risks, including:

39

Table of Contents

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from our acquisitions, realize other anticipated benefits and our ability to meet our debt service requirements.

We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the DOT, through the DOT’s Pipeline and Hazardous Materials Safety Administration, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could do the most harm in “high consequence areas,” including 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 regulations require operators of covered pipelines to:

In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. We currently estimate that we will incur an aggregate cost of approximately $1.0 million for years 2010 through 2012 to implement necessary pipeline integrity management program testing along certain segments of our pipelines required by existing DOT and state regulations. This estimate does not include the costs, if any, 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.

In order to comply with recently enacted legislation relating to the transportation of hazardous liquids by pipeline, we are required to implement procedures no later than February 1, 2012, to address control room management for pipelines where controllers utilize a supervisory control and data acquisition system. Implementing these procedures could cause us to incur unanticipated operating expenditures.

The nature and degree of regulation may adversely affect fee structures or operations.

Our operations are subject to substantial regulation from foreign and domestic federal, state, provincial and local authorities. These authorities regulate numerous aspects of our operations, including our interstate natural gas storage operations, certain crude oil gathering systems, construction and maintenance of facilities, and rate structures among other things. We cannot predict the impact of any future revisions or interpretation changes of existing laws or regulations or the adoption of new laws and regulations applicable to our businesses. Revisions, interpretation changes or additional regulations could influence our operating environment and may result in increased costs.

40

Table of Contents

Our White Cliffs Pipeline is subject to FERC rules and regulations. The FERC’s regulatory authority extends to:

Regulatory actions in these areas can similarly affect new or expanded pipeline operations.

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, petroleum products or wastes into the environment.

Our operations are subject to federal and foreign, state, province 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:

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. Certain environmental laws, including CERCLA and RCRA and analogous state 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. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, petroleum products 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 and natural gas, 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 arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties 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. In particular, we may incur expenditures in order to attain or maintain compliance with legal requirements governing emissions of air pollutants from our facilities. We may not be able to recover all or any of these costs from insurance.

41

Table of Contents

Climate change legislation and related regulatory initiatives could result in increased operating costs and reduced demand for our services.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” (collectively, “GHGs”) present an endangerment to public health and the environment because emissions of such gases are contributing to 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. In anticipation of those findings, the EPA had previously proposed regulations that would require a reduction in emissions of GHGs from motor vehicles and that could lead to the imposition of GHG emission limitations in Clean Air Act permits for certain 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. In March 2010, the EPA proposed revisions to these reporting requirements to apply to all oil and gas production, transmission, processing and other facilities exceeding certain emission thresholds. 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 petroleum products we gather, treat or otherwise handle in connection with our services.

Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (“ACESA”), which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of GHGs, including carbon dioxide and methane. ACESA would require a 17 percent reduction in GHG emissions from 2005 levels by 2020, and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emission allowances to certain major sources of GHG emissions so that such sources could continue to emit GHGs into the atmosphere. These allowances would be expected to significantly escalate in cost over time. The net effect of ACESA, if enacted, would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and the Obama Administration has indicated its support of legislation to reduce GHG emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the petroleum products we gather, treat or otherwise handle in connection with our services.

Canada does not currently have any federal legislation pending relating to the regulation of GHG emissions. It is widely expected that Canadian federal legislation will be proposed and voted on in the next couple of years once the United States GHG mechanisms are decided. 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 petroleum products we gather, treat or otherwise handle in connection with our services.

42

Table of Contents

Although Canada has not yet enacted federal GHG legislation, the province of Alberta has set GHG baselines based on 2003-2005 data which requires a reduction of 12% in GHG emissions from certain facilities, including several of SemCams’ facilities. Beginning with the second half of 2007, penalties are assessed for failure to comply with required reductions. Further limitations may be imposed in the future which could require additional SemCams’ facilities to have to file annual GHG emissions reports.

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 petroleum products, resulting in a decrease in the demand for our services.

Loss of key employees can significantly reduce capability 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. 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.

If any of our subsidiaries were subject to a material amount of additional entity-level taxation by individual states or foreign jurisdictions, or U.S. tax legislation regarding foreign subsidiaries is changed, it could materially impact our financial and operational results.

If any of our subsidiary entities are subjected to a material amount of entity-level taxation by individual states or foreign jurisdictions in which they operate, our financial and operational results could be negatively impacted.

We hold interests in foreign entities that are currently treated as disregarded entities for U.S. federal income tax purposes. The present administration has recently proposed legislation that, if enacted, would (i) require U.S. corporations to treat certain wholly-owned foreign subsidiaries as corporations, rather than disregarded entities, for U.S. federal income tax purposes, (ii) defer certain deductions associated with foreign subsidiaries, and (iii) reform the foreign tax credit regime which may prevent the use of foreign tax credits in certain situations. There can be no assurance as to whether, or in what form, these proposals will be enacted. If these proposals are enacted into legislation, it could have adverse tax consequences to us and negatively impact our financial and operational results.

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.

43

Table of Contents

Risks Related to Our Class A Common Stock and Warrants

No established public market currently exists for our Class A Common Stock or warrants, and an active trading market may not develop or be sustained following the effectiveness of this registration statement.

Prior to the filing of this registration statement, there has been no established public market for our Class A Common Stock or warrants. Although we intend to apply to have our Class A Common Stock and warrants listed on a national securities exchange, an active public trading market for our Class A Common Stock or warrants may not develop or be sustained. The lack of an active market may impede the ability to sell shares of the Class A Common Stock or warrants at the time a holder wishes to sell them or at a price that a holder considers reasonable.

Our Class A Common Stock and warrants may experience significant price and volume fluctuations.

The market price of our Class A Common Stock may fluctuate significantly in response to various factors and events beyond our control, including the following:

To the extent that a market for the warrants develops, we believe that the market price of the warrants will be primarily affected by the market price of our Class A Common Stock and, consequently, may fluctuate significantly in response to the various factors and events affecting the market price of our Class A Common Stock.

We currently do not intend to pay cash dividends on our Class A Common Stock and, consequently, your only opportunity to achieve a return on our Class A Common Stock is if the price of our common stock appreciates.

We have never declared or paid any cash dividends on our Class A Common Stock and do not currently plan to pay any cash dividends on our Class A Common Stock in the foreseeable future. The terms of our credit agreements restrict our ability to pay dividends. Any future payments of cash dividends on our Class A Common Stock will depend upon contractual restrictions limiting our ability to pay dividends, our earnings and cash flows, our capital requirements, our financial condition and other factors deemed relevant by our Board of Directors. Consequently, your only opportunity to achieve a return on our Class A Common Stock will be if the market price of such stock appreciates and you sell your shares at a profit.

44

Table of Contents

Future sales or the potential for sale of a substantial number of shares of our Class A Common Stock may depress the market price of our Class A Common Stock and warrants.

Sales of a substantial number of shares of our Class A Common Stock in the public market, or the perception that these sales could occur, may depress the market price of our Class A Common Stock and warrants and impair our ability to raise capital through the sale of additional equity securities. As of March 31, 2010, we had 40,503,866 shares of our Class A Common Stock issued and outstanding. In addition, as of such date we had reserved additional shares of our Class A Common Stock for issuance as follows:

Stockholders may experience dilution of their ownership interests because of the future issuance of additional shares of our common stock.

We may finance our future operations or future acquisitions in whole or in part through the issuance of common stock or securities convertible into or exercisable for common stock. In addition, we may use our common stock or securities exercisable for common stock as a means of attracting or retaining management and employees for our business. If we do issue additional equity securities, such issuances may create downward pressure on the market price of our Class A Common Stock and warrants and have the effect of diluting our earnings per share as well as our existing stockholders’ individual ownership percentages in our company.

Selected Historical Consolidated Financial 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, 2009 and 2008 and the statement of operations data for the years ended December 31, 2009, 2008, and 2007 have been derived from our audited financial statements for those dates and periods. The balance sheet data as of December 31, 2007, 2006, and 2005 and the statement of operations data for the years ended December 31, 2006 and 2005 have been derived from our unaudited financial statements for those dates and periods. The selected financial data provided below should be read in conjunction with “Item 2. Financial Information—Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes beginning on page F-1 of this registration statement.

45

Table of Contents

Balance sheet data in the following table as of December 31, 2009 and November 30, 2009, and statement of operations data for the month ended December 31, 2009, are that of SemGroup Corporation. Balance sheet and statement of operations data as of all other dates and for all other periods are that of our predecessor, SemGroup, L.P. As described in Note 8 of our consolidated financial statements beginning on page F-1 of this registration statement, we applied fresh-start reporting as of November 30, 2009. As a result, our financial data is not comparable to that of our predecessor. Earnings per share in the table below is only presented for the period subsequent to our emergence from the Bankruptcy, since the limited partner units of SemGroup, L.P. were cancelled upon emergence from the Bankruptcy.

We experienced many changes in our business during the periods shown in the table above, which significantly limits the comparability of the financial data. Such changes include, but are not limited to:

46

Table of Contents

Management’s Discussion and Analysis of

Financial Condition and Results of Operation

This registration statement contains forward-looking statements that are based on current expectations, estimates, forecasts and projections about us, our future performance, our liquidity, our industries, our beliefs and management’s assumptions. Statements included in this registration statement that are not historical facts are forward-looking statements. For additional information, see “Cautionary Note Regarding Forward-Looking Statements.”

Overview of Business

We provide gathering, transportation, storage, distribution, blending, marketing and other midstream services primarily to independent producers, refiners of petroleum products and other market participants located in the Midwest and Rocky Mountain regions of the U.S., Canada and the West Coast of the U.K. We have an owned, contracted and leased asset base consisting of pipelines, gathering systems, storage facilities, terminals, processing plants, blending facilities and other distribution assets located between North American production and supply areas, including the Gulf Coast, Rocky Mountain and Western Canadian regions and areas of high demand such as the Midwest region of the U.S. We maintain and operate storage, terminal and marine facilities at Milford Haven in the U.K. that enable customers to supply product to markets in the Atlantic Basin. We also operate a network of liquid asphalt cement terminals throughout Mexico.

We gather, purchase, transport, store, distribute, blend and market crude oil to supply-constrained refiners primarily in the Midwest, ensuring that these refiners have consistent access to crude oil supply. In addition, we purchase, transport, distribute, store, terminal and market NGLs and natural gas produced by Midwest independent refiners and natural gas producers, which provides them market access. 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.

Company Reorganization

In July 2008, we faced a liquidity crisis and on July 22, 2008, we filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code as well as applications for creditor protection under the Companies’ Creditors Arrangement Act in Canada (collectively, the “Bankruptcy”). From July 2008 through November 2009, in order to minimize disruptions to our operations and preserve the value of our asset base, we:

47

Table of Contents

Business and Performance Drivers

We operate our business through seven primary business segments: SemCrude, SemStream, SemCAMS, SemLogistics, SemMexico, SemCanada Crude and SemGas. We generate revenue in these segments by utilizing our assets to provide products and services to third parties and by selectively using our assets to support our marketing activities. For certain products, the relationship between current and future price is generally seasonal. Propane prices, for example, are generally higher in the winter months than in the summer months. We believe that the variety of our petroleum product assets creates opportunities for us and our customers year round.

Certain factors are key to our operations. These include the safe, reliable and efficient operation of the pipelines and facilities that we own and operate while meeting the regulations that govern the operation of our assets and the costs associated with such regulations. Our revenue is impacted by several factors, including:

Throughput and processing fees

Throughput and processing fees are fees charged to third parties based on volumes of product run through our processing facilities or pipeline gathering systems.

Service, Storage and Terminalling Fees

Storage and terminalling fees are fees for petroleum product storage or terminalling services provided based on leased shell capacity or volumes moved through our terminal facilities by third parties or by us for our own account. Included in these fees are actual fees billed to third parties as well as implied fees, which are calculated to determine the margin that could have been generated from third parties had we not used the capacity for our own account.

Tariffs

Tariffs are fees received for the transportation of petroleum products via pipeline by third parties or by us for our own account. Included in these fees are actual fees received from third parties related to the transportation of their owned product on our owned pipelines and implied tariffs, which are those fees calculated on product we own and transport on either our owned pipelines or on third party pipelines via pipeline space allocated to us.

48

Table of Contents

Petroleum Product Marketing

We intend to capture the normalized gross margin associated with the purchase and sale of petroleum products. Purchases, sales and derivative transactions related to this activity are tracked in our systems to the ultimate realization of profit. We seek to maintain limited net open positions to manage our exposure to commodity prices. Marketing transactions may only be entered into by persons delegated such authority by senior management, as provided in our Comprehensive Risk Management Policy. Each person authorized to make transactions is subject to internal volume and dollar limits, portfolios are subject to net open position and stop loss limits, and counterparties are subject to credit limits and provisions as approved by our credit department. See “Business— Risk Governance and Comprehensive Risk Management Policy” for more information on our Comprehensive Risk Management Policy.

Revenue

Our revenue is generated from third-party fees earned through the gathering, pipeline transporting and storing of petroleum products principally in the Midwest region. Our customers pay us fees based on volumes gathered, transported and stored; through the sale of petroleum products based upon contract or index rates per barrel, million Btu or gallon; and/or through the distribution of petroleum products based upon a mark-up per gallon (principally NGLs). We generate additional revenue through selected marketing of petroleum products, primarily crude oil and NGLs. Marketing operations consist primarily of aggregating petroleum products purchased at the lease along pipeline systems or trucked, and arranging the necessary transportation logistics for the ultimate sale or delivery of the petroleum products to customers or other end-users. Gathering and transportation revenue is recognized as petroleum products are delivered to customers. Storage revenue is recognized upon leasing of shell capacity on a take or pay basis. Marketing revenue is accrued at the time title to the petroleum product sold transfers to the purchaser, which typically occurs upon receipt of the petroleum product by the purchaser.

We utilize futures, swaps and options contracts to manage our exposure to market changes in commodity prices, to protect our gross margins on our purchased petroleum products and to manage our liquidity risk associated with margin deposit requirements on our overall derivative positions. When purchasing petroleum products, we seek to manage our exposure to commodity price risk. As we purchase inventory from suppliers, we may establish a fixed or variable margin with future sales utilizing one of the following methods:

In addition, we may purchase put options or derivatives other than futures or swaps to hedge our inventory of petroleum products prior to our sale of such inventory.

Volumes

Generally, we expect revenue to increase or decrease in conjunction with increases or decreases in total volumes. Our total volumes are affected by different factors including our physical storage or transportation capacity, our working capital and credit availability under our credit facilities to support petroleum product purchases and the availability of the supply of petroleum product available for purchase, which is determined based primarily upon producer activity in market areas contiguous with our asset base.

49

Table of Contents

Commodity Prices

Our business is primarily fee based. As a result, our financial results are typically not correlated with increases and decreases in commodity prices. Our financial results, however, are positively correlated with the absolute difference between current (prompt) and future month petroleum product prices. That is, wide contango (when the prices for future deliveries are higher than current prices) spreads generally have a favorable impact on our results relative to a slightly contango or flat market.

Seasonal Businesses

Some of our assets allow for the purchase and sale of petroleum products and the realization of margins during seasonal periods. Through SemStream, we purchase NGLs during the summer when demand is seasonally low, enter into contracts to deliver the product at higher prices during the winter seasonal peak, store the NGLs and settle delivery at the specified date. While we believe that the combination of our asset-based and marketing activities provides a balance to both petroleum product seasons and commodity price fluctuations, our margins are not fixed and may vary from period to period.

Timing of Purchase and Sales

Our financial results are affected by the timing of the purchase and sale of petroleum products, such that financial results may not be comparable between periods. When we enter into an arrangement to purchase product, place the product in storage and resell the product in the future, our financial results do not reflect any related margin until the settlement of the product sale. Prior to the settlement of the product sale, our results reflect the cost of the product in our inventory. Differences in the timing of our product purchases and sales, especially if they extend over fiscal years or quarters, may result in sizeable differences between our results over the comparable period.

Analysis of Business Segments

The following provides an overview of the makeup of revenue at each of our respective business segments.

SemCrude

SemCrude conducts crude oil transportation, storage, terminalling, gathering, blending and marketing in Colorado, Kansas, Oklahoma, Texas, North Dakota, Montana and Western Canada for third party customers as well as for itself. The SemCrude business segment consists of three primary operations: (i) the White Cliffs Pipeline; (ii) Kansas and Oklahoma pipelines; and (iii) Cushing storage. A majority of SemCrude’s revenue is generated from fee-based contractual arrangements that, in some instances, are fixed and not dependent on usage.

SemStream

SemStream’s operations generate revenue from the purchase, transportation, storage, distribution and resale of NGL products, primarily propane, and to a lesser extent, butane and natural gasoline. SemStream is one of the largest private propane terminal operators in the industry with eleven owned NGL terminals and one leased NGL terminal, each operating 24 hours a day, seven days a week. SemStream also has one additional NGL terminal under construction and scheduled for completion in the third quarter of 2010. SemStream generates revenue at its terminals from marketing and throughput fees. Additionally, SemStream manages a number of exclusive supply and marketing agreements which enable SemStream to execute a seasonal inventory strategy of purchasing inventory in the summer off-season months, storing that product and forward selling the inventory for delivery during the winter months of peak demand.

50

Table of Contents

SemCAMS

SemCAMS operates majority-owned gathering assets and natural gas processing plants. We acquired the Canadian natural gas processing and gathering operations of Central Alberta Midstream, or CAMS, in March 2005. All of SemCAMS’ assets are located in West-Central Alberta, in the heart of the Western Canadian Sedimentary Basin, which accounts for approximately 80% of Canada’s sour natural gas production. SemCAMS’ revenue is based on fee-based throughput arrangements and profit sharing from plant operations.

SemLogistics

SemLogistics owns the largest independent petroleum products storage facility in the U.K. The facility is located on the north bank of the Milford Haven Waterway on the west coast of Wales. The main activities of SemLogistics are the receipt, storage and redelivery of clean petroleum and crude oil products via sea-going vessels at the Milford Haven site. SemLogistic’s revenue is based on fixed-fee storage tank leases and related services.

SemMexico

SemMexico operates a network of liquid asphalt terminals in Mexico. Operations include purchasing, producing, storing and distributing liquid asphalt cement products. SemMexico purchases asphalt from local refineries in Mexico. SemMexico’s revenue is based on margin from contractual arrangements with customers and suppliers for liquid asphalt cement. In general, SemMexico’s sales and purchases of liquid asphalt cement are matched and SemMexico carries limited exposure to price movements.

SemCanada Crude

Crude oil marketing revenue is generated through the purchase and storage of crude oil from producers and aggregators for transportation and resale at market hubs. SemCanada Crude’s business model is to capitalize on market arbitrage opportunities as a result of stream differential pricing by judiciously blending a variety of products at its seven blending facilities. SemCanada Crude earns blending margins based on differentials amongst sweet, sour, condensate and heavy products which expose them to price fluctuations in the relationships between the differentials. The aggregation business supports these opportunities while providing competitive pricing to suppliers and customers. SemCanada Crude also has a long-term lease at a storage facility in Edmonton, which is currently on sub-lease to a third party.

SemGas

SemGas provides gathering, processing and storage services to the natural gas markets in the U.S. SemGas owns and operates gathering and processing plants and assets in Kansas, Oklahoma and Texas. SemGas aggregates gas supplies from the wellhead and provides various services to producers that condition the wellhead gas production for downstream markets. SemGas’ projected financial performance is largely based on percent-of-proceeds and percent-of-index contractual arrangements where SemGas receives a portion of product sales as well as fee-based gathering service payments.

51

Table of Contents

Results of Operations

Overview

On July 22, 2008, SemGroup, L.P. and certain of its U.S. subsidiaries filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code (the “Petition Date”). Also on July 22, 2008, SemGroup, L.P.’s Canadian subsidiaries filed applications for creditor protection under the Companies’ Creditors Arrangement Act. Later during 2008, certain other U.S. subsidiaries filed petitions for reorganization. While under bankruptcy protection, SemGroup, L.P. sold or liquidated certain of its subsidiaries. All remaining subsidiaries emerged from the Bankruptcy on November 30, 2009 (the “Emergence Date”). We emerged as a newly reorganized company named SemGroup Corporation.

The Company lost control of several of its subsidiaries as a direct, or indirect, result of the Bankruptcy petitions, including all Canadian subsidiaries, SemGroup Holdings, L.P. (which directly held the Company’s limited partnership interests in Blueknight and indirectly held the Company’s general partnership interests in Blueknight), and Wyckoff. These subsidiaries were de-consolidated on the Petition Date and accounted for as cost method investments after that date, reported within investments in unconsolidated subsidiaries on the December 31, 2008 consolidated balance sheet and not included in results of operations from July 22, 2008, to November 30, 2009. The Company regained control of SemCams and SemCanada Crude on the Emergence Date, and consolidated these subsidiaries again beginning on that date.

As part of the process of reorganizing to emerge from bankruptcy protection, the Company determined the need to dispose of certain operations. SemFuel, SemMaterials, SemCanada Energy and SemEuro Supply met the criteria to be classified as discontinued operations. During 2008, the Company decided to sell the assets of SemMaterials and to cease the operations of SemEuro Supply, due to their losses from operations and/or working capital requirements. During 2009, the Company decided to sell the assets of SemFuel, due to its working capital requirements. By December 31, 2009, the majority of the assets of SemMaterials and SemFuel had been sold. The Company also ceased operations of SemCanada Energy.

The Company applied fresh-start reporting on November 30, 2009. As such, a reorganization value was determined, which represents the value attributed to the reorganized Company, and this reorganization value was allocated to the Company’s assets.

The reorganization value was determined with the assistance of a financial advisor, applying the following valuation methods:

After completing this analysis, the reorganization value was determined to be approximately $1.5 billion. This reorganization value was determined using numerous projections and assumptions. For additional information relating to the projections and assumptions used in determining the reorganization value, refer to Note 8 of our consolidated financial statements beginning on page F-1 of this registration statement. These projections and assumptions are subject to significant uncertainties, many of which are

52

Table of Contents

beyond the control of the Company. The use of different projections and/or assumptions could have resulted in a materially different reorganization value, and there can be no assurance that actual results will be consistent with the projections and assumptions used to determine the reorganization value.

The Company 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. The Company adjusted deferred tax liabilities, where appropriate, to reflect the change in the financial reporting basis of assets. The Company recorded approximately $188.8 million of goodwill, which represents the excess of the reorganization value over the fair value of the identifiable assets.

As a result of these factors (the Bankruptcy, deconsolidation and reconsolidation of certain subsidiaries, sale of subsidiary assets and fresh-start reporting) and other factors, comparison of the results of operations between periods shown below is not useful as a guide to future results of operations. The financial performance for years 2007, 2008, and the first 11 months of 2009 are presented for historical perspective and does not give pro forma results as if the consummation of the plan of reorganization and the related fresh-start reporting and other adjustments had occurred at the beginning of the period presented.

Additionally, our post-emergence financial statements are not comparable with our pre-emergence financial statements. Despite the lack of comparability, we have combined our results from the first 11 calendar months of 2009 with our results from December of 2009 (which includes the impact of fresh-start reporting) in order to facilitate the year-to-year discussion of our operating results. The combined financial information for 2009 is merely cumulative and does not give pro forma effect to our results as if the consummation of the plan of reorganization and the related fresh-start reporting and other adjustments had occurred at the beginning of the period presented. Combining pre-emergence bankruptcy results and post-emergence bankruptcy results is not in accordance with GAAP.

53

Table of Contents

54

Table of Contents

Revenue and Expenses

Revenue and expenses are analyzed by operating segment below.

Interest Expense

During the time the Company was in bankruptcy, it recorded interest expense only to the extent such interest was expected to be paid. Interest obligations that were expected to be compromised in the reorganization process were not recorded as expenses. The total amount of interest that the Company would have been contractually obligated to pay, but which was compromised in the reorganization process and not recorded as an expense, was $218 million and $105 million for the period January 1, 2009 through November 30, 2009 and the period July 23, 2008 through December 31, 2008, respectively.

In addition, interest expense was reduced $34 million and $84 million in 2008 and 2007, respectively. These reductions were a result of the reclassification from interest expense to Income (loss) from discontinued operations.

Reorganization gain (loss)

Reorganization gain (loss) includes revenue, expenses, realized gains and losses and provisions for losses resulting from the reorganization and restructuring of the business.

The reorganization gain of $3,532 million in the eleven months ended November 30, 2009 is primarily composed of $2,544 million gain on extinguishment of debt, $614 million gain on the disposal of Blueknight and $353 million gain on asset revaluation in fresh-start reporting.

The reorganization loss of $412 million in 2008 is primarily composed of $141 million loss on disposal or impairment of long-lived assets, $138 million expense related to uncollectable accounts and $59 million in professional fees.

We believe that we have captured all of the relevant revenue and expenses associated with the reorganization of the Company.

Discontinued Operations

SemMaterials, SemFuel and SemEuro Supply are presented as discontinued operations. During 2008, the Company decided to sell the assets of SemMaterials and to cease the operations of SemEuro Supply, due to their losses from operations and working capital requirements. During 2009, the Company decided to sell the assets of SemFuel due to its working capital requirements. By December 31, 2009, the majority of the assets of SemMaterials and SemFuel had been sold.

55

Table of Contents

2009 versus 2008

Our business model for SemCrude changed dramatically from 2008 to 2009. As described below, our business transitioned from crude oil marketing activities to a fee for services business model. Until July 2008, SemCrude operated the Kansas and Oklahoma pipelines as a proprietary pipeline system whereby we utilized all of the capacity for ourselves. We also had access to Blueknight’s crude oil storage and pipeline capacity pursuant to a throughput agreement. We were engaged in crude oil marketing activities through the utilization of these and other third party gathering, storage, transportation or terminal assets. In this activity, we captured margin, and recognized revenues and expenses, associated with the purchase and sale of crude oil. Imbedded in the margin recognized from the purchase and sale of crude oil was uplift from the gathering, transportation, storage and blending of crude oil. However, we did not account for margin according to each activity. That is, the total margin was captured through our marketing activities and the purchase and sale of crude oil. During the Bankruptcy in 2008, we no longer had the ability to fund working capital to continue this crude oil marketing strategy and we abandoned this business model on or about July 2008. At that time, we began a transformation towards a fee for service business model whereby we provided midstream services to third parties for a fee. As a result and throughout the Bankruptcy, we provided transportation services on our pipeline assets through fee-based transportation contracts. We also provided storage services at Cushing, when operational, through fee-based contracts with third-parties.

56

Table of Contents

Revenue

Revenue declined in 2009 to $271 million from $3,068 million in 2008. The decline reflects a change in our business model from one in 2008 which emphasized marketing and trading, to one in 2009 which was focused primarily on providing transportation and storage services for a fee. Marketing and trading activities tend to be high volume, low margin. In contrast, our transportation and storage activities tend to be relatively low volume, while generating higher margins.

The focus on transportation and storage was enhanced when the White Cliffs Pipeline began operation in June 2009 and as 4.2 million barrels of new Cushing storage capacity became available between February 2009 and January 2010.

Cost of Sales

Cost of sales declined in 2009 to $185 million from $3,674 million in 2008. This decline is due to the shift from the emphasis on marketing and trading in 2008, to the focus on transportation and storage in 2009.

Operating expense

Operating expense declined in 2009 to $19 million from $295 million in 2008. This decline was due primarily to a write off of an account receivable in 2008 valued at $285 million (Westback). For additional information relating to the write off of this account receivable, refer to Note 22 of our consolidated financial statements beginning on page F-1 of this registration statement.

General and administrative expense

General and administrative expense decreased in 2009 to $9 million from $32 million in 2008. This decline is due primarily to a decrease in the allocation of corporate overhead reflecting a sharp drop in corporate overhead following bankruptcy.

Depreciation and amortization

Depreciation and amortization increased in 2009 to $16 million from $3 million in 2008. The increase is primarily due to the White Cliffs Pipeline which began operation in June of 2009.

2008 versus 2007

Our business model for SemCrude changed dramatically from 2007 to 2008. As described below, our business transitioned from crude oil marketing activities to a fee for services business model. Until July 2008, SemCrude operated the Kansas and Oklahoma Pipelines as a proprietary pipeline system whereby we utilized all of the capacity for ourselves. We also had access to Blueknight’s crude oil storage and pipeline capacity pursuant to a throughput agreement. We were engaged in crude oil marketing activities through the utilization of these and other third party gathering, storage, transportation or terminal assets. In this activity, we captured margin, and recognized revenues and expenses, associated with the purchase and sale of crude oil. Imbedded in the margin recognized from the purchase and sale of crude oil was uplift from the gathering, transportation, storage, and blending of crude oil. However, we did not account for margin according to each activity. That is, the total margin was captured through our marketing activities and the purchase and sale of crude oil. During the Bankruptcy in 2008, we no longer had the ability to fund working capital to continue this

57

Table of Contents

crude oil marketing strategy and we abandoned this business model on or about July 2008. As a result, we determined to operate the Kansas and Oklahoma pipelines as a transportation services provider and pursue business opportunities through the transportation of third-party volumes for a transportation fee. Given we had no operating history for these assets as a transportation services provider, we had little historical data to establish the appropriate transportation fee. In addition, given the distressed financial and commodity markets as well as our distress resulting from the Bankruptcy, the market for leasing our capacity was challenging. As we progressed through 2008, we worked to increase the volumes and fees on our Kansas and Oklahoma pipelines and did not further pursue any marketing activities.

Revenue

Revenue decreased in 2008 to $3,068 million from $3,179 million in 2007. A decrease in marketing revenue of $962 million was largely offset by an increase in trading revenue of $872 million. In addition, transportation revenue and storage revenue each declined by $4 million, reflecting the transfer of transportation and storage assets from the Company to Blueknight.

Cost of Sales

Cost of sales increased in 2008 to $3,674 million from $3,430 million in 2007. The increase in cost of sales was related entirely to marketing activity.

Operating expense

Operating expense increased in 2008 to $295 million from $67 million in 2007. The increase is due primarily to a write off of an account receivable in 2008 valued at $285 million (Westback). For additional information relating to the write off of this account receivable, refer to Note 22 of our consolidated financial statements beginning on page F-1 of this registration statement. However, the increase was partially offset by a decrease in incentive compensation of $27 million and a decrease in other compensation and benefit items such as salaries, commissions, overtime and group insurance totaling an additional $10 million.

General and administrative expense

General and administrative expense decreased in 2008 to $32 million from $70 million in 2007. Of this decline, $28 million relates to a decrease in incentive compensation expense and $8 million relates to allocated corporate overhead.

Depreciation and amortization

Depreciation and amortization decreased in 2008 to $3 million from $7 million in 2007. The decrease is a result of the sale of pipeline assets and storage tanks to Blueknight in May of 2008.

Asset impairment

In 2008, the Company recorded an asset impairment charge of $3 million related to an ownership interest in a pipeline which was abandoned in 2008.

58

Table of Contents

2009 versus 2008

Revenue

Revenue declined in 2009 to $493 million from $1,522 million in 2008. The total volume sold declined in 2009 to 13,220 million barrels from 28,159 million barrels in 2008. The primary product sold is propane. Propane volume sold in 2009 declined to 11,102 million barrels from 19,958 million barrels in 2008. In addition to the decline in propane sales volume, the 2009 sales volume of butane and iso-butane was also down sharply compared to 2008. The effect of decline in sales volume on 2009 revenue was amplified by propane prices, which were sharply lower for most of 2009 compared to 2008.

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. This results in a reduction of sales revenue and cost of sales by the same amount, but has no effect on gross margin. However, changes in the level of such purchase and sale activity between periods can have a material effect on the comparison between those periods. Revenue was reduced by $14 million and $223 million in 2009 and 2008, respectively, in accordance with ASC 845-10-15.

Cost of Sales

Cost of sales declined in 2009 to $501 million from $1,683 million in 2008. The decline in cost of sales reflects the decline in the volume sold. The effect of the decline in sales volume was amplified by propane prices, which were sharply lower for most of 2009 compared to 2008. The combination of the decline in volume and the lower prices resulted in a decrease in cost of sales of $1,292 million. Also included in the cost of sales for 2009 is a lower of cost or market adjustment of $5 million, compared to a $95 million adjustment in 2008.

59

Table of Contents

As part of fresh-start reporting, inventory was revalued from historical weighted average cost to current market value as of November 30, 2009. As a result, cost of sales in 2009 was $9 million higher than it would have been except for the inventory revaluation.

Cost of sales was reduced by $14 million and $223 million in 2009 and 2008, respectively, in accordance with ASC 845-10-15.

General and administrative expense

General and administrative expense increased in 2009 to $7 million from $3 million in 2008. The primary reason for this change is an increase in allocated corporate overhead to $4 million in 2009 from $2 million in 2008.

2008 versus 2007

Revenue

Revenue declined in 2008 to $1,522 million from $1,550 million in 2007. The total volume sold declined in 2008 to 28,159 million barrels from 33,239 million barrels in 2007. The primary product sold is propane. Propane volume sold in 2008 declined to 19,958 million barrels from 24,150 million barrels in 2007. The effect of decline in volume was largely offset by propane prices which began the year at approximately $1.46 per gallon increasing to approximately $1.76 in July then falling sharply to approximately $0.70 per gallon by the end of 2008.

Revenue was reduced by $223 million and $248 million in 2008 and 2007 respectively, in accordance with ASC 845-10-15.

The decline in volume is attributed to the Company’s declaration of bankruptcy in July 2008.

Cost of Sales

Cost of sales increased in 2008 to $1,683 million from $1,520 million in 2007. Included in the cost of sales for 2008 is a lower of cost or market adjustment of $95 million compared to a nominal adjustment in 2007. Cost of sales was also affected by propane prices described above. 2008 prices were higher than 2007 in every month except October, November and December. The combination of these higher prices and lower volume resulted in an increase to cost of sales of $42 million.

Cost of sales was reduced by $223 million and $248 million in 2008 and 2007 respectively, in accordance with ASC 845-10-15.

General and administrative expense

General and administrative expense declined in 2008 to $3 million from $12 million in 2007. A reduction of $9 million in incentive compensation accounts for the decline.

60

Table of Contents

2009 versus 2008

Revenue

Revenue decreased in 2009 to $37 million from $41 million in 2008. This decrease is due to a decline in the exchange rate of British pounds to U.S. dollars, which more than offset the combination of an 18 percent increase in storage capacity used and a 5 percent increase in storage rates.

Expenses

Operating, general and administrative and depreciation and amortization expenses each declined slightly in 2009 compared to 2008. This decline is a result of a decline in the exchange rate of British pounds to U.S. dollars during the period.

2008 versus 2007

Revenue

Revenue increased in 2008 to $41 million from $38 million in 2007. The increase is a result of a 14 percent increase in storage rates offset, in part, by a three percent decline in storage capacity used. In addition, due to market conditions, there was additional throughput revenue; however, this was offset by a decline in product sales. Generally, SemLogistics does not sell product, but from time to time, tank bottoms and line fill become available for sale. In 2007, and to a lesser extent in 2008, such products became available for sale as a result of tank refurbishment.

61

Table of Contents

Expenses

General and administrative expenses decreased in 2008 to $12 million from $14 million in 2007. This decrease is due primarily to a $2 million refund related to property taxes.

SemCAMS