Semgroup (SEMG) 10-K 2018 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2018

or

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

For the transition period from             to             

Commission file number 1-34736

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SEMGROUP CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	20-3533152
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Two Warren Place

6120 S. Yale Avenue, Suite 1500

Tulsa, OK 74136-4231

(918) 524-8100

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

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

Title of Each Class	Name of Each Exchange on Which Registered
Class A Common Stock, par value $0.01 per share	New York Stock Exchange

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

None

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  o    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  x    No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  o

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

The aggregate market value of the registrant’s Class A and Class B Common Stock held by non-affiliates at June 30, 2018, was $1,990,614,027, based on the closing price of the Class A Common Stock on the New York Stock Exchange on June 30, 2018.

At January 31, 2019, there were 79,155,214 shares of Class A Common Stock and 0 shares of Class B Common Stock outstanding.

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DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement to be filed pursuant to Regulation 14A of the Securities Exchange Act of 1934, in connection with the registrant’s Annual Stockholders’ Meeting to be held on May 15, 2019, are incorporated by reference into Part III of this Form 10-K.

SEMGROUP CORPORATION AND SUBSIDIARIES

FORM 10-K—2018 ANNUAL REPORT

Table of Contents

		Page
	PART I
Items 1. and 2.	Business and Properties	1
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	25
Item 3.	Legal Proceedings	26
Item 4.	Mine Safety Disclosures	26
	Executive Officers of the Registrant	26
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of  Equity Securities	28
Item 6.	Selected Financial Data	29
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	55
Item 9A.	Controls and Procedures	55
Item 9B.	Other Information	56
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	57
Item 11.	Executive Compensation	57
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	57
Item 13.	Certain Relationships and Related Transactions, and Director Independence	57
Item 14.	Principal Accountant Fees and Services	57
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	58
Item 16.	Form 10-K Summary	62

Cautionary Note Regarding Forward-Looking Statements

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

All statements, other than statements of historical fact, included in this Form 10-K regarding the prospects of our industry, our anticipated financial performance, management’s plans and objectives for future operations, planned capital expenditures, business prospects, outcome of regulatory proceedings, market conditions, and other matters, may constitute forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking words such as “may,” “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. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that these expectations will prove to be correct. These forward-looking statements are subject to certain known and unknown risks and uncertainties, as well as assumptions that could cause actual results to differ materially from those reflected in these forward-looking statements. Factors that might cause actual results to differ include, but are not limited to, those discussed in Item 1A of this Form 10-K, entitled “Risk Factors,” risk factors discussed in other reports that we file with the Securities and Exchange Commission (“SEC”), and the following:

• Our ability to generate sufficient cash flow from operations to enable us to pay our debt obligations and our current and expected dividends or to fund our other liquidity needs;

• Any sustained reduction in demand for, or supply of, the petroleum products we gather, transport, process, market and store;

• The effect of our debt level on our future financial and operating flexibility, including our ability to obtain additional capital on terms that are favorable to us;

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

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

• The amount of cash distributions, capital requirements and performance of our investments and joint ventures;

• The consequences of any divestitures of non-strategic operating assets or divestitures of interests in some of our operating assets through partnerships and/or joint ventures;

• The failure to realize the anticipated benefits of our acquisition of Meritage Midstream ILC and its midstream infrastructure assets through our joint venture SemCAMS Midstream ULC;

• The amount of collateral required to be posted from time to time in our purchase, sale or derivative transactions;

• The impact of operational and developmental hazards and unforeseen interruptions;

• Our ability to obtain new sources of supply of petroleum products;

• Competition from other midstream energy companies;

• Our ability to comply with the covenants contained in our credit agreements, continuing covenant agreement and the indentures governing our notes, including requirements under our credit agreements and continuing covenant agreement to maintain certain financial ratios;

• Our ability to renew or replace expiring storage, transportation and related contracts;

• The overall forward markets for crude oil, natural gas and natural gas liquids;

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

• Any future impairment of goodwill resulting from the loss of customers or business;

• Changes in currency exchange rates;

• Weather and other natural phenomena, including climate conditions;

• A cyber attack involving our information systems and related infrastructure, or that of our business associates;

• The risks and uncertainties of doing business outside of the United States, including political and economic instability and changes in local governmental laws, regulations and policies;

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

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

• General economic, market and business conditions.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors, may cause actual results to differ from those contained in any forward-looking statement.

Readers are cautioned not to place undue reliance on any forward-looking statements contained in this Form 10-K, which reflect management’s opinions only as of the date hereof. Except as required by law, we undertake no obligation to revise or publicly release the results of any revision to any forward-looking statements.

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As used in this Form 10-K, and unless the context indicates otherwise, the terms the “Company,” “SemGroup,” “we,” “us,” “our,” “ours,” and similar terms refer to SemGroup Corporation, its consolidated subsidiaries, and its 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 residual fuel oil, collectively, as “petroleum products” or “products.”

PART I

Items 1 and 2. Business and Properties

Overview

We provide gathering, transportation, storage, distribution, marketing and other midstream services primarily to producers, refiners of petroleum products and other market participants located in the Gulf Coast, Midwest and Rocky Mountain regions of the United States of America (the “U.S.”) and Canada. We, or our significant equity method investee, have an asset base consisting of pipelines, gathering systems, storage facilities, terminals, processing plants and other distribution assets located in North American production and supply areas, including the Gulf Coast, Midwest, Rocky Mountain and Western Canadian regions. Our U.K. and Mexican operations were disposed during 2018.

Our operations are conducted directly and indirectly through our primary operating segments: U.S. Liquids, U.S. Gas and Canada.

In the fourth quarter of 2018, due to recent changes in our asset portfolio, the company elected to reorganize its business structure and reporting relationships to enhance execution and capture operating efficiencies. In conjunction with the reorganization our reportable segments have changed. Prior period segment disclosures have been recast to reflect the new segments. U.S. Liquids includes the results of both our U.S. crude oil operations including the results of Houston Fuel Oil Terminal Company ("HFOTCO") subsequent to its acquisition in 2017. U.S. Gas contains the results of our historical SemGas segment. Canada includes the operations of our historical SemCAMS segment. Our prior Mexican and U.K. operating segments are included within Corporate and Other, as these businesses were disposed of in 2018.

Company Information

Our principal executive offices are located at Two Warren Place, 6120 South Yale Avenue, Suite 1500, Tulsa, OK 74136-4231 and our telephone number is (918) 524-8100. Our website is www.semgroup.com. Our Class A common stock trades on the New York Stock Exchange under the ticker symbol “SEMG.” Our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as well as proxy statements and other information we file with, or furnish to, the SEC are available free of charge on our website. We make these documents available as soon as reasonably practicable after we electronically file them with, or furnish them to, the SEC. The information contained on our website, or available by hyperlink from our website, is not incorporated into this Form 10-K or other documents we file with, or furnish to, the SEC. We intend to use our website as a means of disclosing material non-public information and for complying with our disclosure obligations under Regulation FD. Such disclosures will be included on our website in the “Investor Relations” sections. Accordingly, investors should monitor such portions of our website, in addition to following our press releases, SEC filings and public conference calls and webcasts.

In addition, we use social media to communicate with our investors and the public about our company, our businesses and our results of operations. The information we post on social media could be deemed to be material information. Therefore, we encourage investors, the media and others interested in our company to review the information we post on the social media channels listed on our investor relations website.

Industry Overview

The market we serve, which begins at the source of production and extends to the crude oil refiner, is commonly referred to as the “midstream” market.

Crude Oil Midstream Market

Our crude oil business operates primarily in Colorado, Kansas, Louisiana, Minnesota, Montana, North Dakota, Oklahoma, Texas and Wyoming. Our assets include gathering systems in and around producing fields and transportation pipelines and trucks carrying crude oil to logistic hubs, such as the Cushing Interchange and Houston Ship Channel, where we have terminalling and storage facilities.

Gathering and Transportation

Pipeline transportation is generally the lowest cost method for shipping crude oil from the wellhead to logistic hubs or refineries. Crude oil gathering assets generally consist of a network of smaller diameter pipelines that are connected directly to the well site or central receipt points delivering into larger diameter trunk lines. Logistic hubs, like the Cushing Interchange, provide storage and connections to other pipeline systems and modes of transportation, such as railroads, trucks and barges. Trucking complements pipeline gathering systems by gathering crude oil from operators at remote wellhead locations not

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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.

Storage Terminals and Supply

Storage terminals complement the crude oil pipeline gathering and transportation systems and address a fundamental imbalance in the energy industry: crude oil is generally produced in different locations and at different times than it is ultimately consumed.

Terminals are facilities in which crude oil is transferred to or from a storage facility or transportation system, such as a gathering pipeline, to another transportation system, such as trucks or another pipeline. Terminals play a key role in moving crude oil to end-users, such as refineries, by providing the following services:

• inventory management;

• distribution; and

• blending to achieve marketable grades or qualities of crude oil.

We have storage terminals located in the central U.S. at the Cushing Interchange and on the U.S. Gulf Coast at the Port of Houston. 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 NYMEX crude oil futures contracts. The Cushing Interchange has multiple inbound and outbound pipeline interconnections and shell capacity of over 90 million barrels. 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 important role in establishing and maintaining markets for many varieties of crude oil. The Port of Houston (the "Port") is the largest port on the U.S. Gulf Coast, the biggest port in Texas and the only port in Houston. With more than 247 million tons of cargo moving through the Port annually, it has consistently been ranked 1st in the U.S. in foreign waterborne tonnage, imports, export tonnage and total tonnage. The Port consists of a 25-mile-long complex and is home to nearly 200 private and public industrial terminals. It is home to the largest petrochemical complex in the nation and second largest in the world. The Houston Ship Channel, from which we operate, consists of a 52-mile waterway that services the Port.

Natural Gas Midstream Market

We operate natural gas gathering and processing assets in the U.S. and Canada. Gathering systems typically consist of a network of small diameter pipelines and compression systems that collect natural gas from producing wells and transport it to larger pipelines for further transmission to a gas processing plant.

In addition to water vapor, wellhead gas may contain 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. As natural gas is processed to remove unwanted elements that interfere with pipeline transportation, higher value natural gas liquids known as NGLs and condensate are separated from the raw natural gas stream. NGLs include ethane, propane, normal butane, iso-butane and natural gasoline. These products are used as petrochemical feedstock, heating and transportation fuels and refinery feedstock. Condensate is a mixture of petroleum products consisting primarily of pentanes and heavier liquids. It is used as refinery feedstock and as a diluent used to dilute crude bitumen so that it can be transported by pipeline or railcar.

Recent Developments

On January 9, 2019, one of our wholly owned subsidiaries, SemCanada II, L.P., and an affiliate of Kohlberg Kravis Roberts & Co, L.P. and wholly owned subsidiary of KKR Global Infrastructure Investors III L.P., KKR Alberta Midstream Inc, entered into definitive documents to create a new joint venture company that owns and operates midstream oil and gas infrastructure in Western Canada, SemCAMS Midstream ULC, an Alberta unlimited liability corporation ("SemCAMS Midstream"). SemGroup owns 51% and KKR owns 49% of SemCAMS Midstream. Subsequent to the joint venture creation, SemCAMS Midstream acquired Meritage Midstream ULC and its midstream infrastructure assets. These transactions closed on February 25, 2019. For information relating to this joint venture and acquisition arrangement, refer to Note 26 of our consolidated financial statements beginning on page F-1 of this Form 10-K.

Business Strategy

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

• move, process and store petroleum products throughout the U.S. and Canada;

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• provide consistently reliable high-quality midstream services under predominantly fee and margin-based contractual arrangements;

• mitigate commodity price risk exposure;

• aggressively manage operating costs to maintain and improve operating margins;

• expand business by improving, enhancing and expanding services at existing facilities and gaining new customers;

• pursue complementary “bolt-on” growth opportunities having acceptable risks and returns; and

• generate consistent operating margins, earnings and cash flows.

Our Business Segments

We conduct our core business through three business segments:

• U.S. Liquids;

• U.S. Gas; and

• Canada.

For information relating to revenue and total assets for each segment, refer to Note 21 of our consolidated financial statements beginning on page F-1 of this Form 10-K.

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.”

U.S. Liquids

Our U.S. Liquids segment operates crude oil pipelines, truck transportation, storage, terminals and marketing businesses in the U.S. Additionally, we store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship and operate a residual fuel oil storage terminal in the U.S. Gulf Coast.

Assets and Operations

• 18.2 million barrels of storage on the Houston Ship Channel;

• 7.6 million barrels of storage at the Cushing Interchange;

• a 460-mile crude oil gathering and transportation pipeline system with over 560,000 barrels of associated storage capacity in Kansas and northern Oklahoma that is connected to several third-party pipelines and refineries;

• the Wattenberg Oil Trunkline ("WOT"), a 75-mile, 12-inch diameter crude oil gathering pipeline system that transports crude oil from production facilities in the DJ Basin to the pipeline owned by White Cliffs Pipeline, L.L.C. ("White Cliffs"). The WOT has a capacity of approximately 85,000 barrels per day, as well as 360,000 barrels of operational storage;

• a 51% ownership interest in White Cliffs, which owns two parallel 527-mile, 12" common carrier, crude oil pipelines that transport crude oil from Platteville, Colorado to Cushing, Oklahoma (the "White Cliffs Pipeline") that we operate. In 2018, we announced that we will convert one of the 12-inch pipelines from crude service to natural gas liquids service. The conversion is expected to be in service during the fourth quarter 2019. As part of the project, SemGroup will construct a 12-mile extension of the White Cliffs Pipeline south of Cushing to interconnect with the Southern Hills Pipeline in order to move NGLs south to Mont Belvieu;

• a 51% ownership interest in Maurepas Pipeline, LLC ("Maurepas"), consisting of three pipelines, with an aggregate of 106 miles of pipe, which services refineries in the Gulf Coast region ("the Maurepas Pipeline");

• a 30-lane crude oil truck unloading facility with 350,000 barrels of associated storage capacity in Platteville, Colorado which connects to the origination point of the White Cliffs Pipeline; and

• a crude oil trucking fleet of over 245 transport trucks and 235 trailers.

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Gulf Coast Facilities. We own and operate storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 million barrels used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. We have five deep-water ship docks on the Houston Ship Channel capable of loading/unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck land loading spots. We are strategically situated on prime real estate on the Houston Ship Channel providing us close proximity to both supply sources (residual fuel oil from refineries and domestic and foreign crude oil) and demand sources (area refineries, third-party pipelines and waterborne export). Our crude oil capacity and connectivity has more than doubled in the last 5 years, including the addition of crude oil export capabilities. Our business is supported by take-or-pay contracts with primarily investment grade counterparties that have been customers for an average of 15 years. Our customers include refiners, producers and independent commodity trading firms that rely on us for storage, blending and timely delivery of crude oil and heated products to be used as feedstocks, exports or marine bunker.

Cushing Facilities. We own and operate crude oil storage tanks in Cushing with an aggregate storage capacity of approximately 7.6 million barrels, of which 5.6 million barrels are leased to customers and 2.0 million barrels are available for crude oil operations, blending and marketing activities. Our storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas and two-way connections with all of the other major storage terminals in Cushing. Connection with this terminal provides our customers with access to multiple pipelines outbound from Cushing. Our Cushing terminal also includes truck unloading facilities. All of our Cushing storage tanks have been built since the beginning of 2008 and had a weighted average age of 8.47 years as of December 31, 2018. The design and construction of our storage tanks meets the specifications established by the American Petroleum Institute in API 650 which establishes minimum requirements for material, design, fabrication, erection and testing of welded tanks for oil storage and includes seismic considerations. Our storage tanks also undergo regular maintenance and inspection programs, and we believe that these design specifications and maintenance and inspection programs reduce our maintenance capital expenditures.

Marketing Activity. We use our transportation and facilities assets and leased capacity arrangements on third-party pipelines to market crude oil. We mitigate the commodity price exposure of our crude oil marketing operations by limiting our net open positions through: (i) the concurrent purchase and sale of like quantities of crude oil to create "back-to-back" transactions intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered; or (ii) derivative contracts. All marketing activities are subject to our Comprehensive Risk Management Policy, a Delegation of Authority policy, and their supporting policies and procedures (collectively, the "Risk Governance Policies"), which establish limits in order to attempt to manage risk and mitigate financial exposure.

Our crude oil purchases in our marketing operations are made at prices that are typically based on published or "posted" prices, plus or minus a differential. The differential is determined based on the grade of oil produced, transportation costs and competitive factors. Both the price and the differential change in response to market conditions. Posted prices can change daily, and differentials, in general, can change every 30 days as contracts renew. We sell crude oil primarily to refiners and other resellers in various types of sale and exchange transactions, at market prices for terms ranging from one to twelve months.

Growth Opportunities. We have 100 acres of additional land, as well as additional infrastructure, in Cushing, which we believe will be sufficient to increase our storage capacity by approximately six million barrels in the future. Our Platteville facility is designed to allow for expansion as production from the DJ Basin and Niobrara Shale increases.

U.S. Gas

Our U.S. Gas segment provides natural gas gathering, processing and marketing services. We aggregates gas supplies from the wellhead and provides various services to producers that condition the wellhead gas production for downstream markets.

Assets and Operations

We own and operate the following assets in Oklahoma:

• a network of processing plants with a combined total capacity of 565 million cubic feet per day processing capacity which includes:

◦ Rose Valley plant, with 400 million cubic feet per day processing capacity;

◦ Hopeton plant, with 125 million cubic feet per day processing capacity; and

◦ Nash plant, with 40 million cubic feet per day processing capacity;

• approximately 842 miles of gathering lines in Northeastern Oklahoma; and

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• a 53-mile, high pressure gathering pipeline (the "Canton pipeline"), located in the STACK play with a capacity of 200 million cubic feet per day and backed by firm commitments from an investment-grade counterparty.

We own and operate the following assets in Texas:

• a processing plant in Sherman with 30 million cubic feet per day processing capacity; and

• approximately 210 miles of gathering lines.

In addition to the above plants and gathering lines, approximately 660,000 acres are dedicated to U.S. Gas from several area producers in the Mississippi Lime Play, as well as an additional 20,000 acre, long-term dedication in the STACK.

Gathering and Processing. We generate revenue from a portfolio of contracts. Initial contract terms can range from monthly and interruptible to the life of the reserves and, upon expiration, continue to renew on a month-to-month or year-to-year evergreen basis. These agreements are a combination of percent of proceeds and fee-based contracts for processing and gathering services. Our U.S. customers include producers, operators, marketers and traders. Because the Mississippi Lime and STACK Plays are primarily crude oil plays with associated natural gas and natural gas liquids, our gathering and processing volumes can be impacted by market demand for the products it handles, as well as the price for crude oil. Gathering and processing activities are also reliant on continued drilling and production activity by producers in our areas of operation.

Market and Competitive Strengths. 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. Our 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. Our U.S. Gas northern Oklahoma assets have natural gas take away capacity on Southern Star Central Gas Pipeline, Panhandle Eastern Pipeline and Enable Midstream Partners and natural gas liquids take away capacity to ONEOK Hydrocarbon LP.

Canada

Our Canada segment owns and operates natural gas processing and gathering facilities in Alberta, Canada. The principal process performed at the processing plants is to remove contaminants and render the gas saleable to downstream pipelines and markets. At our sour gas plants we also “sweeten” sour natural gas by removing sulfur.

Assets and Operations

Canada operates and owns:

• varying working interests in 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”). 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 certain products for transportation by truck and railcar;

• varying working interests in two sweet gas plants known as the West Fox Creek plant and the West Whitecourt plant;

• a combined operating capacity for the above four processing plants of 695 million cubic feet per day;

• a network of approximately 530 miles of natural gas gathering and transportation pipelines;

• a sour gas processing plant in the Wapiti area of the Montney play in Alberta ("Wapiti Plant"), with a capacity of 200 million cubic feet per day; and

• a sour gas processing plant under construction in the Kaybob area of the Duvernay and Montney plays in Alberta ("Smoke Lake Plant"), with an initial capacity of 60 million cubic feet per day and supported by recently signed long-term processing agreements with two area operators. Construction was completed in the first quarter of 2019.

Gathering and Processing. Canada generates revenue from the processing plants through volumetric fees for services under contractual arrangements with working interest owners and third-party customers and the pass through of certain operating costs. Canada does not have direct exposure to commodity prices. In addition, Canada generates fee-based revenue from volume throughput on its pipelines. Canada’s customers include producers of varying sizes. 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. This dedication continues until field depletion. Canada also derives revenue as the owner and operator of pipeline gathering systems that gather gas from multiple wells located in the same production unit and as the owner and operator of pipeline transportation systems that deliver the gathered gas to each plant.

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Market and Competitive Strengths. Natural gas is used for a variety of purposes in Canada including heating, electricity production and other industrial processes. All of Canada’s assets are located in the Montney and Duvernay Plays of the Western Canadian Sedimentary Basin. These formations have a very high liquid content associated with the gas production. It is these liquids, and primarily the condensate, that producers are pursuing as the condensate is the main diluent used for oil sands production.

Other businesses

In early 2018, we disposed of our U.K. and Mexican operations. The historical results of those businesses are reported within Corporate and Other.

Risk Governance

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 operation of our assets. We have Risk Governance Policies that reflect an enterprise-wide approach to risk management and consider both financial and non-financial risks.

Our Board of Directors is responsible for the oversight of our enterprise-wide risk and has approved our Risk Governance Policies. The Risk Governance Policies are 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 Risk Governance Policies.

Our Executive Management Committee, comprised of corporate officers, oversees the financial and non-financial risks associated with all activities governed by our Risk Governance Policies including:

• asset operations;

• marketing;

• 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 Risk Governance Policies.

Collectively, our Risk Governance Policies provide a set of limits or thresholds for activities related to owned assets, physical commodities, and derivatives and capital transactions involving market and credit risk. Our limits monitor these risks for each individual segment and on a consolidated basis. Our Risk Governance Policies also specify the types of transactions that may be executed by incumbents of named positions without specific approval of our Board of Directors or our Executive Management Committee.

Competition

We face intense competition in the operations of each of our segments. 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 logistical assets, distribution capabilities, the ability to meet regulatory requirements and maintenance of quality of service and customer relationships.

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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. The limit of operational insurance maintained covering loss of, or damage to, property and products is $400 million per loss and includes business interruption loss. For claims arising under general liability, automobile liability and excess liability, the limits maintained total $250 million per occurrence/claim, except HFOTCO, which has an additional limit of $10 million per occurrence/claim. Primary and excess liability insurance limits maintained for pollution liability claims vary by location for claims arising from gradual pollution with limits ranging from $30 million to $60 million in the aggregate. The combined primary and excess liability insurance limits for claims arising from sudden and accidental pollution total $280 million per claim. This insurance does not cover every potential risk associated with the operating pipelines, terminals and other facilities. We have a favorable claims history enabling us to self-insure the “working layer” of loss activity using 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. Sizable 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.

With a few limited exceptions, our customers have not agreed to indemnify us for losses arising from a release of petroleum products, and we may instead be required to indemnify our customers in the event of a release or other incident.

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. Transportation Operations

Interstate Transportation

The White Cliffs Pipeline is subject to regulation by the Federal Energy Regulatory Commission ("FERC") because it is a common carrier pipeline that transports crude oil in interstate commerce. Under the Interstate Commerce Act ("ICA") and the rules and regulations promulgated under those laws, tariff rates for interstate service on common carrier oil pipelines, including such pipelines that transport crude oil and petroleum products, must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC regulations require that transportation rates and terms and conditions of service be filed with FERC and posted publicly.

The ICA permits interested persons to challenge new or changed rates or rules and authorizes FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it may require the pipeline to refund the revenues, together with interest in excess of the prior tariff during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates and related rules that are already in effect and may order a pipeline to change them prospectively. Upon an appropriate showing, a shipper may obtain reparations and refunds for a period of up to two years prior to the filing of its complaint.

Gathering and Intrastate Pipeline Regulation

The ICA does not address gathering and natural gas gathering is generally exempt from regulation by FERC under the Natural Gas Act (the "NGA"). We own a number of natural gas pipelines that we believe operate wholly intrastate and are, therefore, exempt from FERC regulation under the NGA. We cannot provide assurances that we will not be subject to regulation by FERC in the future.

In the states in which we operate, regulation of intrastate natural gas 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

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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

Interstate pipelines and certain intrastate pipelines are subject to regulation by the DOT and the PHMSA with respect to the design, construction, operation and maintenance of the pipeline systems. The PHMSA routinely conducts audits of the regulated assets and we must make certain records and reports available to the PHMSA for review as required by the Secretary of Transportation. In some states, the PHMSA has given a state agency authority to assume all or part of the regulatory and enforcement responsibility over the intrastate assets. The majority of our pipelines are regulated by the PHMSA.

Trucking Regulation

Our U.S. Liquids segment operates 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. These regulations include both those concerning the transportation of hazardous materials under the PHMSA, as well as those under the Federal Motor Carrier Safety Administration ("the FMCSA"). 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.

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, is regulated by the NEB. The Government of Alberta tracks volumes exported from Alberta and reserves the right to limit the volume of natural gas that may be removed from Alberta in the event of domestic supply constraint.

Alberta Energy Regulator (“AER”)

The AER’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 AER 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 AER’s primary role is to serve as a licensing authority for the construction and operation of the facilities used in those activities.

While the AER 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 historically 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 AER.

The AER also provides for the safe, efficient, orderly and environmentally responsible development of hydrocarbon resources over the entirety of their life cycle. In March of 2014, the AER assumed responsibility for the regulation of reclamation and remediation activities resulting from oil, gas and coal operations in the province, formerly under the purview of Alberta Environment and Sustainable Resource Development.

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Sulphur Recovery Standards

In 2001, the AER's predecessor set stringent sulfur 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 sulfur recovery to current standards or accept a reduction in their licensed capacity.

At our Canada segment's sour gas processing plants, the sulfur recovery and air quality are monitored and measured to ensure that site-specific sulfur recovery efficiency and provincial emission standards are met. Our Canada segment's licensed sulfur recovery is 98.4% for the KA plant and 98.5% for the K3 plant. Residual sulfur that cannot be removed by processing is disposed of into an acid gas injection scheme at KA while K3 incinerates it, using a minimum stack top temperature to meet the Alberta Ambient Air Quality Objectives as detailed in the plant's site-specific Air Dispersion Model.

Other Provincial Regulatory Agencies

The Alberta Boilers Safety Association (“ABSA”) is the regulatory agency for pressure vessels and related systems in Alberta with a mandate to ensure that pressure equipment is constructed and operated in a manner that protects public safety. Our Canadian operations maintain an approved program for such requirements.

Environmental, Health and Safety Regulation

General

Our operations, including Canadian 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, safety of the public and safety of employees. 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. In addition, Canadian 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.

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 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 limit 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

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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.

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 laws applicable to our Canadian 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 use 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.

Our Canadian operations conduct on-going air, soil and ground water monitoring in accordance with license requirements. Our Canadian operations are required to annually report all specified emissions from its major facilities in Canada to a publicly accessible National Pollutant Release Inventory database.

Sour Gas

Our Canada segment 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 permitted. Proposed facilities are facing increased resistance from community groups which are, in turn, increasing demand for alternate sources of sweetening. 

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. Our Canada segment’s 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. Our Canada segment’s sour gas pipelines are inspected on a regular basis to ensure the integrity of the pipelines and associated facilities.

Our Canadian sour gas plants have continuous sour gas detection equipment, as well as other safety systems which can automatically shut down and de-pressure 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 our Canadian sour gas processing plants, sulfur recovery and air quality are constantly monitored to ensure required sulfur recovery and emission standards are met. Our Canada segment's licensed sulfur recovery is 98.4% for the KA plant and 98.5% for the K3 plant. 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 that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”) (including carbon dioxide and methane), are contributing to the warming of the earth’s atmosphere and other climatic changes, the U.S. Congress has been considering legislation to reduce such emissions. In addition, a number of states, either individually or through multi-state regional initiatives, have 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. Although we would not be impacted to a greater degree than other similarly situated midstream energy service providers, a stringent GHG control program could

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have an adverse effect on our cost of doing business and could reduce demand for the petroleum products we gather, process, transport, store and market.

In October 2016 Canada ratified the Paris Agreement putting in effect the pan-Canadian carbon-pricing framework. Although not specifically directed to the oil and gas industry, the carbon tax is applicable to all CO2 emissions. The pan-Canadian framework sets the price of carbon, which increases $10/t CO2e annually until it reaches $50/t in 2022. The objective of the pan-Canadian carbon-pricing framework is to reduce CO2 emissions to meet the reduction targets set under the Paris Agreement. The Canadian Federal government has deferred implementation of the carbon tax to the provinces, however where a provincial program is not in place to apply the carbon tax the Federal government can implement a process.

In 2018, the Province of Alberta implemented the Carbon Competitiveness and Incentive Regulation (CCIR). This new regulation was developed to implement a carbon tax on GHG emissions. Using an output based allocation methodology, each discrete processing unit within a gas plant is assigned a benchmark value to which each facility is compared. The taxes levied against the facility are measured against this benchmark. Current carbon pricing in Alberta is set at $30/T.

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 Environmental Protection Agency ("EPA") and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the potentially responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. Although “petroleum,” as well as natural gas and NGLs, have been, for the most part, excluded from CERCLA’s definition of a “hazardous substance”, we may, in the course of ordinary operations, 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 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 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 or Canadian federal or provincial laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater

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contamination, or to take action to prevent future contamination. In some instances, any such requirements may have been dealt with in the bankruptcy proceedings of our predecessor.

Employee Safety

We are subject to the requirements of the Occupational Safety and Health Administration ("OSHA"), as well as to comparable national, state, provincial and local Canadian laws that are applicable to our Canadian 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.

HFOTCO is subject to the Maritime Transportation Security Act ("MTSA") of 2002, which combines international requirements, existing domestic policy on implementation of national maritime security and adherence to the United States Coast Guard (USCG) approved Facility Security Plan.

Our Canadian facilities are also subject to regulation by ABSA. Our Canada segment 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.

Office Facilities

In addition to our gathering, storage, terminalling and processing facilities discussed above, we maintain corporate office headquarters in Tulsa, Oklahoma. All of the U.S. business segments use Tulsa as their center of operations, excluding our HFOTCO operations, whose center of operation is in Houston, Texas. Our Canada segment, uses Calgary, Alberta as their center of operations. Many of our business segments also have satellite offices located throughout North America. The current

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lease for our Tulsa headquarters expires in May 2022, 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, 2018, we had approximately 880 employees, including 265 employees in Canada. As of December 31, 2018, we had 55 employees in Canada represented by labor unions and subject to collective bargaining agreements governing their employment with us. This collective bargaining agreement expired on January 31, 2019. We are in the midst of negotiating the terms of the new contract and expect an agreement soon. We have never had a labor related work stoppage and believe our employee relations are good.

Item 1A. Risk Factors

Our business faces many risks. We believe the risks described below identify 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 could decline significantly. Investors should consider the specific risk factors discussed below, together with other information contained in this report on Form 10-K and the other documents that we will file from time to time with the SEC.

Risks Related to Our Business

The instruments governing our indebtedness contain various covenants limiting the conduct of our business.

Our credit agreement, the indentures governing our senior notes and the instruments governing our other indebtedness and our Series A Cumulative Perpetual Convertible Preferred Stock ("Preferred Stock") contain various restrictive covenants that limit the conduct of our business and our credit agreements require us to maintain certain financial ratios. These covenants and restrictions limit our ability to respond to changing business and economic conditions and may prevent us from engaging in transactions that might otherwise be considered beneficial to us. In particular, this agreement places certain limits on our ability to, among other things:

• incur additional indebtedness;

• incur liens;

• enter into sale and lease back transactions;

• make investments;

• pay dividends or distributions;

• make certain restricted payments;

• consummate certain asset sales;

• enter into certain transactions with affiliates; and

• merge, consolidate and/or sell or dispose of all, or substantially all, of our assets.

If we fail to comply with the restrictions in our credit agreement, the indentures governing our senior notes, or the instruments governing our other indebtedness or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt. Even if new financing were available at that time, it may not be available on terms acceptable to us.

If we are unable to repay amounts outstanding under our credit agreement when due, the lenders thereunder could, subject to the terms of the agreement, seek to sell or otherwise transfer our assets granted to them as collateral to secure the indebtedness outstanding under the agreement. Substantially all of our assets have been pledged as collateral to secure our credit agreement. Substantially all of the assets of HFOTCO have been pledged as collateral to secure the indebtedness of HFOTCO. In addition, the lenders under our credit agreement and the HFOTCO credit agreement could choose to terminate any commitments to supply us with further funds.

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Under certain economic conditions, our access to capital and credit markets may be limited, which may adversely impact our liquidity.

We may require additional funds from outside sources from time to time. Our ability to raise capital or arrange financing or renew existing facilities, along with the cost of such capital, is dependent upon a number of variables, including:

• general economic, financial and business conditions;

• industry specific conditions;

• prevailing interest rates;

• credit availability from banks and other financial institutions;

• investor confidence in us;

• cash flow and earnings before interest, taxes, depreciation and amortization ("EBITDA") levels;

• competitive, legislative and regulatory matters; and

• provisions of tax and securities laws that may impact raising capital.

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

Our substantial indebtedness could limit our flexibility, adversely affect our financial health and prevent us from making payments on such indebtedness.

Our substantial indebtedness could have important consequences to you. For example, it could:

• make it difficult for us to satisfy our obligations with respect to our indebtedness;

• make us more vulnerable to general adverse economic and industry conditions;

• require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow for operations and other purposes;

• limit our ability to maintain or increase the dividends we pay to holders of our Class A common stock

• limit our flexibility in planning for, or reacting to, changes in our business and industry in which we operate; and

• place us at a competitive disadvantage compared to competitors that may have proportionately less indebtedness.

In addition, our ability to make scheduled payments or to refinance our obligations depends on our successful financial and operating performance. We cannot assure you that our operating performance will generate sufficient cash flow or that our capital resources will be sufficient for payment of our debt obligations in the future. Our financial and operating performance, cash flow and capital resources depend on prevailing economic conditions and financial, business and other factors, many of which are beyond our control.

If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to sell material assets or operations, obtain additional capital or restructure our debt. In the event that we are required to dispose of material assets or operations or restructure our debt to meet our debt service and other obligations, we cannot assure you as to the terms of any such transaction or how quickly any such transaction could be completed, if at all.

We may incur substantial additional indebtedness in the future. Our incurrence of additional indebtedness would intensify the risks described above.

The Preferred Stock gives the holders thereof liquidation and distribution preferences, certain rights relating to our business and management, and the ability to convert such shares into our Class A common stock, potentially causing dilution to our common stockholders.

In January 2018, we issued 350,000 shares of Preferred Stock (the “Preferred Shares”), which rank senior to the Class A common stock with respect to distribution rights and rights upon liquidation. Subject to certain exceptions, so long as any Preferred Shares remain outstanding, we may not declare any dividend or distribution on our Class A common stock unless all accumulated and unpaid dividends have been declared and paid (in cash or in kind) on the Preferred Shares. In the event of our

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liquidation, winding-up or dissolution, the holders of the Preferred Shares would have the right to receive proceeds from any such transaction before the holders of the Class A common stock. The payment of the liquidation preference could result in common stockholders not receiving any consideration if we were to liquidate, dissolve or wind up, either voluntarily or involuntarily. Additionally, the existence of the liquidation preference may reduce the value of the Class A common stock, make it harder for us to sell shares of Class A common stock in offerings in the future, or prevent or delay a change of control.

In connection with the issuance of the Preferred Shares, we entered into an agreement with WP SemGroup Holdings, LP (“Warburg”), an entity controlled by funds affiliated with Warburg Pincus LLC, pursuant to which we granted Warburg the right to appoint an observer to our Board of Directors. In addition, the Certificate of Designations governing the Preferred Shares provides the holders of the Preferred Shares with the right to vote on an as-converted basis with our common stockholders on matters submitted to a stockholder vote. Also, so long as any Preferred Shares are outstanding, subject to certain exceptions, the affirmative vote or consent of the holders of at least a majority of the outstanding Preferred Shares, voting together as a separate class, will be necessary for effecting or validating, among other things: (i) any issuance of stock senior to the Preferred Shares, (ii) any issuance by us of parity stock, subject to certain exceptions, (iii) any repurchase by us of any Preferred Stock, other than on a pro rata basis among all Holders, (iv) any special, one-time dividend or distribution with respect to any class of junior stock and (v) any spin-off or other distribution of any equity securities or assets of any of our subsidiaries to its stockholders in which the consideration received by us in such transaction is less than fair market value, subject to certain exceptions. These restrictions may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Furthermore, the conversion of the Preferred Shares into Class A common stock beginning on or after the eighteen-month anniversary of the issuance of the Preferred Shares, may cause substantial dilution to holders of the Class A common stock. Because our Board of Directors is entitled to designate the powers and preferences of preferred stock without a vote of our Class A common stockholders, subject to NYSE rules and regulations, our Class A common stockholders will have no control over what designations and preferences our future preferred stock, if any, will have.

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. A reduction in demand can result from a number of factors including:

• an increase in the price of products derived from petroleum products;

• higher taxes, including federal excise taxes, crude oil severance taxes or sales taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of petroleum based products;

• adverse economic conditions which result in lower spending by consumers and businesses on products derived from petroleum products;

• effects of weather, natural phenomena, terrorism, war, or other similar acts;

• an increase in fuel economy, whether as a result of a shift by consumers to more fuel efficient vehicles, technological advances by manufacturers or federal or state regulations;

• increasing levels of congestion in the Houston Ship Channel could result in a diversion of business to less busy ports;

• decision by our customers or suppliers to use alternate service providers for a portion of or all of their needs, operate in different markets not served by us, reduce operations or cease operations entirely; and

• an increase in the use of alternative fuel sources such as ethanol, biodiesel, fuel cells, solar and wind power.

We may not realize the anticipated benefits of our acquisition of Meritage.

On February 25, 2019, we completed the acquisition of Meritage Midstream ULC. We believe that the Meritage acquisition will, among other things, expand and optimize our portfolio of assets and create a more attractive Canadian growth platform. However, our assessments and expectations regarding these anticipated benefits of the Meritage acquisition may prove to be incorrect. Accordingly, there can be no assurance we will realize the anticipated benefits of the Meritage acquisition.

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Certain of our operations are conducted through joint ventures which have unique risks.

Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Differences in views among the partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations.

An impairment of our assets, including goodwill, property, plant, and equipment, intangible assets, and/or equity-method investments, could reduce our earnings.

Accounting principles generally accepted in the U.S. require us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our goodwill, property, plant, and equipment, intangible assets, and/or equity method investments. Additionally, any asset monetizations could result in impairments if any other assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate non-cash charge to earnings.

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, transport, store, process or market could adversely affect our business and operating results.

The volumes that support our business are dependent, in part, on the level of production from wells connected to our operations, 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, in order to maintain or increase the amount of petroleum products that we handle, 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 operations 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.

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 have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our assets and a reduced need for our marketing operations. 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 the levels of petroleum products that we handle, 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.

One of the ways we intend to continue to grow our business is through the construction of new assets. 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, or at all, 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 may 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

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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.

Increased regulation of hydraulic fracturing or produced water disposal could result in reductions or delays in crude oil and natural gas production in our areas of operation, which could adversely impact our business and results of operations.

The adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or produced water disposal could make drilling certain wells less economically attractive. As a result, the volume of crude oil and natural gas we gather, transport and store for our customers could be substantially reduced which could have an adverse effect on our business, results of operations, financial condition and ability to pay dividends to our stockholders.

Our operations could be adversely affected if third-party pipelines, or other facilities connected 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 operation of such third-party pipelines or facilities is not within our control. These pipelines and other facilities may become unavailable, or available only at a reduced capacity, 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.

Our Risk Governance Policies' provisions governing our internal marketing activities cannot eliminate all risks associated with the marketing of commodities, nor can we ensure full compliance at all times with the Risk Governance Policies by our employees, both of which could impact our financial and operational results.

We have in place Risk Governance Policies that establish authorized commodities and transaction types, delegations of authority, and limits for marketing exposures and require 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 Governance Policies have restrictive terms with respect to acquiring and holding physical inventory, futures contracts or derivative products. Net open positions are monitored by our Risk Management department for compliance with policy limits. These policies and practices, however, cannot eliminate all risks. Derivatives contracts and contracts for the future delivery of crude oil expose us to the risk of non-delivery under product purchase contracts or the failure of gathering and transportation systems. 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.

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. Our exposure to price risks could impact our operational and financial results.

We also have a risk that employees involved in our marketing operations may not comply at all times with our Risk Governance Policies. Even with management oversight, we cannot ensure with certainty that all violations of the Risk Governance Policies, particularly if deception or other intentional misconduct is involved, will be detected prior to our businesses being materially affected.

Conventional gas operations face continued competitive pressure from shale gas production.

The U.S. Energy Information Administration reports that higher estimates of domestic shale gas resources support increasing estimates of domestic natural gas production at prices below its previous estimates.

The abundant supply of shale gas, driven by horizontal drilling and hydraulic fracturing, places pressure on all conventional gas production, including sour gas production. In addition, facilities designed to remove hydrogen sulfide from a raw gas stream face increased competitive pressure because sour gas is more expensive to process than gas which does not contain sulfur.

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Our construction of new assets is subject to regulatory, environmental, legal and economic risks which could adversely affect our business.

One of the ways we intend to continue 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. 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 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. Our results of operations, cash flows and financial condition could be adversely affected if we are unable to complete the construction of new assets or additions to existing assets, the cost of such projects significantly exceed our estimates, such projects are delayed beyond our expectations, the cost of renewing existing rights-of-way increases, or if we lose our existing rights-of-way through our inability to renew right-of-way contracts or otherwise.

We may face opposition to the construction and operation of our pipelines and facilities from various groups.

We may face opposition to the construction and operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the construction and operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying dividends to our Class A common stockholders and, accordingly, adversely affect our financial condition and the market price of our securities.

Changes in currency exchange rates could adversely affect our results of operations.

A portion of our revenue is generated from our operations in Canada, which use the Canadian dollar as the functional currency. Therefore, changes in the exchange rate between the U.S. dollar and the Canadian dollar could adversely affect our results of operations.

We are exposed to the creditworthiness and performance of our customers, suppliers and transactional counterparties, including our hedge 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, including our hedge 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. There is no certainty that our counterparties will perform or adhere to existing or future contractual arrangements.

Our business involves many hazards and operational risks, some of which may not be covered by insurance.

Leaks and other releases of hydrocarbons are possible in operations involving pipelines, tanks and processing units. 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 inventories of spare parts;

• operator error;

• labor disputes;

• disputes with connected facilities and carriers;

• public opposition activities; and

• catastrophic events such as natural disasters, earthquakes, hurricanes, fires, explosions, fractures, acts of terrorism and other similar events, many of which are beyond our control.

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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. With a few exceptions, our customers have not agreed to indemnify us for losses arising from a release of petroleum products, and we may instead be required to indemnify our customers in the event of a release or other incident.

We may not be able to make acquisitions on economically acceptable terms, which may limit our ability to grow. In addition, any acquisition that we pursue will involve risks that may adversely affect our business.

As part of our business strategy, we have expanded our operations through acquisitions and may continue to do so. We cannot accurately predict the timing, size and success of our acquisition efforts. We may be unable to identify attractive acquisition candidates, negotiate acceptable purchase terms or obtain financing for these acquisitions on economically acceptable terms or because we are outbid by competitors. If we are unable to successfully acquire new businesses or assets, our future growth may be limited.

Any acquisition that we may pursue will involve potential risks, including:

• performance from the acquired businesses or assets that is below the forecasts we used in evaluating the acquisition;

• a significant increase in our indebtedness and working capital requirements;

• the inability to timely and effectively integrate the operations of recently acquired businesses or assets;

• the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets prior to our acquisition;

• risks associated with operating in lines of business that are distinct and separate from our historical operations;

• loss of customers or key employees of the acquired businesses; and

• the diversion of management’s attention from other business concerns.

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

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, which are expected to expand with our recent acquisition of Meritage Midstream and further organic growth. In addition to the other risks described in this report on Form 10-K, 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.

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 PHMSA, has adopted regulations requiring pipeline operators to develop and implement integrity management programs for 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 integrity management regulations require operators, including us, to:

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• perform on-going assessments of pipeline integrity on a recurring frequency schedule;

• identify and characterize applicable potential threats to pipeline segments that could impact a high consequence area;

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary; and

• implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. We currently estimate that we will incur an aggregate cost of approximately $11.8 million during 2019 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, preventive 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. 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.

A prolonged decline in index prices at Cushing relative to other index prices could reduce the demand for our transportation to, and storage in, Cushing.

Shifts in the overall supply of, and demand for, crude oil in regional, national and global markets, over which we have no control, can have an adverse impact on crude oil index prices in the markets we serve relative to other index prices. A prolonged decline in the WTI Index price, relative to other index prices, may cause reduced demand for our transportation to, and storage in, Cushing, which could have a material adverse effect on our business, results of operations and financial condition.

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, treating and marketing petroleum products and are principally located in the Midwest, Gulf Coast and Rocky Mountain supply regions 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.

We are subject to regulation by multiple governmental agencies, and the nature and degree of regulation from such agencies could adversely impact our business, results of operations and financial condition.

Our business activities are subject to regulation by multiple federal, state and local governmental agencies. Our historical operating costs reflect the recurring costs resulting from compliance with these regulations and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions, or changes in regulation, or discovery of existing but unknown compliance issues. Additional proposals and proceedings that affect the midstream industry are regularly considered by Congress, as well as by state legislatures and federal and state regulatory commissions, agencies and courts. We cannot predict when or whether any such proposals may become effective or the magnitude of the impact changes in laws and regulations may have on our business. However, additions to the regulatory burden on our industry generally increase our cost of doing business and affect our profitability.

Our trucking fleet operations are subject to the Federal Motor Carrier Safety Regulations which are enacted, reviewed and amended by the FMCSA. Our fleet currently has a "satisfactory" safety rating; however, if our safety rating were downgraded to "unsatisfactory," our business and results of operations could be adversely affected.

All federally regulated carriers safety ratings are measured through a program implemented by the FMCSA known as the Compliance Safety Accountability ("CSA") program. The CSA program measures a carrier's safety performance based on violations observed during roadside inspections as opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of comparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is a progressive intervention

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strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an "unsatisfactory" rating and the revocation of our operating authority by the FMCSA could have an adverse effect on our business, results of operations and financial condition.

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, provincial and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws include, for example:

• federal and comparable state and foreign laws that impose obligations related to air emissions;

• federal and comparable state and foreign laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from our facilities;

• federal and comparable state and foreign laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which our hazardous substances have been transported for disposal; and

• federal and comparable state and foreign laws that regulate discharges from our facilities, require spill protection planning and preparation and set requirements for other actions for protection of waters.

Failure to comply with these laws and regulations, or newly adopted laws or regulations, may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Claims pursued under certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or petroleum products have been disposed or otherwise released. Provisions also exist that may require remediation or other compensation to pay for damages to natural resources. Moreover, it is not uncommon for individuals to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, 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 for environmental cleanup and restoration costs, claims made by individuals for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and, the cost of any remediation that may become necessary. We may not be able to recover all or any of these costs from insurance and fines or penalties paid for compliance violations, whether alleged or proven, will not be covered by insurance.

Our storage operations are influenced by the overall forward market for crude oil and other products we store, and certain market conditions may adversely affect our financial and operating results.

Our storage operations are influenced by the overall forward market for crude oil and other products we store. A contango market (meaning that the price of crude oil or other products for future delivery is higher than the current price) is associated with greater demand for storage capacity, because a party can simultaneously purchase crude oil or other products at current prices for storage and sell at higher prices for future delivery. A backwardated market (meaning that the price of crude oil or other products for future delivery is lower than the current price) is associated with lower demand for storage capacity because a party can capture a premium for prompt delivery of crude oil or other products rather than storing it for future sale. A prolonged backwardated market, or other adverse market conditions, could have an adverse impact on our ability to negotiate favorable prices under new or renewing storage contracts, which could have an adverse impact on our storage revenues. As a result, the overall forward market for crude oil or other products may have an adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our stockholders.

An increase in interest rates could impact demand for our storage capacity.

There is a financing cost for a storage capacity user to own crude oil while it is stored. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user, in addition to the commodity cost of the crude oil in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing crude oil for future sale. As

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a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.

Severe weather conditions and natural or man-made disasters could severely disrupt normal operations and have a material adverse effect on our business, financial condition, results of operations and cash flows.

We operate in various locations across the U.S. and Canada, which may be adversely affected by severe weather conditions and natural or man-made disasters. During periods of heavy snow, ice, rain or extreme weather conditions such as high winds, tornadoes and hurricanes or after other natural disasters such as earthquakes or wildfires, we may be unable to move our trucks between locations and our facilities may be damaged, thereby reducing our ability to provide services and generate revenues. These same conditions may cause serious damage or destruction to the property and operations of our customers. Such disruptions could potentially have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

Beginning in December 2009, the EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain greenhouse gases ("GHG") including CO₂ and methane. Our facilities are subject to these requirements. Operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting and permitting requirements.

On October 23, 2015, the EPA published as a final rule the Clean Power Plan, which sets interim and final CO₂ emission performance rates for power generating units that are fueled by coal, oil or natural gas. The final rule is the focus of legislative discussion in the U.S. Congress and litigation in federal court. On February 10, 2016, the U.S. Supreme Court stayed the final rule, effectively suspending the duty to comply with the rule until certain legal challenges are resolved. In October 2017, the EPA proposed to repeal the Clean Power Plan. In August 2018, the EPA proposed to replace the Clean Power Plan and Affordable Clean Energy rule. The ultimate determination of the Clean Power Plan and Affordable Clean Energy rule remains uncertain. While we do not operate power plants that would be subject to the Clean Power Plan or the Affordable Clean Energy rule, it remains unclear what effect a final rule, if it comes into force, might have on the anticipated demand for natural gas, including natural gas that we gather, process, store and transport.

At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs, primarily through the planned development of emission inventories or regional GHG "cap and trade" programs. Although many of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that sources such as our gas-fueled compressors and processing plants could become subject to related state regulations. Various states are also proposing or have implemented more strict regulations for GHGs that go beyond the requirements of the EPA. Some of the states have implemented regulations that require additional monitoring and reporting of methane emissions. Depending on the state programs pending implementation, we could be required to conduct additional monitoring, do additional emissions reporting and/or purchase and surrender emission allowances

Canadian federal regulations creating GHG performance standards for the transportation sector and for coal-fired electricity generation were established by the previous federal government in recent years and the oil and gas sector was targeted for similar regulations in the future. A new federal government was elected on October 19, 2015. It indicated that a key priority is to provide national leadership to reduce emission, combat climate change and price carbon, in partnership with provinces and territories. On December 12, 2015, the federal government reached an international agreement with 195 countries at the Paris Climate Conference and stated that it will support and implement policies that contribute to a low-carbon economy. In October 2016 the Federal Government ratified the Paris Agreement and implemented the pan-Canadian carbon-pricing framework, which set the price of emissions of CO2 at $50 per tonne by 2022. The implementation of the pan-Canadian framework will be left to the individual provincial governments.

The province of Alberta is currently reviewing how to integrate the pan-Canadian framework into the existing legislation for large GHG emitters. Based upon the federal carbon pricing direction, the costs of future emissions will increase from the current $20/t CO2e to $50/t CO2e in 2022. The details of which processes will be taxed is still being evaluated by the Alberta Provincial government.

Depending on the particular law, regulation or program, we could be required to incur capital expenditures for installing new monitoring equipment, acquire and surrender allowances for the GHG emissions, pay taxes related to the GHG emissions and administer and manage a GHG emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to us. While we may be able to

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include some or all of such increased costs in the rates charged by our pipelines, recovery of costs in all cases is uncertain and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects

We face intense competition in our gathering, transportation, processing, storage and marketing activities. Competition from other providers of those services that are able to supply our customers with those services at a lower price or on otherwise better terms could adversely affect our business and operating results.

We are subject to competition from other gathering, transportation, processing, storage and marketing operations that may be able to supply our customers with the same or comparable services at a lower price or otherwise on better terms. We compete with national, regional and local gathering, transportation and storage companies of widely varying sizes, financial resources and experience, including the major integrated oil companies. Our ability to compete could be harmed by numerous factors, including:

• price competition;

• the perception that another company can provide better service; and

• the availability of alternative supply points, or supply points located closer to the operations of our customers.

Some of our competitors have greater financial, managerial and other resources than we do, and control substantially more storage or transportation capacity than we do. Our competitors may expand their assets or operations, creating additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, transportation and storage systems or marketing operations in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers.

We may not be able to renew or replace expiring storage and transportation contracts.

We have significant exposure to market risk at the time our existing storage and transportation contracts expire and are subject to renegotiation and renewal. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

• the level of existing and new competition to provide storage and transportation services to our markets;

• the macroeconomic factors affecting crude oil storage and transportation economics for our current and potential customers;

• the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

• the extent to which the customers in our markets are willing to contract on a long-term basis; and

• the effects of federal, state or local regulations on the contracting practices of our customers.

Any failure to extend or replace a significant portion of our existing contracts, or extend or replace them at comparable rates, could have a material adverse effect on our business, results of operations, and financial condition.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies, or a change in policy by those agencies, could result in increased regulation of our assets, which could affect existing costs and rates.

Interstate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by FERC. However, the distinction between FERC-regulated interstate pipeline transportation, on the one hand, and intrastate pipeline transportation, on the other hand, is a fact-based determination. The classification and regulation of our crude oil pipelines are subject to change based on future determinations by FERC, federal courts, Congress or regulatory commissions, courts or legislatures in the states in which we operate.

Our Kansas and Oklahoma gathering pipeline system carries crude oil owned by us and by third parties. We own all of the crude oil shipped on our pipeline system across state lines. We believe that the pipeline segments on which we provide service to third parties and the services we provide to third parties on the gathering pipeline system meet the traditional tests that FERC has used to determine that the pipeline services provided are not interstate commerce. We believe that the pipeline segments on which we transport only crude oil owned by us should not be subject to regulation by FERC under the ICA, or that these pipeline segments would qualify for waiver from FERC’s regulatory requirements, if applicable. However, we cannot provide assurance that FERC will not in the future, either at the request of other entities or on its own initiative, determine that

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some or all of our Kansas and Oklahoma gathering pipeline system and the services we provide on that system are within its jurisdiction, or that such a determination would not adversely affect our results of operations. If some or all of the gathering system were subject to FERC jurisdiction, and not otherwise exempt from any applicable regulatory requirements, for that portion of the gathering pipeline system we would be required to file a tariff with FERC, and if our tariff rates were subject to protest, provide a cost justification for the transportation rate subject to protest and provide service to all potential shippers without undue discrimination. In addition, if the services we provide on any segment(s) of our gathering system become regulated by FERC under the ICA, our services could be subject to a protest and/or complaint before FERC. If FERC were to determine, in response to a complaint, that our rates are unjust and unreasonable, we could be required to pay reparations and refunds dating to two years before the filing of the complaint. Furthermore, if in the future our services become subject to state regulation, they could be subject to a protest and/or complaint before a state commission with jurisdiction.

Increasing levels of congestion in the Houston Ship Channel could result in a diversion of business to less busy ports.

Our Gulf Coast facilities are strategically situated on prime real estate located in the Houston Ship Channel, which is in close proximity to both supply sources and demand sources. In recent years, the success of the Port of Houston has led to an increase in vessel traffic driven in part by the growing overseas demand for U.S. crude, gasoline, liquefied natural gas and petrochemicals and in part by the Port of Houston’s recent decision to accept large container vessels, which can restrict the flow of other cargo. Increasing congestion in the Port of Houston could cause our customers or potential customers to divert their business to smaller ports in the Gulf of Mexico, which could result in lower utilization of our facilities.

Increased regulation of hydraulic fracturing or produced water disposal could result in reductions or delays in crude oil and natural gas production in our areas of operation, which could adversely impact our business and results of operations.

The hydraulic fracturing process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies and may have other detrimental impacts on public health, safety, welfare and the environment. In addition, the water disposal process has come under scrutiny from sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. The adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or produced water disposal or prohibiting hydraulic fracturing in proximity to areas considered to be environmentally sensitive could make drilling certain wells impossible or less economically attractive. As a result, the volume of crude oil and natural gas we gather, transport and store for our customers could be substantially reduced which could have an adverse effect on our business, results of operations, financial condition and ability to pay dividends to our stockholders.

Competition for water resources or limitations on water usage for hydraulic fracturing could disrupt crude oil and natural gas production from shale formations.

Hydraulic fracturing is the process of creating or expanding cracks by pumping water, sand and chemicals under high pressure into an underground formation in order to increase the productivity of crude oil and natural gas wells. Water used in the process is generally fresh water, recycled produced water or salt water.

There is competition for fresh water from municipalities, farmers, ranchers and industrial users. In addition, the available supply of fresh water can also be reduced directly by drought. Prolonged drought conditions increase the intensity of competition for fresh water.

Limitations on oil and gas producers’ access to fresh water may restrict their ability to use hydraulic fracturing and could reduce new production. Such disruptions could potentially have a material adverse impact on our business, financial condition, results of operations and cash flows.

Loss of key employees could significantly reduce our ability to execute strategies.

Much of our future success depends on the continued availability and service of key personnel including the executive team and skilled employees in technical, operational and staff positions. 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 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.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

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Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems could result in losses that are difficult to detect.

We have become more reliant on technology to help increase efficiency in our business. We use numerous technologies to help run our operations, and this may subject our business to increased risks. Any cyber security attack that affects our facilities, our customers or any financial data could have a material adverse effect on our business. In addition, a cyber attack on our customer and employee data may result in a financial loss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also suffer system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

The threat or attack of terrorists aimed at our facilities could adversely affect our business.

The U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. 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 business. In addition, any governmental body mandated actions to prepare for, or protect against, potential terrorist attacks could require us to spend money or modify our operations.

Risks Related to Our Class A Common Stock

Holders of our Class A common stock may not receive dividends in the amount identified in guidance or any dividends.

    We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we pay out in dividends may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including:

• the amount of cash that our subsidiaries distribute to us;

• the amount of cash we generate from our operations, our working capital needs, our level of capital expenditures and our ability to borrow;

• the restrictions contained in our indentures, the certificate of designations for our Preferred Stock and our credit agreements and our debt service requirements; and

• the cost of acquisitions, if any.

A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage and a decrease in the market price of our Class A common stock.

Our Class A Common Stock 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:

• the risk factors described in this report on Form 10-K;

• our operating and financial results differing from that expected by securities analysts and investors;

• the financial and stock price performance of our competitors or companies in our industry generally;

• changes in accounting standards, policies, interpretations or principles;

• changes in laws or regulations which adversely affect our industry or us;

• general conditions in our customers’ industries, including changes in commodity prices; and

• general economic conditions, prevailing interest rates and conditions in the securities markets.

Item 1B. Unresolved Staff Comments

None.

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Item 3. Legal Proceedings

For information regarding legal proceedings, see the discussion under the captions "Environmental" and "Other matters" in Note 14 of our consolidated financial statements beginning on page F-1 of this Form 10-K, which information is incorporated by reference into this Item 3.

Item 4. Mine Safety Disclosures

Not applicable.

Executive Officers of the Registrant

Our executive officers are elected annually by, and serve at the discretion of, our Board of Directors. Set forth below is information concerning our executive officers.

    

Name	Age	Position
Carlin G. Conner	51	President and Chief Executive Officer and Director
Robert N. Fitzgerald	59	Executive Vice President and Chief Financial Officer
Susan S. Lindberg	54	Executive Vice President and General Counsel
David M. Minielly	50	Executive Vice President - US Operations
Shaun M. Revere	49	Executive Vice President - US Commercial
David B. Gosse	51	Executive Vice President - Canadian Operations and Commercial

Carlin G. Conner. Mr. Conner became President, Chief Executive Officer, and a director of SemGroup in 2014. In 2000, he joined a subsidiary of Oiltanking GmbH (“Oiltanking”), an independent worldwide storage provider of crude oil, refined petroleum products, liquid chemicals, and gases. During his nearly 14 years with Oiltanking and its affiliates he focused on international business development while serving in various leadership roles. From 2012 to 2014, Mr. Conner served as managing director of Oiltanking and he served as chairman of the Board of Directors of the general partner of Oiltanking Partners, L.P., a publicly traded master limited partnership engaged in independent terminaling, storage and transportation of crude oil, refined petroleum products and liquefied petroleum gas, from 2011 to 2014. From 2012 to 2014, Mr. Conner also served as an executive board member of Marquard & Bahls, AG, the parent company of Oiltanking, where he was instrumental in defining a new strategy for the energy supply, trading, and logistics business across Europe, the Americas, Asia, and Africa. He began his career at GATX Terminals Corporation and served in various roles, including operations and commercial management. From April 2014 to October 2014, Mr. Conner served on the Board of Directors of the general partner of NGL Energy Partners LP, a publicly traded master limited partnership engaged in water solutions, crude oil logistics, NGL logistics, refined products/renewables and retail propane. He also served as chairman of the Board of Directors, President and Chief Executive Officer of the general partner of Rose Rock Midstream, L.P. (“Rose Rock”), a publicly traded master limited partnership and subsidiary of the Company, which owned and operated a diversified portfolio of midstream energy assets, from 2014 until September 2016, when SemGroup acquired all of Rose Rock. Mr. Conner holds a bachelor’s degree in environmental science from McNeese State University, where he was also named 2016 Distinguished Alumnus of the Year. In addition, he completed INSEAD and MCE executive management training in France and Belgium, respectively.

Robert N. Fitzgerald. Mr. Fitzgerald joined SemGroup in 2009 and serves as Executive Vice President and Chief Financial Officer. Mr. Fitzgerald also served as a director, Senior Executive Vice President and Chief Financial Officer of the general partner of Rose Rock from 2011 until September 2016, when SemGroup acquired all of Rose Rock. Prior to joining SemGroup, Mr. Fitzgerald served as Chief Financial Officer from 2008 to 2009 of Windsor Energy Group, a private independent oil and gas exploration and development company. He has also served from 2006 to 2008 as Executive Vice President of LinkAmerica Corp. and from 2003 until 2006 as Chief Operating Officer and Chief Financial Officer of Arrow Trucking Company, both commodity transportation companies. From 2000 to 2003, he served as Vice President, Finance of Williams Communications Group, a global communication company. Prior to that, Mr. Fitzgerald was with BP Amoco and Amoco Corporation for 20 years, working in various financial and operations positions in Tulsa, Oklahoma; Houston, Texas; Denver, Colorado; and Chicago, Illinois. Mr. Fitzgerald received a master’s degree in business administration from the University of Tulsa and a Bachelor of Business Administration degree from Western Illinois University. He is currently a member of the American Institute of Certified Public Accountants, the Institute of Management Accountants and the Institute of Internal Auditors. He is a certified public accountant.

Susan S. Lindberg. Ms. Lindberg has served as Executive Vice President and General Counsel of SemGroup since January 2019. Ms. Lindberg joined SemGroup in 2017 and served as Vice President and General Counsel of SemGroup from 2017 to 2019. She has 26 years of energy industry experience with extensive expertise in corporate governance, complex transactions,

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energy regulation and strategy development. From 2006 to 2017, Ms. Lindberg served as General Counsel and Corporate Secretary for Eni US Operating Co. Inc., which is part of Eni Spa, a major integrated energy company based in Italy. Before Eni, Ms. Lindberg was Assistant General Counsel at Duke Energy Corp. Previously, she was with Enron Corp., where she joined the company as Senior Counsel for Enron Transportation Services and later became a director of government affairs. Ms. Lindberg began her career as an associate in the energy section of law firm Akin, Gump, Strauss, Hauer & Feld, LLP after earning her Juris Doctorate from the University of Texas School of Law.

David M. Minielly. Mr. Minielly has served as Executive Vice President - US Operations since January 2019. Mr. Minielly joined SemGroup in 2007, serving as Vice President - Crude from 2016 to 2019, Vice President Operations for the Company’s crude business from 2010 to 2016, and Operations Manager for White Cliffs from 2007 to 2010. He also served as Vice President of Rose Rock from August 2016 until September 2016, when SemGroup acquired all of Rose Rock. Prior to joining SemGroup, Mr. Minielly held operational and environmental, health, and safety positions in the energy sector. He has 25 years of experience in the energy industry. Mr. Minielly holds a Bachelor of Science degree from Texas Christian University and a Master of Science degree from Oklahoma State University.

Shaun M. Revere. Mr. Revere has served as Executive Vice President - US Commercial since January 2019. From 2012 to 2019, Mr. Revere served as Chief Executive Officer of HFOTCO. Prior to joining HFOTCO, he served as President of Mabanaft, Inc., a physical petroleum trading business, from 2007 to 2012. From 1999 to 2007, Mr. Revere served in various commercial roles for Oiltanking Houston, a liquid terminal company, including Vice President - Marketing. Mr. Revere began his career in the energy sector in 1993 with GATX Terminals Corporation. He holds a Bachelor of Industrial Engineering degree from the Georgia Institute of Technology and a Master of Business Administration from Rice University.

David B. Gosse. Mr. Gosse has served as Executive Vice President - Canadian Operations and Commercial since January 2019. He joined SemGroup in 2011, serving as VP - Canadian Operations from 2011-2014. He has also served as Vice President and General Manager of SemCAMS ULC since 2014 and President of SemCAMS Midstream ULC since January 2019, both of which are subsidiaries of SemGroup. From 1993 to 2011, Mr. Gosse held senior operations and engineering positions in the Canadian energy and chemicals sector. He holds a bachelor’s degree in chemical engineering from Lakehead University and a Masters in Business Administration from Athabasca University.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our Class A Common Stock trades on the New York Stock Exchange under the ticker symbol “SEMG.” At January 31, 2019, we had 2,480 holders of record of our Class A Common Stock. The following table sets forth the high and low sales prices of our Class A Common Stock (New York Stock Exchange composite transactions) during the periods indicated.

	High		Low
For the year ended December 31, 2018:
First quarter	$	30.95	$	20.20
Second quarter	$	26.40	$	20.45
Third quarter	$	26.79	$	20.85
Fourth quarter	$	22.96	$	12.86
For the year ended December 31, 2017:
First quarter	$	43.05	$	32.48
Second quarter	$	36.65	$	22.55
Third quarter	$	29.05	$	22.60
Fourth quarter	$	30.60	$	21.35

Dividends

Our credit agreement allows payments or distributions as long as we are in compliance on a pro forma basis with our financial covenants. Subject to certain exceptions, so long as any Preferred Shares remain outstanding, no dividend or distribution will be declared or paid on, and no redemption or repurchase will be agreed to or consummated of, stock on a parity with the Preferred Shares, our common stock, unless all accumulated and unpaid dividends for all preceding full fiscal quarters (including the fiscal quarter in which such accumulated and unpaid dividends first arose) have been declared and paid (in cash or in kind).

The following table sets forth the dividend paid in the quarter indicated.

Year Ended December 31, 2018	$/Share
First quarter	$0.4725
Second quarter	$0.4725
Third quarter	$0.4725
Fourth quarter	$0.4725
Year Ended December 31, 2017	$/Share
First quarter	$0.45
Second quarter	$0.45
Third quarter	$0.45
Fourth quarter	$0.45

Performance Graph

Set forth below is a line graph comparing the cumulative total stockholder return on our Class A Common Stock with the cumulative total return of the S&P 500 Stock Index and the Alerian MLP Infrastructure Index ("AMZIX Index") for the period from January 1, 2014 to December 31, 2018. The AMZIX Index is a liquid, midstream-focused subset of the Alerian MLP index, comprised of 25 energy infrastructure master limited partnerships. The graph was prepared assuming $100 was invested on December 31, 2013 in our Class A Common Stock, the S&P 500 Stock Index and the AMZIX Index and dividends/distributions have been reinvested subsequent to the initial investment.

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COMPARISON OF CUMULATIVE TOTAL RETURN

Among SemGroup Corporation, the S&P 500 Index

and the Alerian MLP Infrastructure Index

The above performance graph and related information shall not be deemed “soliciting material” or be deemed to be “filed” with the SEC, nor shall such information be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.

Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases of our common stock by us during the quarter ended December 31, 2018:

	Total Number of Shares Purchased (1)	Weighted Average Price Paid per Share (2)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
October 1, 2018 - October 31, 2018	344	$	22.00	—	—
November 1, 2018 - November 30, 2018	626	19.32		—	—
December 1, 2018 - December 31, 2018	—	—		—	—
Total	970	$	22.27	—	—

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

Item 6. Selected Financial Data

Selected Consolidated Financial Data

The following table provides selected consolidated financial data as of and for the periods shown. The balance sheet data as of December 31, 2018, 2017, 2016, 2015 and 2014, and the statement of operations data for the years ended December 31, 2018, 2017, 2016, 2015 and 2014, have been derived from our audited financial statements for those dates and periods. The selected financial data provided below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included in this Form 10-K.

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The following table presents the non-GAAP financial measure Adjusted EBITDA, which we use in our business and view as an important supplemental measure of our performance. Adjusted EBITDA is not calculated or presented in accordance with GAAP. For the definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP, please see "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate our Operations."

	Year Ended December 31,
	2018			2017			2016			2015			2014
	(amounts in thousands, except per share amounts)
	Under ASC 606			Under ASC 605
Statement of operations data:
Total revenues	$	2,503,262		$	2,081,917		$	1,332,164		$	1,455,094		$	2,122,579
Operating income	$	155,811		$	94,060		$	121,315		$	129,153		$	126,993
Income (loss) from continuing operations	$	(24,328	)	$	(17,150	)	$	13,263		$	42,816		$	52,058
Income (loss) from discontinued operations	—			—			(1		)	(4		)	(1		)
Net income (loss)	$	(24,328	)	$	(17,150	)	$	13,262		$	42,812		$	52,057
Net income attributable to noncontrolling interests	2,421			—			11,167			12,492			22,817
Net income (loss) attributable to SemGroup	$	(26,749	)	$	(17,150	)	$	2,095		$	30,320		$	29,240
Income (loss) from continuing operations per share of common stock:
Basic	$	(0.65	)	$	(0.24	)	$	0.04		$	0.69		$	0.69
Diluted	$	(0.65	)	$	(0.24	)	$	0.04		$	0.69		$	0.68
Other financial data:
Adjusted EBITDA	$	394,184		$	328,303		$	282,795		$	305,282		$	287,441
Cash dividend paid per common share	$	1.89		$	1.80		$	1.80		$	1.59		$	1.03

	As of December 31,
	2018		2017		2016		2015		2014
	(amounts in thousands)
	Under ASC 606		Under ASC 605
Balance sheet data:
Total assets	$	5,210,307	$	5,376,817	$	3,074,972	$	2,853,909	$	2,576,388
Long-term debt, including current portion	$	2,284,834	$	2,858,620	$	1,050,944	$	1,057,847	$	753,718
Redeemable preferred stock	$	359,658	—		—		—		—
Owners’ equity:
SemGroup Corporation owners’ equity	$	1,490,832	$	1,658,365	$	1,445,965	$	1,115,527	$	1,149,508
Noncontrolling interests in consolidated subsidiaries	349,489		—		—		80,829		69,929
Total owners’ equity	$	1,840,321	$	1,658,365	$	1,445,965	$	1,196,356	$	1,219,437

We have 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, various impairments of long-lived assets, gains/losses on disposal of long-lived assets, acquisitions and debt issuances. Further, we adopted Accounting Standards Codification 606 - Revenue from Contracts with Customers (“ASC 606”) on January 1, 2018, using a modified retrospective approach. As such, prior periods are presented under the revenue guidance of ASC 605 - Revenue ("ASC 605") and lack comparability with amounts reported for the current year.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We, and our significant equity method investee, own gathering systems, transportation pipelines, crude oil transport trucks, processing plants, storage facilities and terminals in Colorado, Kansas, Louisiana, Minnesota, Montana, North Dakota, Oklahoma, Texas and Wyoming and in Alberta, Canada.

General Trends and Outlook

The prices of crude oil and natural gas have historically been volatile. For example, from January 1, 2014 to December 31, 2018, the NYMEX prompt month settle price ranged from a high of $107.26 per barrel to a low of $26.21 per barrel. The range for natural gas during that period was $6.15 to $1.64 per MMBtu. Substantial declines in crude oil and natural gas prices, particularly prolonged declines, can have negative effects on producers including:

•reduced revenue, operating income and cash flows;

•reduced volume of crude oil and natural gas that can be produced economically;

•delayed or postponed capital projects; and/or

•limited access to or increased cost of capital, such as equity and long-term debt.

The substantial declines in crude oil and natural gas prices since mid-2014 and continuing throughout 2018 have had these effects on a number of companies in the oil and gas industry, including our customers. While we do not have significant direct exposure to commodity prices, we are exposed to a reduction in volumes to be transported, stored, gathered, processed and marketed as a result of lower prices. Additionally, changes to price differentials between basins also impact our crude oil marketing operations. We were impacted by these factors in 2018 and expect them to continue in 2019.

We continue to execute on our de-leveraging strategy. We have pre-funded capital growth projects and reduced debt leverage through the issuance of subsidiary preferred equity representing a 49% interest in Maurepas Pipeline for $350 million in November of 2018 and our 2019 contribution of our Canadian business to a joint venture with KKR which returned $484 million of cash to SemGroup. We own a 51% interest in the joint venture which subsequently acquired Meritage Midstream ULC and its midstream infrastructure assets for approximately $490 million. The transaction closed on February 25, 2019.

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include financial measures such as operating expenses, Segment Profit and Adjusted EBITDA and operating data including contracted storage capacity and sales, transportation and processing volumes.

Operating Expenses

Our management seeks to maximize the profitability of our operations, in part, by minimizing operating expenses. These expenses are comprised of salary and wage expense, utility costs, insurance premiums, taxes and other operating costs, some of which are independent of the volumes we handle.

Segment Profit

Our management analyzes the performance of our operating segments through our segment profit measure which is defined as revenue, less cost of products sold (exclusive of depreciation and amortization) and operating expenses, plus equity earnings and is adjusted to remove unrealized gains and losses on commodity derivatives and to reflect equity earnings on an EBITDA basis. Reflecting equity earnings on an EBITDA basis is achieved by adjusting equity earnings to exclude our percentage of interest, taxes, depreciation and amortization from equity earnings for operated equity method investees. For our investment in NGL Energy, we exclude equity earnings and include cash distributions received.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) before interest expense, income tax expense (benefit), depreciation and amortization and adjusted for selected items that we believe impact the comparability of financial results between reporting periods. In addition to non-cash items, we have selected items for adjustment to EBITDA which management feels decrease the comparability of our results among periods. These items are identified as those which are generally outside of the results of day-to-day operations of the business. These items are not considered non-recurring, infrequent or unusual, but do erode comparability among periods in which they occur with periods in which they do not occur or occur to a greater or lesser degree.

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Historically, we have selected items such as gains on the sale of NGL Energy common units, costs related to our predecessor’s bankruptcy, significant business development related costs, significant legal settlements, severance and other similar costs. Management believes these types of items can make comparability of the results of day to day operations among periods difficult and have chosen to remove these items from our Adjusted EBITDA. We expect to adjust for similar types of items in the future. Although we present selected items that we consider in evaluating our performance, you should be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, mechanical interruptions and numerous other factors. We do not adjust for these types of variances.

We use Adjusted EBITDA as a supplemental performance measure to assess:

• our operating performance as compared to that of other companies in our industry, without regard to financing methods, historical cost basis, capital structure or the impact of fluctuating commodity prices; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

Note About Non-GAAP Financial Measures

Adjusted EBITDA is not a financial measure presented in accordance with GAAP. We believe that the presentation of this non-GAAP financial measure will provide useful information to investors in assessing our financial condition and results of operations.

Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA. Our non-GAAP financial measure should not be considered as an alternative to the most directly comparable GAAP financial measure. This non-GAAP financial measure has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measure. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of this non-GAAP financial measure may not be comparable to similarly titled measures of other companies, thereby diminishing the utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measure, understanding the difference between Adjusted EBITDA and net income (loss) and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.

The following table presents a reconciliation of net income to Adjusted EBITDA, the most directly comparable GAAP financial measure, on a historical basis for each of the periods indicated.

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	Year Ended December 31,
	2018			2017			2016		2015			2014
	(Unaudited; in thousands)
	Under ASC 606			Under ASC 605
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	(24,328	)	$	(17,150	)	$	13,262	$	42,812		$	52,057
Add:
Interest expense	149,714			103,009			62,650		69,675			49,044
Income tax expense (benefit)	23,304			(2,388		)	11,268		33,530			46,513
Depreciation and amortization	209,254			158,421			98,804		100,882			98,397
Loss (gain) on disposal or impairment, net	(3,563		)	13,333			$	16,048	$	11,472		32,592
Loss from discontinued operations	—			—			1		4			1
Foreign currency transaction (gain) loss	9,501			(4,709		)	4,759		(1,067		)	(86		)
Adjustments to reflect equity earnings on an EBITDA basis	19,532			26,890			28,757		32,965			11,033
Remove loss (gain) on sale or impairment of NGL units	—			—			30,644		(14,517		)	(34,211		)
M&A transaction related costs	3,152			21,988			3,269		10,000			—
Inventory valuation adjustment including equity method investees	—			—			—		3,187			7,781
Pension curtailment gain	—			(3,008		)	—		—			—
Employee severance and relocation expense	1,149			1,694			2,128		90			220
Unrealized loss (gain) on commodity derivatives	(5,053		)	40			989		2,014			(1,734		)
Change in fair value of warrants	—			—			—		—			13,423
Bankruptcy related expenses	—			—			—		224			1,310
Charitable contributions	—			—			—		—			3,379
Legal settlement expense	—			—			—		3,394			—
Recovery of receivables written off at emergence	—			—			—		—			(664		)
Non-cash equity compensation	11,522			10,253			10,216		10,617			8,386
Loss on early extinguishment of debt	—			19,930			—					—
Adjusted EBITDA	$	394,184		$	328,303		$	282,795	$	305,282		$	287,441

Business and Performance Drivers

We operate our core businesses through three business segments: U.S. Liquids, U.S. Gas and Canada. We generate revenue in these segments by using our assets to provide products and services to third parties and by selectively using our assets to support our marketing activities.

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.

Revenue

Our revenue is generated through the gathering, transportation, processing and storage of petroleum products. Our customers pay us fees based on volumes gathered, transported, processed and stored. We also generate revenue by marketing petroleum products.

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We may use 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 using one of the following methods:

• we have already sold that product for physical delivery pursuant to sales contracts at a market index price,

• we sell the product for future physical delivery pursuant to effectively back-to-back sales contracts, or

• we enter into futures and swaps contracts on the NYMEX or over the counter markets.

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 various 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 areas near our asset base.

Commodity Prices

Our business is primarily fee based. As a result, our financial results are typically not directly 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, flat or backwardated (when the prices for future deliveries are lower than current prices) market. While we do not have significant direct exposure to commodity prices, we are exposed to reductions in volumes transported, stored, gathered, processed and marketed as a result of lower prices. Additionally, changes to price differentials between basins also impact our crude oil marketing operations.

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 sizable differences between our results over the comparable period.

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Results of Operations

Consolidated Results of Operations

	Year Ended December 31,
(in thousands)	2018			2017			2016
Revenues	$	2,503,262		$	2,081,917		$	1,332,164
Expenses:
Costs of products sold	1,823,095			1,514,891			873,431
Operating	284,769			254,764			212,099
General and administrative	91,568			113,779			84,183
Depreciation and amortization	209,254			158,421			98,804
Loss (gain) on disposal or impairment, net	(3,563		)	13,333			16,048
Total expenses	2,405,123			2,055,188			1,284,565
Earnings from equity method investments	57,672			67,331			73,757
Gain (loss) on issuance of common units by equity method investee	—			—			(41		)
Operating income	155,811			94,060			121,315
Other expense (income):
Interest expense	149,714			103,009			62,650
Loss on early extinguishment of debt	—			19,930			—
Foreign currency transaction loss (gain)	9,501			(4,709		)	4,759
Loss on sale or impairment of non-operated equity method investment	—			—			30,644
Other income, net	(2,380		)	(4,632		)	(1,269		)
Total other expenses	156,835			113,598			96,784
Income (loss) from continuing operations before income taxes	(1,024		)	(19,538		)	24,531
Income tax expense (benefit)	23,304			(2,388		)	11,268
Income (loss) from continuing operations	(24,328		)	(17,150		)	13,263
Loss from discontinued operations, net of income taxes	—			—			(1		)
Net income (loss)	(24,328		)	(17,150		)	13,262
Less: net income attributable to noncontrolling interest	2,421			—			11,167
Net income (loss) attributable to SemGroup	$	(26,749	)	$	(17,150	)	$	2,095

Revenue, costs of products sold and operating expenses

Revenue, costs of products sold and operating expenses are analyzed by operating segment below.

General and administrative expenses

General and administrative expenses decreased in 2018 to $91.6 million from $113.8 million in 2017. The decrease is primarily due to a reduction in acquisition related costs, the disposition of our U.K. and Mexican businesses in early 2018 and full year of expense related to our HFOTCO acquisition, which was acquired in July of 2017. Current year acquisition related costs are $2.7 million compared with $22.0 million in the prior year, primarily due to the HFOTCO acquisition. Our U.K. and Mexican businesses incurred a combined $4.1 million of general and administrative expense in the current year prior to their disposals compared with a combined $16.0 million in the prior year. The decreases in general and administrative expense were offset by an increase of $7.8 million from the prior year for the HFOTCO business as a result of a full year of operations in 2018.

General and administrative expenses increased in 2017 to $113.8 million from $84.2 million in 2016 primarily due to $26 million of HFOTCO related costs, of which $22 million were acquisition related costs. General and administrative costs for Canada increased by $3 million compared to prior year primarily due to employment costs, office costs and an increase in foreign exchange rates between periods.

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Depreciation and amortization

Depreciation and amortization costs increased in 2018 to $209.3 million from $158.4 million in 2017, primarily due to a full year of depreciation and amortization from the HFOTCO acquisition and the Maurepas Pipeline which was placed in service in 2017 and other projects placed in-service during the period, partially offset by the disposition of our U.K. and Mexican businesses. The increase due to HFOTCO was $38.0 million, the increase due to the Maurepas Pipeline was $14.9 million and the decrease due to the U.K. and Mexican business dispositions was $11.7 million.

Depreciation and amortization costs increased in 2017 to $158.4 million from $98.8 million in 2016, of which $44 million related to the HFOTCO assets including finite-lived intangible assets acquired in July 2017. The Maurepas Pipeline which was placed in service in 2017 accounted for $11 million of the increase. The remaining increase relates to smaller projects placed in-service during the period.

Loss (gain) on disposal or impairment, net

In 2018 we had a net gain on disposal or impairment of $3.6 million. The net gain was primarily a result of small gains due to the finalization of the sales of our U.K. and Mexican businesses and a post-closing adjustment of $1.4 million related to the disposal of Glass Mountain in 2017.

Loss on disposal or impairment, net in 2017 was $13.3 million. The net loss on disposal or impairment in 2017 was due to the following (in thousands):

	Segment	Loss/(Gain)
Write-down Mexican asphalt business to net realizable value	Corporate and Other	$	13,511
Write-down U.K. operations to net realizable value	Corporate and Other	76,661
Sherman natural gas gathering and processing asset impairment	U.S. Gas	30,985
Crude oil trucking goodwill impairment	U.S. Liquids	26,628
Crude oil trucking intangible asset impairment	U.S. Liquids	12,087
Gain on sale of Glass Mountain	U.S. Liquids	(150,266		)
Other		3,727
Loss on disposal or impairment, net		$	13,333

The write-downs of the Mexican asphalt business and the U.K. operations to net realizable value was due to the businesses being categorized as held-for-sale at December 31, 2017.

The impairment of our Sherman, Texas natural gas gathering and processing assets was due to the evaluation of capital raising alternatives which indicated that the carrying value of our Sherman, Texas assets might be in excess of fair value. We used an income approach, based on a discounted cash flow model, to estimate the fair value of the assets, which resulted in a non-cash impairment.

The impairment of the goodwill and intangible assets of our crude oil trucking business was due to a reduction in the long range forecast for crude oil trucking due to the on-going challenging business environment. We viewed the decrease in the forecast as a triggering event that indicated a potential impairment and performed an interim impairment analysis on the business unit’s assets including goodwill and intangible assets.

We performed a recoverability test of our definite lived assets under ASC 360 whereby we compared the undiscounted cash flows of the asset group, which was determined to be the entire crude oil trucking reporting unit and included goodwill, to the carrying value of the assets at September 30, 2017. This test indicated that the assets were not fully recoverable. Therefore, we estimated the fair value of the definite lived assets using an income approach, supplemented by a market approach to measure impairment. We also performed an interim impairment test of our goodwill associated with the crude oil trucking reporting unit and determined the estimated fair value was less than the adjusted carrying value of the reporting unit resulting in impairment of goodwill. The cash flow models used to determine recoverability of our assets and to measure impairment expense involved using significant judgments and assumptions, which included the discount rate, anticipated revenue and volume growth rates, estimated operating expenses and capital expenditures, which were based on our operating and capital budgets as well as our strategic plans. We considered the market approach by comparing the revenue and earnings multiples implied by our income approach to those of comparable companies for reasonableness and for estimating the fair value of certain assets of our reporting unit.

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The gain on the sale of Glass Mountain is due to the December 22, 2017 sale of our ownership interest in Glass Mountain for $300 million, subject to working capital and other adjustments.

Loss on disposal or impairment, net in 2016 was primarily due to a $13.1 million impairment of U.S. Gas goodwill as a result of producer forecast reductions following the release of the Oklahoma Corporation Commission's Regional Earthquake Response Plan which curtailed the amount of volume that can be injected into disposal wells.

Interest expense

Interest expense increased in 2018 to $149.7 million from $103.0 million in 2017. The increase is primarily the result of a net increase of $15.2 million related to the $300 million, 7.25% senior unsecured notes sold in September 2017, the $325 million, 6.375% senior unsecured notes sold in March 2017, and the early payoff of $300 million, 7.50% senior unsecured notes sold in March 2017. There was a $22.1 million increase in HFOTCO bank interest due to a full year of interest in 2018 compared to only six months interest in 2017. These net increases were offset by a net decrease in capitalized interest of $5.8 million due to fewer U.S. projects in 2018 and the initial on-line operations of the Maurepas Pipeline, offset slightly by increased projects in Canada.

Interest increased in 2017 to $103.0 million from $62.7 million in 2016. The increase is primarily the result of $28.4 million related to HFOTCO debt subsequent to acquisition including accretion of the final payment, $22.8 million attributable to the new $325 million, 6.375% senior unsecured notes sold in March 2017 and the $300 million, 7.25% senior unsecured notes sold in September 2017 and $8.6 million due to increased borrowings on SemGroup's revolving credit facility. These increases were offset by a $17.8 million decrease in interest expense due to the early payoff of $300 million, 7.50% senior unsecured notes in March 2017.

Loss on early extinguishment of debt

During the year ended December 31, 2017, we purchased $290 million of our outstanding $300 million senior unsecured notes due 2021 (the “2021 Notes”) through a tender offer. The price included a premium and interest to the purchase date. A notice of redemption was issued for the remaining $10 million of 2021 Notes, which were not redeemed through the tender offer pursuant to the redemption and satisfaction and discharge provisions of the indenture governing the 2021 Notes. The redemption price includes a redemption premium and interest to the redemption date. As a result, we recognized a loss of $19.9 million on the early extinguishment of the 2021 Notes, which included premiums of $15.9 million and the write off of $3.6 million of associated unamortized debt issuance costs.

Foreign currency transaction loss (gain)

Foreign currency transaction changed to a loss of $9.5 million in 2018 from a gain of $4.7 million in 2017. The change is primarily due to realized and unrealized losses of $10.2 million on foreign currency forwards for purchases of Canadian dollars to limit exposure to foreign currency rate fluctuations for capital contributions to our Canadian operations compared with $2.8 million of realized and unrealized gains in the prior year. The remaining change is primarily due to foreign currency changes related to U.S. dollar denominated payables of our U.K. business which was sold in early 2018.

Foreign currency transaction changed to a gain of $4.7 million in 2017 from a loss of $4.8 million in 2016. The change is primarily due to changes in the foreign currency rates and amounts of U.S. dollar denominated payables of our U.K. business compared to the prior year and $2.8 million of realized and unrealized gains on foreign currency forwards entered into in the fourth quarter of 2017. The forwards are for purchases of Canadian dollars to limit exposure to foreign currency rate fluctuations for capital contributions to our Canadian operations.

Loss on sale or impairment of non-operated equity method investment

In 2016, we incurred a $30.6 million loss due to a $39.8 million other-than-temporary impairment recorded on our NGL Energy common units, partially offset by a $9.1 million gain on the sale of remaining NGL Energy common units in 2016.

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Results of Operations by Reporting Segment

U.S. Liquids

	Year Ended December 31,
(in thousands)	2018		2017			2016
Revenues
Product sales	$	1,680,327	$	1,299,343		$	716,570
Pipeline transportation	84,878		43,642			23,099
Truck transportation	23,553		31,352			41,754
Storage fees	161,498		85,712			27,673
Facility service fees	49,896		27,657			18,283
Lease revenue	17,549		5,843			—
Total revenue	2,017,701		1,493,549			827,379
Less:
Costs of products sold	1,646,244		1,259,349			652,383
Operating expense	134,185		99,253			82,817
Unrealized gain (loss) on commodity derivatives, net	5,053		(40		)	(989		)
Plus:
Earnings from equity method investments	57,625		67,345			71,569
Adjustments to reflect equity earnings on an EBITDA basis	19,579		26,876			26,031
Segment profit	$	309,423	$	229,208		$	190,768

	Year Ended December 31,
(in thousands)	2018			2017			2016
Gross product sales	$	5,357,101		$	4,616,804		$	3,118,759
Nonmonetary transaction adjustment	(3,681,827		)	(3,317,421		)	(2,401,200		)
Unrealized gain (loss) on commodity derivatives, net	5,053			(40		)	(989		)
Product sales	$	1,680,327		$	1,299,343		$	716,570

2018 versus 2017

Revenues

Product sales increased in 2018 to $1.7 billion from $1.3 billion in 2017.

Gross product revenue increased in 2018 to $5.4 billion from $4.6 billion in 2017. The increase was primarily due to an increase in the average sales price to $65 per barrel in 2018, from an average sales price of $50 per barrel in 2017, partially offset by a decrease in the volume sold to 83 million barrels in 2018 from 92 million barrels in 2017. Volumes decreased as compared to prior year due to fewer location trades.

Gross product revenue was reduced by $3.7 billion and $3.3 billion during 2018 and 2017, respectively, in accordance with Accounting Standards Codification (ASC) 845-10-15, "Nonmonetary Transactions," ("ASC 845-10-15"). ASC 845-10-15 requires that certain transactions -- those where inventory is purchased from a customer then resold to the same customer -- to be presented in the income statement on a net basis, resulting in a reduction of revenue and costs of products sold by the same amount.

Pipeline transportation revenue increased to $84.9 million in 2018 from $43.6 million in 2017, primarily due to an increase of $37.9 million, as a result of a full year of operations on the Maurepas Pipeline, and a $3.5 million increase on the WOT due to higher transportation volumes.

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Truck transportation revenue decreased to $23.6 million in 2018 from $31.4 million in 2017, due to lower transportation volumes.

Storage revenue increased to $161.5 million in 2018 from $85.7 million in 2017. The increase was primarily due to an increase of $78.1 million reflecting a full year of HFOTCO operations, partially offset by a $2.3 million decrease in crude storage compared to prior year, as the average capacity leased by storage customers decreased to 5.9 million barrels from 6.3 million barrels.

Facility service fees increased to $49.9 million in 2018 from $27.7 million in 2017. The increase was primarily due to an increase of $26.2 million reflecting a full year of HFOTCO operations, partially offset by a $4.6 million decrease at Platteville as a result of lower truck unloading volumes.

Lease revenue increased to $17.5 million in 2018 from $5.8 million in 2017. The increase was primarily due to a full year of HFOTCO operations.

Cost of Products Sold

Costs of products sold increased in 2018 to $1.7 billion from $1.3 billion in 2017. The cost of products sold reflect reductions of $3.7 billion and $3.3 billion in 2018 and 2017, respectively, in accordance with ASC 845-10-15. There was a decrease in the barrels sold, as described above, combined with an increase in the average per barrel cost of crude oil to $65 in 2018 from $50 in 2017.

Operating Expense

Operating expense increased in 2018 to $134.2 million from $99.3 million in 2017 due to a $35.9 million increase at HFOTCO reflecting a full year of operations, as well as other increases in insurance and taxes and maintenance and repair expense, partially offset by a decrease in outside services.

Unrealized Gain (Loss) on Commodity Derivatives, net

Unrealized gain (loss) on commodity derivatives, net increased in 2018 to a gain of $5.1 million from a loss of $40.0 thousand in 2017. The gain is due to open positions and changes in market prices in the current year.

Earnings from Equity Method Investments

Earnings from equity method investments decreased in 2018 to $57.6 million from $67.3 million in 2017. The decrease is primarily due to the sale of Glass Mountain and decreased earnings by White Cliffs of $7.5 million and $2.2 million, respectively.

2017 versus 2016

Revenue

Product sales increased in 2017 to $1.3 billion from $716.6 million in 2016.

Gross product revenue increased in 2017 to $4.6 billion from $3.1 billion in 2016. The increase was primarily due to an increase in the volume sold to 92 million barrels at an average sales price of $50 per barrel in 2017, from the volume sold of 75 million barrels at an average sales price of $42 per barrel in 2016. Volumes increased as compared to prior year due to additional location trades.

Gross product revenue was reduced by $3.3 billion and $2.4 billion during 2017 and 2016, respectively, in accordance with ASC 845-10-15.

Pipeline transportation revenue increased to $43.6 million in 2017 from $23.1 million in 2016. The increase was primarily the result of $20.8 million related to the start-up of the Maurepas Pipeline and a $3.7 million increase on the WOT. These increases were partially offset by a $3.6 million reduction related to the Tampa Pipeline, that was sold in the first quarter of 2017.

Truck transportation revenue decreased to $31.4 million in 2017 from $41.8 million in 2016, primarily as a result of slightly lower volumes and rates.

Storage fee revenue increased in 2017 to $85.7 million from $27.7 million in 2016. The increase was primarily due to the 2017 acquisition of HFOTCO resulting in $60.5 million of revenue, offset by a reduction in crude oil storage revenue of

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$2.2 million, mainly resulting from scheduled tank cleanings, as the average capacity leased by storage customers decreased to 6.2 million barrels from 6.6 million barrels. The remainder is due to decreases in pump-over revenue of $0.7 million, third-party unloading revenue of $0.3 million and other revenue of $0.2 million.

Facility service fees increased to $27.7 million in 2017 from $18.3 million in 2016. The increase was primarily due to an increase of $10.6 million reflecting the 2017 acquisition of HFOTCO, partially offset by a $1.2 million decrease at Platteville as a result of lower truck unloading volumes.

Costs of Products Sold

Costs of products sold increased in 2017 to $1.3 billion from $652.4 million in 2016. The cost of products sold reflects reductions of $3.3 billion and $2.4 billion in 2017 and 2016, respectively, in accordance with ASC 845-10-15. There was an increase in the barrels sold, as described above, combined with an increase in the average per barrel cost of crude oil to $50 in 2017 from $41 in 2016.

The increase in cost of products sold outpaced the increase in revenue leading to a decrease in segment profit of $31.8 million as compared to the prior year. This is primarily due to lower blending margins of $8.2 million due to increased competition at Cushing, lower contango margins of $5.8 million, increased pipeline transportation fees of $8.2 million related to firm commitments beginning in June 2017 and increased truck transportation fees of $7.3 million related to increased volume.

Operating Expense

Operating expense increased in 2017 to $99.3 million from $82.8 million in 2016 due to a $15.3 million increase as a result of the acquisition of HFOTCO during 2017.

U.S. Gas

	Year Ended December 31,
(in thousands)	2018		2017		2016
Revenues
Product sales	$	210,827	$	180,581	$	167,319
Service fees	54,494		52,637		51,651
Total revenue	265,321		233,218		218,970
Less:
Cost of products sold	165,508		135,689		120,516
Operating expense	32,743		29,724		31,924
Segment profit	$	67,070	$	67,805	$	66,530

2018 versus 2017

Revenues

Revenues increased in 2018 to $265.3 million from $233.2 million in 2017. The increase is primarily due to higher volumes (134,135 MMcf in 2018 compared to 101,709 MMcf for 2017) and higher average NGL basket price of $0.86/gallon in 2018 versus $0.85/gallon in 2017. The increase was partially offset by lower average natural gas NYMEX price of $3.09/MMbtu in 2018 versus $3.11/MMbtu in 2017. Volume increases are primarily due to Stack production, offset by reduced Mississippi Lime drilling, coupled with natural well production declines.

Gathering and processing fee revenue increased in 2018 to $54.5 million from $52.6 million in 2017. In the current year, certain fees are reported as gathering and processing fee revenue under ASU 2016-15 - “Revenue from Contracts with Customers” (“ASC 606”), whereas in the prior year these amounts were reported as reductions to cost of sales under ASC 605. The current year includes $15.0 million of fee revenue which would have been included as a reduction to cost of sales under the prior year methodology. Exclusive of the impact of ASC 606, fee revenue decreased by $13.1 million due lower product recovery fees and unfavorable contract mix, partially offset by higher volumes.

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Cost of Products Sold

Cost of products sold increased in 2018 to $165.5 million from $135.7 million in 2017. The increase was primarily due to higher NGL prices, the impact of ASC 606 discussed above, offset by lower Mississippi Lime volumes and lower natural gas prices.

Operating Expense

Operating expense increased slightly in 2018 to $32.7 million from $29.7 million in 2017. This increase was primarily due to compression overhauls, turbine maintenance, and employee costs.

2017 versus 2016

Revenue

Revenue increased in 2017 to $233.2 million from $219.0 million in 2016. The increase was primarily due to a higher average natural gas NYMEX price of $3.108/MMbtu in 2017 versus $2.46/MMbtu in 2016, a higher average NGL basket price of $0.85/gallon in 2017 versus $0.65/gallon in 2016, and increased fees of $53 million in 2017 versus $52 million in 2016 due to higher rates. The increase was offset, in part, by lower volume (101,709 million cubic feet in 2017 versus 116,748 million cubic feet in 2016).

Costs of Products Sold

Costs of products sold increased in 2017 to $135.7 million from $120.5 million in 2016. The increase was attributable to higher prices and was offset, in part, by lower volume processed in northern Oklahoma.

Operating Expense

Operating expense decreased in 2017 to $29.7 million from $31.9 million in 2016. This decrease was due to lower equipment lease, field expense (which includes materials and supplies, lubricants, water disposal, electricity and fuel), maintenance/repair, and office expense. All decreases are primarily driven by lower volume in northern Oklahoma. These decreases were offset by increases in employment, outside services, taxes, and other expenses.

Canada

	Year Ended December 31,
(in thousands)	2018		2017		2016
Revenues
Service fees	$	134,059	$	120,575	$	75,715
Other revenues	59,075		62,657		57,501
Total revenue	193,134		183,232		133,216
Less:
Cost of products sold	347		113		122
Operating expense	111,457		106,845		79,830
Segment profit	$	81,330	$	76,274	$	53,264

2018 versus 2017

Revenue

Revenue increased in 2018 to $193.1 million from $183.2 million in 2017. This increase is primarily due to higher operating costs recoveries of $5.2 million, changes in foreign currency exchange rates between periods of $1.7 million and higher gathering and processing revenue of $1.3 million. These increases were offset, in part, by true-ups of take-or-pay minimum volumes commitments of $3.6 million. Further, a 31-day planned outage at the KA plant in 2018 decreased gathering and processing revenue by $2.2 million. This was offset by the 2017 planned outage at the K3 plant which decreased gathering and processing revenue by $2.5 million.

Additionally, subsequent to the adoption of ASC 606, we recognized $4.5 million of revenue, to recognize certain deficiencies on take-or-pay agreements for which there is a contractual make-up period. Under ASC 605, revenue related to

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deficiencies with a make-up period was deferred until the contractual right to make up a deficiency expired. Under ASC 606, we can recognize all or a portion of revenue related to deficiencies before the make-up period expires if we determine that it is probable that the customer will not make-up all or some of its deficient volumes, for example if there is insufficient capacity to make up the deficient volumes in future periods.

Operating Expense

Operating expense increased in 2018 to $111.5 million from $106.8 million in 2017. This increase is primarily due to turnaround costs related to the KA plant of $25.6 million, higher power costs of $5.0 million, and changes in foreign currency exchange rates between periods of $1.4 million. These increases were offset, in part, by turnaround costs in 2017 for the K3 plant of $27.2 million.

2017 versus 2016

Revenue

Revenue increased in 2017 to $183.2 million from $133.2 million in 2016. This increase was primarily due to higher operating cost recoveries of $27.6 million (primarily attributable to the K3 plant turnaround), higher gathering and processing revenue of $4.7 million, non-recurring 2016 fee concessions of $4.6 million, true-up of take-or-pay minimum volumes commitments of $4.4 million and changes in foreign currency exchange rates between periods of $3.1 million.

Operating Expense

Operating expense increased in 2017 to $106.8 million from $79.8 million in 2016. This increase was primarily due to turnaround costs related to the K3 plant, offset by lower contractor costs of $4.1 million.

Corporate and Other

	Year Ended December 31,
(in thousands)	2018			2017			2016
Revenues	$	27,106		$	171,918		$	152,599
Less:
Costs of products sold	10,996			119,740			100,410
Operating expense	6,384			18,942			17,528
Plus:
Earnings from equity method investments	47			(14		)	2,147
Adjustments to reflect NGL Energy equity earnings on a cash basis	(47		)	14			2,726
Segment profit	$	9,726		$	33,236		$	39,534

Corporate and Other is not an operating segment. This table is included to permit the reconciliation of segment information to that of the consolidated Company. The amounts reported for the year ended December 31, 2016 above have been recast to include our former U.K. and Mexico segments which, subsequent to our acquisition of HFOTCO, were no longer expected to be significant for separate presentation. The main activities of our U.K. operations were the receipt, storage and redelivery of clean petroleum and crude oil products via sea-going vessels. Our U.K. revenue was based on fixed-fee storage tank leases and related services. Revenue from our Mexico operations was based on contractual arrangements with customers for liquid asphalt cement. Our U.K. operations and Mexico operations were sold in 2018. Earnings from equity method investments in the table above relates to our investments in NGL Energy.

2018 versus 2017

The decreases in revenues, cost of products sold and operating expenses are due to the disposal of our U.K. operations and Mexican asphalt business in early 2018 compared with a full year of operations for both entities in the prior year.

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2017 versus 2016

Revenues

The increase in revenue relates primarily to higher revenues in our Mexico operations ($155 million in 2017 compared to $139 million in 2016), mostly due to higher product sales prices, partially offset by slightly lower volume and foreign exchange impacts between periods. Revenue in our U.K. operations increased to $28 million in 2017 compared to $25 million in 2016, primarily as a result of increased storage volume thereby creating increased throughput revenue and storage volume and price variances. The remaining change was primarily due to an increase in the intersegment eliminations which are reported in Corporate and Other. Intersegment revenues relate to product sales from our U.S. Gas segment to our U.S. Liquids segment.

Costs of products sold

The increase in costs of products sold relates primarily to higher costs in Mexico ($131 million in 2017 compared to $111 million in 2016), as a result of higher unit costs in Mexico, partially offset by lower volume.

Earnings from Equity Method Investments

The decrease in earnings from equity method investments is due to the sale of our limited partner interest in NGL Energy in April of 2016.

Liquidity and Capital Resources

Sources and Uses of Cash

Our principal sources of short-term liquidity are cash generated from our operations and borrowings under our revolving credit facilities. The consolidated cash balance on December 31, 2018 was $86.7 million. Of this amount, $17.1 million was held in Canada and may be subject to tax if transferred to the U.S. Potential sources of long-term liquidity include issuances of debt securities and equity securities and the sale of assets. Our primary cash requirements currently are operating expenses, capital expenditures, debt payments and our quarterly dividends. In general, we expect to fund:

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

• expansion capital expenditures and any working capital deficits through cash on hand, borrowings under our credit facilities and the issuance of debt securities and equity securities;

• acquisitions through cash on hand, borrowings under our credit facilities, the issuance of debt securities and equity securities and proceeds from the divestiture of assets or interests in assets; and

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

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

We believe our cash from operations and our remaining borrowing capacity allow us to manage our day-to-day cash requirements, distribute our quarterly dividends and meet our capital expenditure commitments for the coming year.

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

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	Year Ended December 31,
(in thousands)	2018			2017			2016
Statement of cash flow data:
Cash flows provided by (used in):
Operating activities	$	269,704		$	140,476		$	169,974
Investing activities	(229,670		)	(439,801		)	(228,284		)
Financing activities	(45,004		)	315,256			75,909
Subtotal	(4,970		)	15,931			17,599
Effect of exchange rate on cash and cash equivalents	(2,074		)	3,552			(1,479		)
Change in cash and cash equivalents	(7,044		)	19,483			16,120
Cash and cash equivalents at beginning of period	93,699			74,216			58,096
Cash and cash equivalents at end of period	$	86,655		$	93,699		$	74,216

Operating Activities

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

	Year Ended December 31,
(in thousands)	2018			2017			2016
Net income (loss)	$	(24,328	)	$	(17,150	)	$	13,262
Non-cash expenses, net	248,219			190,649			178,678
Changes in operating assets and liabilities	45,813			(33,023		)	(21,966		)
Net cash flows provided by operating activities	$	269,704		$	140,476		$	169,974

2018 Compared to 2017

Adjustments to net income for non-cash expenses increased to $248.2 million in 2018 from $190.6 million in 2017. Significant changes from prior year include:

• $50.8 million increase in depreciation and amortization expense primarily due to the HFOTCO acquisition and completion of the Maurepas Pipeline;

• $18.1 million due to a deferred tax expense in the current year compared to deferred tax benefit in the prior year, primarily as a result of the change to the federal statutory income tax rate and other discrete tax items in 2017;

• $14.2 million due to current year currency losses as compared to prior year currency gains primarily due to foreign currency forwards for purchases of Canadian dollars to limit exposure to foreign currency rate fluctuations for capital contributions to our Canadian operations;

• $9.7 million reduction in earnings from equity method investments due to the sale of Glass Mountain Pipeline in December 2017, as well as rate reductions on White Cliffs Pipeline partially offset by higher volumes;

• $4.7 million increase in write-downs of inventory to net realizable value;

• $3.0 million due to a pension curtailment gain related to the HFOTCO pension which was curtailed subsequent to acquisition in the prior year;

• $1.4 million amortization of debt costs; and

• $1.3 million non-cash equity compensation.

These increases to the adjustments to net income for non-cash expenses, net were offset by decreases due to:

• a decrease of $19.9 million in loss on the early extinguishment of our 2021 Notes in the prior year;

• a decrease of $16.9 million in losses on disposal and impairments primarily due to small current year gains from the finalization of the sales of our U.K. and Mexican businesses and a post-closing adjustment related to our Glass Mountain disposal compared to prior year gain on disposal of Glass Mountain offset by impairments

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related to the held for sale status of our Mexican asphalt business and our U.K. operations and impairments to U.S. Gas and U.S. Liquids assets; and

• a $9.1 million decrease in distributions from equity method investees primarily due to the disposition of Glass Mountain in the prior year.

Changes in operating assets and liabilities during the year ended December 31, 2018 relative to the prior year-end consisted primarily of:

• a $52.2 million decrease in inventory due to a reduction in the number of barrels on hand and crude oil price declines compared to prior year end;

• a $79.3 million decrease in accounts receivable, including receivable from affiliates, generally due to timing of sales and changes in commodity prices and volumes;

• a $3.4 million increase in other current assets and a $1.6 million increase in other assets; and

• a $82.0 million decrease in accounts payable, including payable to affiliates, and accrued liabilities generally due to timing of purchases and changes in commodity prices and volumes.

2017 Compared to 2016

Non-cash expenses increased to $190.6 million in 2017 from $178.7 million in 2016. Significant changes from prior year include:

• a $59.6 million increase in depreciation and amortization expense primarily due to the HFOTCO acquisition;

• a $19.9 million loss on the early extinguishment of our 2021 Notes in the current year;

• a $6.4 million increase due to lower current year earnings from equity method investments as compared with the prior year primarily due to lower White Cliffs volumes and the prior year sale of our limited partner investment in NGL Energy;

These increases to non-cash adjustment to net income were offset by:

• $30.6 million decrease due to the prior year other-than-temporary impairment recorded on our limited partner investment in NGL Energy, partially offset by prior year gain on the sale of our common limited partner units of NGL Energy;

• a decrease of $18.3 million due to a deferred tax benefit in the current year compared to deferred tax expense in the prior year primarily as a result of changes to federal statutory income tax rates and a current year pre-tax loss compared with prior year pre-tax income;

• a $9.7 million decrease in distributions from equity method investees primarily due to the disposition of our limited partner unit investment in NGL Energy in the prior year and lower volumes on White Cliffs;

• a $9.5 million decrease due to currency gains as compared to prior year currency losses;

• a $3.0 million decrease due to a pension curtailment gain related to the HFOTCO pension which was curtailed subsequent to acquisition; and

• a decrease of $2.7 million in losses on disposal and impairments primarily due to gain on disposal of Glass Mountain offset by impairments related to the held for sale status of our Mexican asphalt business and our U.K. operations and impairments to U.S. Gas and U.S. Liquids assets.

Changes in operating assets and liabilities during the year ended December 31, 2017 relative to the prior year-end consisted primarily of:

• $213.6 million increase in accounts receivable, including receivable from affiliates, generally due to higher commodity prices and volumes;

• $17.9 million increase in inventory primarily due to increased inventory of our U.S. Liquids segment due to an additional 0.3 million barrels of crude oil on hand at a higher weighted average cost;

• $190.4 million increase in accounts payable, including payable to affiliates, and accrued liabilities generally due to higher prices and volumes and timing of purchases; and

• $19.4 million increase in other noncurrent liabilities primarily due to accretion of the final payment in the HFOTCO acquisition.

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Investing Activities

For the year ended December 31, 2018, we had net cash outflows of $229.7 million, primarily as a result of $390.7 million in capital expenditures and $7.8 million in contributions to equity method investments. These cash outflows were offset, in part, by cash inflows of $147.8 million in proceeds from business divestitures and $19.1 million in distributions from equity method investments in excess of equity in earnings. Capital expenditures included our Canada segment's Wapiti expansion and our U.S. Liquids segment's expansion projects at our Gulf Coast terminal. Distributions in excess of equity earnings represent cash distributions from White Cliffs in excess of our cumulative equity in earnings and are accounted for as a return of investment.

For the year ended December 31, 2017, we had net cash outflows of $439.8 million, primarily as a result of $462.7 million in capital expenditures, $294.2 million cash paid as a portion of the first payment to acquire HFOTCO and $26.4 million in contributions to equity method investments. These cash outflows were offset, in part, by cash inflows of $314.8 million in proceeds from the sale of long-lived assets, primarily due to the Glass Mountain disposal, and $28.8 million in distributions from equity method investments in excess of equity in earnings. Capital expenditures included the U.S. Liquids segment's projects including the Maurepas Pipeline project, our U.S. Gas segment's northern Oklahoma expansion projects and our Canada segment's Wapiti expansion. Distributions in excess of equity earnings represent cash distributions from White Cliffs and Glass Mountain in excess of our cumulative equity in earnings and are accounted for as a return of investment.

For the year ended December 31, 2016, we had net cash outflows of $228.3 million, primarily as a result of $312.5 million in capital expenditures and $4.2 million in contributions to equity method investments. These cash outflows were offset, in part, by cash inflows of $60.5 million in proceeds from the sale of common units of NGL Energy, an equity method investee, and $27.7 million in distributions from equity method investments in excess of equity in earnings. Capital expenditures included the U.S. Liquids segment's projects including the Maurepas Pipeline project, our U.S. Gas segment's northern Oklahoma expansion projects and our Canada segment's Wapiti expansion. Distributions in excess of equity earnings represent cash distributions from White Cliffs and Glass Mountain in excess of our cumulative equity in earnings and are accounted for as a return of investment.

Financing Activities

For the year ended December 31, 2018, we had net cash outflows of $45.0 million, primarily as a result of $1.3 billion of borrowings (offset by $1.8 billion of principal payments including the final HFOTCO payment), $350.0 million of proceeds from the issuance of Maurepas Pipeline Class B shares, $342.3 million of net proceeds from the issuance of SemGroup Series A Cumulative Perpetual Convertible Preferred Stock, partially offset by $148.5 million of dividends paid, $4.7 million of payments related to debt issuances and $2.9 million of distributions to noncontrolling interests related to the Maurepas Pipeline Class B shares.

For the year ended December 31, 2017, we had net cash inflows of $315.3 million, primarily as a result of $1.5 billion of borrowings and assumption of HFOTCO indebtedness (offset by $1.1 billion of principal payments), partially offset by $129.9 million of dividends paid, $16.3 million of debt extinguishment costs and $11.1 million of payments related to debt issuances. Debt extinguishment costs related to the early payoff of our 2021 Notes. Debt issuance costs primarily related to the issuance of our 2025 and 2026 Notes.

For the year ended December 31, 2016, we had net cash inflows of $75.9 million, primarily as a result of $382.5 million of borrowings (offset by $396.9 million of principal payments) and $223.0 million in proceeds from the issuance of common shares (net of offering costs), partially offset by $92.9 million of dividends paid, $32.1 million of cash distributions to noncontrolling interests and $7.7 million of payments related to debt issuances. Debt issuance costs primarily relate to the increase in capacity under the SemGroup credit facility.

Long-term Debt

SemGroup Senior Unsecured Notes

At December 31, 2018, we had outstanding $400 million of 5.625% senior unsecured notes due 2022, $350 million of 5.625% senior unsecured notes due 2023, $325 million of 6.375% senior unsecured notes due 2025 and $300 million of 7.250% senior unsecured notes due 2026 (collectively, the "Notes"). The Notes are governed by indentures, as supplemented, between the Company and its subsidiary guarantors and Wilmington Trust, N.A., as trustee (the “Indentures”). The Indentures include customary covenants and events of default.

At December 31, 2018, we were in compliance with the terms of the Indentures.

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SemGroup Revolving Credit Facility

At December 31, 2018, we had $119.5 million of cash borrowings outstanding under our $1.0 billion revolving credit facility. In addition, we had $24.3 million in outstanding letters of credit on that date. The maximum letter of credit capacity under this facility is $250 million. The facility can be increased up to $300 million with the consent of the administrative agent. The credit agreement expires on March 15, 2021.

The credit agreement includes customary affirmative and negative covenants, including limitations on the creation of new indebtedness, liens, sale and lease-back transactions, new investments, making fundamental changes including mergers and consolidations, making of dividends and other distributions, making material changes in our business, modifying certain documents and maintenance of a consolidated leverage ratio, a senior secured leverage ratio and an interest coverage ratio. In addition, the credit agreement prohibits any commodity transactions that are not permitted by our Risk Governance Policies.

The terms of our credit facility restrict, to some extent, the payment of cash dividends on our common stock. The credit agreement is guaranteed by all of our wholly-owned, material domestic subsidiaries and secured by a lien on substantially all of our property and assets, subject to customary exceptions.

At December 31, 2018, we had available borrowing capacity of $856.2 million under this facility.

HFOTCO Credit Agreement

On June 26, 2018, HFOTCO and Buffalo Gulf Coast Terminals LLC ("BGCT") entered into an Amendment and Restatement Agreement (the “Amendment and Restatement Agreement”). Pursuant to the Amendment and Restatement Agreement, the HFOTCO credit agreement was amended and restated in its entirety (as so amended and restated, the “Restated HFOTCO Credit Agreement”).

The Restated HFOTCO Credit Agreement increased the aggregate term loans incurred thereunder to $600 million, terminated the HFOTCO $75.0 million revolving credit facility, and extended the maturity date of the term loans to June 26, 2025 (the “Maturity Date”). In addition, HFOTCO may incur additional term loans in an aggregate amount not to exceed the greater of $120 million and a measure of HFOTCO’s EBITDA, defined in the credit agreement, at the time of determination, plus additional amounts subject to satisfaction of certain leverage-based criteria, subject to receiving commitments for such additional term loans from either new lenders or increased commitments from existing lenders. The term loan B was issued at a discount of $1.5 million.

At HFOTCO’s option, the term loans will bear interest at the Eurodollar rate or an alternate base rate (“ABR”), plus, in each case, an applicable margin of 2.75% relating to any term loans accruing interest at the Eurodollar rate and 1.75% relating to term loans accruing interest at ABR.

The Restated HFOTCO Credit Agreement includes customary representations and warranties and affirmative and negative covenants, which were made only for the purposes of the Restated HFOTCO Credit Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties, and apply only to BGCT, HFOTCO and any subsidiaries of HFOTCO party to the Restated HFOTCO Credit Agreement. Such limitations include the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to material agreements, modifying the fiscal year, dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, and funding or engaging in sanctioned activities.

The Restated HFOTCO Credit Agreement includes customary events of default, including events of default relating to inaccuracy of representations and warranties in any material respect when made or when deemed made, non-payment of principal and other amounts owing under the Restated HFOTCO Credit Agreement, including, in respect of, violation of covenants, cross acceleration to any material indebtedness of BGCT, HFOTCO and its subsidiaries, bankruptcy and insolvency events, certain unsatisfied judgments, certain ERISA events, certain invalidities of loan documents and the occurrence of a change of control. A default under the Restated HFOTCO Credit Agreement would permit the participating banks to require immediate repayment of any outstanding loans with interest and any unpaid accrued fees, and subject to intercreditor arrangements with the holders of the HFOTCO tax exempt notes payable, exercise other rights and remedies.

HFOTCO acquisition final payment

On April 17, 2018, we made the final payment related to the HFOTCO acquisition in the amount of $579.6 million. The payment was funded through revolving credit facility borrowings and cash on hand.

SemCAMS Midstream    

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On February 25, 2019, SemCAMS Midstream entered into a credit agreement providing for a C$350.0 million senior secured term loan facility and a C$450.0 million senior secured revolving credit facility. For additional information, refer to Note 26 of our consolidated financial statements beginning on page F-1 of this Form 10-K.

Shelf Registration Statement

We have access to a universal shelf registration statement which provides us the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. This shelf registration statement expires in March 2019 and we intend to file a new universal shelf registration statement in March 2019.

We have also established an "at the market" offering program under the existing shelf registration statement, which provides for the offer and sale, from time to time, of common shares having an aggregate offering price of up to $300 million. We are able to make sales in transactions at prices which are prevailing market prices at the time of sale, prices related to market prices or at negotiated prices. Such sales may be made pursuant to an Equity Distribution Agreement between us and certain agents who may act as sales agents or purchase for their own accounts as principals. To date, there have been no such sales.

Capital Requirements

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

• expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long-term; or

• maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity.

During the year ended December 31, 2018, we spent $390.7 million (cash basis), on capital projects. Projected capital expenditures, excluding capitalized interest, for 2019 are estimated at $262 million in expansion projects, including capital contributions to equity method investees to fund growth projects and $45 million in maintenance projects. These estimates may change as future events unfold. See "Cautionary Note Regarding Forward-Looking Statements."

In addition to our budgeted capital program, we anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by cash from operations, borrowings under our credit facilities and the issuance of debt and equity securities.

SemGroup Dividends

The table below sets out the dividends declared and/or paid by SemGroup for the periods indicated.

Quarter Ended	Record Date	Payment Date	Dividend Per Share
March 31, 2017	March 7, 2017	March 17, 2017	$0.45
June 30, 2017	May 15, 2017	May 26, 2017	$0.45
September 30, 2017	August 18, 2017	August 28, 2017	$0.45
December 31, 2017	November 20, 2017	December 1, 2017	$0.45
March 31, 2018	March 9, 2018	March 19, 2018	$0.4725
June 30, 2018	May 16, 2018	May 25, 2018	$0.4725
September 30, 2018	August 20, 2018	August 28, 2018	$0.4725
December 31, 2018	November 16, 2018	November 26, 2018	$0.4725
March 31, 2019	March 4, 2019	March 14, 2019	$0.4725

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On January 19, 2018, we sold to certain institutional investors, in a private placement, an aggregate of 350,000 shares of our Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share (the “Preferred Stock”), convertible into shares of our Class A common stock. Holders of the Preferred Stock will receive quarterly distributions equal to an annual rate of 7.0% ($70.00 per share annualized) of $1,000 per share of Preferred Stock, subject to certain adjustments. With respect to any quarter ending on or prior to June 30, 2020, we may elect, in lieu of paying a distribution in cash, to have the amount that would have been payable if such dividend had been paid in cash added to the Liquidation Preference.

On February 20, 2019, we declared a dividend, in the aggregate, of $6.4 million to the holders of Preferred Stock. We elected to have the $6.4 million, that would have been paid in cash as a dividend, added to the liquidation preference of such shares as a payment-in-kind. The payment-in-kind on the shares of Preferred Stock is March 1, 2019, and the record date is February 22, 2019.

Credit Risk

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

Customer Concentration

Shell Trading (US) Company, a customer of our U.S. Liquids segment, accounted for more than 10% of our consolidated revenue for the year ended December 31, 2018, at approximately 26%. The contracts from which our revenues are derived from this customer primarily relate to our crude marketing operations and are for crude oil purchases and sales at market prices. We are not substantially dependent on such contracts and believe that if we were to lose any or all of these contracts, they could be readily replaced under substantially similar terms. Although we have contracts with customers of varying durations, if one or more of our major customers were to default on their contract, or if we were unable to renew our contract with one or more of these customers on favorable terms, we might not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our revenues and our ability to pay cash dividends to our stockholders may be adversely affected. We expect our exposure to risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our revenues.

Our U.S. Gas segment has a significant concentration of producers which account for a large portion of our U.S. Gas segment's volumes. During the year ended December 31, 2018, three producers accounted for approximately 89% of our total processed volumes. During the year ended December 31, 2018, two producers accounted for 83% of our total gathered volumes. Additionally, all of the gathering and processing volumes from these customers are produced in the Northern Oklahoma region.

Our Canada segment's processing plants require a minimum rate of sulfur tonnage to operate and to comply with the regulatory requirements for air emissions.  We have several large producers that provide significant sour gas to our plants.  If these producers shut in their sour gas production due to current or future commodity prices, it could result in regulatory non-compliance, as well as operating and financial impacts to our Canada segment. We expect to mitigate this risk for our KA plant through a sulfur turn-down project that was placed into service in 2018.

Off-Balance Sheet Arrangements

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

Commitments

Contractual Obligations

In the ordinary course of business we enter into various contractual obligations for varying terms and amounts. The following table includes our contractual obligations as of December 31, 2018, and our best estimate of the period in which the obligation will be settled (in thousands): 

	2019		2020		2021		2022		2023		Thereafter
Long-term debt (1)	$	6,000	$	6,000	$	125,500	$	406,000	$	356,000	$	1,417,000
Interest (1)	132,128		132,253		125,942		114,056		99,408		328,803
Operating leases	5,795		5,796		5,312		3,455		2,453		40,551

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Take-or-pay commitments (2)	31,648		28,814		20,313		20,136		16,350		6,816
Purchase commitments (3)	981,273		—		—		—		—		—
Capital expenditure expansion projects	104,400		—		—		—		—		—
Total	$	1,261,244	$	172,863	$	277,067	$	543,647	$	474,211	$	1,793,170

(1) Assumes interest rates, fee rates and letters of credit and loans outstanding as of December 31, 2018, and that same remain constant thereafter until maturity except for required principal payments.

(2) Take-or-pay commitments include: (a) a five-year transportation take-or-pay agreement with White Cliffs for approximately 5,000 barrels per day which began in October 2015; (b) a seven-year transportation take-or-pay agreement for 5,000 barrels per day on a third-party pipeline which began in June 2017; and (c) a commitment related to fractionation of natural gas liquids through 2023.

(3) The bulk of the commitments shown in the table above relate to agreements to purchase product from a counterparty and to sell a similar amount of product (in a different location) to the same counterparty. Many of the commitments shown in the table above are cancellable by either party, as long as notice is given within the time frame specified in the agreement (generally 30 to 120 days).

In addition to the items in the table above, we have entered into various operational commitments and agreements related to pipeline operations and to the marketing, transportation, terminalling and storage of petroleum products. We have also entered into certain derivative instruments. See Note 14 of our consolidated financial statements beginning on page F-1 of this Form 10-K.

Letters of Credit

In connection with our purchasing activities, we provide certain suppliers and transporters with irrevocable standby letters of credit to secure our obligation for the purchase of petroleum products. Our liabilities with respect to these purchase obligations are recorded as accounts payable on our balance sheet in the month the petroleum products are purchased. Generally, these letters of credit are issued for 70-day periods (with a maximum of 364-day periods) and are terminated upon completion of each transaction. At December 31, 2018 and December 31, 2017, we had outstanding letters of credit of approximately $43.4 million and $110.8 million, respectively.

Critical Accounting Policies and Estimates

Management’s Discussion and Analysis of Financial Condition and Results of Operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. The preparation of these financial statements and related disclosures requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates and judgments that affect the reported amount of assets, liabilities, revenue, expenses and related disclosures of contingent assets and liabilities. The application of these policies involves judgments regarding future events, including the likelihood of success of particular projects and legal and regulatory challenges. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.

On an on-going basis, we evaluate these estimates using historical experience, consultation with experts and other methods we consider reasonable. Actual results may differ substantially from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Our significant accounting policies are summarized in Note 3 of our consolidated financial statements beginning on page F-1 of this Form 10-K. We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and results of operations, and that require the most difficult, subjective and complex judgments by management regarding estimates about matters that are inherently uncertain.

Accounting Policy	Judgment/Uncertainty Affecting Application
Income Taxes	Ability to withstand legal challenges of tax authority decisions or appeals

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	Anticipated future decisions of tax authorities
	Application of tax statutes and regulations to transactions
	Ability to use tax benefits carry forwards to future periods
Impairment of Long Lived Assets and Other Intangible Assets	Recoverability of investment through future operations
	Regulatory and political environments and requirements
	Estimated useful lives of assets
	Environmental obligations and operational limitations
	Identification of asset groups
	Estimates of future cash flows
	Estimates of fair value
	Judgment about triggering events and held-for-sale classification
Goodwill	Judgment about impairment triggering events
	Identification of reporting units
	Purchase price allocation
	Estimates of reporting unit's fair value
Derivative Instruments	Instruments used in valuation techniques
	Market maturity and economic conditions
	Contract interpretation
	Market conditions in the energy industry, especially the effects of price volatility on contractual commitments
Contingencies	Estimated financial impact of event
	Judgment about the likelihood of event occurring
	Regulatory and political environments and requirements

Income Taxes

At December 31, 2018, we had a cumulative U.S. federal net operating loss of approximately $535.6 million that can be carried forward to apply against taxable income generated in future years. $350.4 million of this carryforward has an indefinite carryforward period and the remaining carryforward begins to expire in 2031. We had cumulative U.S. state net operating losses of approximately $371.0 million available for carryforward, which begin to expire in 2019. We had foreign net operating losses of $0.8 million available for carryforward, which begin to expire in 2025. We had foreign tax credits of approximately $44.6 million available for carryforward, which begin to expire in 2020. We had interest expense limitation of $31.8 million available for indefinite carryforward.

Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. We are subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including Canada.

Evaluation of Long-Lived Assets and Other Intangible Assets for Impairment

In accordance with ASC 360, “Property, Plant and Equipment” and ASC 350, “Intangibles – Goodwill and Other”, we evaluate property, plant and equipment and intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators are:

• significant decrease in the market price of a long-lived asset;

• significant adverse change in the manner an asset is used or its physical condition;

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• adverse business climate;

• accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;

• current period loss combined with a history of losses or the projection of future losses; and

• change in our intent about an asset from an intent to hold such asset through the end of its estimated useful life to a greater than fifty percent likelihood that such asset will be disposed of before then.

Recoverability of assets to be held and used is measured by comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount exceeds the fair value of the assets. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. However, actual future market prices and costs could vary from the assumptions used in our estimates and the impact of such variations could be material.

Goodwill

We apply ASC 805, “Business Combinations,” and ASC 350, “Intangibles – Goodwill and Other,” to account for goodwill. In accordance with these standards, goodwill has an indefinite life and is not amortized. However, goodwill is tested for impairment at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test for impairment at the reporting unit level using three valuation approaches: first, the income approach which measures the value of an asset by the present value of its future economic benefit; second, the market approach which measures the value of an asset through the analysis of recent sales or offerings of comparable properties; and third, the cost approach which measures the value of an asset by the cost to reconstruct or replace it with another of like utility.

Estimation of future economic benefit requires management to make assumptions about numerous variables including selling prices, costs, the level of activity and appropriate discount rates. When goodwill balances are material, such as with our HFOTCO acquisition, relatively minor revisions to assumptions could result in a material future impairment. If it is determined that the fair value of a reporting unit is below its carrying amount, our goodwill will be impaired at that time.

Derivative Instruments

We follow the guidance of ASC 815, “Derivatives and Hedging,” to account for derivative instruments. ASC 815 requires us to mark-to-market all derivative instruments on the balance sheet, and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings. In certain cases, we may apply hedge accounting to our derivative instruments. The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the fair value of the derivative instrument and the underlying hedged item. Changes in the fair value of derivative instruments accounted for as hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged item, or deferred and recorded as a component of other comprehensive income and subsequently recognized in earnings when the hedged transactions occur.

Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be a normal purchase normal sale (“NPNS”). The availability of this exception is based on the assumption that the company has the ability, and it is probable, to deliver or take delivery of the underlying item. These assumptions are based on internal forecasts of sales and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with immediate recognition through earnings.

Contingencies

We record a loss contingency when management determines that it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. Gain contingencies are not recorded until realized.

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Recent Accounting Pronouncements

See Note 3 of our consolidated financial statements beginning on page F-1 of this Form 10-K.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

This discussion on market risks represents an estimate of possible changes in future earnings that would occur assuming hypothetical future movements in commodity prices, interest rates and currency exchange rates. Our views on market risk are not necessarily indicative of actual results that may occur, and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in commodity prices, interest rates, currency exchange rates and the timing of transactions.

We are exposed to various market risks, including changes in (i) petroleum prices, particularly crude oil, natural gas and natural gas liquids, (ii) interest rates, and (iii) currency exchange rates. We may use from time-to-time various derivative instruments to manage such exposure. Our risk management policies and procedures are designed to monitor physical and financial commodity positions and the resulting outright commodity price risk as well as basis risk resulting from differences in commodity grades, purchase and sale locations and purchase and sale timing. We have a risk management function that has responsibility and authority for our Risk Governance Policies, which govern our enterprise-wide risks, including the market risks discussed in this item. Subject to our Risk Governance Policies, our finance and treasury function has responsibility and authority for managing exposure to interest rates and currency exchange rates. To manage the risks discussed above, we engage in price risk management activities.

Commodity Price Risk

The table below outlines the range of NYMEX prompt month daily settle prices for crude oil and natural gas futures, and the range of daily propane spot prices provided by an independent, third-party broker for the years ended December 31, 2018, 2017 and 2016.

	Light Sweet Crude Oil Futures ($ per Barrel)	Mont Belvieu (Non-LDH) Spot Propane ($ per Gallon)	Henry Hub Natural Gas Futures ($ per MMBtu)
Year Ended December 31, 2018
High	$76.41	$1.10	$4.84
Low	$42.53	$0.61	$2.55
High/Low Differential	$33.88	$0.49	$2.29
Year Ended December 31, 2017
High	$60.42	$1.01	$3.42
Low	$42.53	$0.57	$2.56
High/Low Differential	$17.89	$0.44	$0.86
Year Ended December 31, 2016
High	$54.06	$0.71	$3.93
Low	$26.21	$0.29	$1.64
High/Low Differential	$27.85	$0.42	$2.29

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

However, our U.S. Gas segment has exposure to commodity price risk because of the nature of certain contracts for which our fee is based on a percentage of proceeds or index related to the prices of natural gas, natural gas liquids and

53

condensate. Given current volumes, liquid recoveries and contract terms, we estimate the following sensitivities over the next twelve months:

• A 10% increase in the price of natural gas and natural gas liquids results in approximately a $4.0 million increase to gross margin.

• A 10% decrease in those prices would have the opposite effect.

The above sensitivities may be impacted by changes in contract mix, change in production or other factors which are outside of our control.

Additionally, based on our open commodity derivative contracts at December 31, 2018, an increase in the applicable market price or prices for each derivative contract would result in a decrease in our crude oil sales revenues. Likewise, a decrease in the applicable market price or prices for each derivative contract would result in an increase in our crude oil sales revenues. However, the increases or decreases in crude oil sales revenues we recognize from our open commodity derivative contracts are substantially offset by higher or lower crude oil sales revenues when the physical sale of the product occurs. These contracts may be for the purchase or sale of crude oil or in markets different from the physical markets in which we are attempting to hedge our exposure, or may have timing differences relative to the physical markets. As a result of these factors, our hedges may not eliminate all price risks.

The notional volumes and fair value of our commodity derivatives open positions at December 31, 2018, as well as the change in fair value that would be expected from a 10% market price increase or decrease, is shown in the table below (in thousands):

	Notional Volume (Barrels)	Fair Value		Effect of 10% Price Increase			Effect of 10% Price Decrease		Settlement Date
Crude Oil:
Futures contracts	861	$	3,685	$	(3,900	)	$	3,900	January - May 2019

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

Interest Rate Risk

We use variable rate debt and are exposed to market risk due to the floating interest rates on our credit facilities. Therefore, from time-to-time we may use interest rate derivatives to manage interest obligations on specific debt issuances. Our variable rate debt bears interest at LIBOR or prime, subject to certain floors, plus the applicable margin. At December 31, 2018, an increase in these base rates of 1%, above the base rate floors, would increase our interest expense by $10.6 million per year. Increases in interest expense due to an increase in interest rates as presented above, would have been partially offset by a $4.2 million reduction in interest expense from interest rate swaps, discussed below.

The average interest rates presented below are based upon rates in effect at December 31, 2018 and December 31, 2017. The carrying value of the variable rate instruments in our credit facilities approximate fair value primarily because our rates fluctuate with prevailing market rates.

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The following table summarizes our debt obligations:

Liabilities	December 31, 2018			December 31, 2017
Long-term debt—variable rate	$	935.5	million	$	948.1	million
Average variable interest rate	4.93		%	4.32		%
Short-term debt—variable rate	$	6.0	million	$	5.5	million
Average variable interest rate	5.28		%	5.19		%
Long-term debt—fixed rate	$	1,375.0	million	$	1,375.0	million
Average fixed interest rate	6.16		%	6.16		%

We have interest rate swaps which allow us to limit exposure to interest rate fluctuations. The swaps only apply to a portion of our outstanding debt and provide only partial mitigation of interest rate fluctuations. We have not designated the swaps as hedges, as such changes in the fair value of the swaps are recorded through current period earnings as a component of interest expense. At December 31, 2018 and December 31, 2017, we had interest rate swaps with notional values of $524.3 million and $491.1 million, respectively. At December 31, 2018 and December 31, 2017, the fair value of our interest rate swaps was $1.5 million and $1.2 million, respectively, which was reported within "other current liabilities" and "other noncurrent liabilities” in our condensed consolidated balance sheet. For the years ended December 31, 2018 and 2017, we recognized realized and unrealized gains of $0.2 million and $1.1 million, respectively, related to interest rate swaps.

Currency Exchange Risk

The cash flows relating to our Canada operations are based on the U.S. dollar equivalent of such amounts measured in Canadian dollars. Assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenue, expenses and cash flows are translated using the average exchange rate during the reporting period.

A 10% change in the average exchange rate during the years ended December 31, 2018 and 2017, would change operating income by $12.9 million and $7.7 million, respectively.

We have foreign currency forwards primarily to purchase Canadian dollars to limit exposure to foreign currency rate fluctuations for capital contributions to our Canadian operations. We have not designated the forwards as hedges, as such changes in the fair value of the forwards are recorded through current period earnings as a component of foreign currency translation gain/loss. At December 31, 2018 and December 31, 2017, we had foreign currency forwards with notional values of $56.1 million and $197.7 million, respectively. At December 31, 2018 and December 31, 2017, the fair value of our foreign currency swaps was $3.0 million and $2.6 million, respectively, which is reported within "other current liabilities" and "other noncurrent assets, net", respectively, in our consolidated balance sheet. For the year ended December 31, 2018, we recognized realized and unrealized losses of $10.2 million, related to foreign currency forwards. For the year ended December 31, 2017, we recognized realized and unrealized gains of $2.8 million, related to foreign currency forwards. We did not have any foreign currency forwards during the year ended December 31, 2016.

Based on the exchange rates at December 31, 2018, a 1% increase in the USD/CAD foreign exchange rate would result in a $0.9 million gain, while a 1% decrease in the USD/CAD foreign exchange rate would have the opposite effect.

Item 8. Financial Statements and Supplementary Data

The consolidated financial statements of the Company required to be included in this Form 10-K appear immediately following the signature page to this Form 10-K beginning on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have concluded that the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) under the Exchange Act) are effective as of December 31, 2018. This conclusion is based on an evaluation conducted under the supervision and participation of our Chief Executive Officer and Chief Financial Officer along with our management. Disclosure controls and procedures are those controls and procedures designed to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that such

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information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on our evaluation under that framework and applicable SEC rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2018.

Our internal control over financial reporting as of December 31, 2018, has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report that is included herein.

Changes in Internal Control over Financial Reporting

None

Item 9B. Other Information

None

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item concerning our directors and corporate governance matters is incorporated by reference to the information in the sections entitled “PROPOSAL 1 – ELECTION OF DIRECTORS” and “CORPORATE GOVERNANCE,” respectively, of our Proxy Statement for the 2019 Annual Meeting of Stockholders (the “Proxy Statement”). The information required by this item with respect to the Section 16 ownership reports is incorporated by reference to the section entitled “SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the Proxy Statement. The information required by this item with respect to our executive officers is included in Part I of this Form 10-K under the section entitled “Executive Officers of the Registrant.” A copy of our Code of Business Conduct and Ethics is posted on our website at www.semgroup.com.

Item 11. Executive Compensation

The information required by this item is incorporated by reference to the information set forth in the sections entitled “EXECUTIVE COMPENSATION” and “DIRECTOR COMPENSATION” of the Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters

The information required by this item regarding security ownership and equity compensation plans is incorporated by reference to the information set forth in the sections entitled “PRINCIPAL STOCKHOLDERS AND SECURITY OWNERSHIP OF MANAGEMENT” and “EQUITY COMPENSATION PLAN INFORMATION,” respectively, of the Proxy Statement.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item regarding certain relationships and related transactions and director independence is incorporated by reference to the information set forth in the sections entitled “CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS” and “CORPORATE GOVERNANCE,” respectively, of the Proxy Statement.

Item 14. Principal Accountant Fees and Services

The information required by this item regarding principal accounting fees and services is incorporated by reference to the information set forth in the sections entitled “FEES OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM” and “AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES” of the Proxy Statement.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) (1)    Financial Statements. The consolidated financial statements of the Company included in this Form 10-K are listed on page F-1, which follows the signature page to this Form 10-K.

(2)    Financial Statement Schedules. All financial statement schedules are omitted as inapplicable or because the required information is contained in the financial statements or the notes thereto.

The financial statements of White Cliffs Pipeline, L.L.C., our equity method investee, are included in this filing as Exhibit 99.1 pursuant to Rule 3-09 of Regulation S-X.

(3)    Exhibits. The following documents are included as exhibits to this Form 10-K. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, such exhibit is filed herewith.

Exhibit Number	Description
2.1	Purchase and Sale Agreement by and among SemGroup Corporation, Beachhead I LLC, Beachhead II LLC, Buffalo Investor I, LP and Buffalo Investor II, LP, dated as of June 5, 2017 (filed as Exhibit 2.1 to our current report on Form 8-K dated June 5, 2017, filed June 6, 2017).
2.2	Agreement and Plan of Merger dated as of May 30, 2016, by and among SemGroup Corporation, PBMS, LLC, Rose Rock Midstream, L.P. and Rose Rock Midstream GP, LLC (filed as Exhibit 2.1 to our current report on Form 8-K dated May 30, 2016, filed May 31, 2016).
2.3	Membership Interest Purchase Agreement, dated as of January 5, 2018, between SemMaterials, L.P. and SemMexico, L.L.C. and Ergon Asfaltos Mexico HC, LLC, Ergon Mexico HC, LLC, and Ergon Asphalt & Emulsions, Inc. (filed as Exhibit 2 to our current report on Form 8-K dated March 15, 2018, filed March 20, 2018).
3.1	Amended and Restated Certificate of Incorporation, dated as of November 30, 2009, as amended, of SemGroup Corporation.
3.2	Amended and Restated Bylaws, dated as of November 3, 2017, of SemGroup Corporation (filed as Exhibit 3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2017, filed November 9, 2017).
3.3	Certificate of Designations of Series A Cumulative Perpetual Convertible Preferred Stock of SemGroup Corporation, filed with the Secretary of State of the State of Delaware on January 19, 2018 (including form of stock certificate for our Series A Cumulative Perpetual Convertible Preferred Stock attached as Exhibit A thereto) (filed as Exhibit 3.1 to our current report on Form 8-K dated January 16, 2018, filed January 19, 2018).
4.1	Form of stock certificate for our Class A Common Stock, par value $0.01 per share (filed as Exhibit 4.1 to our registration statement on Form 10, File No. 001-34736 (the “Form 10”)).
4.2	Form of stock certificate for our Class B Common Stock, par value $0.01 per share (filed as Exhibit 4.2 to the Form 10).
4.3	Indenture (and form of 5.625% Senior Note due 2022 attached as Exhibit A thereto), dated as of July 2, 2014, by and among Rose Rock Midstream, L.P., Rose Rock Finance Corporation, the Guarantors party thereto and Wilmington Trust, National Association, as trustee (filed as Exhibit 4.1 to Rose Rock Midstream, L.P.'s current report on Form 8-K dated June 27, 2014, filed July 2, 2014).
4.4	Indenture (and form of 5.625% Senior Note due 2023 attached as Exhibit A thereto), dated as of May 14, 2015, by and among Rose Rock Midstream, L.P., Rose Rock Finance Corporation, the Guarantors party thereto and Wilmington Trust, National Association, as trustee (filed as Exhibit 4.1 to Rose Rock Midstream, L.P.'s current report on Form 8-K dated May 14, 2015, filed May 18, 2015).
4.5	Second Supplemental Indenture dated as of September 30, 2016, by and among SemGroup Corporation, the subsidiaries of SemGroup Corporation named therein as "Guarantors," the subsidiaries of SemGroup Corporation named therein as "Guaranteeing Subsidiaries" and Wilmington Trust, National Association, as trustee (filed as Exhibit 4.2 to our current report on Form 8-K dated September 30, 2016, filed September 30, 2016).

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Exhibit Number	Description
4.6	First Supplemental Indenture dated as of September 30, 2016, by and among SemGroup Corporation, the subsidiaries of SemGroup Corporation named therein as "Guarantors," the subsidiaries of SemGroup Corporation named therein as "Guaranteeing Subsidiaries" and Wilmington Trust, National Association, as trustee (filed as Exhibit 4.3 to our current report on Form 8-K dated September 30, 2016, filed September 30, 2016).
4.7	Indenture (and form of 6.375% Senior Note due 2025 attached as Exhibit A thereto), dated as of March 15, 2017, by and among SemGroup Corporation, certain of its wholly-owned subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee (filed as Exhibit 4.1 to our current report on Form 8-K dated March 15, 2017, filed March 21, 2017).
4.8	Indenture (and form of 7.25% Senior Note due 2026 attached as Exhibit A thereto), dated as of September 20, 2017, by and among SemGroup Corporation, certain of its wholly owned subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee (filed as Exhibit 4.1 to our current report on Form 8-K dated September 20, 2017, filed September 21, 2017).
4.9	Amended and Restated Bond Indenture, dated as of August 19, 2014, between Harris County Industrial Development Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee, relating to $75 million Series 2010 Marine Terminal Revenue Bonds (filed as Exhibit 4.1 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.10	Amended and Restated Bond Indenture, dated as of August 19, 2014, between Harris County Industrial Development Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee, relating to $50 million Series 2011 Marine Terminal Revenue Bonds (filed as Exhibit 4.2 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.11	Amended and Restated Bond Indenture, dated as of August 19, 2014, between Harris County Industrial Development Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee, relating to $100 million Series 2012 Marine Terminal Revenue Bonds (filed as Exhibit 4.3 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.12	Continuing Covenant Agreement, dated as of August 19, 2014, between HFOTCO LLC, as obligor, Buffalo Gulf Coast Terminals LLC, as the parent, Bank of America, N.A., as administrative agent and collateral agent, and the bondholders party thereto (filed as Exhibit 4.4 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.13	Consent and Amendment to Continuing Covenant Agreement, dated as of June 5, 2017, between HFOTCO LLC, as obligor, Buffalo Gulf Coast Terminals LLC, as the parent, Bank of America, N.A., as administrative agent and collateral agent, and the bondholders party thereto (filed as Exhibit 4.5 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.14	Amendment No. 2 to Continuing Covenant Agreement, dated as of June 26, 2018, between HFOTCO LLC, as obligor, Buffalo Gulf Coast Terminals, LLC, as the parent, Bank of America, N.A., as administrative agent and collateral agent, and the bondholders party thereto (filed as Exhibit 10.2 to our current report on Form 8-K dated June 26, 2018, filed July 2, 2018).
4.15	Loan Agreement, dated as of November 1, 2010, by and between HFOTCO LLC and Harris County Industrial Development Corporation, relating to $75 million Series 2010 Marine Terminal Revenue Bonds (filed as Exhibit 4.6 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.16	Loan Agreement, dated as of December 1, 2011, by and between HFOTCO LLC and Harris County Industrial Development Corporation, relating to $50 million Series 2011 Marine Terminal Revenue Bonds (filed as Exhibit 4.7 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.17	Loan Agreement, dated as of October 1, 2012, by and between HFOTCO LLC and Harris County Industrial Development Corporation, relating to $100 million Series 2012 Marine Terminal Revenue Bonds (filed as Exhibit 4.8 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.18	First Amendment to Loan Agreement, dated as of August 19, 2014, by and between HFOTCO LLC and Harris County Industrial Development Corporation, relating to $75 million Series 2010 Marine Terminal Revenue Bonds (filed as Exhibit 4.9 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.19	First Amendment to Loan Agreement, dated as of August 19, 2014, by and between HFOTCO LLC and Harris County Industrial Development Corporation, relating to $50 million Series 2011 Marine Terminal Revenue Bonds (filed as Exhibit 4.10 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).

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Exhibit Number	Description
4.20	First Amendment to Loan Agreement, dated as of August 19, 2014, by and between HFOTCO LLC and Harris County Industrial Development Corporation, relating to $100 million Series 2012 Marine Terminal Revenue Bonds (filed as Exhibit 4.11 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
4.21	Registration Rights Agreement by and among SemGroup Corporation, Buffalo Investor I, LP and Buffalo Investor II, LP dated as of July 17, 2017 (filed as Exhibit 10.1 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
10.1	Amended and Restated Credit Agreement, dated as of September 30, 2016, by and among SemGroup Corporation, as borrower, the guarantors named therein, the lenders named therein, and Wells Fargo Bank, National Association, as administrative agent (filed as Exhibit 10.1 to our current report on Form 8-K dated September 30, 2016, filed September 30, 2016).
10.2	First Amendment to Amended and Restated Credit Agreement, dated as of April 4, 2017, to the Amended and Restated Credit Agreement, dated as of September 30, 2016, entered into by and among others, SemGroup Corporation, as borrower, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent (filed as Exhibit 10.2 to our quarterly report on Form 10-Q for the quarter ended March 31, 2017, filed May 5, 2017).
10.3	Second Amendment to Amended and Restated Credit Agreement, dated as of February 20, 2018, by and among SemGroup Corporation, as borrower, the guarantors named therein, the lenders named therein, and Wells Fargo Bank, National Association, as administrative agent (filed as Exhibit 10.3 to our annual report on Form 10-K for the fiscal year ended December 31, 2017, filed February 26, 2018).
10.4	Third Amendment to Amended and Restated Credit Agreement dated as of December 21, 2018, by and among SemGroup Corporation, as borrower, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent.
10.5	Credit Agreement, dated as of August 19, 2014, among Buffalo Gulf Coast Terminals LLC, as the parent, HFOTCO LLC, as the borrower, Morgan Stanley Senior Funding, Inc. as administrative agent, Bank of America, N.A., as collateral agent, and the lenders party thereto (filed as Exhibit 10.2 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
10.6	Consent and Amendment No. 1 to Credit Agreement, dated as of June 14, 2017, among Buffalo Gulf Coast Terminals LLC, as the parent, HFOTCO LLC, as the borrower, Morgan Stanley Senior Funding, Inc. as administrative agent, Bank of America, N.A., as collateral agent, and the lenders party thereto (filed as Exhibit 10.3 to our current report on Form 8-K dated July 17, 2017, filed July 17, 2017).
10.7	Guarantee, Pledge and Security Agreement, dated as of July 17, 2017, by and among Buffalo Investor I, L.P., Buffalo Investor II, L.P., Beachhead Holdings LLC, Beachhead I LLC, Beachhead II, LLC and Buffalo Parent Gulf Coast Terminals, LLC (filed as Exhibit 10.3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2017, filed November 9, 2017).
10.8	Amendment and Restatement Agreement, dated as of June 26, 2018, among Buffalo Gulf Coast Terminals LLC, as the parent, HFOTCO LLC, as the borrower, the lenders party thereto, Toronto Dominion (Texas) LLC, as administrative agent, and Morgan Stanley Senior Funding, Inc. as existing agent (filed as Exhibit 10.1 to our current report on Form 8-K dated June 26, 2018, filed July 2, 2018).
10.9	Equity Distribution Agreement, dated November 8, 2016, by and among SemGroup Corporation, Wells Fargo Securities, LLC, Citigroup Global Markets Inc., and SunTrust Robinson Humphrey, Inc. (filed as Exhibit 1.1 to our current report on Form 8-K dated November 8, 2016, filed November 8, 2016).
10.10	Securities Purchase Agreement, dated as of January  16, 2018, by and among SemGroup Corporation, WP SemGroup Holdings, L.P., Atlas Point Energy Infrastructure Fund, LLC and several affiliates of Tortoise Capital Advisors, L.L.C. (filed as Exhibit 10.1 to our current report on Form 8-K dated January 16, 2018, filed January 19, 2018).
10.11*	SemGroup Corporation Board of Directors Compensation Plan, effective September 26, 2018 (filed as Exhibit 10.1 to our quarterly report on Form 10-Q for the quarter ended September 30, 2018, filed November 8, 2018).
10.12*	SemGroup Corporation Nonexecutive Directors’ Compensation Deferral Program (filed as Exhibit 10.7 to the Form 10).
10.13*	SemGroup Corporation Equity Incentive Plan, as amended and restated (filed as Annex A to our definitive proxy statement, filed April 13, 2016).

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Exhibit Number	Description
10.14*	SemGroup Corporation Equity Incentive Plan Form of Restricted Stock Award Agreement for Directors for awards granted on or after May 22, 2012 (filed as Exhibit 10.31 to our Amendment No. 1 to our annual report on Form 10-K for the fiscal year ended December 31, 2012, filed March 1, 2013).
10.15*	SemGroup Corporation Equity Incentive Plan Form of Restricted Stock Award Agreement for executive officers and employees in the United States for awards granted on or after March 1, 2013 (filed as Exhibit 10.33 to our annual report on Form 10-K for the fiscal year ended December 31, 2012, filed March 1, 2013).
10.16*	SemGroup Corporation Equity Incentive Plan Form of 2016 Performance Share Unit Award Agreement for executive officers and employees in the United States (filed as Exhibit 10.16 to our annual report on Form 10-K for the fiscal year ended December 31, 2015, filed February 26, 2016).
10.17*	SemGroup Corporation Equity Incentive Plan Form of Restricted Stock Award Agreement for executive officers and employees in the United States for awards granted pursuant to that certain Agreement and Plan of Merger, dated May 30, 2016, by and among SemGroup Corporation, PBMS, LLC, Rose Rock Midstream, L.P. and Rose Rock Midstream GP, LLC (filed as Exhibit 10.2 to our current report on Form 8-K dated September 30, 2016, filed September 30, 2016).
10.18*	SemGroup Corporation Equity Incentive Plan Form of 2017 Performance Share Unit Award Agreement for executive officers and employees in the United States (filed as Exhibit 10.12 to our annual report on Form 10-K for the fiscal year ended December 31, 2016, filed February 24, 2017).
10.19*	SemGroup Corporation Equity Incentive Plan Form of 2018 Performance Share Unit Award Agreement for executive officers and employees in the United States (filed as Exhibit 10.3 to our quarterly report on Form 10-Q for the quarter ended March 31, 2018, filed May 9, 2018).
10.20*	Employment Agreement dated as of March 6, 2014, by and among SemManagement, L.L.C., SemGroup Corporation, Rose Rock Midstream GP, LLC and Carlin G. Conner (filed as Exhibit 10.2 to our current report on Form 8-K dated March 6, 2014, filed March 12, 2014).
10.21*	Form of Severance Agreement between SemGroup Corporation and each of its executive officers other than Carlin G. Conner (filed as Exhibit 10.19 to our annual report on Form 10-K for the fiscal year ended December 31, 2017, filed February 26, 2018).
10.22*	SemGroup Corporation Short-Term Incentive Program (filed as Exhibit 10.1 to our current report on Form 8-K dated February 24, 2011, filed March 2, 2011).
10.23*	SemGroup Employee Stock Purchase Plan (filed as Appendix A to our definitive proxy statement, filed April 19, 2013).
21	Subsidiaries of SemGroup Corporation.
23.1	Consent of Independent Registered Public Accounting Firm - Grant Thornton LLP
23.2	Consent of Independent Registered Public Accounting Firm - Grant Thornton LLP
23.3	Consent of Independent Registered Public Accounting Firm - BDO USA, LLP.
23.4	Consent of Independent Auditors - BDO USA, LLP.
31.1	Rule 13a – 14(a)/15d – 14(a) Certification of Carlin G. Conner, Chief Executive Officer.
31.2	Rule 13a – 14(a)/15d – 14(a) Certification of Robert N. Fitzgerald, Chief Financial Officer.
32.1	Section 1350 Certification of Carlin G. Conner, Chief Executive Officer.
32.2	Section 1350 Certification of Robert N. Fitzgerald, Chief Financial Officer.
99.1	White Cliffs Pipeline, L.L.C. financial statements presented pursuant to Rule 3-09 of Regulation S-X.

61

Exhibit Number

Description

101

Interactive data files pursuant to Rule 405 of Regulation S-T: (i) the Consolidated Balance Sheets at December 31, 2018 and 2017, (ii) the Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended December 31, 2018, 2017 and 2016, (iii) the Consolidated Statements of Changes in Owners’ Equity for the years ended December 31, 2018, 2017 and 2016, (iv) the Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016, and (v) the Notes to Consolidated Financial Statements. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

* Management contract or compensatory plan or arrangement

Item 16. Form 10-K Summary

None

62

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SEMGROUP CORPORATION
February 28, 2019
	By:	/s/ Robert N. Fitzgerald
	Robert N. Fitzgerald
	Executive Vice President and
	Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

Signature	Title	Date
/s/ Carlin G. Conner	President, Chief Executive Officer and Director (Principal Executive Officer)	February 28, 2019
Carlin G. Conner
/s/ Robert N. Fitzgerald	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 28, 2019
Robert N. Fitzgerald
/s/ Thomas D. Sell	Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer)	February 28, 2019
Thomas D. Sell
/s/ Thomas R. McDaniel	Chairman of the Board and Director	February 28, 2019
Thomas R. McDaniel
/s/ Ronald A. Ballschmiede	Director	February 28, 2019
Ronald A. Ballschmiede
/s/ Sarah M. Barpoulis	Director	February 28, 2019
Sarah M. Barpoulis
/s/ Karl F. Kurz	Director	February 28, 2019
Karl F. Kurz
/s/ James H. Lytal	Director	February 28, 2019
James H. Lytal
/s/ William J. McAdam	Director	February 28, 2019
William J. McAdam

63

Index to Financial Statements

	Page
SemGroup Corporation
Reports of Independent Registered Public Accounting Firms	F-1
Consolidated Balance Sheets as of December 31, 2018 and 2017	F-4
Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended December 31, 2018, 2017 and 2016	F-5
Consolidated Statements of Changes in Owners’ Equity for the years ended December 31, 2018, 2017 and 2016	F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016	F-8
Notes to Consolidated Financial Statements	F-10

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

SemGroup Corporation

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of SemGroup Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of operations and comprehensive income (loss), changes in owner’ equity, and cash flows for each of the two years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 28, 2019 expressed an unqualified opinion.

Change in accounting principle

As disclosed in Note 3 to the consolidated financial statements, the Company has changed its method of accounting for revenue in the year ended December 31, 2018 due to the adoption of FASB Accounting Standards Codification Topic 606 Revenue from Contracts with Customers.

Change in reportable segments

We also have audited the adjustments described in Note 21 that were applied to the 2016 financial statements to retrospectively apply the change in reportable segments. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2016 financial statements of the Company other than with respect to such adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2016 financial statements taken as a whole.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2017.

Tulsa, Oklahoma

February 28, 2019

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

SemGroup Corporation

Tulsa, Oklahoma

We have audited, before the effects of the adjustments to retrospectively apply the changes in segmentation described in Note 21, the accompanying consolidated statements of operations and comprehensive income (loss), changes in owners’ equity, and cash flows of SemGroup Corporation ("the Company") for the year ended December 31, 2016. The 2016 financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above, before the effects of the adjustments to retrospectively apply the changes in segmentation described in Note 21, present fairly, in all material respects, the results of operations and cash flows of SemGroup Corporation for the year ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively apply the change in segmentation described in Note 21 and, accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by Grant Thornton LLP.

/s/ BDO USA, LLP

Dallas, Texas

February 24, 2017

F-2

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

SemGroup Corporation

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of SemGroup Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2018, and our report dated February 28, 2019 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 28, 2019

F-3

SEMGROUP CORPORATION

Consolidated Balance Sheets

(In thousands, except par value)

	December 31,
	2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	86,655		$	93,699
Accounts receivable (net of allowance of $2,244 and $2,628, respectively)	562,214			653,484
Receivable from affiliates	295			1,691
Inventories	49,397			101,665
Current assets held for sale	—			38,063
Other current assets	17,264			14,297
Total current assets	715,825			902,899
Property, plant and equipment (net of accumulated depreciation of $607,903 and $444,842, respectively)	3,457,326			3,315,131
Equity method investments	274,009			285,281
Goodwill	257,302			257,302
Other intangible assets (net of accumulated amortization of $90,014 and $56,409, respectively)	365,038			398,643
Other noncurrent assets, net	140,807			132,600
Noncurrent assets held for sale	—			84,961
Total assets	$	5,210,307		$	5,376,817
LIABILITIES, PREFERRED STOCK AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	494,792		$	587,898
Payable to affiliates	3,715			6,971
Accrued liabilities	115,095			131,407
Deferred revenue	11,060			7,518
Current liabilities held for sale	—			23,847
Other current liabilities	6,495			3,395
Current portion of long-term debt	6,000			5,525
Total current liabilities	637,157			766,561
Long-term debt	2,278,834			2,853,095
Deferred income taxes	55,789			46,585
Other noncurrent liabilities	38,548			38,495
Noncurrent liabilities held for sale	—			13,716
Commitments and contingencies (Note 14)
Redeemable preferred stock, $0.01 par value, $367,360 liquidation preference (authorized - 4,000 shares; issued - 350 and 0 shares, respectively)	359,658			—
SemGroup Corporation owners’ equity:
Common stock, $0.01 par value (authorized - 190,000 shares and 100,000 shares, respectively; issued - 79,270 and 79,708 shares, respectively)	786			786
Additional paid-in capital	1,615,969			1,770,117
Treasury stock, at cost (126 and 1,024 shares, respectively)	(705		)	(8,031		)
Accumulated deficit	(73,971		)	(50,706		)
Accumulated other comprehensive loss	(51,247		)	(53,801		)
Total SemGroup Corporation owners’ equity	1,490,832			1,658,365
Noncontrolling interest in consolidated subsidiary	349,489			—
Total owners' equity	1,840,321			1,658,365
Total liabilities, preferred stock and owners’ equity	$	5,210,307		$	5,376,817

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

F-4

SEMGROUP CORPORATION

Consolidated Statements of Operations and Comprehensive Income (Loss)

(Dollars in thousands, except per share amounts)

	Year Ended December 31,
	2018			2017			2016
Revenues:
Product	$	1,907,436		$	1,621,918		$	1,009,409
Service	518,764			391,266			265,030
Lease	17,549			5,843			—
Other	59,513			62,890			57,725
Total revenues	2,503,262			2,081,917			1,332,164
Expenses:
Costs of products sold, exclusive of depreciation and amortization shown below	1,823,095			1,514,891			873,431
Operating	284,769			254,764			212,099
General and administrative	91,568			113,779			84,183
Depreciation and amortization	209,254			158,421			98,804
Loss (gain) on disposal or impairment, net	(3,563		)	13,333			16,048
Total expenses	2,405,123			2,055,188			1,284,565
Earnings from equity method investments	57,672			67,331			73,757
Loss on issuance of common units by equity method investee	—			—			(41		)
Operating income	155,811			94,060			121,315
Other expenses (income):
Interest expense	149,714			103,009			62,650
Loss on early extinguishment of debt	—			19,930			—
Foreign currency transaction loss (gain)	9,501			(4,709		)	4,759
Loss on sale or impairment of non-operated equity method investment	—			—			30,644
Other income, net	(2,380		)	(4,632		)	(1,269		)
Total other expenses, net	156,835			113,598			96,784
Income (loss) from continuing operations before income taxes	(1,024		)	(19,538		)	24,531
Income tax expense (benefit)	23,304			(2,388		)	11,268
Income (loss) from continuing operations	(24,328		)	(17,150		)	13,263
Loss from discontinued operations, net of income taxes	—			—			(1		)
Net income (loss)	(24,328		)	(17,150		)	13,262
Less: net income attributable to noncontrolling interest	2,421			—			11,167
Net income (loss) attributable to SemGroup	(26,749		)	(17,150		)	2,095
Less: cumulative preferred stock dividends	23,790			—			—
Net income (loss) attributable to common shareholders	$	(50,539	)	$	(17,150	)	$	2,095
Net income (loss)	$	(24,328	)	$	(17,150	)	$	13,262
Other comprehensive income (loss), net of income taxes
Currency translation adjustments, net of income taxes	5,198			20,411			(14,224		)
Other, net of income taxes	(2,644		)	(298		)	(1,128		)
Total other comprehensive income (loss)	2,554			20,113			(15,352		)
Comprehensive income (loss)	(21,774		)	2,963			(2,090		)
Less: comprehensive income attributable to noncontrolling interest	2,421			—			11,167
Comprehensive income (loss) attributable to SemGroup	$	(24,195	)	$	2,963		$	(13,257	)
Net income (loss) attributable to SemGroup per common share (Note 19):
Basic	$	(0.65	)	$	(0.24	)	$	0.04
Diluted	$	(0.65	)	$	(0.24	)	$	0.04

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

F-5

SEMGROUP CORPORATION

Consolidated Statements of Changes in Owners’ Equity

(Dollars in thousands)

	Year Ended December 31, 2016
	Common Stock		Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Owners’ Equity
Balance at December 31, 2015	$	439	$	1,217,255		$	(5,593	)	$	(38,012	)	$	(58,562	)	$	80,829		$	1,196,356
Net income	—		—			—			2,095			—			11,167			13,262
Other comprehensive loss, net of income taxes	—		—			—			—			(15,352		)	—			(15,352		)
Issuance of common stock	86		228,460			—			—			—			—			228,546
Acquisition of Rose Rock's noncontrolling interest	133		198,381			—			—			—			(61,122		)	137,392
Distributions to noncontrolling interests	—		—			—			—			—			(32,133		)	(32,133		)
Dividends paid	—		(92,910		)	—			—			—			—			(92,910		)
Unvested dividend equivalent rights	—		521			—			—			—			66			587
Non-cash equity compensation	—		8,752			—			—			—			1,193			9,945
Issuance of common stock under compensation plans	1		1,236			—			—			—			—			1,237
Repurchase of common stock	—		—			(965		)	—			—			—			(965		)
Balance at December 31, 2016	$	659	$	1,561,695		$	(6,558	)	$	(35,917	)	$	(73,914	)	$	—		$	1,445,965

	Year Ended December 31, 2017
	Common Stock		Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Owners’ Equity
Balance at December 31, 2016	$	659	$	1,561,695		$	(6,558	)	$	(35,917	)	$	(73,914	)	$	1,445,965
Adoption of ASU 2016-09 and other	—		(2,073		)	—			2,361			—			288
Net loss	—		—			—			(17,150		)	—			(17,150		)
Other comprehensive income, net of income taxes	—		—			—			—			20,113			20,113
Dividends paid	—		(129,925		)	—			—			—			(129,925		)
Unvested dividend equivalent rights	—		(1,033		)	—			—			—			(1,033		)
Non-cash equity compensation	—		10,066			—			—			—			10,066
Issuance of common stock	124		330,217			—			—			—			330,341
Issuance of common stock under compensation plans	3		1,170			—			—			—			1,173
Repurchase of common stock	—		—			(1,473		)	—			—			(1,473		)
Balance at December 31, 2017	$	786	$	1,770,117		$	(8,031	)	$	(50,706	)	$	(53,801	)	$	1,658,365

	Year Ended December 31, 2018
	Common Stock		Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Accumulated Other Comprehensive Loss			Noncontrolling interests		Total Owners’ Equity
Balance at December 31, 2017	$	786	$	1,770,117		$	(8,031	)	$	(50,706	)	$	(53,801	)	$	—	$	1,658,365
Adoption of ASC 606	—		—			—			11,513			—			—		11,513
Net income (loss)	—		—			—			(26,749		)	—			2,421		(24,328		)
Other comprehensive income, net of income taxes	—		—			—			—			2,554			—		2,554
Dividends paid	—		(165,842		)	—			—			—			—		(165,842		)
Unvested dividend equivalent rights	—		(728		)	—			—			—			—		(728		)
Non-cash equity compensation	—		11,398			—			—			—			—		11,398

F-6

Equity issuance to noncontrolling interest	—			—		—			—			—			350,000			350,000
Cash distributions to noncontrolling interest	—			—		—			—			—			(2,932		)	(2,932		)
Issuance of common stock under compensation plans	2			1,024		—			—			—			—			1,026
Retirement of treasury stock	(2		)	—		8,031			(8,029		)	—			—			—
Repurchase of common stock	—			—		(705		)	—			—			—			(705		)
Balance at December 31, 2018	$	786		$	1,615,969	$	(705	)	$	(73,971	)	$	(51,247	)	$	349,489		$	1,840,321

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

F-7

SEMGROUP CORPORATION

Consolidated Statements of Cash Flows

(Dollars in thousands)

	Year Ended December 31,
	2018			2017			2016
Cash flows from operating activities:
Net income (loss)	$	(24,328	)	$	(17,150	)	$	13,262
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	209,254			158,421			98,804
Loss on disposal or impairment, net	(3,563		)	13,333			16,048
Earnings from equity method investments	(57,672		)	(67,331		)	(73,757		)
Loss on issuance of common units by equity method investee	—			—			41
Loss on sale or impairment of non-operated equity method investee	—			—			30,644
Distributions from equity method investments	57,625			66,748			76,442
Amortization of debt issuance costs	7,651			6,221			7,561
Loss on early extinguishment of debt	—			19,930			—
Deferred tax expense (benefit)	8,311			(9,829		)	8,447
Non-cash equity compensation	11,522			10,253			10,216
Provision for uncollectible accounts receivable, net of recoveries	390			165			(527		)
Gain on pension curtailment	—			(3,008		)	—
Inventory valuation adjustment	5,200			455			—
Currency (gain) loss	9,501			(4,709		)	4,759
Changes in operating assets and liabilities (Note 22)	45,813			(33,023		)	(21,966		)
Net cash provided by operating activities	269,704			140,476			169,974
Cash flows from investing activities:
Capital expenditures	(390,734		)	(462,713		)	(312,456		)
Proceeds from sale of equity method investment and other long-lived assets	1,958			314,821			151
Contributions to equity method investments	(7,781		)	(26,444		)	(4,188		)
Payments to acquire business, net of cash acquired	—			(294,239		)	—
Proceeds from sale of common units of equity method investee	—			—			60,483
Proceeds from business divestitures	147,787			—			—
Distributions from equity method investments in excess of equity in earnings	19,100			28,774			27,726
Net cash used in investing activities	(229,670		)	(439,801		)	(228,284		)
Cash flows from financing activities:
Debt issuance costs	(4,720		)	(11,116		)	(7,728		)
Borrowings on credit facilities and issuance of senior unsecured notes	1,258,500			1,525,377			382,500
Principal payments on credit facilities and other obligations	(1,839,894		)	(1,052,428		)	(396,890		)
Debt extinguishment costs	—			(16,293		)	—
Equity issuance to noncontrolling interest	350,000			—			—
Distributions to noncontrolling interests	(2,932		)	—			(32,133		)
Proceeds from preferred stock issuance, net of offering costs	342,299			—			—
Repurchase of common stock for payment of statutory taxes due on equity-based compensation	(705		)	(1,473		)	(965		)
Dividends paid	(148,482		)	(129,925		)	(92,910		)
Proceeds from issuance of common stock under employee stock purchase plan	930			1,114			1,010
Proceeds from issuance of common shares, net of offering costs	—			—			223,025
Net cash provided by (used in) financing activities	(45,004		)	315,256			75,909

F-8

Effect of exchange rate changes on cash and cash equivalents	(2,074		)	3,552		(1,479		)
Change in cash and cash equivalents	(7,044		)	19,483		16,120
Cash and cash equivalents at beginning of period	93,699			74,216		58,096
Cash and cash equivalents at end of period	$	86,655		$	93,699	$	74,216

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

F-9

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

1. OVERVIEW

SemGroup Corporation is a Delaware corporation headquartered in Tulsa, Oklahoma that provides diversified services for end-users and consumers of crude oil, natural gas, natural gas liquids and refined products.

The accompanying consolidated financial statements include the activities of SemGroup Corporation and its subsidiaries. The terms “we,” “our,” “us,” “the Company” and similar language used in these notes to consolidated financial statements refer to SemGroup Corporation and its subsidiaries.

At December 31, 2018, our operating and reportable segments include the following:

• our U.S. Liquids segment operates crude oil pipelines, truck transportation, storage, terminals and marketing businesses in the U.S. Additionally, we store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship and operate a residual fuel oil storage terminal in the U.S. Gulf Coast;

• our U.S. Gas segment provides natural gas gathering, processing and marketing services. U.S. Gas aggregates gas supplies from the wellhead and provides various services to producers that condition the wellhead gas production for downstream markets; and

• our Canada segment provides natural gas gathering and processing services in Alberta, Canada and owns working interests in, and operates, a network of natural gas gathering and transportation pipelines and natural gas processing plants.

Additionally, we own an 11.78% interest in the general partner of NGL Energy Partners LP ("NGL Energy") (NYSE: NGL). See Note 4 for discussion of the disposal of our Mexican asphalt business and our U.K. operations during the year ended December 31, 2018.

2. CONSOLIDATION AND BASIS OF PRESENTATION

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States.

Consolidated subsidiaries

Our consolidated financial statements include the accounts of our controlled subsidiaries. All significant transactions between our consolidated subsidiaries have been eliminated. Outside ownership interests in consolidated subsidiaries are reported as noncontrolling interests in the consolidated financial statements.

Proportionally consolidated assets

Our Canada segment owns undivided interests in certain natural gas gathering and processing assets, for which we record only our proportionate share of the assets on the consolidated balance sheets. The net book value of the property, plant and equipment recorded by us associated with these undivided interests is approximately $570.8 million at December 31, 2018. We serve as operator of these facilities and incur the costs of operating the facilities (recorded as operating expenses in the consolidated statements of operations) and charge the other owners, which are also customers, for their proportionate share of the costs (recorded as other revenue in the consolidated statements of operations).

Equity method investments

We own a 51% interest in White Cliffs Pipeline, LLC ("White Cliffs"), which we account for under the equity method as the other owners have substantive rights to participate in its management. White Cliffs is included in our U.S. Liquids segment.

We own an 11.78% interest in the general partner of NGL Energy Partners LP (NYSE: NGL) ("NGL Energy") which we account for under the equity method. Our investment in NGL Energy is included in Corporate and Other for segment reporting.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures in the financial statements. Our significant estimates include, but are not limited to: (1) allowances for doubtful accounts receivable; (2) estimated useful lives of assets, which impact depreciation and amortization; (3) estimated fair values used in impairment tests; (4) fair values of derivative instruments; (5) valuation allowances for

F-10

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, Continued

deferred tax assets; and (6) accrual and disclosure of contingent losses. Although management believes these estimates are reasonable, actual results could differ materially from these estimates.

CASH AND CASH EQUIVALENTS—Cash includes currency on hand and demand and time deposits with banks or other financial institutions. Cash equivalents include highly liquid investments with maturities of three months or less at the date of purchase. Balances at financial institutions may exceed federally insured limits.

ACCOUNTS RECEIVABLE—Accounts receivable are reported net of the allowance for doubtful accounts. Our assessment of the allowance for doubtful accounts is based on several factors, including the overall creditworthiness of our customers, existing economic conditions, and the amount and age of past due accounts. We enter into netting arrangements with certain counterparties to help mitigate credit risk. Receivables subject to netting are presented as gross receivables (with the related accounts payable also presented gross) until such time as the balances are settled. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.

In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments", which introduces new guidance for estimating credit losses on certain types of financial instruments based on expected losses and the timing of the recognition of such losses. For public entities, this ASU is effective for annual periods beginning after December 15, 2019, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We will adopt this guidance in the first quarter of 2020. The impact is not expected to be material.

INVENTORY—Inventory consists of crude oil and is valued at the lower of cost or net realizable value, with cost generally determined using the weighted-average method. The cost of inventory includes applicable transportation costs.

We enter into exchanges with third parties whereby we acquire products that differ in location, grade, or delivery date from products we have available for sale. These exchanges are valued at cost, and although a transportation, location or product differential may be recorded, generally no gain or loss is recognized.

During the year ended December 31, 2018 and 2017, our U.S. Liquids segment recorded non-cash charges of $5.2 million and $0.5 million, respectively, to write-down crude oil inventory to the lower of cost or net realizable value. Asphalt inventory related to our former Mexican operations of $15.6 million was classified as held for sale at December 31, 2017.

PROPERTY, PLANT AND EQUIPMENT—Property, plant and equipment is recorded at cost. We capitalize costs that extend or increase the future economic benefits of property, plant and equipment, and expense maintenance costs that do not. When assets are disposed of, their cost and related accumulated depreciation are removed from the balance sheet, and any resulting gain or loss is recorded as a gain or loss on disposal or impairment in the consolidated statements of operations and comprehensive income (loss).

Our Canada segment operates plants which periodically undergo planned major maintenance activities, typically occurring every four to five years.  Planned major maintenance projects that do not increase the overall life or capacity of the related assets are recorded in operating expense as incurred, whereas major maintenance activity costs that materially increase the life or capacity of the underlying assets are capitalized. When maintenance expenses are recoverable from the producers who use the plants, they are recorded as revenue, and typically include a 10% overhead fee. 

Depreciation is calculated primarily using the straight-line method over the following estimated useful lives:

Pipelines and related facilities	10 – 31 years
Storage and terminal facilities	10 – 25 years
Natural gas gathering and processing facilities	10 – 31 years
Trucking equipment and other	3 – 7 years
Office property and equipment	3 – 31 years

Construction in process is reclassified to the fixed asset categories above and depreciation commences once the asset has been placed in-service.

LINEFILL—Pipelines and storage facilities generally require a minimum volume of product in the system to enable the system to operate. Such product, known as linefill, is generally not available to be withdrawn from the system. Linefill

F-11

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, Continued

owned by us in facilities operated by us is recorded at historical cost, is included in property, plant and equipment in the consolidated balance sheets, and is not depreciated. We also own linefill in third-party facilities, which is included in inventory on the consolidated balance sheets.

IMPAIRMENT OF LONG-LIVED ASSETS—We test long-lived asset groups for impairment when events or circumstances indicate that the net book value of the asset group may not be recoverable. We test an asset group for impairment by estimating the undiscounted cash flows expected to result from its use and eventual disposition. If the estimated undiscounted cash flows are lower than the net book value of the asset group, we then estimate the fair value of the asset group and record a reduction to the net book value of the assets and a corresponding impairment loss.

GOODWILL—We test goodwill for impairment on an annual basis, or more often if circumstances warrant, by estimating the fair value of the reporting unit to which the goodwill relates and comparing this fair value to the net book value of the reporting unit. If fair value is less than net book value, we reduce the book value accordingly and record a corresponding impairment loss. Our policy is to test goodwill for impairment on October 1 of each year.

FINITE-LIVED INTANGIBLE ASSETS—Finite-lived intangible assets are stated at cost, net of accumulated amortization, which is recorded on a straight-line or accelerated basis over the life of the asset. We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value.

EQUITY METHOD INVESTMENTS—We account for an investment under the equity method when we have significant influence over, but not control of, the significant operating decisions of the investee. Under the equity method, we record in the consolidated statements of operations our share of the earnings or losses of the investee, with a corresponding adjustment to the investment balance on our consolidated balance sheet. When we receive a distribution from an equity method investee, we record a corresponding reduction to the investment balance. When an equity method investee issues additional ownership interests which dilute our ownership interest, we recognize a gain or loss in our consolidated statements of operations.

We assess our equity method investments for impairment when circumstances indicate that the carrying value may not be recoverable and record an impairment when a decline in value is considered to be other than temporary.

For equity method investments for which we do not expect financial information to be consistently available on a timely basis to apply the equity method currently, our policy is to apply the equity method consistently on a one-quarter lag.

DEBT ISSUANCE COSTS—Costs incurred in connection with the issuance of long-term debt are reported as a reduction to the carrying value of the associated debt instrument and are amortized to interest expense using the straight-line method over the term of the related debt. Use of the straight-line method of amortization does not differ materially from the “effective interest” method.

Capitalized loan fees related to our revolving credit facility are presented as other noncurrent assets.

COMMODITY DERIVATIVE INSTRUMENTS—We generally record the fair value of commodity derivative instruments on the consolidated balance sheets and the change in fair value as an increase or decrease to product revenue.

As shown in Note 10, the fair value of commodity derivatives at December 31, 2018 and 2017 are recorded to other current assets or other current liabilities on the consolidated balance sheets. Related margin deposits are recorded to other current assets or other current liabilities on the consolidated balance sheets. Margin deposits are not generally netted against derivative assets or liabilities.

The fair value of a derivative contract is determined based on the nature of the transaction and the market in which the transaction was executed. Quoted market prices, when available, are used to value derivative transactions. In situations where quoted market prices are not readily available, we estimate the fair value using other valuation techniques that reflect the best information available under the circumstances. Fair value measurements of derivative assets include consideration of counterparty credit risk. Fair value measurements of derivative liabilities include consideration of our creditworthiness.

We have elected “normal purchase” and “normal sale” treatment for certain commitments to purchase or sell petroleum products at future dates. This election is only available when a transaction that would ordinarily meet the definition of a derivative but instead is expected to result in physical delivery of product over a reasonable period in the normal course of business and is not expected to be net settled. Agreements accounted for under this election are not recorded at fair value; instead, the transaction is recorded when the product is delivered.

F-12

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, Continued

CONTINGENT LOSSES—We record a liability for a contingent loss when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. We record attorneys’ fees incurred in connection with a contingent loss at the time the fees are incurred. We do not record liabilities for attorneys’ fees that are expected to be incurred in the future.

ASSET RETIREMENT OBLIGATIONS—Asset retirement obligations include legal or contractual obligations associated with the retirement of long-lived assets, such as requirements to incur costs to dispose of equipment or to remediate the environmental impacts of the normal operation of the assets. We record liabilities for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made.

PREFERRED STOCK—Preferred stock is classified as debt, equity or mezzanine equity based on its redemption features. Preferred stock with redemption features outside of the control of the issuer, such as contingent redemption features, is classified as mezzanine equity. Preferred stock with mandatory redemption features is classified as debt. Preferred stock with no redemption features, or redemption features over which the issuer has control, is classified as equity.

REVENUE RECOGNITION—Product sales revenues are recognized at the time control of the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. Service revenues are generally recognized overtime as the service is performed. Certain revenue transactions are reported on a net basis, including certain buy/sell transactions (see “Purchases and Sales of Inventory with the Same Counterparty”). Other revenue primarily represents operating cost recovery from working interest owners, who are also customers, in certain processing plants and is recorded when earned in accordance with the terms of related agreements. Taxes collected from customers and remitted to governmental authorities are recorded on a net basis (excluded from revenue).

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers”, as amended, which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than were required under previous U.S. GAAP.

On January 1, 2018, we adopted the guidance of ASU 2014-09, codified as Accounting Standards Codification 606 - Revenue from Contracts with Customers (“ASC 606”), using a modified retrospective approach. Upon adoption, a reduction to accumulated deficit of $11.5 million was recorded to reflect the impact of adoption related to uncompleted contracts at the date of adoption. The impacts of adoption to the current period results are as follows (in thousands):

	December 31, 2018
	Under ASC 606			Under ASC 605			Increase/(Decrease)
Accounts receivable, net	$	562,214		$	562,057		$	157
Other noncurrent assets	$	140,807		$	119,911		$	20,896
Other current liabilities	$	6,495		$	6,538		$	(43	)
Deferred income taxes	$	55,789		$	50,045		$	5,744
Accumulated deficit	$	(73,971	)	$	(89,324	)	$	15,353

	Year Ended December 31, 2018
	Under ASC 606			Under ASC 605			Increase/(Decrease)
Revenue	$	2,503,262		$	2,483,962		$	19,300
Cost of sales	$	1,823,095		$	1,808,129		$	14,966
General and administrative expense	$	91,568		$	91,168		$	400
Income tax benefit	$	23,304		$	23,209		$	95
Net loss	$	(24,328	)	$	(28,167	)	$	3,839

F-13

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, Continued

Net loss attributable to common shareholders	$	(50,539	)	$	(54,378	)	$	3,839
Net loss per common share:
Basic	$	(0.65	)	$	(0.70	)	$	0.05
Diluted	$	(0.65	)	$	(0.70	)	$	0.05

• Changes to revenue primarily relate to the timing of recognition of deficiencies on take-or-pay agreements for which there is a contractual make-up period and a change to reporting certain gas gathering and processing fees as revenue rather than a reduction of cost of sales. Under ASC 605 - Revenue (“ASC 605”), revenue related to deficiencies with a make-up period was deferred until the contractual right to make-up a deficiency expired. Under ASC 606, we recognize all or a portion of revenue related to deficiencies before the make-up period expires if we determine that it is probable that the customer will not make-up all or some of its deficient volumes, for example if there is insufficient capacity to make up the deficient volumes. This may lead to earlier recognition of deficiency revenues under ASC 606 as compared with ASC 605.

• Changes to cost of sales are due to how certain gathering and processing fees related to percentage of proceeds contracts are treated as revenues rather than reductions to purchase price of commodities (cost of sales).

• Changes to accounts receivable, net and noncurrent receivables (included in other noncurrent assets on the condensed consolidated balance sheets) primarily relate to the timing of recognizing take-or-pay deficiencies with make-up rights as discussed above. Noncurrent receivables relate to contracts for which we do not have the right to bill the customer for deficiencies until the contract expiration date.

• Changes to other noncurrent assets include success fee payments to third parties for certain contracts which were expensed as incurred under ASC 605, but which have been recognized as assets under ASC 606 and are amortized to general and administrative expense in the consolidated statement of operations and comprehensive income (loss).

• Changes to deferred income taxes primarily relate to the deferred tax impact of adoption entries.

• Changes to retained earnings are due to the impact of adoption at January 1, 2018, as described above, and cumulative differences in net income through December 31, 2018.

See Note 18 for additional information.

COSTS OF PRODUCTS SOLD—Costs of products sold consists of the cost to purchase the product, the cost to transport the product to the point of sale, and the cost to store the product until it is sold.

PURCHASES AND SALES OF INVENTORY WITH THE SAME COUNTERPARTY—We routinely enter into transactions to purchase inventory from, and sell inventory to, the same counterparty. Such transactions that are entered into in contemplation of one another are recorded on a net basis.

CURRENCY TRANSLATION—The consolidated financial statements are presented in U.S. dollars. Our segments operated in four countries, until the disposal of our U.K. and Mexican operations in early 2018, and each segment has identified a “functional currency,” which is the primary currency in the environment in which the segment operates. The functional currencies included the U.S. dollar, the Canadian dollar, the British pound sterling, and the Mexican peso. Subsequent to the disposal of our U.K. and Mexican operations, our functional currencies are the U.S. and Canadian dollars.

At the end of each reporting period, the assets and liabilities of each segment are translated from its functional currency to U.S. dollars using the exchange rate at the end of the month. The monthly results of operations of each segment are generally translated from its functional currency to U.S. dollars using the average exchange rate during the month. Changes in exchange rates result in currency translation gains and losses, which are recorded within other comprehensive income (loss).

Certain segments also enter into transactions in currencies other than their functional currencies. At the end of each reporting period, each segment re-measures the related receivables, payables, and cash to its functional currency using the exchange rate at the end of the period. Changes in exchange rates between the time the transactions were entered into and the end of the reporting period result in currency transaction gains or losses, which are recorded in the consolidated statements of operations.

F-14

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, Continued

INCOME TAXES—Deferred income taxes are accounted for under the liability method, which takes into account the differences between the basis of the assets and liabilities for financial reporting purposes and amounts recognized for income tax purposes. We record valuation allowances on deferred tax assets when, in the opinion of management, it is more likely than not that the asset will not be recovered.

We monitor uncertain tax positions and we recognize tax benefits only when management believes the relevant tax positions would more likely than not be sustained upon examination. We record any interest and any penalties related to income taxes within income tax expense in the consolidated statements of operations.

In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory”, which requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. We adopted this guidance in the first quarter of 2018. The impact was not material.

In February 2018, the FASB issued ASU 2018-02, “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. For public entities, this ASU is effective for annual periods beginning after December 15, 2018, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We adopted this guidance in the first quarter of 2019. We recorded a $10.9 million adjustment to retained earnings upon adoption.

RECLASSIFICATIONS—Certain reclassifications have been made to conform prior year balances to the current year presentation.

PENSION BENEFITS—Pension cost and obligations are actuarially determined and are affected by assumptions including expected return on plan assets, discount rates, compensation increases, and employee turnover rates. We evaluate our assumptions periodically and make adjustments to these assumptions and the recorded liability as necessary. Actuarial gains or losses are amortized on a straight-line basis over the expected remaining service life of employees in the pension plan.

In March 2017, the FASB issued ASU 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost”, which requires that an employer disaggregate the service cost component from other components of net benefit cost. This ASU also provides explicit guidance on how to present the service cost component and the other components of net benefit cost in the income statement and allows only the service cost component of net benefit cost to be eligible for capitalization. We adopted this guidance retrospectively in the first quarter of 2018. For the years ended December 31, 2017 and 2016, we reclassified $3.2 million, of non-service pension gains and $0.3 million of non-service pension costs, respectively, from “general and administrative expense” to “other expense (income)”.

EQUITY-BASED COMPENSATION—We grant certain of our employees and non-managerial directors equity-based compensation awards which vest contingent on continued service of the recipient and, in some cases, on their achievement of specific performance targets or market conditions. We record compensation expense for these outstanding awards over applicable service or performance periods based on their grant date fair value with a corresponding increase to additional paid-in capital.

In May 2017, the FASB issued ASU 2017-09, “Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting”, to provide clarity and reduce diversity in practice in determining which changes to terms or conditions of a share-based payment award require an entity to apply modification accounting under Accounting Standards Codification Topic 718. We adopted this guidance in the first quarter of 2018. The impact was not material.

NONCONTROLLING INTEREST—Noncontrolling interests represents a 49% interest in our consolidated subsidiary, Maurepas Pipeline, LLC in the form of Class B shares of Maurepas Pipeline, LLC. The Class B shares provide for a monthly preference on Maurepas Pipeline, LLC distributions for the owners.

COMPREHENSIVE INCOME (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)—Comprehensive income (loss) is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Our comprehensive income (loss) includes currency translation adjustments and changes in the funded status of pension benefit plans.

F-15

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, Continued

OTHER RECENT ACCOUNTING PRONOUNCEMENTS— On August 27, 2018, the FASB issued ASU 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement”, which modifies the disclosure requirements in Topic 820 by removing, adding or modifying certain fair value measurement disclosures. For public entities, this ASU is effective for annual periods beginning after December 15, 2019, and interim periods therein. Early adoption is permitted. We will adopt this guidance in the first quarter of 2020. The impact is not expected to be material.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)”, to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The update addresses eight different transaction types and clarifies how to classify each in the statement of cash flows, where previously there was unclear or no specific guidance. We adopted this guidance in the first quarter of 2018. The impact was not material.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”, as amended, which amends the existing lease guidance to require lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by operating and finance leases and to disclose additional quantitative and qualitative information about leasing arrangements. This ASU, as amended, also provides clarifications surrounding the presentation of the effects of leases in the income statement and statement of cash flows. For public entities, this ASU will be effective for annual periods beginning after December 15, 2018, and interim periods within those years. We have elected the package of practical expedients such that we will not reassess whether any expired or existing contracts contain leases, we will not reassess the lease classification for any expired or existing leases and we will not reassess initial direct costs for any leases. Additionally, we have elected the practical expedient not to reassess certain land easements. As such, certain storage tank, pipeline leases and land easements, which are not currently treated as leases, maybe become leases as these agreements are renewed or modified depending on the terms of the renewal or modification. Additionally, the classification for existing leases may change as agreements are renewed or modified. We adopted the standard at January 1, 2019, and recorded approximately $100 million of right of use assets and lease liabilities. We recognized a cumulative-effect adjustment to the opening balance of retained earnings of approximately $0.2 million as allowed by ASU 2018-11, “Leases (Topic 842): Targeted Improvements”.

4. DISPOSALS OR IMPAIRMENTS OF LONG-LIVED ASSETS

Year ended December 31, 2018

On January 5, 2018, we entered into a definitive agreement to sell our Mexican asphalt business. The sale closed on March 15, 2018, for $70.7 million. We recorded a pre-tax gain on disposal of $1.6 million for the year ended December 31, 2018. The Mexican asphalt business contributed $2.3 million of pre-tax income for the year ended December 31, 2018, excluding the gain on disposal. At December 31, 2017, the assets and liabilities of the Mexican asphalt business were written down to net realizable value by recording an impairment of $13.5 million, including the impact of a deferred foreign currency translation loss of $30.9 million, and classified as held for sale. The Mexican asphalt business contributed a pre-tax loss of $8.2 million for the year ended December 31, 2017, including the write-down to net realizable value. At December 31, 2017, the Mexican assets and liabilities held for sale included $29.4 million of property, plant and equipment, $34.9 million of current assets and $19.4 million of current liabilities, prior to the write-down to net realizable value.

On February 23, 2018, we entered into an agreement to sell our U.K. operations, SemLogistics. The sale closed on April 12, 2018, for $73.1 million. We recorded a pre-tax gain on disposal of $0.4 million for the year ended December 31, 2018. The U.K. business contributed pre-tax income of $5.4 million for the year ended December 31, 2018, excluding the gain on disposal. At December 31, 2017, the assets and liabilities of the U.K. operations were written down to net realizable value by recording an impairment of $76.7 million, including the impact of a deferred foreign currency translation loss of $22.8 million, and classified as held for sale. The U.K. business contributed a pre-tax loss of $73.0 million for the year-ended December 31, 2017, including the write-down to net realizable value. At December 31, 2017, the U.K. assets and liabilities held for sale included $136.8 million of property, plant and equipment, $3.1 million of current assets and $4.4 million of current liabilities, prior to the write-down to net realizable value.

Year ended December 31, 2017

The following amounts are included in "loss on disposal or impairment, net" on our consolidated statement of operations and comprehensive income (loss) for the year ended December 31, 2017 (in thousands):

F-16

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

4. DISPOSALS AND IMPAIRMENTS OF LONG-LIVED ASSETS, Continued

	Segment	Loss/(Gain)
Write-down of Mexican asphalt business to net realizable value	Corporate and Other	$	13,511
Write-down U.K. operations to net realizable value	Corporate and Other	76,661
Sherman natural gas gathering and processing asset impairment	U.S. Gas	30,985
Crude oil trucking goodwill impairment (Note 9)	U.S. Liquids	26,628
Crude oil trucking intangible asset impairment (Note 9)	U.S. Liquids	12,087
Gain on sale of Glass Mountain Pipeline LLC (Note 6)	U.S. Liquids	(150,266		)
Other		3,727
Loss on disposal or impairment, net		$	13,333

At December 31, 2017, we recorded a $31.0 million impairment of our Sherman, Texas natural gas gathering and processing assets of our U.S. Gas segment. Evaluation of capital raising alternatives indicated that the carrying value of our Sherman, Texas assets might be in excess of fair value. We compared the forecasted undiscounted cash flows for the assets to the carrying value of the assets, which indicated that the carrying value of assets was impaired. We used an income approach, based on a discounted cash flow model, to estimate the fair value of the assets and recorded a non-cash impairment.

Impairments are based on unobservable inputs and considered to be Level 3 measurements. See Note 6 for discussion of the sale of our equity method investment in Glass Mountain Pipeline LLC ("Glass Mountain"). See Note 9 for discussion of impairment of goodwill and finite-lived intangible assets recorded by our U.S. Liquids segment.

Year ended December 31, 2016

There were no significant disposals or impairments of long-lived assets during the year ended December 31, 2016. See Note 6 for discussion of our sale of NGL Energy limited partner units accounted for under the equity method. See Note 9 for discussion of goodwill impairment related to our U.S. Gas segment.

5. ACQUISITIONS

Year ended December 31, 2018

There were no significant acquisitions during the year ended December 31, 2018.

Year ended December 31, 2017

On July 17, 2017, we acquired Houston Fuel Oil Terminal Company (“HFOTCO”), one of the largest oil terminals in the U.S., for a purchase price paid in two payments. The first payment consisted of $297.8 million in cash funded from our revolving credit facility, the issuance of approximately 12.4 million shares of our Class A common stock with an acquisition date fair value of $330 million, and the assumption of existing HFOTCO debt of approximately $766 million. On April 17, 2018, we made the final payment related to the HFOTCO acquisition in the amount of $579.6 million. The payment was funded through revolving credit facility borrowings and cash on hand.

From the acquisition date through December 31, 2017, HFOTCO contributed $76.9 million of revenue and $2.4 million of net loss to our consolidated financial results. Our results for the year ended December 31, 2017, include $19.2 million of acquisition related expenses, which are included in "general and administrative expenses" in our consolidated statement of operations and comprehensive income (loss). Included in the results of HFOTCO for the post acquisition period is a gain of $3.0 million related to the curtailment of HFOTCO’s defined benefit pension plan. Subsequent to the acquisition, SemGroup closed the plan to new members and stopped the accrual of future benefits under the plan to better align HFOTCO with SemGroup’s compensation strategy. Accordingly, the pension liability assumed at acquisition of $10.0 million was reduced to $7.0 million as of December 31, 2017. HFOTCO is included in the U.S. Liquids segment.

F-17

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

5.    ACQUISITIONS, Continued

Year ended December 31, 2016

On September 30, 2016, we completed the acquisition of the outstanding common limited partner interests of Rose Rock Midstream, L.P. ("Rose Rock") which we did not already own (the "Merger"). We issued 13.1 million common shares as consideration and recorded a reduction to equity for $5.3 million of fees associated with the issuance. In addition, we recorded a reduction to our deferred tax liabilities and offsetting increase to additional paid-in capital of $143.3 million associated with the transaction. This non-cash adjustment represents the deferred tax impact of the difference between the book value of the noncontrolling interests acquired and the tax basis which is stepped-up to the fair market value of the consideration, which includes the common shares issued and the assumption of liabilities associated with the noncontrolling interests.

We accounted for the Merger in accordance with FASB Accounting Standards Codification 810, Consolidation — Overall — Changes in a Parent’s Ownership Interest in a Subsidiary. As SemGroup controlled Rose Rock both before and after the Merger, the changes in SemGroup’s ownership interest in Rose Rock were accounted for as an equity transaction and no gain or loss was recognized in SemGroup’s consolidated statements of operations and comprehensive income (loss) as a result of the Merger. Subsequent to the Merger, Rose Rock was a wholly owned subsidiary of SemGroup.

Substantially all of Rose Rock's assets were pledged as collateral under its senior secured revolving credit facility agreement which was terminated following the Merger. Substantially all of Rose Rock's assets are now pledged as collateral under SemGroup's senior secured revolving credit facility. Rose Rock's senior unsecured notes were assumed by SemGroup.

6. EQUITY METHOD INVESTMENTS

Our equity method investments consist of the following (in thousands):

	December 31,
	2018		2017
White Cliffs	$	255,043	$	266,362
NGL Energy	18,966		18,919
Total equity method investments	$	274,009	$	285,281

Our earnings from equity method investments consist of the following (in thousands):

	Year Ended December 31,
	2018		2017			2016
White Cliffs	$	57,625	$	59,851		$	69,007
Glass Mountain	—		7,494			2,562
NGL Energy(1)	47		(14		)	2,188
Total earnings from equity method investments	$	57,672	$	67,331		$	73,757

(1) Excluding a loss on issuance of common units of $41.0 thousand for the year ended December 31, 2016.

Cash distributions received from equity method investments consist of the following (in thousands):

	Year Ended December 31,
	2018		2017		2016
White Cliffs	$	76,725	$	77,511	$	88,839
Glass Mountain	—		18,011		10,456
NGL Energy	—		—		4,873
Total cash distributions received from equity method investments	$	76,725	$	95,522	$	104,168

F-18

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

6. EQUITY METHOD INVESTMENTS, Continued

White Cliffs

We own a 51% interest in White Cliffs, which we account for under the equity method. The equity in earnings of White Cliffs for the years ended December 31, 2018, 2017 and 2016, reported in our consolidated statements of operations and comprehensive income (loss), is less than 51% of the net income of White Cliffs for the same period. This is primarily due to certain general and administrative expenses we incur in managing the operations of White Cliffs that the other members are not obligated to share. In addition, our equity in earnings is also impacted by the elimination of revenue on the sale of inventory to White Cliffs. Revenue related to inventory transactions with White Cliffs is deferred until a sale of the inventory has been made with a third party.

The members of White Cliffs are required to contribute capital to White Cliffs to fund various projects. For the years ended December 31, 2018, 2017 and 2016, we contributed $6.5 million, $1.4 million and $2.2 million, respectively, to fund White Cliffs capital projects. In 2018, we announced that we will convert one of the White Cliffs 12-inch carrier pipelines from crude service to natural gas liquids service. Remaining contributions related to the conversion project will be paid in 2019 and are expected to total $27.2 million. The project is expected to be completed during the fourth quarter of 2019.

Our membership interest in White Cliffs is significant as defined by Securities and Exchange Commission’s Regulation S-X Rule 1-02(w). Accordingly, as required by Regulation S-X Rule 3-09, we have included the audited financial statements of White Cliffs as of December 31, 2018 and 2017 and for each of the three years in the period ended December 31, 2018 as an exhibit to this Form 10-K.

Glass Mountain

On December 22, 2017, we completed the sale of our equity method investment in Glass Mountain for $300 million, subject to working capital and other adjustments. For the year ended December 31, 2017, we recorded a pre-tax gain on disposal of $150.3 million, which was reported in "loss (gain) on disposal or impairment, net" in our consolidated statement of operations and comprehensive income (loss). Proceeds from the sale were used to repay borrowings on SemGroup's revolving credit facility. For the year ended December 31, 2018, we recorded an incremental gain of $1.1 million related to customary post-closing adjustments related to the prior year sale of our equity interest in Glass Mountain.

NGL Energy

At December 31, 2018, we held an 11.78% interest in the general partner of NGL Energy which is being accounted for under the equity method in accordance with ASC 323-30-S99-1, as our ownership is in excess of the 3 to 5 percent interest which is generally considered to be more than minor.

The general partner of NGL Energy is not a publicly traded company. The information below pertains to our general partner interest, and previously held limited partner interest, in NGL Energy.

NGL Energy unit issuance and sale of NGL Energy units

During the year ended December 31, 2016, we sold 4,652,568 NGL Energy limited partner units for $13.00 per unit, or $60.5 million, and recorded a $9.1 million gain on disposal. Subsequent to this disposal, we no longer hold a limited partner interest in NGL Energy. Gain on disposal of NGL Energy limited partner units is included in "loss on sale or impairment of non-operated equity method investment" in our consolidated statements of operations and comprehensive income (loss).

During the year ended December 31, 2016, our limited partnership interest was diluted in connection with an NGL Energy common unit issuance. Accordingly, we recorded a non-cash loss of $41.0 thousand for the year ended December 31, 2016 related to this transaction, which is included in "loss on issuance of common units by equity method investee" in our consolidated statements of operations and comprehensive income (loss).

Other-than-temporary impairment of equity method investment in NGL Energy

During the year ended 2016, we recorded an impairment of $39.8 million to our investment in the limited partner units of NGL Energy subsequent to NGL Energy's April 21, 2016 announcement of a reduction in its quarterly distribution and lowering of financial performance guidance. These units were subsequently sold in the second quarter of 2016. The impairment was included in "loss on sale or impairment of non-operated equity method investment" in our consolidated statements of operations and comprehensive income (loss).

F-19

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

7. OTHER ASSETS

Other current assets consist of the following (in thousands):

	December 31,
	2018		2017
Prepaid expenses	$	8,379	$	8,746
Other	8,885		5,551
Total other current assets	$	17,264	$	14,297

Other noncurrent assets consist of the following (in thousands):

	December 31,
	2018		2017
Capitalized loan fees	$	6,074	$	8,774
Net investment in direct financing lease	69,222		67,825
Deferred tax asset	25,307		33,792
Other	40,204		22,209
Total other noncurrent assets, net	$	140,807	$	132,600

Net investment in direct financing lease, included in the table above, relates to our HFOTCO operations' lease of certain land, tanks and a barge dock which are accounted for as a direct financing lease. The assets are leased through 2025. At December 31, 2018, minimum lease payments to be received for each of the five succeeding fiscal years and thereafter are as follows (in thousands):

For the year ending:
December 31, 2019	$	13,732
December 31, 2020	13,031
December 31, 2021	12,800
December 31, 2022	12,804
December 31, 2023	12,808
Thereafter	18,151
Total minimum lease payments	$	83,326

8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of the following (in thousands):

F-20

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

8.    PROPERTY, PLANT AND EQUIPMENT, Continued

	December 31,
	2018			2017
Land	$	308,166		$	273,168
Pipelines and related facilities	1,023,502			926,799
Storage and terminal facilities	1,247,115			1,111,001
Natural gas gathering and processing facilities	1,055,305			940,130
Linefill	27,972			25,747
Trucking equipment and other	45,567			45,162
Office property and equipment	69,498			63,052
Construction-in-progress	288,104			374,914
Property, plant and equipment, gross	4,065,229			3,759,973
Accumulated depreciation	(607,903		)	(444,842		)
Property, plant and equipment, net	$	3,457,326		$	3,315,131

Land in the table above includes $120.2 million and $106.2 million of rights-of-way at December 31, 2018 and 2017, respectively. The weighted average remaining useful life of rights-of-way at December 31, 2018, was approximately 19 years.

We recorded depreciation expense of $173.1 million, $126.3 million and $87.9 million for the years ended December 31, 2018, 2017 and 2016, respectively.

We include within the cost of property, plant and equipment interest costs incurred while an asset is being constructed. We capitalized $12.6 million, $18.4 million and $17.0 million of interest costs during the years ended December 31, 2018, 2017 and 2016, respectively.

9. GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Goodwill relates to our U.S Liquids segment. Changes in goodwill balances during the period from December 31, 2015 to December 31, 2018 are shown below (in thousands):

Balance, December 31, 2015	$	48,032
U.S. Gas impairment loss	(13,052		)
Currency translation adjustments	(750		)
Balance, December 31, 2016	34,230
U.S. Liquids - Crude oil trucking impairment loss	(26,628		)
Reclassification of Mexican asphalt business goodwill as held for sale (Note 4)	(7,808		)
U.S. Liquids - HFOTCO acquisition (Note 5)	257,302
Currency translation adjustments	206
Balance, December 31, 2017	257,302
Balance, December 31, 2018	$	257,302

For U.S. federal income tax purposes, goodwill is amortized on a straight-line basis over 15 years.

We assess our goodwill for impairment at least annually as of October 1. Testing goodwill for impairment requires estimation of future economic benefit based on management's judgment and assumptions about numerous variables including selling prices, costs, the level of activity and appropriate discount rates. Future results may be different from management's assumptions. No impairments were indicated as of October 1, 2018.

F-21

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

9. GOODWILL AND OTHER INTANGIBLE ASSETS, Continued

U.S. Liquids - Crude oil trucking goodwill impairment - 2017

Based on market conditions, in the third-quarter of 2017, management lowered the long range forecast for our crude oil trucking business unit, which provides truck transportation services as part of our U.S. Liquids segment. The decrease in the long range forecast for crude oil trucking is primarily due to the on-going challenging business environment. We viewed the decrease in the forecast as a triggering event that indicated a potential impairment and performed an interim impairment analysis on the business unit’s assets including goodwill and intangible assets.

We performed a recoverability test of our definite lived assets under ASC 360 whereby we compared the undiscounted cash flows of the asset group, which was determined to be the entire crude oil trucking reporting unit and included goodwill, to the carrying value of the assets at September 30, 2017. This test indicated that the assets were not fully recoverable. Therefore, we estimated the fair value of the definite lived assets using an income approach, supplemented by a market approach to measure impairment. We also performed an interim impairment test of our goodwill associated with the crude oil trucking reporting unit and determined the estimated fair value was less than the adjusted carrying value of the reporting unit resulting in impairment of goodwill. The cash flow models used to determine recoverability of our assets and to measure impairment expense involved using significant judgments and assumptions, which included the discount rate, anticipated revenue and volume growth rates, estimated operating expenses and capital expenditures, which were based on our operating and capital budgets as well as our strategic plans. We considered the market approach by comparing the revenue and earnings multiples implied by our income approach to those of comparable companies for reasonableness and for estimating the fair value of certain assets of our reporting unit.

We recorded a $26.6 million impairment of goodwill and a $12.1 million impairment of intangible assets, which are reflected in “loss (gain) on disposal or impairment, net” in our consolidated statements of operations and comprehensive income (loss).

U.S. Gas goodwill impairment - 2016

In March 2016, our U.S. Gas segment revised the volume forecast for its northern Oklahoma system based on revised volume forecasts provided by certain producers who have chosen to adjust plans for production following release of the Oklahoma Corporation Commission’s Regional Earthquake Response Plan that curtails the amount of volume that can be injected into disposal wells.  

Based on the reduction to our forecast, we tested our U.S. Gas segment's long-lived assets, finite-lived intangible assets and goodwill for impairment at March 31, 2016. No impairment was indicated for U.S. Gas' long-lived assets and finite-lived intangible assets based on an undiscounted cash flow analysis. However, we did record an impairment of U.S. Gas' goodwill for the entire balance of $13.1 million.

To test the goodwill for impairment, we used an income approach, supplemented by a market approach to calculate the fair value of the reporting unit. Under the income approach, we utilized a discounted cash flow model to determine the fair value of our U.S. Gas operations. Significant judgments and assumptions included the discount rate, anticipated revenue and volume growth rates, estimated operating expenses and capital expenditures, which were based on our operating and capital budgets as well as our strategic plans. A significant underlying assumption is that commodity prices will eventually improve, water disposal issues will be resolved and production volumes will begin to increase. If production does not increase in the future or the production takes longer than anticipated to return, this would negatively affect our key assumptions and potentially lead to finite-lived intangible and long-lived asset impairments in the future. We considered the market approach by comparing the revenue and earnings multiples implied by our income approach to those of comparable companies for reasonableness. See Note 4 for 2017 impairment of long-lived assets.

Other intangible assets

The gross carrying amount and accumulated amortization of intangible assets are shown below (in thousands):

F-22

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

9. GOODWILL AND OTHER INTANGIBLE ASSETS, Continued

	December 31, 2018							December 31, 2017
	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount		Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Customer relationships	$	424,000	$	(67,917	)	$	356,083	$	424,000	$	(49,717	)	$	374,283
Non-compete agreement	30,000		(21,250		)	8,750		30,000		(6,250		)	23,750
Trade names	52		(47		)	5		52		(42		)	10
Customer contract	1,000		(800		)	200		1,000		(400		)	600
Total other intangible assets	$	455,052	$	(90,014	)	$	365,038	$	455,052	$	(56,409	)	$	398,643

Changes in other intangible asset balances during the period from December 31, 2015 to December 31, 2018, are shown below (in thousands):

Balance, December 31, 2015	$	162,223
Amortization	(10,928		)
Currency translation adjustments	(317		)
Balance, December 31, 2016	150,978
U.S. Liquids - HFOTCO acquisition (Note 5)	291,000
U.S. Liquids - Crude oil trucking impairment	(12,087		)
Reclassification of Mexican asphalt assets as held for sale (Note 4)	(715		)
Amortization	(30,628		)
Currency translation adjustments	95
Balance, December 31, 2017	398,643
Amortization	(33,605		)
Balance, December 31, 2018	$	365,038

Our other intangible assets consist primarily of customer relationships at our U.S. Liquids and U.S. Gas segments and a non-compete agreement at our U.S. Liquids segment. These assets may be subject to impairments in the future if we are unable to maintain the relationships with the customers to which the assets relate or if the cash flows associated with those relationships decrease.

We estimate that future amortization of other intangible assets will be as follows (in thousands):

For the year ending:
December 31, 2019	$	39,455
December 31, 2020	30,000
December 31, 2021	30,200
December 31, 2022	28,600
December 31, 2023	27,100
Thereafter	209,683
Total estimated amortization expense	$	365,038

10. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK

Fair value of financial instruments

We record certain financial assets and liabilities at fair value at each balance sheet date. The table below summarizes the balances of commodity derivative assets and liabilities at December 31, 2018 and 2017 (in thousands):

F-23

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

10. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK, Continued

	December 31, 2018
	Level 1			Level 2			Level 3			Netting(1)			Total
Assets:
Commodity derivatives (2)	$	4,658		$	—		$	—		$	(973	)	$	3,685
Total assets	4,658			—			—			(973		)	3,685
Liabilities:
Commodity derivatives	973			—			—			(973		)	—
Foreign currency forwards	—			2,985			—			—			2,985
Interest rate swaps	—			—			1,482			—			1,482
Total liabilities	973			2,985			1,482			(973		)	4,467
Net assets (liabilities) at fair value	$	3,685		$	(2,985	)	$	(1,482	)	$	—		$	(782	)
	December 31, 2017
	Level 1			Level 2			Level 3			Netting(1)			Total
Assets:
Commodity derivatives (2)	$	602		$	—		$	—		$	(602	)	$	—
Foreign currency forwards	—			2,564			—			—			$	2,564
Total assets	602			2,564			—			(602		)	2,564
Liabilities:
Commodity derivatives	1,970			—			—			(602		)	1,368
Interest rate swaps	—			—			1,228			—			1,228
Total liabilities	1,970			—			1,228			(602		)	2,596
Net assets (liabilities) at fair value	$	(1,368	)	$	2,564		$	(1,228	)	$	—		$	(32	)

(1)	Relates primarily to exchange traded futures. Gain and loss positions on multiple contracts are settled net on a daily basis with the exchange.
(2)	Commodity derivatives are subject to netting arrangements.

“Level 1” measurements are based on inputs consisting of unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. These include commodity futures contracts that are traded on an exchange.

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

“Level 3” measurements are based on inputs from a pricing service and/or internal valuation models incorporating observable and unobservable market data. These could include commodity derivatives, such as forwards and swaps for which there is not a highly liquid market and therefore are not included in Level 2 above and interest rate swaps for which certain unobservable inputs are used in the valuation.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value levels. At December 31, 2018, all of our physical fixed price forward purchases and sales contracts were being accounted for as normal purchases and normal sales.

Our assessment of the significance of a particular input to the measurement requires judgment, and may affect the valuation of assets and liabilities and their placement within the fair value levels. The following table summarizes changes in the fair value of our net financial liabilities classified as Level 3 in the fair value hierarchy (in thousands):

F-24

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

10. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK, Continued

	Year Ended December 31, 2018		Year Ended December 31, 2017
Net liabilities - beginning balance	$	1,228	$	—
Interest rate swaps acquired through acquisition (Note 5)	—		3,275
Transfers out of Level 3	—		—
Realized/Unrealized (gain) loss included in earnings*	163		(1,124		)
Settlements	91		(923		)
Net liabilities - ending balance	$	1,482	$	1,228

*Gains and losses related to interest rate swaps are recorded in interest expense in the condensed consolidated statements of operations and comprehensive income (loss).

There were no financial assets or liabilities classified as Level 3 during the year ended December 31, 2016.

See Note 12 for fair value of debt instruments and Note 13 for fair value of benefit plan assets. The approximate fair value of cash and cash equivalents, accounts receivable and accounts payable is equal to book value due to the short-term nature of these items.

Commodity derivative contracts

Our consolidated results of operations and cash flows are impacted by changes in market prices for petroleum products. This exposure to commodity price risk is managed, in part, by entering into various commodity derivatives.

We seek to manage the price risk associated with our marketing operations by limiting our net open positions through (i) the concurrent purchase and sale of like quantities of petroleum products to create back-to-back transactions that are intended to lock in positive margins based on the timing, location or quality of the petroleum products purchased and delivered or (ii) derivative contracts. Our storage and transportation assets can also be used to mitigate time and location basis risks, respectively. All marketing activities are subject to our Comprehensive Risk Management Policy, a Delegation of Authority policy and their supporting policies and procedures, which establish limits in order to manage risk and mitigate financial exposure.

Our commodity derivatives can be comprised of swaps, futures contracts and forward contracts of crude oil, natural gas and natural gas liquids. These are defined as follows:

Swaps – OTC transactions where a floating price, basis or index is exchanged for a fixed (or a different floating) price, basis or index at a preset schedule in the future, according to an agreed-upon formula.

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

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

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

	Year Ended December 31,
	2018	2017	2016
Sales	14,013	12,979	33,694
Purchases	13,417	13,430	33,819

We have not designated any of our commodity derivative instruments as accounting hedges. We have recorded the fair value of our commodity derivative instruments on our consolidated balance sheets in "other current assets" and "other current liabilities" in the following amounts (in thousands):

F-25

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

10. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK, Continued

December 31, 2018				December 31, 2017
Other Current Assets		Other Current Liabilities		Other Current Assets		Other Current Liabilities
$	3,685	$	—	$	—	$	1,368

 

We have posted margin deposits as collateral with brokers who have the right of set off associated with these funds. Our margin deposit balances were $0.1 million and $1.9 million at December 31, 2018 and 2017, respectively. These margin account balances have not been offset against our net commodity derivative instrument (contract) positions. Had these margin account balances been netted against our net commodity derivative instrument (contract) positions as of December 31, 2018 and 2017, we would have had net asset positions of $3.8 million and $0.5 million, respectively.

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

	Year Ended December 31,
	2018		2017			2016
Realized and unrealized gain (loss)	$	12,088	$	(2,193	)	$	(4,485	)

Interest rate swaps

We have interest rate swaps which allow us to limit exposure to interest rate fluctuations. The swaps only apply to a portion of our outstanding debt and provide only partial mitigation of interest rate fluctuations. We have not designated the swaps as hedges, as such changes in the fair value of the swaps are recorded through current period earnings as a component of interest expense. At December 31, 2018 and 2017, we had interest rate swaps with notional values of $524.3 million and $491.1 million, respectively. At December 31, 2018 and 2017, the fair value of our interest rate swaps was $1.5 million and $1.2 million, respectively, which was reported within "other current liabilities" and "other noncurrent liabilities” in our condensed consolidated balance sheet. For the year ended December 31, 2018, we recognized realized and unrealized losses of $0.2 million related to interest rate swaps. For the year ended December 31, 2017, we recognized realized and unrealized gains of $1.1 million related to interest rate swaps. We did not have any interest rate swaps during the year ended December 31, 2016.

Foreign currency forwards

We have foreign currency forwards primarily to purchase Canadian dollars to limit exposure to foreign currency rate fluctuations for capital contributions to our Canadian operations. We have not designated the forwards as hedges, as such changes in the fair value of the forwards are recorded through current period earnings as a component of foreign currency translation gain/loss. At December 31, 2018 and 2017, we had foreign currency forwards with notional values of $56.1 million and $197.7 million, respectively. At December 31, 2018 and 2017, the fair value of our foreign currency swaps was $3.0 million and $2.6 million, respectively, which is reported within "other current liabilities" and "other noncurrent assets, net", respectively, in our consolidated balance sheet. For the year ended December 31, 2018, we recognized realized and unrealized losses of $10.2 million, related to foreign currency forwards. For the year ended December 31, 2017, we recognized realized and unrealized gains of $2.8 million, related to foreign currency forwards. We did not have any foreign currency forwards during the year ended December 31, 2016.

Concentrations of risk

During the year ended December 31, 2018, one customer, primarily of our U.S. Liquids segment, accounted for more than 10% of our consolidated revenue with revenues of $645.0 million. One third-party supplier, primarily of our U.S. Liquids segment, accounted for more than 10% of our costs of products sold with purchases of $248.7 million. At December 31, 2018, two customers, primarily of our U.S. Liquids segment, accounted for approximately 28% of our consolidated accounts receivable.

Our U.S. Gas segment has a significant concentration of producers which account for a large portion of our U.S. Gas segment's volumes. During the year ended December 31, 2018, three producers accounted for approximately 89% of our total processed volumes. During the year ended December 31, 2018, two producers accounted for 83% of our total

F-26

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

10. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK, Continued

gathered volumes. Additionally, all of the processing and gathering volumes from these customers are produced in the Northern Oklahoma region.

Our Canada segment's processing plants require a minimum rate of sulfur tonnage to operate, and to comply with the regulatory requirements for air emissions.  We have several large producers that provide significant sour gas to our plants.  If these producers shut in their sour gas production due to low commodity prices, it could result in regulatory non-compliance, as well as operating and financial impacts to our Canada segment.

Assets and liabilities of subsidiaries outside the United States

The following table summarizes the assets and liabilities (excluding affiliate balances) at December 31, 2018, of our subsidiaries outside the United States (in thousands):

	Canada
Cash and cash equivalents	$	17,107
Other current assets	78,542
Noncurrent assets	590,714
Total assets	$	686,363
Current liabilities	$	69,798
Noncurrent liabilities	76,192
Total liabilities	145,990
Net assets	$	540,373

Employees

At December 31, 2018, we had approximately 880 employees, including approximately 265 employees in Canada. Approximately 55 of the employees in Canada are represented by labor unions and are subject to collective bargaining agreements governing their employment with us. This collective agreement expires on January 31, 2019. We have never had a labor related work stoppage and believe our employee relations are good.

11. INCOME TAXES

Income tax expense (benefit)

Our consolidated income from continuing operations before income taxes was generated in the following jurisdictions (in thousands):

	Year Ended December 31,
	2018			2017			2016
U.S.	$	(53,517	)	$	(64,423	)	$	(766	)
Foreign	52,493			44,885			25,297
Consolidated	$	(1,024	)	$	(19,538	)	$	24,531

The following table summarizes income tax provision (benefit) from continuing operations by jurisdiction (in thousands):

F-27

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

11. INCOME TAXES, Continued

	Year Ended December 31,
	2018			2017			2016
Current income tax provision:
Foreign	$	14,343		$	7,058		$	2,821
U.S. federal	—			—			—
U.S. state	650			383			—
	14,993			7,441			2,821
Deferred income tax provision (benefit):
Foreign	9,610			5,318			4,071
U.S. federal	(664		)	(15,379		)	5,142
U.S. state	(635		)	232			(766		)
	8,311			(9,829		)	8,447
Provision (benefit) for income taxes	$	23,304		$	(2,388	)	$	11,268

The following table reconciles income tax provision at the U.S. federal statutory rate to the consolidated provision (benefit) for income taxes (in thousands):

	Year Ended December 31,
	2018				2017			2016
Income from continuing operations before income taxes	$	(1,024	)		$	(19,538	)	$	24,531
U.S. federal statutory rate	21		%		35		%	35		%
Provision at statutory rate	(215		)		(6,838		)	8,586
State income taxes—net of federal benefit	13				401			(498		)
Effect of rates other than statutory	3,042				(3,842		)	(1,966		)
Effect of U.S. taxation on foreign branches	11,023				15,710			8,854
Noncontrolling interest	(508		)		—			(3,908		)
Foreign tax credit and offset to branch deferreds	1,447				45,245			(6,026		)
Effect of U.S. deduction of foreign tax	(3,012		)		(7,514		)	—
Impact of valuation allowance on deferred tax assets	—				(65,327		)	6,026
Foreign withholding taxes	10,187				858			18
Stock-based compensation	1,427				1,351			—
Effect of U.S. federal statutory rate reduction	—			—	17,638			—
Other, net	(100		)		(70		)	182
Provision (benefit) for income taxes	$	23,304			$	(2,388	)	$	11,268

For the years ended December 31, 2018, 2017 and 2016, the foreign subsidiaries are disregarded entities for U.S. federal income tax purposes. The foreign earnings are taxed in foreign jurisdictions as well as in the U.S. Foreign tax credits, subject to limitations, or foreign tax deductions are available to reduce U.S. taxes. The decision to deduct foreign taxes or claim the foreign tax credit is made with respect to each tax period.

Deferred tax positions

Deferred income taxes reflect the effects of temporary differences between the amounts of assets and liabilities recognized for financial reporting purposes and the amounts recognized for income tax purposes. Significant components of deferred tax assets and liabilities are as follows at December 31, 2018 and 2017 (in thousands):

December 31,
2018	2017

F-28

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

11. INCOME TAXES, Continued

Deferred tax assets:
Net operating loss and other credit carryforwards	$	139,274		$	44,867
Compensation and benefits	5,480			7,156
Inventories	44			322
Intangible assets	—			16,714
Pension plan	813			1,760
Allowance for doubtful accounts	577			956
Deferred revenue	2,493			4,953
Foreign tax credit and offset to branch deferreds	55,272			56,719
Other	19,127			28,201
less: valuation allowance	(45,614		)	(45,682		)
Net deferred tax assets	177,466			115,966
Deferred tax liabilities:
Intangible assets	(12,849		)	(5,074		)
Prepaid expenses	—			(1,447		)
Property, plant and equipment	(189,529		)	(108,646		)
Equity investment in partnerships	(3,572		)	(24,315		)
Other	(2,010		)	(2,402		)
Total deferred tax liabilities	(207,960		)	(141,884		)
Net deferred tax liabilities	$	(30,494	)	$	(25,918	)

At December 31, 2018, we had a cumulative U.S. federal net operating loss of approximately $535.6 million that can be carried forward to apply against taxable income generated in future years. $350.4 million of this carryforward may be carried forward indefinitely and the remaining carryforward begins to expire in 2031. We had cumulative U.S. state net operating losses of approximately $371.0 million available for carryforward, which begin to expire in 2019. We had foreign net operating losses of $0.8 million available for carryforward, which begin to expire in 2025. We had foreign tax credits of approximately $44.6 million available for carryforward, which begin to expire in 2020. We had interest expense limitation of $31.8 million available for indefinite carryforward.

The valuation allowance decreased by $0.1 million during 2018. The change is primarily related to state net operating losses.

We have a valuation allowance on a small portion of our state net operating loss carryovers with shorter carryover periods, our foreign net operating loss carryovers and our foreign tax credit carryover. We have not released the valuation allowance on the foreign tax credits due to the foreign tax credit limitation and the relative subjectivity of forecasts of the relational magnitude of U.S. and foreign taxable income in future periods, as well as the shorter carryover period available for the credits. Deferred tax assets are reduced by a valuation allowance when a determination is made that it is more likely than not that some, or all, of the deferred tax assets will not be realized based on the weight of all available evidence. Evidence which is objectively verifiable carries a higher weight in the analysis. The ultimate realization of deferred tax assets is dependent upon the existence of sufficient taxable income of the appropriate character within the carryback and carryforward period available under the tax law. Sources of taxable income include future reversals of existing taxable temporary differences, future earnings and available tax planning strategies.

We have analyzed filing positions in all of the federal, state and foreign jurisdictions where we are required to file income tax returns and determined that no accruals related to uncertainty in tax positions are required. All income tax years of the Company ending after the emergence from bankruptcy remain open for examination in U.S. jurisdictions under general operation of the statute of limitations, including special provisions with regard to net operating loss carryovers. In foreign jurisdictions, all tax periods prior to the emergence from bankruptcy are closed. The statute of limitations has not been waived with respect to any foreign jurisdictions post emergence and tax periods are open for

F-29

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

11. INCOME TAXES, Continued

examination in accordance with the general statutes of each foreign jurisdiction. Currently, there are no examinations in progress for our federal, state or foreign jurisdictions.

12. LONG-TERM DEBT

Our long-term debt consisted of the following (dollars in thousands):

	Interest rate at December 31, 2018	December 31, 2018			December 31, 2017
Senior unsecured notes due 2022	5.625%	400,000			400,000
Senior unsecured notes due 2023	5.625%	350,000			350,000
Senior unsecured notes due 2025	6.375%	325,000			325,000
Senior unsecured notes due 2026	7.250%	300,000			300,000
SemGroup $1.0 billion corporate revolving credit facility (1)
Alternate base rate borrowings	7.250%	24,500			—
Eurodollar borrowings	5.156%	95,000			131,000
HFOTCO acquisition final payment		—			565,868
HFOTCO term loan B (2)	5.280%	597,000			532,125
HFOTCO tax exempt notes payable due 2050	3.399%	225,000			225,000
HFOTCO $75 million revolving credit facility		—			60,000
Capital leases		—			25
Unamortized premium (discount) and debt issuance costs, net		(31,666		)	(30,398		)
Total long-term debt, net		2,284,834			2,858,620
Less: current portion of long-term debt		6,000			5,525
Noncurrent portion of long-term debt, net		$	2,278,834		$	2,853,095

(1) SemGroup $1.0 billion corporate revolving credit facility matures on May 15, 2021.

(2) HFOTCO term loan B is due in quarterly installments of $1.5 million, with a final payment due on June 26, 2025.

HFOTCO credit agreement

On June 26, 2018, HFOTCO and Buffalo Gulf Coast Terminals LLC ("BGCT") entered into an Amendment and Restatement Agreement (the “Amendment and Restatement Agreement”). Pursuant to the Amendment and Restatement Agreement, the HFOTCO credit agreement was amended and restated in its entirety (as so amended and restated, the “Restated HFOTCO Credit Agreement”).

The Restated HFOTCO Credit Agreement increased the aggregate term loans incurred thereunder to $600 million, terminated the HFOTCO $75.0 million revolving credit facility, and extended the maturity date of the term loans to June 26, 2025 (the “Maturity Date”). In addition, HFOTCO may incur additional term loans in an aggregate amount not to exceed the greater of $120 million and a measure of HFOTCO’s EBITDA, defined in the credit agreement, at the time of determination, plus additional amounts subject to satisfaction of certain leverage-based criteria, subject to receiving commitments for such additional term loans from either new lenders or increased commitments from existing lenders. The term loan B was issued at a discount of $1.5 million.

At HFOTCO’s option, the term loans will bear interest at the Eurodollar rate or an alternate base rate (“ABR”), plus, in each case, an applicable margin of 2.75% relating to any term loans accruing interest at the Eurodollar rate and 1.75% relating to term loans accruing interest at ABR.

HFOTCO acquisition final payment

On April 17, 2018, we made the final payment related to the HFOTCO acquisition in the amount of $579.6 million. The payment was funded through revolving credit facility borrowings and cash on hand.

F-30

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

12. LONG-TERM DEBT, Continued

Early extinguishment of senior unsecured notes due 2021

On March 15, 2017, we purchased $290 million of our outstanding $300 million, 7.50% senior unsecured notes due 2021 (the “2021 Notes”) through a tender offer. The purchase price included a premium and interest to the purchase date. On March 17, 2017, a notice of redemption was issued for the remaining $10 million of the 2021 Notes which were not purchased through the tender offer pursuant to the redemption and satisfaction and discharge provisions of the indenture governing the 2021 Notes. These remaining 2021 Notes were redeemed on June 15, 2017, including a redemption premium and accrued unpaid interest to the redemption date. We recorded a loss on early extinguishment of $19.9 million for the above transactions, which included premiums totaling $15.9 million and the write off of $3.6 million of associated unamortized debt issuance costs.

Issuance of senior unsecured notes due 2025 and 2026

On March 15, 2017, we sold $325 million of 6.375% senior unsecured notes due 2025 (the “2025 Notes”). The 2025 Notes were sold at 98.467% of par, a discount of $5.0 million. The discount is reported as a reduction to the face value of the 2025 Notes on our condensed consolidated balance sheets and is being amortized over the life of the 2025 Notes using the interest method.

The net proceeds from the offering of $315.1 million, after the discount and $4.9 million of initial purchasers’ fees and offering expenses, together with cash on hand, were used to purchase and redeem the 2021 Notes.

On September 20, 2017, we sold $300 million of 7.25% senior unsecured notes due 2026 (the “2026 Notes”). The 2026 Notes were sold at 98.453% of par, a discount of $4.6 million. The discount is reported as a reduction to the face value of the 2026 Notes on our condensed consolidated balance sheets and is being amortized over the life of the 2026 Notes using the interest method.

The net proceeds from the offering of $290.3 million, after the discount and $5.1 million of initial purchasers’ fees and offering expenses, were used to repay amounts borrowed under our revolving credit facility.

Senior unsecured notes

Our senior unsecured notes (collectively, the "Notes") are guaranteed by certain of our subsidiaries: Rose Rock Finance Corporation, Rose Rock Midstream Operating, LLC, Rose Rock Midstream Energy GP, LLC, Rose Rock Midstream Crude, L.P., Rose Rock Midstream Field Services, LLC, SemGas, L.P., SemMaterials, L.P., SemGroup Europe Holding, L.L.C., SemOperating G.P., L.L.C., SemMexico, L.L.C., SemDevelopment, L.L.C., Mid-America Midstream Gas Services, L.L.C., SemCrude Pipeline, L.L.C., Wattenberg Holding, LLC, LLC, Beachhead Holdings LCC, Beachhead I LLC and Beachhead II LLC (collectively, the "Guarantors"). The guarantees of the Notes are full and unconditional and constitute the joint and several obligations of the Guarantors.

The Notes are governed by indentures, as supplemented, between the Company and its subsidiary Guarantors and Wilmington Trust, N.A., as trustee (the “Indentures”). The Indentures include customary covenants, including limitations on our ability to incur additional indebtedness or issue certain preferred shares; pay dividends and make certain distributions, investments and other restricted payments; create certain liens; sell assets; enter into transactions with affiliates; enter into sale and lease-back transactions; merge, consolidate, sell or otherwise dispose of all or substantially all of our assets; and designate our subsidiaries as unrestricted under the Indentures.

The Indentures include customary events of default, including events of default relating to non-payment of principal and other amounts owing from time to time, failure to provide required reports, failure to comply with agreements in the Indentures, cross payment-defaults to any material indebtedness, bankruptcy and insolvency events, certain unsatisfied judgments, and invalidation or cessation of the subsidiary guarantee of a significant subsidiary. A default would permit holders to declare the Notes and accrued interest due and payable.

The Notes are effectively subordinated in right of payment to any of our, and the Guarantors', existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness and are structurally subordinated to the obligations of any subsidiary that is not a guarantor of the Notes.

The Company may issue additional Notes under the Indentures from time to time, subject to the terms of the Indentures.

F-31

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

12. LONG-TERM DEBT, Continued

Except as described below, the Company may redeem the Notes, in whole or in part, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if redeemed during the twelve-month period beginning with each period as indicated below:

2022 Notes
From and after July 15, 2018	102.813%
From and after July 15, 2019	101.406%
From and after July 15, 2020	100.000%

2023 Notes
Not redeemable before May 15, 2019
From and after May 15, 2019	102.813%
From and after May 15, 2020	101.406%
From and after May 15, 2021	100.000%

2025 Notes
Not redeemable before March 15, 2020
From and after March 15, 2020	103.188%
From and after March 15, 2021	101.594%
From and after March 15, 2022	100.000%

2026 Notes
Not redeemable before March 15, 2021
From and after March 15, 2021	103.625%
From and after March 15, 2022	101.813%
From and after March 15, 2023	100.000%

Prior to the redemption dates set forth above, the Company may, at its option, on one or more occasions, redeem up to 35% of the sum of the original aggregate principal amount of the Notes at a redemption price equal to the aggregate principal amount thereof plus a premium equal to stated interest rate of the Notes, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings of the Company, subject to certain conditions.

Prior to the redemption dates set forth above, the Company may also redeem all or part of the Notes at a price equal to the principal plus a premium equal to the greater of 1% of the principal or the excess of the present value of the first redemption price from the table above plus all required interest payments due through the first redemption date in the table above, computed using a discount rate based on a published United States Treasury Rate plus 50 basis points, over the principal value of such Note.

In the event of a change of control, the Company is required to offer to repurchase the Notes at an amount equal to 101% of the principal plus accrued and unpaid interest.

Pledges and guarantees

Our senior unsecured notes are guaranteed by certain subsidiaries. See Note 25 for additional information.

Our $1.0 billion corporate revolving credit facility is guaranteed by all of SemGroup’s material domestic subsidiaries, with the exception of Maurepas Pipeline LLC and HFOTCO, and secured by a lien on substantially all of the property and assets of SemGroup Corporation and the other loan parties, subject to customary exceptions.

F-32

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

12. LONG-TERM DEBT, Continued

The HFOTCO term loan B and HFOTCO tax exempt notes payable are secured by substantially all of the assets of HFOTCO and its immediate parent, Buffalo Gulf Coast Terminals LLC. The HFOTCO tax exempt notes payable have a priority position over the HFOTCO term loan B.

Covenants and restrictions

The SemGroup credit agreement includes customary affirmative and negative covenants, including limitations on the creation of new indebtedness, liens, sale and lease-back transactions, new investments, making fundamental changes including mergers and consolidations, making of dividends and other distributions, making material changes in our business, modifying certain documents and maintenance of a consolidated leverage ratio and an interest coverage ratio. In addition, the credit agreement prohibits any commodity transactions that are not permitted by our Risk Governance Policies.

The terms of the SemGroup credit facility restrict, to some extent, the payment of cash dividends on our common stock.

The Restated HFOTCO Credit Agreement includes customary representations and warranties and affirmative and negative covenants, which were made only for the purposes of the Restated HFOTCO Credit Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties, and apply only to BGCT, HFOTCO and any subsidiaries of HFOTCO party to the Restated HFOTCO Credit Agreement. Such limitations include the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to material agreements, modifying the fiscal year, dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, and funding or engaging in sanctioned activities.

The Restated HFOTCO Credit Agreement includes customary events of default, including events of default relating to inaccuracy of representations and warranties in any material respect when made or when deemed made, non-payment of principal and other amounts owing under the Restated HFOTCO Credit Agreement, including, in respect of, violation of covenants, cross acceleration to any material indebtedness of BGCT, HFOTCO and its subsidiaries, bankruptcy and insolvency events, certain unsatisfied judgments, certain ERISA events, certain invalidities of loan documents and the occurrence of a change of control. A default under the Restated HFOTCO Credit Agreement would permit the participating banks to require immediate repayment of any outstanding loans with interest and any unpaid accrued fees, and subject to intercreditor arrangements with the holders of the HFOTCO tax exempt notes payable, exercise other rights and remedies.

The indentures covering HFOTCO's tax exempt notes payable due 2050 ("IKE Bonds") are subject to the Continuing Covenant Agreement. The Continuing Covenant Agreement includes customary representations and warranties and affirmative and negative covenants, which were made only for the purposes of the Continuing Covenant Agreement and as of the specific date (or dates) set forth therein, may be subject to certain limitations as agreed upon by the contracting parties, and apply only to BGCT, HFOTCO and any subsidiaries of HFOTCO party to the Continuing Covenant Agreement. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax-exempt status of the IKE Bonds.

In addition, the Continuing Covenant Agreement contains financial performance covenants as follows:

• the super senior leverage ratio of BGCT and its restricted subsidiaries under the Continuing Covenant Agreement may not exceed 3.50 to 1.00 as of the last day of any fiscal quarter; and

• the interest coverage ratio of BGCT and its restricted subsidiaries under the Continuing Covenant Agreement may not be less than 2.00 to 1.00 as of the last day of any fiscal quarter.

See "senior unsecured notes" section above for discussion of covenants and restrictions related to the Notes.

F-33

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

12. LONG-TERM DEBT, Continued

Letters of credit

We had the following outstanding letters of credit at December 31, 2018 (dollars in thousands):

SemGroup $1.0 billion revolving credit facility	2.75%	$	24,335
Secured bi-lateral (1)	1.75%	$	19,053

(1) Secured bi-lateral letters of credit are external to the SemGroup $1.0 billion revolving credit facility and do not reduce availability for borrowing on the credit facility.

Scheduled principal payments

The following table summarizes the scheduled principal payments as of December 31, 2018 (in thousands):

	Total
For the year ended:
December 31, 2019	$	6,000
December 31, 2020	6,000
December 31, 2021	125,500
December 31, 2022	406,000
December 31, 2023	356,000
Thereafter	1,417,000
Total	$	2,316,500

Fair value

We estimate the fair value of the Notes based on unadjusted, transacted market prices near the measurement date. Our other long-term debts are estimated to be carried at fair value as a result of the recent timing of borrowings or acquisition. We estimate the fair value of our consolidated long-term debt, including current maturities, to be approximately $2.2 billion at December 31, 2018, which is categorized as a Level 2.

13. EMPLOYEE BENEFIT PLANS

Defined contribution plans

We sponsor defined contribution retirement plans in which the majority of employees are eligible to participate. Our contributions to the defined contribution plans were $3.0 million, $3.0 million, and $2.7 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Pension plans

We sponsor a defined benefit pension plan and a supplemental defined benefit pension plan for certain employees of the Canada segment hired before June 30, 2001 (the “Canada Plans”). Additionally, we sponsor a defined benefit pension plan for certain employees of the U.S. Liquids segment at HFOTCO and a supplemental defined benefit plan covering a former key executive of HFOTCO (the “HFOTCO Plans”). These plans are closed to new participants and do not accrue any additional benefits (collectively, the "Pension Plans").

F-34

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

13. EMPLOYEE BENEFIT PLANS, Continued

We recognize the funded status of the Pension Plans, measured as the difference between the fair value of the plan assets and the projected benefit obligation, in the consolidated balance sheets. The table below summarizes the balances of the projected benefit obligation and fair value of the plan assets at December 31, 2018 and 2017 (in thousands):

	December 31,
	2018			2017
Projected benefit obligation	$	50,049		$	53,489
Fair value of plan assets	39,197			43,098
Funded status:	$	(10,852	)	$	(10,391	)

We recorded other noncurrent liabilities of $2.0 million and $2.3 million at December 31, 2018 and 2017, respectively, to reflect the funded status of the Canada Plans.

We recorded other noncurrent liabilities of $8.8 million and $8.1 million at December 31, 2018 and 2017, respectively, to reflect the funded status of the HFOTCO Plans.

All of the Canada Plans' assets are invested in pooled funds that hold highly-liquid securities and are classified as Level 2 within the fair value hierarchy. Substantially all of the HFOTCO Plans' assets are invested in mutual funds, for which the fair values are determined by quoted prices in active markets, and are classified as Level 1 within the fair value hierarchy. The following information discloses the fair values of our Pension Plans' assets, by asset category, for the periods indicated (in thousands):

	December 31, 2018								December 31, 2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	831	$	—	$	—	$	831	$	538	$	—	$	—	$	538
Mutual funds	15,125		—		—		15,125		16,671		—		—		16,671
Pooled mutual funds	—		23,241		—		23,241		—		25,889		—		25,889
Total	$	15,956	$	23,241	$	—	$	39,197	$	17,209	$	25,889	$	—	$	43,098

We record changes in the funded status of the Pension Plans to other comprehensive income (loss), net of income taxes. These amounts were losses of $2.6 million, $0.3 million and $1.1 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Retiree medical plan

We sponsor an unfunded, post-employment health benefit plan (the “Health Plan”) for certain employees of our Canada segment. The projected benefit obligation related to the Health Plan was $1.5 million at December 31, 2018, and $1.7 million at December 31, 2017, and is reported within "other noncurrent liabilities" on the consolidated balance sheets.

14. COMMITMENTS AND CONTINGENCIES

Environmental

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

The Kansas Department of Health and Environment ("the KDHE") initiated discussions during our bankruptcy proceeding regarding six of our sites in Kansas (five owned by our U.S. Liquids segment and one owned by our U.S. Gas segment) that KDHE believed, based on their historical use, may have had soil or groundwater contamination in excess of state standards. KDHE sought our agreement to undertake assessments of these sites to determine whether they are contaminated. We reached an agreement with KDHE on this matter and entered into a Consent Agreement and Final Order with KDHE to conduct environmental assessments on the sites and to pay KDHE’s costs associated with their oversight of this matter. We have conducted Phase II investigations at all sites. Four sites are in various stages of follow up investigation, remediation, monitoring, or closure under KDHE oversight.  The environmental work at these sites is

F-35

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

14. COMMITMENTS AND CONTINGENCIES, Continued

being completed under consent orders between Rose Rock Midstream Crude, L.P. and the KDHE. Two of the remaining sites have limited impacts to shallow soil and groundwater and the groundwater is currently being monitored on a semi-annual basis until such time that closure can be granted by the KDHE.  No active remediation is anticipated for these two sites.  The final two sites have required additional investigation and soil and groundwater remediation may be necessary to achieve KDHE closure. We do not anticipate any penalties or fines for these historical sites.

Other matters

We are party to various other claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our consolidated liabilities may change materially as circumstances develop.

Asset retirement obligations

We will be required to incur significant removal and restoration costs when we retire our natural gas gathering and processing facilities in Canada. We have recorded a liability associated with these obligations, which is reported within other noncurrent liabilities on the consolidated balance sheets. The following table summarizes the changes in this liability from December 31, 2015 through December 31, 2018 (in thousands):

Balance, December 31, 2015	$	15,946
Accretion	2,292
Payments made	(159		)
Currency translation adjustments	469
Balance, December 31, 2016	18,548
Accretion	2,812
Payments made	(160		)
Currency translation adjustments	1,404
Balance, December 31, 2017	22,604
Accretion	4,070
Payments made	(3,111		)
Currency translation adjustments	(1,820		)
Balance, December 31, 2018	$	21,743

The December 31, 2018 liability was calculated using the $127.1 million cost we estimate we would incur to retire these facilities, discounted based on our risk-adjusted cost of borrowing and the estimated timing of remediation. An additional $18.1 million of estimated costs are attributable to third-party owners’ proportionate share of the obligations. If an owner fails to perform on its obligations, the other owners (including SemGroup) could be obligated to bear that party’s share of the remediation costs.

The calculation of the liability for an asset retirement obligation requires the use of significant estimates, including those related to the length of time before the assets will be retired, cost inflation over the assumed life of the assets, actual remediation activities to be required and the rate at which such obligations should be discounted. Future changes in these estimates could result in material changes in the value of the recorded liability. In addition, future changes in laws or regulations could require us to record additional asset retirement obligations.

Our other segments may also be subject to removal and restoration costs upon retirement of their facilities. However, we are unable to predict when, or if, our pipelines, storage tanks and other facilities would become completely obsolete and require decommissioning. Accordingly, we have not recorded a liability or corresponding asset, as both the amount and timing of such potential future costs are indeterminable.

F-36

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

14. COMMITMENTS AND CONTINGENCIES, Continued

Operating leases

We have entered into operating lease agreements for office space, office equipment, land and vehicles. Future minimum payments required under operating leases that have initial or remaining non-cancellable lease terms in excess of one year at December 31, 2018, are as follows (in thousands): 

For year ending:
December 31, 2019	$	5,795
December 31, 2020	5,796
December 31, 2021	5,312
December 31, 2022	3,455
December 31, 2023	2,453
Thereafter	40,551
Total future minimum lease payments	$	63,362

We recorded lease and rental expenses of $15.1 million, $15.4 million and $15.0 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Purchase and sale commitments

We routinely enter into agreements to purchase and sell petroleum products at specified future dates. We account for these commitments as normal purchases and sales, therefore, we do not record assets or liabilities related to these agreements until the product is purchased or sold. At December 31, 2018, such commitments included the following (in thousands):

	Volume (barrels)	Value
Fixed price purchases	4,626	$	230,562
Fixed price sales	4,920	$	246,755
Floating price purchases	14,638	$	750,711
Floating price sales	17,290	$	830,407

Certain of the commitments shown in the table above relate to agreements to purchase product from a counterparty and to sell a similar amount of product (in a different location) to the same counterparty. Many of the commitments shown in the table above are cancellable by either party, as long as notice is given within the time frame specified in the agreement (generally 30 to 120 days).

Our U.S. Gas segment has a take or pay contractual obligation related to the fractionation of natural gas liquids through June 2023. At December 31, 2018, the approximate amount of future obligations is as follows (in thousands):

For year ending:
December 31, 2019	$	9,783
December 31, 2020	9,063
December 31, 2021	7,337
December 31, 2022	6,905
December 31, 2023	2,854
Thereafter	—
Total expected future payments	$	35,942

The U.S. Gas segment also enters into contracts under which we are responsible for marketing the majority of the gas and natural gas liquids produced by the counterparties to the agreements. The majority of U.S. Gas' revenues were generated from such contracts.

Our U.S. Liquids segment has minimum volume commitments for pipeline transportation of crude oil. At December 31, 2018, the approximate amount of future obligations is as follows (in thousands):

F-37

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

14. COMMITMENTS AND CONTINGENCIES, Continued

For year ending:
December 31, 2019	$	21,865
December 31, 2020	19,751
December 31, 2021	12,976
December 31, 2022	13,231
December 31, 2023	13,496
Thereafter	6,816
Total expected future payments	$	88,135

Capital expenditures

We have commitments to spend approximately $104.4 million in 2019 related to property, plant and equipment.

15. REDEEMABLE PREFERRED STOCK

On January 19, 2018 (the “Issue Date”), we issued and sold to WP SemGroup Holdings L.P. (“Warburg”) and certain other investors an aggregate of 350,000 shares of Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share, of the Company (the “Preferred Stock”), convertible into shares of the Company’s Class A Common Stock, par value $0.01 per share (the “Common Stock”), for a cash purchase price of $1,000 per share of Preferred Stock and aggregate gross proceeds to the Company of $350,000,000, which proceeds were utilized (i) to repay amounts borrowed under the Company’s revolving credit facility, (ii) to fund growth capital expenditures and (iii) for general corporate purposes. The Preferred Stock was recorded on our condensed consolidated balance sheets net of $7.7 million of issuance costs.

The Preferred Stock is a new class of equity security that ranks senior to the Common Stock with respect to distribution rights and rights upon liquidation. Subject to certain exceptions, so long as any Preferred Stock remains outstanding, no dividend or distribution will be declared or paid on, and no redemption or repurchase will be agreed to or consummated of, stock on a parity with the Preferred Stock (“Parity Stock”), Common Stock or any other shares of stock junior to the Preferred Stock, unless all accumulated and unpaid dividends for all preceding full fiscal quarters have been declared and paid with respect to the Preferred Stock. In addition, no dividend or distribution or redemption or repurchase shall be paid on Parity Stock, Common Stock or any other shares of stock junior to the Preferred Stock for any period unless the Preferred Stock has been paid full cash dividends in respect of the same period; provided, however, that the Company may pay dividends on Common Stock in respect of any fiscal quarter ending on or prior to June 30, 2020 (the “PIK Period”).

The holders of Preferred Stock (the “Holders”) will receive quarterly distributions equal to an annual rate of 7.0% ($70.00 per share annualized) of $1,000 per share of Preferred Stock, subject to certain adjustments (the “Liquidation Preference”). With respect to any quarter ending on or prior to the PIK Period, the Company may elect, in lieu of paying a distribution in cash, to have the amount that would have been payable if such dividend had been paid in cash added to the Liquidation Preference.

On or after the eighteen month anniversary of the Issue Date, the Holders may convert their Preferred Stock into a number of shares of Common Stock equal to, per share of Preferred Stock, the quotient of the Liquidation Preference divided by $33.00 (the “Conversion Price”), subject to certain adjustments including customary anti-dilution adjustments (such quotient, the “Conversion Rate”). Holders may elect to convert the Preferred Stock, in whole or in part, so long as the aggregate value of Common Stock to be issued pursuant to such partial conversion is not for less than $50,000,000 or a lesser amount if such conversion relates to all of a Holder’s remaining Preferred Stock.

On or after the three year anniversary of the Issue Date, if the Holders have not elected to convert all of their shares of Preferred Stock, the Company may cause the outstanding Preferred Stock to be converted into a number of shares of Common Stock equal to, per share of Preferred Stock, the quotient of the Liquidation Preference divided by the Conversion Price, subject to certain adjustments including customary anti-dilution adjustments; provided, that in order for the Company to exercise such conversion right, the closing sale price of the Common Stock during a designated period be greater than or equal to $47.85, the resale of the shares of Common Stock issuable upon conversion shall be registered and available for resale by the Holders pursuant to a registration statement declared effective by the SEC

F-38

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

15. REDEEMABLE PREFERRED STOCK, Continued

covering such resales, the Common Stock is listed on a national securities exchange, and certain average daily trading volume minimum requirements are met. The Company may elect to convert the Preferred Stock, in whole or in part, so long as the aggregate value of Common Stock to be issued pursuant to such partial conversion is not for less than $50,000,000 or such lesser amount if such conversion relates to the aggregate amount of all remaining Preferred Stock.

Upon a change of control that involves consideration that is at least 90% cash, Holders are required to convert their shares of Preferred Stock into Common Stock at a rate equal to the greater of (i) the product of the Conversion Rate and the quotient of (a) the product of the Conversion Price and the Cash Change of Control Conversion Premium (as defined below), divided by (b) the average volume weighted average price of the Common Stock during a designated period and (ii) the Conversion Rate otherwise in effect at such time. The “Cash Change of Control Conversion Premium” equals (i) on or prior to the first anniversary of the Issue Date, 130%, (ii) after the first anniversary of the Issue Date, but on or prior to the second anniversary of the Issue Date, 120%, (iii) after the second anniversary of the Issue Date, but on or prior to the third anniversary of the Issue Date, 105%, and (iv) thereafter, 101%.

Upon a change of control that involves consideration that is less than 90% cash, Holders may elect to: (i) convert all, but not less than all, outstanding shares of Preferred Stock into Common Stock at the then-applicable Conversion Rate; (ii) except as described below, if the Company will not be the surviving person upon the consummation of such change of control, require the Company to use its commercially reasonable efforts to deliver to the Holders a security in the surviving person or the parent of the surviving person that has rights, preferences and privileges substantially similar to the Preferred Stock; provided, however, that, if the Company is unable to do so, such Holders shall be entitled to: (A) instead elect to convert shares of Preferred Stock pursuant to the mechanics described in clause (i) above or (B) require the Company to redeem all (but not less than all) of such Holder’s Preferred Stock at a price per share equal to 101% of the Liquidation Preference, with the redemption price being paid (at the Company’s option): (1) in cash or (2) in Common Stock; (iii) if the Company is the surviving person upon the consummation of such change of control, continue to hold such Holders’ shares of Preferred Stock; or (iv) require the Company to redeem all (but not less than all) of such Holder’s Preferred Stock at a cash price per share equal to the Liquidation Preference. At December 31, 2018, a change in control is not considered probable.

Holders shall be entitled to vote on all matters on which the holders of shares of Common Stock are entitled to vote and, except as otherwise provided in the Certificate of Incorporation, or by law, the Holders shall vote together with the holders of shares of Common Stock as a single class. Each Holder is entitled to a number of votes equal to the number of votes such Holder would have had if all shares of Preferred Stock held by such Holder had been converted into shares of Common Stock.

So long as any Preferred Stock is outstanding, the affirmative vote or consent of the Holders of at least 66 2/3% of the outstanding Preferred Stock, voting together as a separate class, will be necessary for effecting or validating: (i) any issuance of stock senior to the Preferred Stock, (ii) any issuance by the Company of Parity Stock, subject to certain exceptions described below, (iii) any repurchase by the Company of any Preferred Stock, other than on a pro rata basis among all Holders of Preferred Stock, (iv) any special, one-time dividend or distribution with respect to any class of junior stock and (v) any spinoff or other distribution of any equity securities or assets of any of the Company’s subsidiaries to its stockholders in which the consideration received by the Company in such transaction is less than fair market value, subject to certain exceptions. However, the foregoing rights of the Holders will not restrict any of the following actions, subject to certain terms: (i) the Company and any of its controlled affiliates entering into joint ventures with third parties, (ii) the issuance of securities, capital contributions or incurrence of intercompany indebtedness among the Company or any of its subsidiaries, or (iii) the issuance of securities, capital contributions or incurrence of intercompany indebtedness among the Company and any joint ventures, partnerships or other minority owned entities in which the Company or its subsidiaries have an equity or other interest, in each case, which exist as of the Issue Date.

Notwithstanding the vote or consent of the Holders described above, after the Issue Date, the Company may issue certain amounts of Parity Stock without the approval of the Holders if: (A) the aggregate amount of such issuances is less than or equal to $250,000,000 (excluding the aggregate amount of any additional shares of Preferred Stock issued to Warburg); or (B) the aggregate initial purchase price of the then outstanding Preferred Stock is less than $100,000,000.

Prior to the first anniversary of the Issue Date, no Holder may transfer any Preferred Stock without the prior written consent of the Company. Prior to the second anniversary of the Issue Date, Holders and their affiliates are prohibited from directly or indirectly engaging in any short sales or other hedging transactions involving the Preferred Stock and Common Stock underlying such Holder’s Preferred Stock.

F-39

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

15. REDEEMABLE PREFERRED STOCK, Continued

For so long as Warburg and its affiliates collectively own 75% or more of the outstanding Preferred Stock acquired by Warburg and its affiliates on the Issue Date, the Company, prior to any issuance of Parity Stock, is required to provide Warburg with a reasonable opportunity to purchase all or any portion of such shares of Parity Stock to be issued by the Company on substantially the same terms offered to the other purchasers of such securities.

The terms of the Preferred Stock purchase agreement (the “Purchase Agreement”) contains customary representations, warranties and covenants of the Company and the Purchasers made as of the date of the Purchase Agreement and as of the Issue Date, and the parties have agreed to indemnify each other against certain losses resulting from breaches of their respective representations, warranties and covenants.

Pursuant to the Purchase Agreement, the Company has granted to Warburg, until Warburg no longer owns at least 50% of the Preferred Stock issued to Warburg and its affiliates on the Issue Date, certain rights to designate an observer (the “Board Observer”) to the board of directors of the Company (the “Board”), who shall have the right to attend full meetings of the Board (including any executive session and certain committees thereof) and receive such materials as other members of the Board receive.

In addition, pursuant to the Purchase Agreement, the Company also granted Warburg and its affiliates rights to require the Company to file and maintain, subject to the penalties described in the Purchase Agreement, registration statements with respect to the resale of the Common Stock issuable upon conversion of the Preferred Stock. The Company is required to file or cause to be filed a registration statement (the “Preferred Registration Statement”) for the resale of registrable securities and is required to cause the Preferred Registration Statement to become effective no later than the eighteen month anniversary of the Issue Date. In certain circumstances, Warburg and its affiliates will have piggyback registration rights on offerings initiated by the Company or other persons who have been granted registration rights, and Warburg has the right to request two underwritten offerings upon certain terms and conditions set forth in the Purchase Agreement. Holders of registrable securities will cease to have registration rights under the Purchase Agreement on the earlier of (i) the second anniversary of the date on which shares Preferred Stock are first converted into shares of Common Stock and (ii) the date on which no registrable securities remain outstanding; provided, that the Company shall use reasonable best efforts to maintain the effectiveness of the Preferred Registration Statement during all periods in which Warburg (A) is deemed to be an affiliate of the Company pursuant to Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”), or (B) together with its affiliates, owns more than 5% of the Company’s Common Stock (including Common Stock it would own on an as-converted basis).

On May 25, 2018, we paid-in-kind a preferred stock dividend of $4.8 million, which was prorated for the period from January 19, 2018 to March 31, 2018. On August 29, 2018, we paid-in-kind a preferred stock dividend of $6.2 million. On November 26, 2018, we paid-in-kind a preferred stock dividend of $6.3 million. These dividends paid-in-kind increased the Liquidation Preference such that as of December 31, 2018, the Preferred Stock was convertible into 11,132,121 shares. On February 20, 2019, we declared a preferred stock dividend to be paid-in-kind of $6.4 million, which will be paid on March 01, 2019.

16. EQUITY

Common stock

The common stock for which the par value is reflected on the consolidated balance sheet at December 31, 2018 is summarized below:

F-40

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

16. EQUITY, Continued

	Class A
Shares accounted for at December 31, 2015	43,823,739
Issuance of common shares in public offering	8,625,000
Shares issued for Merger	13,140,020
Issuance of shares under employee and director compensation programs(1)	170,772
Shares issued under employee stock purchase plan	46,836
Shares accounted for at December 31, 2016	65,806,367
Shares issued for HFOTCO acquisition	12,383,900
Issuance of shares under employee and director compensation programs(1)	149,961
Shares issued under employee stock purchase plan	39,545
Shares accounted for at December 31, 2017	78,379,773
Issuance of shares under employee and director compensation programs(1)	202,545
Shares issued under employee stock purchase plan	53,757
Shares accounted for at December 31, 2018(2)	78,636,075

(1) Of these vested shares, recipients sold back to the Company 57,041, 42,347 and 46,941 shares during the years ended December 31, 2018, 2017 and 2016, respectively, to satisfy tax withholding obligations. These repurchased shares are being recognized at cost as treasury stock on the consolidated balance sheet.

(2) In addition to the shares in the table above, there are shares of unvested restricted stock outstanding which are considered legally issued and outstanding and have been included in the number of shares presented on the consolidated balance sheets. The par value of unvested restricted stock has not yet been reflected in common stock on the consolidated balance sheet, as these shares have not yet vested and could be forfeited. There are also shares of restricted stock that were returned to treasury upon forfeiture. The par value of these shares is not reflected in the consolidated balance sheet, as no accounting recognition is given to forfeited shares.

The common stock includes Class A and Class B stock. Class A stock is eligible to be listed on an exchange, whereas Class B stock is not. Any share of Class B stock may be converted to Class A at the election of the holder. Both classes of stock have full voting rights. Both classes of stock have a par value of $0.01 per share. No Class B stock is currently issued. The total number of shares authorized for issuance is 180,000,000 shares of Class A stock and 10,000,000 shares of Class B stock.

Preferred Stock Issuances

On May 17, 2017, our stockholders voted to approve an amendment to the Company's Amended and Restated Certificate of Incorporation to authorize 4,000,000 shares of preferred stock. On January 19, 2018, we issued an aggregate of 350,000 shares of preferred stock. See Note 15 for further information on the issuance.

Equity issuances

On June 22, 2016, we issued and sold 8,625,000 shares of our Class A common stock, valued at $27.00 per share, to the public for proceeds of $228.5 million, net of underwriting fees and other offering costs of $4.3 million. Proceeds were used to repay borrowings on our revolving credit facility and for capital expenditures and general corporate purposes.

On September 30, 2016, we completed the Merger with Rose Rock. We issued 13.1 million common shares in exchange for the outstanding common limited partner units of Rose Rock which we did not already own. Issuance costs of $5.3 million were recorded as a reduction to additional paid in capital. In addition, we recorded a reduction to our deferred tax liabilities and offsetting increase to additional paid-in capital of $143.3 million associated with the transaction. This non-cash adjustment represents the deferred tax impact of the difference between the book value of the noncontrolling interests acquired and the tax basis which is stepped-up to the fair market value of the consideration which includes the common shares issued and the assumption of liabilities associated with the noncontrolling interests. See Note 5 for further information on the Merger.

On July 17, 2017, we completed the acquisition of HFOTCO. We issued 12.4 million common shares with an acquisition date fair value of $330 million, based on $26.68 per common share market price at issuance. See Note 5 for further information on the acquisition.

F-41

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

16. EQUITY, Continued

Noncontrolling Interest

On October 22, 2018, Maurepas Pipeline, LLC, a subsidiary of SemGroup, sold Class B shares representing a 49% ownership interest to Alinda Capital Partners (“Alinda”) for $350 million, subject to customary post-closing adjustments. The Class B shares provide Alinda with a $2.2 million monthly preference on distributions. The Class B shares are convertible to Class A shares of Maurepas Pipeline, LLC at Alinda’s option any time after the second anniversary of closing. SemGroup has a call option to repurchase Alinda’s shares prior to the fifth anniversary of closing for a fixed amount of $350 million plus 1% per annum, subject to a 24 month non-call period. The Class B shares provide Alinda with two out of five seats on the Board of Managers of Maurepas Pipeline, LLC and certain protective rights. The Class B shares are reported as a noncontrolling interest in our consolidated financial statements.

Dividends

The following table sets forth the quarterly dividends per share declared and paid to shareholders for the periods indicated:

Quarter Ending	Dividend Per Share		Date of Record	Date Paid
March 31, 2016	$	0.45	March 7, 2016	March 17, 2016
June 30, 2016	$	0.45	May 16, 2016	May 26, 2016
September 30, 2016	$	0.45	August 15, 2016	August 25, 2016
December 31, 2016	$	0.45	November 18, 2016	November 28, 2016
March 31, 2017	$	0.45	March 7, 2017	March 17, 2017
June 30, 2017	$	0.45	May 15, 2017	May 26, 2017
September 30, 2017	$	0.45	August 18, 2017	August 28, 2017
December 31, 2107	$	0.45	November 20, 2017	December 1, 2017
March 31, 2018	$	0.4725	March 9, 2018	March 19, 2018
June 30, 2018	$	0.4725	May 16, 2018	May 25, 2018
September 30, 2018	$	0.4725	August 20, 2018	August 29, 2018
December 31, 2018	$	0.4725	November 16, 2018	November 26, 2018
March 31, 2019	$	0.4725	March 4, 2019	March 14, 2019

Rose Rock Midstream, L.P.

The following table shows the distributions paid by Rose Rock Midstream, L.P., prior to the Merger, related to the earnings for each of the following periods (in thousands, except for per unit amounts):

	Distribution Per Unit		Distributions Paid
Quarter Ended			SemGroup								Noncontrolling Interest Common Units		Total Distributions
			General Partner		Incentive Distributions		Common Units		Subordinated Units
December 31, 2015	$	0.6600	$	604	$	5,333	$	13,665	$	—	$	10,622	$	30,224
March 31, 2016	$	0.6600	$	605	$	5,338	$	13,665	$	—	$	10,643	$	30,251
June 30, 2016	$	0.6600	$	605	$	5,339	$	13,665	$	—	$	10,648	$	30,257

F-42

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

17.    ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table presents changes in the components of accumulated other comprehensive loss (in thousands):

	Currency Translation			Employee Benefit Plans			Total
Balance, December 31, 2015	$	(57,201	)	$	(1,361	)	$	(58,562	)
Currency translation adjustment, net of income tax benefit of $8,672	(14,224		)	—			(14,224		)
Changes related to benefit plans, net of income tax benefit of $417	—			(1,128		)	(1,128		)
Balance, December 31, 2016	(71,425		)	(2,489		)	(73,914		)
Currency translation adjustment, net of income tax expense of $12,404	20,411			—			20,411
Changes related to benefit plans, net of income tax expense of $99	—			(298		)	(298		)
Balance, December 31, 2017	(51,014		)	(2,787		)	(53,801		)
Currency translation adjustment, net of income tax benefit of $4,949	(32,379		)	—			(32,379		)
Currency translation adjustment reclassified to gain on disposal, net of income tax expense of $11,769	37,577			—			37,577
Changes related to benefit plans, net of income tax benefit of $311	—			(2,644		)	(2,644		)
Balance, December 31, 2018	$	(45,816	)	$	(5,431	)	$	(51,247	)

There were no significant items reclassified out of accumulated other comprehensive loss to net income for the years ended December 31, 2017 and 2016.

18. REVENUE FROM CONTRACTS WITH CUSTOMERS

We provide gathering, transportation, storage, distribution, marketing and other midstream services primarily to producers, refiners of petroleum products and other market participants located in the Gulf Coast, Midwest and Rocky Mountain regions of the United States of America (the “U.S.”) and Western Canada. In general, we recognize service revenue as the service is performed (“over time”) and product sales revenues are recognized when control of the product transfers to the customer (“point in time”). Our revenue from contracts with customers are disaggregated by segment as follows:

U.S. Liquids

• U.S. Liquids generates revenue by:

◦ providing crude oil pipeline and truck transportation services to customers under fee-based contractual arrangements generally based on units of volume transported;

◦ providing crude oil storage services primarily to customers in the Houston Ship Channel and at the Cushing Hub under fee-based contractual arrangements that, in some cases, are fixed and not dependent on usage;

◦ providing terminalling services including pump-over, unloading, heating, berthing and excess throughput fees which are based on per volume fees for units delivered or withdrawn; and

◦ performing marketing activities including purchasing crude oil for its own account from producers and aggregators and selling to traders and refiners under contracts generally with initial terms of less than one year. Revenue is recognized based on market prices at the time the commodities are sold. In certain transactions, we purchase inventory from, and sell inventory to, the same counterparty. Such transactions that are entered into in contemplation of one another are recorded on a net basis.

U.S. Liquids also generates revenue from leases of certain land, tanks and a barge dock, which are accounted for as a direct financing lease and are outside of the scope of ASC 606.

F-43

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

18. REVENUE FROM CONTRACTS WITH CUSTOMERS, Continued

U.S. Gas

• U.S. Gas generates revenue by providing natural gas and natural gas liquids gathering and processing services to customers based on agreements that are a combination of percent of proceeds and fee-based contracts. Initial contract terms can range from monthly and interruptible to the life of the reserves and, upon expiration, continue to renew on a month-to-month or year-to-year evergreen basis. U.S. Gas’ customers include producers, operators, marketers and traders. Gathering and processing fees are generally based on per volume fees. Product sales revenue is generated from the sale of NGLs and residue gas arising from processing at prevailing market prices.

Canada

• Canada generates revenue from its processing plants through volumetric fees for services under contractual arrangements with working interest owners and third-party customers and the pass through of certain operating costs. Pass-through cost recoveries are reported as "Other revenue" in the consolidated statements of operations and comprehensive income (loss). Canada also derives revenue as the owner and operator of pipeline gathering systems that gather gas from multiple wells located in the same production unit and as the owner and operator of pipeline transportation systems that deliver the gathered gas to its processing plant. Canada’s customers include producers of varying sizes. To support operations at our plants, several producers have committed to process all of their current and future natural gas production.

Corporate and Other

• Corporate and Other is not an operating segment, but contains the results of operations for our former U.K. and Mexican businesses which were disposed of in early 2018.

Key areas of judgment    

Take or pay

Contracts with take-or-pay provisions are recognized over time as the customer simultaneously receives and consumes the benefit of available capacity. Payments made for unused take-or-pay capacity, which allow the customer to carryforward a portion of the unused capacity to future periods, are deferred until it becomes unlikely that the capacity will be used prior to contract expiration. Determining when, or if, the capacity will be used requires judgment.

Percentage of proceeds

Contracts with percentage of proceeds terms typically involve the receipt of natural gas at the wellhead and include gathering, processing and marketing of the resulting NGLs and residue gas with SemGroup retaining a portion of the proceeds from the ultimate sale to a third-party. The terms of these agreements include various gathering and processing fees. The determination of whether the transaction is a purchase at the wellhead by SemGroup with gathering and processing performed on our own account or whether the transaction represents gathering and processing as a service provided to the producer by SemGroup with a purchase and sale of processed gas at the completion of the service, requires judgment and is impacted by when control of the underlying commodity has been deemed to move from the producer to the processor. This determination impacts whether gathering and processing fees are recorded as reductions to cost of sales or recorded as service revenue.

Principal vs. agent

We engage in various types of transactions where we perform marketing activities for producers, such as our percentage of proceeds contracts, or transactions where costs are incurred and reimbursed by customers or other owners in facilities, such as Canada's pass-through costs. These types of transactions require judgment to determine whether we are the principal or an agent in the transaction and as a result whether revenues are recorded gross or net.

Non-cash consideration

SemGroup receives commodities from its customers in the form of plant and field fuel, pipeline loss allowance and retention of drip liquids. The purpose of the receipt of these commodities is to keep the Company whole in the case of

F-44

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

18. REVENUE FROM CONTRACTS WITH CUSTOMERS, Continued

minor operational usage or loss of product and is not intended as a consideration for services performed. Therefore, the receipt of these commodities does not represent consideration and is not recorded as revenue. Any net retention of commodities in excess of actual losses is recorded in inventory and recognized as revenue when sold.

Tiered pricing and material rights

We have certain contracts that provide customers with rates that reduce incrementally as volumes increase beyond certain thresholds. These types of agreements require judgment to determine if the option for the customer to acquire additional services constitutes a material right that the customer would not receive without entering into the contract, e.g. the discount exceeds the range of discounts typically given. If it is determined that a material right exists, a portion of the revenue is allocated to that right at contract inception and recognized as revenue as the option for additional services is exercised or when the option expires. In contrast, if it is concluded that the option to acquire additional services reflects standalone selling price, this would constitute a marketing offer and not a material right.

Disaggregated revenue

Our revenue is disaggregated by segment and by activity below (in thousands):

	Year Ended December 31,
	2018			2017			2016
U.S. Liquids
Product sales	$	1,680,327		$	1,299,343		$	716,570
Pipeline transportation	84,878			43,642			23,099
Truck transportation	23,553			31,351			41,754
Storage fees	161,498			85,712			27,673
Facility service fees	49,896			27,658			18,283
Lease revenue	17,549			5,843			—
U.S. Gas
Product sales	210,827			180,581			167,319
Service fees	54,494			52,637			51,651
Canada
Service fees	134,059			120,575			75,715
Other revenue	59,075			62,657			57,501
Corporate and Other
Product sales	31,319			153,164			136,448
Storage fees	7,753			22,764			20,542
Service fees	3,070			7,160			6,537
Intersegment eliminations	(15,036		)	(11,170		)	(10,928		)
Total revenue	$	2,503,262		$	2,081,917		$	1,332,164

F-45

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

18. REVENUE FROM CONTRACTS WITH CUSTOMERS, Continued

Remaining performance obligations

Most of our service contracts are such that we have the right to consideration from a customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Therefore, we are utilizing the practical expedient in ASC 606-10-55-18 under which we recognize revenue in the amount to which we have the right to invoice. Applying this practical expedient, we are not required to disclose the transaction price allocated to remaining performance obligations under these agreements. However, certain of our agreements, such as "take-or-pay" agreements, do not qualify for the practical expedient. The amount and timing of revenue recognition for such contracts is presented below (in thousands):

	2019		2020		2021		2022		2023		Thereafter
Expected timing of revenue recognized for remaining performance obligations	$	280,984	$	227,981	$	186,465	$	169,252	$	163,193	$	1,349,773

For our product sales contracts, we have elected the practical expedient set out in ASC 606-10-50-14A that states that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these agreements, each unit of product represents a separate performance obligation and therefore future volumes are wholly unsatisfied and disclosure of transaction price allocated to remaining performance obligations is not required. Under product sales contracts, the variability arises as both volume and pricing (typically index based) are not known until the product is delivered.

Receivables from contracts with customers

Accounts receivable, net on the condensed consolidated balance sheets represents current receivables from contracts with customers. Certain noncurrent receivables from contracts with customers are included in “other noncurrent assets” on the condensed consolidated balance sheets. These amounts are accruals to recognize revenue for performance to date related to customer deficiencies on minimum volume commitments with make-up rights for which the use of the make-up rights are not probable due to capacity constraints or other factors. Therefore, we have accrued the amount for which no future performance by SemGroup will be required, but for which we do not have a present right to bill the customer until the end of the contract. The balance of noncurrent receivables from customer contracts was (in thousands):

	December 31, 2018		December 31, 2017
Noncurrent receivables	$	11,496	$	—

Noncurrent receivables for the transactions described above were not recorded prior to the adoption of ASC 606 as our policy was to defer recognition of deficiencies with make-up rights until the contractual make-up rights expired.

Deferred revenue

We record deferred revenue when we have received a payment in advance of delivering a product or performing a service. For the year ended December 31, 2018, we recognized $4.2 million of revenue which was included in deferred revenue at the beginning of the period.

Costs to obtain or fulfill a contract

Unless material, we expense costs to obtain or fulfill a contract in the period incurred. At December 31, 2018, we had contract assets of $9.4 million related to costs incurred to obtain contracts which had been expensed as incurred under previous guidance. These costs are reported within “other noncurrent assets” on the condensed consolidated balance sheets and are being amortized straight-line over 25 years, the life of the related contracts. We recognized $0.4 million of amortization of these assets for the year ended December 31, 2018.

F-46

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

19. EARNINGS PER SHARE

Earnings per share is calculated based on income from continuing and discontinued operations less any income attributable to noncontrolling interests and cumulative preferred stock dividends. Prior to completion of the Merger in 2016, income attributable to noncontrolling interests represented third-party limited partner unitholders' interests in the earnings of our consolidated subsidiary, Rose Rock. Rose Rock allocated net income to its limited partners based on the distributions pertaining to the current period's available cash as defined by Rose Rock's partnership agreement. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, were allocated to Rose Rock's general partner, limited partners and participating securities in accordance with the contractual terms of Rose Rock's partnership agreement and as further prescribed under the two-class method. Incentive distribution rights did not participate in undistributed earnings. Subsequent to the Merger, there is no longer a noncontrolling interest for Rose Rock. In 2018, Maurepas Pipeline, LLC, a subsidiary of SemGroup, sold Class B shares representing a 49% interest in the form of Class B shares of Maurepas Pipeline, LLC. The Class B shares provide for a monthly preference on Maurepas Pipeline, LLC distributions and are reported as a noncontrolling interest.

Basic earnings (loss) per share is calculated based on the weighted average shares outstanding during the period. Diluted earnings (loss) per share includes the dilutive effect of unvested equity compensation awards and the potential conversion of preferred stock, if dilutive.

The following summarizes the calculation of basic earnings per share for the years ended December 31, 2018, 2017 and 2016 (in thousands, except per share amounts):

	Year Ended December 31, 2018
	Continuing Operations			Discontinued Operations		Net
Loss	$	(24,328	)	$	—	$	(24,328	)
less: Income attributable to noncontrolling interest	2,421			—		2,421
Loss attributable to SemGroup	$	(26,749	)	$	—	$	(26,749	)
less: cumulative preferred stock dividends	23,790			—		23,790
Net loss attributable to common shareholders	(50,539		)	—		(50,539		)
Weighted average common stock outstanding	78,313			78,313		78,313
Basic loss per share	$	(0.65	)	$	—	$	(0.65	)

	Year Ended December 31, 2017
	Continuing Operations			Discontinued Operations		Net
Loss	$	(17,150	)	$	—	$	(17,150	)
less: Income attributable to noncontrolling interest	—			—		—
Loss attributable to SemGroup	$	(17,150	)	$	—	$	(17,150	)
Weighted average common stock outstanding	71,418			71,418		71,418
Basic loss per share	$	(0.24	)	$	—	$	(0.24	)

	Year Ended December 31, 2016
	Continuing Operations		Discontinued Operations			Net
Income	$	13,263	$	(1	)	$	13,262
less: Income attributable to noncontrolling interest	11,167		—			11,167
Income attributable to SemGroup	$	2,096	$	(1	)	$	2,095
Weighted average common stock outstanding	51,889		51,889			51,889
Basic earnings per share	$	0.04	$	—		$	0.04

F-47

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

19. EARNINGS PER SHARE, Continued

The following summarizes the calculation of diluted earnings per share for the years ended December 31, 2018, 2017 and 2016 (in thousands, except per share amounts):

	Year Ended December 31, 2018
	Continuing Operations			Discontinued Operations		Net
Loss	$	(24,328	)	$	—	$	(24,328	)
less: Income attributable to noncontrolling interest	2,421			—		2,421
Loss attributable to SemGroup	$	(26,749	)	$	—	$	(26,749	)
Less: cumulative preferred stock dividends	23,790			—		23,790
Net loss attributable to common shareholders	(50,539		)	—		(50,539		)
Weighted average common stock outstanding	78,313			78,313		78,313
Effect of dilutive securities	—			—		—
Diluted weighted average common stock outstanding	78,313			78,313		78,313
Diluted loss per share	$	(0.65	)	$	—	$	(0.65	)

	Year Ended December 31, 2017
	Continuing Operations			Discontinued Operations		Net
Loss	$	(17,150	)	$	—	$	(17,150	)
less: Income attributable to noncontrolling interest	—			—		—
Loss attributable to SemGroup	$	(17,150	)	$	—	$	(17,150	)
Weighted average common stock outstanding	71,418			71,418		71,418
Effect of dilutive securities	—			—		—
Diluted weighted average common stock outstanding	71,418			71,418		71,418
Diluted loss per share	$	(0.24	)	$	—	$	(0.24	)

	Year Ended December 31, 2016
	Continuing Operations		Discontinued Operations			Net
Income	$	13,263	$	(1	)	$	13,262
less: Income attributable to noncontrolling interest	11,167		—			11,167
Income attributable to SemGroup	$	2,096	$	(1	)	$	2,095
Weighted average common stock outstanding	51,889		51,889			51,889
Effect of dilutive securities	392		392			392
Diluted weighted average common stock outstanding	52,281		52,281			52,281
Diluted earnings per share	$	0.04	$	—		$	0.04

For the year ended December 31, 2018, the preferred stock would have been antidilutive and therefore, was not included in the computation of diluted earnings. For the years ended December 31, 2018 and 2017, we experienced net losses attributable to SemGroup. The unvested equity compensation awards would have been antidilutive and, therefore, were not included in the computation of diluted earnings per share.

20.    EQUITY-BASED COMPENSATION

SemGroup Corporation equity awards

We have reserved a total of 3,710,220 shares of common stock for issuance pursuant to employee and director compensation programs. Awards under these programs give the recipients the right to receive shares of common stock, once specified service, performance or market related vesting conditions are met. The awards typically have a one year

F-48

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

20. EQUITY-BASED COMPENSATION, Continued

vesting period for non-management directors and three years for employees. The awards may be subject to accelerated vesting in the event of involuntary terminations. We record expense for these awards (and corresponding increases to additional paid-in capital) based on the grant date fair value of the awards over the vesting period. We use authorized but unissued shares to satisfy our equity-based payment obligations. Although these awards are to be settled in shares, we may elect to give participants the option of surrendering a portion of the awards, to meet statutory minimum tax withholding requirements. The activity related to these awards during the period from December 31, 2015 to December 31, 2018 is summarized below:

	Unvested Shares		Average Grant Date Fair Value		Aggregate Fair Value of Shares (in thousands)
Outstanding at December 31, 2015	411,308		$	75.25
Awards granted - 2016	702,309		$	19.18
Awards vested - 2016	(168,096	)	$	20.38	$	3,426
Awards forfeited - 2016	(34,255	)	$	42.42
Outstanding at December 31, 2016	911,266		$	31.09
Awards granted - 2017	377,766		$	35.22
Awards vested - 2017	(149,961	)	$	33.60	$	5,039
Awards forfeited - 2017	(54,981	)	$	81.80
Outstanding at December 31, 2017	1,084,090		$	29.07
Awards granted - 2018	781,100		$	22.10
Awards vested - 2018	(202,545	)	$	23.18	$	4,695
Awards forfeited - 2018	(188,410	)	$	49.72
Outstanding at December 31, 2018	1,474,235		$	21.04

Of the awards vested during the years ended December 31, 2018, 2017 and 2016, 57,041, 42,347 and 46,941 shares were withheld to satisfy minimum tax requirements, respectively.

Included in the awards granted for the year ended December 31, 2016, is 128,585 restricted stock awards granted in exchange for Rose Rock equity based awards which were canceled as part of the Merger transaction described in Note 5. Incremental compensation expense was not significant. Accrued unvested unit distribution rights associated with unvested Rose Rock restricted unit awards carried over to the restricted stock awards issued in the exchange.

For certain of the awards granted in 2018, 2017, and 2016, the number of shares that will vest is contingent upon our achievement of certain specified targets. Awards with performance conditions are valued based on the grant date closing price on the New York Stock Exchange based on the number of awards expected to vest. Awards with market conditions are valued using Monte Carlo simulations and were granted in 2017 and 2016. There were no awards with market conditions granted in 2018. The following table sets forth the assumptions used in the valuations of these awards granted in 2017 and 2016:

	2017	2016
Volatility	54.2%	51.9%
Risk-free interest rate	1.57%	0.98%

Volatility assumptions were based on historical volatility using a simple average calculation of volatility over a period equal to the vesting period of the awards.  We do not expect future volatility over the term of the awards to be significantly different from historical volatility. 

If we meet the specified maximum targets, approximately 558 thousand additional shares could vest.

The holders of certain restricted stock awards are entitled to equivalent dividends (“UDs”) to be settled in cash upon vesting of the restricted stock awards. The UDs are subject to the same forfeiture and acceleration conditions as the associated restricted stock awards. At December 31, 2018, the value of UDs related to unvested restricted stock awards was approximately $2.7 million.

F-49

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

20. EQUITY-BASED COMPENSATION, Continued

Compensation costs expensed for restricted stock awards for the years ended December 31, 2018, 2017 and 2016 were $11.4 million, $10.1 million and $8.8 million, respectively. As of December 31, 2018, there was $13.9 million of total unrecognized compensation cost related to our non-vested restricted stock awards, which is expected to be recognized over a weighted-average period of 16 months.

Director retainer

For the year ended December 31, 2016, we issued 2,676 shares of common stock to a director, in lieu of an annual cash retainer. No shares were issued to directors in lieu of an annual cash retainer for the years ended December 31, 2017 and 2018.

Employee stock purchase plan

Our employee stock purchase plan ("ESPP") allows eligible employees to contribute up to 10% of their base earnings toward the semi-annual purchase of our common stock, subject to an annual maximum dollar amount. The purchase price is 85% of the closing price on the last business day of the offering period. We have reserved a total of 1,000,000 shares of common stock for issuance under the ESPP. During the years ended December 31, 2018, 2017 and 2016, we issued 53,757, 39,545 and 46,836 shares, respectively, under our ESPP.

Rose Rock equity-based compensation

Prior to the Merger, certain of our employees who supported Rose Rock participated in Rose Rock's equity-based compensation program. Awards under this program generally represented awards of restricted common units representing limited partner interests of Rose Rock. Generally, the awards vested three years after the date of grant for employees and one year after the date of grant for non-management directors, contingent upon the continued service of the recipients and may have been subject to accelerated vesting in the event of involuntary terminations. Awards were valued based on the grant date closing price listed on the New York Stock Exchange. Compensation expense was recognized over the vesting period and was discounted for estimated forfeitures. Vesting of these awards diluted our ownership interest. The activity related to these awards is summarized below:

	Unvested Units		Average Grant Date Fair Value		Aggregate Fair Value of Units (in thousands)
Outstanding at December 31, 2015	100,191		$	38.70
Awards granted - 2016	117,204		$	9.62
Awards vested - 2016	(57,458	)	$	11.58	$	665
Awards forfeited - 2016	(1,846	)	$	26.55
Awards converted to SemGroup awards	(158,091	)	$	19.57
Outstanding at December 31, 2016	—		$	—

Of the awards vested during the year ended December 31, 2016, 254 were withheld to satisfy minimum tax requirements.

Compensation cost expensed for the year ended December 31, 2016, was $1.2 million and represents an increase in noncontrolling interests in consolidated subsidiaries.

The holders of certain of these restricted unit awards were entitled to equivalent distributions (“UUDs”) to be received upon vesting of the restricted unit awards. As part of the Merger transaction, the value of these cash settled UUDs related to unvested restricted units was transferred to SemGroup and is now included in the balance for SemGroup UD's noted above.

21. SEGMENTS

As described in Note 1, our businesses are organized based on the nature and location of the services they provide. Certain summarized information related to our reportable segments is shown in the tables below. None of the operating segments have been aggregated. Although Corporate and Other does not represent an operating segment, it is included in the tables below to reconcile segment information to that of the consolidated Company.

F-50

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

21. SEGMENTS, Continued

In the fourth quarter of 2018, due to recent changes in our asset portfolio, the company elected to reorganize its business structure and reporting relationships to enhance execution and capture operating efficiencies. In conjunction with the reorganization, our reportable segments have changed. Prior period segment disclosures have been recast to reflect the new segments. U.S. Liquids includes the results of our U.S. crude oil operations, including the results of HFOTCO, subsequent to its acquisition in 2017. U.S. Gas contains the results of our historical SemGas segment. Canada includes the operations of our historical SemCAMS segment. Our prior SemMexico and SemLogistics segments are included within Corporate and Other, as these businesses were disposed of in 2018. Eliminations of transactions between segments are also included within Corporate and Other in the tables below.

The accounting policies of each segment are the same as the accounting policies of the consolidated Company. Transactions between segments are generally recorded based on prices negotiated between the segments.

Segment Profit is defined as revenue, less cost of products sold (exclusive of depreciation and amortization) and operating expenses, plus equity earnings and is adjusted to remove unrealized gains and losses on commodity derivatives and to reflect equity earnings on an EBITDA basis. Reflecting equity earnings on an EBITDA basis is achieved by adjusting equity earnings to exclude our percentage of interest, taxes, depreciation and amortization from equity earnings for operated equity method investees. For our investment in NGL Energy, we exclude equity earnings and include cash distributions received.

Our results by segment are presented in the tables below (in thousands):

	Year Ended December 31,
	2018			2017			2016
Revenues:
U.S. Liquids
External	$	2,017,701		$	1,493,548		$	827,379
U.S. Gas
External	250,285			222,048			208,042
Intersegment	15,036			11,170			10,928
Canada
External	193,134			183,232			133,216
Corporate and Other
External	42,142			183,089			163,527
Intersegment	(15,036		)	(11,170		)	(10,928		)
Total Revenues	$	2,503,262		$	2,081,917		$	1,332,164
	Year Ended December 31,
	2018			2017			2016
Earnings from equity method investments:
U.S. Liquids	$	57,625		$	67,345		$	71,569
Corporate and Other	47			(14		)	2,147
Total earnings from equity method investments	$	57,672		$	67,331		$	73,716
	Year Ended December 31,
	2018			2017			2016
Depreciation and amortization:
U.S. Liquids	$	142,237		$	88,738		$	32,449
U.S. Gas	42,997			37,059			36,170
Canada	21,051			18,530			16,867
Corporate and Other	2,969			14,094			13,318
Total depreciation and amortization	$	209,254		$	158,421		$	98,804

F-51

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

21. SEGMENTS, Continued

	Year Ended December 31,
	2018			2017			2016
Income tax expense (benefit):
U.S. Liquids	$	575		$	362		$	—
Canada	11,018			8,863			3,667
Corporate and Other	11,711			(11,613		)	7,601
Total income tax expense (benefit)	$	23,304		$	(2,388	)	$	11,268
	Year Ended December 31,
	2018			2017			2016
Segment profit:
U.S. Liquids	$	309,423		$	229,208		$	190,768
U.S. Gas	67,070			67,805			66,530
Canada	81,330			76,274			53,264
Corporate and Other	9,726			33,236			39,534
Total segment profit	$	467,549		$	406,523		$	350,096
	Year Ended December 31,
	2018			2017			2016
Reconciliation of segment profit to net income (loss):
Total segment profit	$	467,549		$	406,523		$	350,096
Less:
Adjustment to reflect equity earnings on an EBITDA basis	19,532			26,890			28,757
Net unrealized loss (gain) related to derivative instruments	(5,053		)	40			989
General and administrative expense	91,568			113,779			84,183
Depreciation and amortization	209,254			158,421			98,804
Loss (gain) on disposal or impairment, net	(3,563		)	13,333			16,048
Interest expense	149,714			103,009			62,650
Loss on early extinguishment of debt	—			19,930			—
Foreign currency transaction loss (gain)	9,501			(4,709		)	4,759
Loss (gain) on sale or impairment of non-operated equity method investment	—			—			30,644
Other expense (income), net	(2,380		)	(4,632		)	(1,269		)
Income tax expense (benefit)	23,304			(2,388		)	11,268
Loss from discontinued operations	—			—			1
Net income (loss)	$	(24,328	)	$	(17,150	)	$	13,262
	Year Ended December 31,
	2018			2017			2016
Additions to long-lived assets, including acquisitions and contributions to equity method investments:
U.S. Liquids	$	119,064		$	2,289,218		$	240,242
U.S. Gas	31,102			100,537			21,913
Canada	218,566			113,263			34,506
Corporate and Other	1,804			18,062			28,020
Total additions to long-lived assets	$	370,536		$	2,521,080		$	324,681

F-52

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

21. SEGMENTS, Continued

	December 31,
	2018		2017
Total assets (excluding intersegment receivables):
U.S. Liquids	$	3,689,384	$	3,871,334
U.S. Gas	716,837		714,777
Canada	684,418		518,900
Corporate and Other	119,668		271,806
Total	$	5,210,307	$	5,376,817
	December 31,
	2018		2017
Equity investments:
U.S. Liquids	$	255,043	$	266,362
Corporate and Other	18,966		18,919
Total equity investments	$	274,009	$	285,281

22.    SUPPLEMENTAL CASH FLOW INFORMATION

Operating assets and liabilities

The following table summarizes the changes in the components of operating assets and liabilities, net of the effects of acquisitions (in thousands):

	Year Ended December 31,
	2018			2017			2016
Decrease (increase) in restricted cash	$	33		$	(1	)	$	(1	)
Decrease (increase) in accounts receivable	78,624			(237,394		)	(90,810		)
Decrease (increase) in receivable from affiliates	685			23,764			(19,541		)
Decrease (increase) in inventories	52,166			(17,862		)	(30,686		)
Decrease (increase) in other current assets	(3,406		)	2,947			634
Decrease (increase) in other assets	(1,636		)	(14,307		)	(297		)
Increase (decrease) in accounts payable and accrued liabilities	(78,829		)	209,982			94,687
Increase (decrease) in payable to affiliates	(3,198		)	(19,537		)	21,475
Increase (decrease) in other noncurrent liabilities	1,374			19,385			2,573
	$	45,813		$	(33,023	)	$	(21,966	)

Non-cash transactions

In connection with our acquisition of the noncontrolling interest in Rose Rock in 2016 (Note 5), we recorded a reduction to our deferred tax liabilities and offsetting increase to additional paid-in capital of $143.3 million associated with the transaction. This non-cash adjustment represents the deferred tax impact of the difference between the book value of the noncontrolling interest acquired and the tax basis which is stepped-up to the fair market value of the consideration which included the common shares issued and the assumption of liabilities associated with the noncontrolling interest.

Other supplemental disclosures

We paid cash for interest totaling $141.2 million, $82.0 million and $71.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

F-53

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

22. SUPPLEMENTAL CASH FLOW INFORMATION, Continued

We paid cash for income taxes (net of refunds received) in the amount of $16.8 million, $7.2 million and $0.7 million during the years ended December 31, 2018, 2017 and 2016, respectively.

We accrued $51.3 million, $76.1 million and $1.4 million at December 31, 2018, 2017 and 2016, respectively, for purchases of property, plant and equipment.

We financed prepayments of insurance premiums of $8.0 million, $6.2 million and $4.7 million for the years ended December 31, 2018, 2017 and 2016, respectively.

23.    QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized information on our consolidated results of operations for the quarters during the year ended December 31, 2018 is shown below (in thousands, except per share amounts):

	First Quarter			Second Quarter				Third Quarter			Fourth Quarter			Total
Total revenues	$	661,609		$	595,794			$	633,996		$	611,863		$	2,503,262
Loss (gain) on disposal or impairment, net	(3,566		)	1,824				(383		)	(1,438		)	(3,563		)
Other operating costs and expenses	642,936			576,975				609,208			579,567			2,408,686
Total expenses	639,370			578,799				608,825			578,129			2,405,123
Earnings from equity method investments	12,614			14,351				14,528			16,179			57,672
Operating income	34,853			31,346				39,699			49,913			155,811
Other expenses, net	44,805			37,685				33,935			40,410			156,835
Income (loss) before income taxes	(9,952		)	(6,339		)		5,764			9,503			(1,024		)
Income tax expense (benefit)	23,083			(3,613		)		(2,697		)	6,531			23,304
Net income (loss)	(33,035		)	(2,726		)		8,461			2,972			(24,328		)
Less: net income attributable to noncontrolling interest	—			—				—			2,421			2,421
Net income (loss) attributable to SemGroup	(33,035		)	(2,726		)	—	8,461			551			(26,749		)
Less: cumulative preferred stock dividends	4,832			6,211				6,317			6,430			23,790
Net income (loss) attributable to common shareholders	$	(37,867	)	$	(8,937	)		$	2,144		$	(5,879	)	$	(50,539	)
Earnings (loss) per share—basic	$	(0.48	)	$	(0.11	)		$	0.03		$	(0.08	)	$	(0.65	)
Earnings (loss) per share—diluted	$	(0.48	)	$	(0.11	)		$	0.03		$	(0.08	)	$	(0.65	)

Summarized information on our consolidated results of operations for the quarters during the year ended December 31, 2017 is shown below (in thousands, except per share amounts):

F-54

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

23. QUARTERLY FINANCIAL DATA (UNAUDITED), Continued

	First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total
Total revenues	$	456,100			$	473,089			$	545,922			$	606,806			$	2,081,917
Loss (gain) on disposal or impairment, net	2,410				(234		)		41,625				(30,468		)		13,333
Other operating costs and expenses	447,392				465,874				549,442				579,147				2,041,855
Total expenses	449,802				465,640			—	591,067			—	548,679			—	2,055,188
Earnings from equity method investments	17,091				17,753				17,367				15,120				67,331
Operating income (loss)	23,389				25,202			—	(27,778		)	—	73,247			—	94,060
Other expenses, net	33,571				11,966				28,574				39,487				113,598
Income (loss) from continuing operations before income taxes	(10,182		)	—	13,236			—	(56,352		)	—	33,760			—	(19,538		)
Income tax expense (benefit)	95				3,625				(37,249		)		31,141				(2,388		)
Net income (loss)	$	(10,277	)		$	9,611			$	(19,103	)		$	2,619			$	(17,150	)
Earnings (loss) per share—basic	$	(0.16	)		$	0.15			$	(0.25	)		$	0.03			$	(0.24	)
Earnings (loss) per share—diluted	$	(0.16	)		$	0.15			$	(0.25	)		$	0.03			$	(0.24	)

The first quarter in the table above includes a $4.5 million out of period loss on disposal of rights-of-way related to immaterial prior period errors. The third and fourth quarters in the table above include the impact of our third quarter acquisition of HFOTCO (Note 5). The third quarter includes the impairment of goodwill and intangible assets related to our crude oil trucking operations of $26.6 million and $12.1 million, respectively. The fourth quarter includes the write-down of our Mexican asphalt and U.K. businesses to net realizable value (Note 4). We recorded impairments of $13.5 million and $76.7 million for the Mexican asphalt and U.K. businesses, respectively. The fourth quarter also includes a $150.3 million gain on the sale of Glass Mountain (Note 6).

24.    RELATED PARTY TRANSACTIONS

As described in Note 6, we own equity method investments in the general partner of NGL Energy and a 51% ownership interest in White Cliffs.

Transactions with NGL Energy and its subsidiaries primarily relate to marketing, leased storage and transportation services of crude oil, including buy/sell transactions. Transactions with White Cliffs primarily relate to leased storage, purchases and sales of crude oil, transportation fees for shipments on the White Cliffs Pipeline, and management fees.

In accordance with ASC 845-10-15, the buy/sell transactions with NGL Energy and White Cliffs were reported as revenue on a net basis in our consolidated statements of operations and comprehensive income (loss) because the purchases of inventory and subsequent sales of the inventory were with the same counterparty.

During the years ended December 31, 2018, 2017 and 2016, we generated the following transactions with related parties (in thousands):

	Year Ended December 31,
	2018		2017		2016
NGL Energy
Revenues	$	18,168	$	45,918	$	61,639
Purchases	$	681	$	29,695	$	57,739
White Cliffs
Crude oil revenues	$	—	$	436	$	4,973
Storage revenues	$	4,350	$	4,350	$	4,350
Transportation fees	$	12,506	$	11,298	$	10,797
Management fees	$	545	$	519	$	494
Crude oil purchases	$	6,201	$	11,870	$	4,758

F-55

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

25. CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS

Our senior unsecured notes are guaranteed by certain of our subsidiaries as follows: Rose Rock Finance Corporation, Rose Rock Midstream Operating, LLC, Rose Rock Midstream Energy GP, LLC, Rose Rock Midstream Crude, L.P., Rose Rock Midstream Field Services, LLC, SemGas, L.P., SemMaterials, L.P., SemGroup Europe Holding, L.L.C., SemOperating G.P., L.L.C., SemMexico, L.L.C., SemDevelopment, L.L.C., Mid-America Midstream Gas Services, L.L.C., SemCrude Pipeline, L.L.C., and Wattenberg Holding, LLC (collectively, the “Guarantors”).

As of June 30, 2018, Beachhead Holdings LLC, Beachhead I LLC and Beachhead II LLC were added to the Guarantors and Glass Mountain Holding, LLC was removed as a guarantor. Accordingly, prior period financial information for 2017 below has been recast to reflect these changes. Financial information for 2016 was not recast due to immateriality.

Each of the Guarantors is 100% owned by SemGroup Corporation (the "Parent"). Such guarantees of the Notes are full and unconditional and constitute the joint and several obligations of the Guarantors. There are no significant restrictions upon the ability of the Parent or any of the Guarantors to obtain funds from its respective subsidiaries by dividend or loan. None of the assets of the Guarantors represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

Condensed consolidating financial statements for the Parent, the Guarantors and non-guarantors as of December 31, 2018 and 2017 and for the years ended December 31, 2018, 2017 and 2016 are presented on an equity method basis in the tables below (in thousands).

Intercompany receivable and payable balances, including notes receivable and payable, are capital transactions primarily to facilitate the capital needs of our subsidiaries. As such, subsidiary intercompany balances have been reported as a reduction to equity on the condensed consolidating Guarantor balance sheets. The Parent's net intercompany balance, including note receivable, and investments in subsidiaries have been reported in equity method investments on the condensed consolidating Guarantor balance sheets. Intercompany transactions, such as daily cash management activities, have been reported as financing activities within the condensed consolidating Guarantor statements of cash flows. The Parent's investing activities with subsidiaries have been reflected as cash flows from investing activities. These balances are eliminated through consolidating adjustments below.

F-56

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

25. CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS, Continued

Condensed Consolidating Guarantor Balance Sheets

	December 31, 2018
	Parent		Guarantors		Non-guarantors		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	40,064	$	—	$	50,742	$	(4,151	)	$	86,655
Accounts receivable	83		461,980		100,151		—			562,214
Receivable from affiliates	120		18		157		—			295
Inventories	—		49,397		—		—			49,397
Other current assets	6,682		6,711		3,871		—			17,264
Total current assets	46,949		518,106		154,921		(4,151		)	715,825
Property, plant and equipment	6,732		992,974		2,457,620		—			3,457,326
Equity method investments	3,267,581		1,553,360		—		(4,546,932		)	274,009
Goodwill	—		—		257,302		—			257,302
Other intangible assets	5		119,583		245,450		—			365,038
Other noncurrent assets, net	41,981		4,788		94,038		—			140,807
Total assets	$	3,363,248	$	3,188,811	$	3,209,331	$	(4,551,083	)	$	5,210,307
LIABILITIES, PREFERRED STOCK AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	38	$	444,984	$	49,770	$	—		$	494,792
Payable to affiliates	1		3,714		—		—			3,715
Accrued liabilities	33,239		18,424		63,430		2			115,095
Other current liabilities	5,723		3,409		14,423		—			23,555
Total current liabilities	39,001		470,531		127,623		2			637,157
Long-term debt	1,467,083		6,315		811,751		(6,315		)	2,278,834
Deferred income taxes	4,882		—		50,907		—			55,789
Other noncurrent liabilities	1,792		—		36,756		—			38,548
Commitments and contingencies
Redeemable preferred stock	359,658		—		—		—			359,658
Owners' equity excluding noncontrolling interest in consolidated subsidiary	1,490,832		2,711,965		1,832,805		(4,544,770		)	1,490,832
Noncontrolling interest in consolidated subsidiary	—		—		349,489		—			349,489
Total owners’ equity	1,490,832		2,711,965		2,182,294		(4,544,770		)	1,840,321
Total liabilities, preferred stock and owners’ equity	$	3,363,248	$	3,188,811	$	3,209,331	$	(4,551,083	)	$	5,210,307

F-57

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

25. CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS, Continued

	December 31, 2017
	Parent			Guarantors		Non-guarantors		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	32,457		$	—	$	69,872	$	(8,630	)	$	93,699
Accounts receivable	(9		)	562,967		90,526		—			653,484
Receivable from affiliates	58			1,421		212		—			1,691
Current assets held for sale	—			—		38,063		—			38,063
Inventories	—			101,665		—		—			101,665
Other current assets	6,671			4,493		3,133		—			14,297
Total current assets	39,177			670,546		201,806		(8,630		)	902,899
Property, plant and equipment	8,086			1,002,982		2,304,063		—			3,315,131
Equity method investments	3,085,274			2,110,299		—		(4,910,292		)	285,281
Goodwill	—			—		257,302		—			257,302
Other intangible assets	10			127,783		270,850		—			398,643
Other noncurrent assets, net	45,587			3,097		83,916		—			132,600
Noncurrent assets held for sale	—			—		84,961		—			84,961
Total assets	$	3,178,134		$	3,914,707	$	3,202,898	$	(4,918,922	)	$	5,376,817
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable	$	646		$	533,651	$	53,601	$	—		$	587,898
Payable to affiliates	10			6,961		—		—			6,971
Accrued liabilities	38,747			26,092		66,570		(2		)	131,407
Current liabilities held for sale	—			—		23,847		—			23,847
Other current liabilities	1,922			5,532		8,984		—			16,438
Total current liabilities	41,325			572,236		153,002		(2		)	766,561
Long-term debt	1,474,491			572,558		829,236		(23,190		)	2,853,095
Deferred income taxes	1,892			—		44,693		—			46,585
Other noncurrent liabilities	2,061			—		36,434		—			38,495
Noncurrent liabilities held for sale	—			—		13,716		—			13,716
Commitments and contingencies
Total owners’ equity	1,658,365			2,769,913		2,125,817		(4,895,730		)	1,658,365
Total liabilities and owners’ equity	$	3,178,134		$	3,914,707	$	3,202,898	$	(4,918,922	)	$	5,376,817

F-58

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

25. CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS, Continued

Condensed Consolidating Guarantor Statements of Operations

	Year Ended December 31, 2018
	Parent			Guarantors			Non-guarantors			Consolidating Adjustments			Consolidated
Revenues:
Product	$	—		$	1,876,100		$	31,336		$	—		$	1,907,436
Service	—			140,275			378,489			—			518,764
Lease	—			—			17,549			—			17,549
Other	—			—			59,513			—			59,513
Total revenues	—			2,016,375			486,887			—			2,503,262
Expenses:
Costs of products sold, exclusive of depreciation and amortization shown below	—			1,796,716			26,379			—			1,823,095
Operating	—			110,795			173,974			—			284,769
General and administrative	23,580			24,742			43,246			—			91,568
Depreciation and amortization	2,890			76,788			129,576			—			209,254
Loss (gain) on disposal or impairment, net	133,053			(154,302		)	17,686			—			(3,563		)
Total expenses	159,523			1,854,739			390,861			—			2,405,123
Earnings from equity method investments	219,181			73,010			—			(234,519		)	57,672
Operating income	59,658			234,646			96,026			(234,519		)	155,811
Other expenses (income):
Interest expense	68,389			56,217			25,348			(240		)	149,714
Foreign currency transaction (gain) loss	10,246			147			(892		)	—			9,501
Other income, net	(976		)	(138		)	(1,506		)	240			(2,380		)
Total other expenses, net	77,659			56,226			22,950			—			156,835
Income (loss) from continuing operations before income taxes	(18,001		)	178,420			73,076			(234,519		)	(1,024		)
Income tax expense	8,748			—			14,556			—			23,304
Net income (loss)	(26,749		)	178,420			58,520			(234,519		)	(24,328		)
Less: net income attributable to noncontrolling interest	—			—			2,421			—			2,421
Net income (loss) attributable to SemGroup	(26,749		)	178,420			56,099			(234,519		)	(26,749		)
Less: cumulative preferred stock dividends	23,790			—			—			—			23,790
Net income (loss) attributable to common shareholders	$	(50,539	)	$	178,420		$	56,099		$	(234,519	)	$	(50,539	)
Net income (loss)	$	(26,749	)	$	178,420		$	58,520		$	(234,519	)	$	(24,328	)
Other comprehensive income (loss), net of income taxes	(9,420		)	387			11,587			—			2,554
Comprehensive income (loss)	(36,169		)	178,807			70,107			(234,519		)	(21,774		)
Less: comprehensive income attributable to noncontrolling interest	—			—			2,421			—			2,421
Comprehensive income (loss) attributable to SemGroup	$	(36,169	)	$	178,807		$	67,686		$	(234,519	)	$	(24,195	)

F-59

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

25. CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS, Continued

	Year Ended December 31, 2017
	Parent			Guarantors			Non-guarantors			Consolidating Adjustments			Consolidated
Revenues:
Product	$	—		$	1,468,754		$	153,164		$	—		$	1,621,918
Service	—			149,197			242,069			—			391,266
Lease	—			—			5,843			—			5,843
Other	—			—			62,890			—			62,890
Total revenues	—			1,617,951			463,966			—			2,081,917
Expenses:
Costs of products sold, exclusive of depreciation and amortization shown below	—			1,383,868			131,023			—			1,514,891
Operating	—			112,863			141,901			—			254,764
General and administrative	42,422			24,492			46,865			—			113,779
Depreciation and amortization	2,294			70,053			86,074			—			158,421
Loss (gain) on disposal or impairment, net	—			70,681			(57,348		)	—			13,333
Total expenses	44,716			1,661,957			348,515			—			2,055,188
Earnings from equity method investments	68,964			(21,499		)	7,494			12,372			67,331
Operating income (loss)	24,248			(65,505		)	122,945			12,372			94,060
Other expenses (income):
Interest expense	40,053			55,119			8,691			(854		)	103,009
Loss on early extinguishment of debt	19,930			—			—			—			19,930
Foreign currency transaction gain	(2,764		)	—			(1,945		)	—			(4,709		)
Other income, net	(913		)	(33		)	(4,540		)	854			(4,632		)
Total other expenses, net	56,306			55,086			2,206			—			113,598
Income (loss) from continuing operations before income taxes	(32,058		)	(120,591		)	120,739			12,372			(19,538		)
Income tax expense (benefit)	(14,908		)	—			12,520			—			(2,388		)
Income (loss) from continuing operations	(17,150		)	(120,591		)	108,219			12,372			(17,150		)
Net income (loss)	$	(17,150	)	$	(120,591	)	$	108,219		$	12,372		$	(17,150	)
Net income (loss)	$	(17,150	)	$	(120,591	)	$	108,219		$	12,372		$	(17,150	)
Other comprehensive income (loss), net of income taxes	(11,987		)	(573		)	32,673			—			20,113
Comprehensive income (loss)	$	(29,137	)	$	(121,164	)	$	140,892		$	12,372		$	2,963

F-60

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

25. CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS, Continued

	Year Ended December 31, 2016
	Parent			Guarantors		Non-guarantors			Consolidating Adjustments			Consolidated
Revenues:
Product	$	—		$	872,961	$	136,448		$	—		$	1,009,409
Service	—			162,460		102,570			—			265,030
Other	—			—		57,725			—			57,725
Total revenues	—			1,035,421		296,743			—			1,332,164
Expenses:
Costs of products sold, exclusive of depreciation and amortization shown below	—			761,971		111,460			—			873,431
Operating	—			115,431		96,668			—			212,099
General and administrative	22,349			31,196		30,638			—			84,183
Depreciation and amortization	1,647			68,669		28,488			—			98,804
Loss (gain) on disposal or impairment, net	—			16,115		(67		)	—			16,048
Total expenses	23,996			993,382		267,187			—			1,284,565
Earnings from equity method investments	56,815			81,366		—			(64,424		)	73,757
Loss on issuance of common units by equity method investee	(41		)	—		—			—			(41		)
Operating income	32,778			123,405		29,556			(64,424		)	121,315
Other expenses (income):
Interest expense (income)	(4,002		)	72,277		(4,819		)	(806		)	62,650
Foreign currency transaction loss	—			—		4,759			—			4,759
Loss on sale or impairment of non-operated equity method investment, net	30,644			—		—			—			30,644
Other expenses (income), net	(339		)	63		(1,799		)	806			(1,269		)
Total other expenses (income), net	26,303			72,340		(1,859		)	—			96,784
Income from continuing operations before income taxes	6,475			51,065		31,415			(64,424		)	24,531
Income tax expense	4,380			—		6,888			—			11,268
Income from continuing operations	2,095			51,065		24,527			(64,424		)	13,263
Loss from discontinued operations, net of income taxes	—			—		(1		)	—			(1		)
Net income	2,095			51,065		24,526			(64,424		)	13,262
Less: net income attributable to noncontrolling interests	—			11,167		—			—			11,167
Net income attributable to SemGroup	$	2,095		$	39,898	$	24,526		$	(64,424	)	$	2,095
Net income	$	2,095		$	51,065	$	24,526		$	(64,424	)	$	13,262
Other comprehensive income (loss), net of income taxes	7,360			1,223		(23,935		)	—			(15,352		)
Comprehensive income (loss)	9,455			52,288		591			(64,424		)	(2,090		)
Less: comprehensive income attributable to noncontrolling interests	—			11,167		—			—			11,167
Comprehensive income (loss) attributable to SemGroup	$	9,455		$	41,121	$	591		$	(64,424	)	$	(13,257	)

F-61

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

25. CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS, Continued

Condensed Consolidating Guarantor Statements of Cash Flows

	Year Ended December 31, 2018
	Parent			Guarantors			Non-guarantors			Consolidating Adjustments			Consolidated
Net cash provided by (used in) operating activities	$	(90,572	)	$	144,902		$	215,374		$	—		$	269,704
Cash flows from investing activities:
Capital expenditures	(1,529		)	(65,798		)	(323,407		)	—			(390,734		)
Proceeds from sale of equity method investment and other long-lived assets	—			664			1,294			—			1,958
Contributions to equity method investments	—			(7,781		)	—			—			(7,781		)
Proceeds from business divestitures	156,499			6,753			(15,465		)	—			147,787
Distributions from equity method investees in excess of equity in earnings	—			19,100			—			—			19,100
Net cash provided by (used in) investing activities	154,970			(47,062		)	(337,578		)	—			(229,670		)
Cash flows from financing activities:
Debt issuance costs	(475		)	—			(4,245		)	—			(4,720		)
Borrowings on credit facilities and issuance of senior unsecured notes	660,000			—			598,500			—			1,258,500
Principal payments on credit facilities and other obligations	(678,865		)	(565,904		)	(595,125		)	—			(1,839,894		)
Equity issuance to noncontrolling interest	350,000			—			—			—			350,000
Distributions to noncontrolling interests	(2,932		)	—			—			—			(2,932		)
Proceeds from preferred stock issuance, net of offering costs	342,299			—			—			—			342,299
Repurchase of common stock for payment of statutory taxes due on equity-based compensation	(705		)	—			—			—			(705		)
Dividends paid	(148,482		)	—			—			—			(148,482		)
Proceeds from issuance of common stock under employee stock purchase plan	930			—			—			—			930
Intercompany borrowings (advances), net	(578,561		)	468,079			106,003			4,479			—
Net cash provided by (used in) financing activities	(56,791		)	(97,825		)	105,133			4,479			(45,004		)
Effect of exchange rate changes on cash and cash equivalents	—			(15		)	(2,059		)	—			(2,074		)
Change in cash and cash equivalents	7,607			—			(19,130		)	4,479			(7,044		)
Cash and cash equivalents at beginning of period	32,457			—			69,872			(8,630		)	93,699
Cash and cash equivalents at end of period	$	40,064		$	—		$	50,742		$	(4,151	)	$	86,655

F-62

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

25. CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS, Continued

	Year Ended December 31, 2017
	Parent			Guarantors			Non-guarantors			Consolidating Adjustments			Consolidated
Net cash provided by (used in) operating activities	$	(46,556	)	$	93,107		$	93,925		$	—		$	140,476
Cash flows from investing activities:
Capital expenditures	(4,554		)	(135,999		)	(322,160		)	—			(462,713		)
Proceeds from sale of long-lived assets	—			15,565			299,256			—			314,821
Contributions to equity method investments	—			(2,888		)	(23,556		)	—			(26,444		)
Payments to acquire business, net of cash acquired	—			—			(294,239		)	—			(294,239		)
Distributions from equity method investments in excess of equity in earnings	—			18,261			10,513			—			28,774
Net cash provided by (used in) investing activities	(4,554		)	(105,061		)	(330,186		)	—			(439,801		)
Cash flows from financing activities:
Debt issuance costs	(11,116		)	—			—			—			(11,116		)
Borrowings on credit facilities and issuance of senior unsecured notes	1,470,377			—			55,000			—			1,525,377
Principal payments on debt and other obligations	(1,049,652		)	(26		)	(2,750		)	—			(1,052,428		)
Debt extinguishment costs	(16,293		)	—			—			—			(16,293		)
Repurchase of common stock	(1,473		)	—			—			—			(1,473		)
Dividends paid	(129,925		)	—			—			—			(129,925		)
Proceeds from issuance of common stock under employee stock purchase plan	1,114			—			—			—			1,114
Intercompany borrowings (advances), net	(198,467		)	11,980			190,535			(4,048		)	—
Net cash provided by (used in) financing activities	64,565			11,954			242,785			(4,048		)	315,256
Effect of exchange rate changes on cash and cash equivalents	—			—			3,552			—			3,552
Change in cash and cash equivalents	13,455			—			10,076			(4,048		)	19,483
Cash and cash equivalents at beginning of period	19,002			—			59,796			(4,582		)	74,216
Cash and cash equivalents at end of period	$	32,457		$	—		$	69,872		$	(8,630	)	$	93,699

F-63

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

25. CONDENSED CONSOLIDATING GUARANTOR FINANCIAL STATEMENTS, Continued

	Year Ended December 31, 2016
	Parent			Guarantors			Non-guarantors			Consolidating Adjustments			Consolidated
Net cash provided by operating activities	$	84,460		$	79,054		$	65,282		$	(58,822	)	$	169,974
Cash flows from investing activities:
Capital expenditures	(2,928		)	(56,102		)	(253,426		)	—			(312,456		)
Proceeds from sale of long-lived assets	—			53			98			—			151
Contributions to equity method investments	—			(4,188		)	—			—			(4,188		)
Proceeds from sale of common units of equity method investee	60,483			—			—			—			60,483
Distributions from equity method investments in excess of equity in earnings	—			27,726			—			—			27,726
Net cash provided by (used in) investing activities	57,555			(32,511		)	(253,328		)	—			(228,284		)
Cash flows from financing activities:
Debt issuance costs	(7,728		)	—			—			—			(7,728		)
Borrowings on credit facilities and issuance of senior unsecured notes	382,500			—			—			—			382,500
Principal payments on credit facilities and other obligations	(396,859		)	(31		)	—			—			(396,890		)
Distributions to noncontrolling interests	—			(32,133		)	—			—			(32,133		)
Proceeds from issuance of common shares, net of offering costs	223,025			—			—			—			223,025
Repurchase of common stock	(965		)	—			—			—			(965		)
Dividends paid	(92,910		)	—			—			—			(92,910		)
Proceeds from issuance of common stock under employee stock purchase plan	1,010			—			—			—			1,010
Intercompany borrowings (advances), net	(235,645		)	(23,437		)	203,278			55,804			—
Net cash provided by (used in) financing activities	(127,572		)	(55,601		)	203,278			55,804			75,909
Effect of exchange rate changes on cash and cash equivalents	—			—			(1,479		)	—			(1,479		)
Change in cash and cash equivalents	14,443			(9,058		)	13,753			(3,018		)	16,120
Cash and cash equivalents at beginning of period	4,559			9,058			46,043			(1,564		)	58,096
Cash and cash equivalents at end of period	$	19,002		$	—		$	59,796		$	(4,582	)	$	74,216

F-64

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

26.    SUBSEQUENT EVENTS

SemCAMS Midstream

On January 9, 2019, a wholly owned subsidiary of SemGroup Corporation, SemCanada II, L.P., an Oklahoma limited partnership (“SemGroup”), and an affiliate of Kohlberg Kravis Roberts & Co. L.P. and wholly owned subsidiary of KKR Global Infrastructure Investors III L.P., KKR Alberta Midstream Inc., an Alberta corporation (“KKR”), entered into definitive documents to create a new joint venture company that will own and operate midstream oil and gas infrastructure in Western Canada, SemCAMS Midstream ULC, an Alberta unlimited liability corporation (“SemCAMS Midstream”). SemGroup owns 51% and KKR owns 49% of SemCAMS Midstream, subsequent to close of the transactions described below.

Share Purchase Agreement

In connection with the formation of SemCAMS Midstream, on January 9, 2019, SemCAMS Midstream entered into a Share Purchase Agreement (the “Share Purchase Agreement”) with Meritage Midstream Services III, LP (“Meritage”) to acquire 100% of the issued and outstanding equity interests in Meritage Midstream ULC, an Alberta unlimited liability corporation (“Meritage ULC” and such acquisition, the “Meritage Acquisition”). On February 25, 2019, SemCAMS Midstream completed the Meritage Acquisition pursuant to the Share Purchase Agreement for a debt-free, cash purchase price of C$646.5 million (US$489.5 million), subject to customary post-closing adjustments. The purchase price included C$152.3 million (US$115.5 million) in reimbursements for estimated capital expenditures incurred from September 1, 2018 to the closing of the Meritage Acquisition (the “Meritage Closing”).

Pursuant to the Share Purchase Agreement, SemCAMS Midstream has obtained a representation and warranty insurance policy to cover losses arising from breaches of representations and warranties by Meritage. Each party has agreed to indemnify the other for breaches of covenants and certain other matters, subject to certain exceptions and limitations.

Investment and Contribution Agreement

Concurrently with the execution of the Share Purchase Agreement, SemGroup, KKR and SemCAMS Midstream entered into an Investment and Contribution Agreement (the “Contribution Agreement”). On February 25, 2019, the Contribution (as defined below) closed immediately prior to the Meritage Closing (the “Contribution Closing”). Pursuant to the terms of the Contribution Agreement, each of SemGroup and KKR made the following contributions to SemCAMS Midstream: (i) SemGroup contributed 100% of the issued and outstanding equity interests in its wholly owned subsidiary, SemCAMS ULC, an Alberta unlimited liability company, (the “SemGroup Contribution”) in exchange for (A) 51% of the common shares of SemCAMS Midstream, (B) a cash amount of C$645.6 million (US$489.6 million), subject to adjustments for working capital of SemCAMS ULC, capital contributions to SemCAMS ULC by SemGroup, and other customary adjustments, (C) a potential payment of C$14.7 million (US$11.1 million) contingent on positive final investment decision of a specific project by SemCAMS Midstream, and (D) earnout consideration in the form of a special share in SemCAMS Midstream entitled to dividend payments up to a maximum (pre-tax) aggregate amount of C$50.0 million (US$37.9 million) if either or both of two specific projects proceed and EBITDA thresholds pertaining to those projects are achieved; and (ii) KKR contributed cash in the amount of C$785.6 million (US$595.7 million), subject to adjustments for working capital of SemCAMS ULC, capital contributions to SemCAMS ULC by SemGroup and a payment of C$14.7 million (US$11.1 million) contingent on the pursuit of a specific project (unrelated to the two projects referred to above) by SemCAMS Midstream, and other customary adjustments (the “KKR Contribution” and, together with the SemGroup Contribution, the “Contribution”) in exchange for (A) 49% of the common shares of SemCAMS Midstream and (B) 300,000 preferred shares in SemCAMS Midstream (representing C$300 million (US$227.5 million) of KKR cash contribution) which will pay quarterly dividends at an annual rate of 8.75%. SemCAMS Midstream may elect, for any of the first ten quarters following issuance of the preferred shares, to pay the dividends in-kind in the form of additional preferred shares. SemCAMS Midstream will have the right to convert the preferred shares into common shares in the event of an initial public offering of its common shares, at a conversion price equal to 92.5% of the IPO offering price. In connection with the issuance of the preferred shares, KKR received a C$6.0 million (US$4.5 million) transaction fee from SemCAMS Midstream.

F-65

SEMGROUP CORPORATION

Notes to Consolidated Financial Statements

26. SUBSEQUENT EVENTS, Continued

KKR and SemGroup have agreed to indemnify each other for breaches of covenants and certain other matters, subject to certain exceptions and limitations.

Upon the Contribution Closing, KKR and SemGroup entered into a unanimous shareholder agreement (the “Shareholder Agreement”) to cover corporate governance, transfer restrictions, funding obligations and other similar matters related to SemCAMS Midstream. The Shareholder Agreement includes customary restrictions on the activities of SemGroup and KKR that relate to the business of SemCAMS Midstream within a defined area of mutual interest surrounding the location in which SemCAMS Midstream will operate. In addition, the Shareholder Agreement includes certain liquidity rights that allow each of KKR and SemGroup to cause SemCAMS Midstream to pursue an initial public offering of its respective common shares after the third anniversary of the parties’ entry into the Shareholder Agreement.

SemCAMS Midstream Credit Agreement

On February 25, 2019, SemCAMS Midstream entered into a Credit Agreement (the “Credit Agreement”), together with The Toronto-Dominion Bank, as administrative agent, providing for a C$350.0 million senior secured term loan facility and a C$450.0 million senior secured revolving credit facility. Both facilities under the Credit Agreement mature on February 25, 2024. SemCAMS Midstream may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250.0 million, subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.

The Credit Agreement is guaranteed on a non-recourse basis by each of SemGroup and KKR, limited to each respective entity’s equity interests in SemCAMS Midstream, and fully guaranteed by any future material subsidiary of SemCAMS Midstream. The obligations under the Credit Agreement and related lender hedge instruments and cash management instruments are secured by a lien on substantially all of the property and assets of SemCAMS Midstream and the other loan parties, subject to customary exceptions.

F-66