MARATHON PETROLEUM CORP
10-Qs and 10-Ks
PROXIES
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended
December 31, 2014
Commission file number 001-35054
Marathon Petroleum Corporation
(Exact name of registrant as specified in its charter)
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Delaware
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27-1284632
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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539 South Main Street, Findlay, OH 45840-3229
(Address of principal executive offices)
(419) 422-2121
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, par value $.01
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New York Stock Exchange
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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
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No
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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
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No
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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 and (2) has been subject to such filing requirements for the past 90 days. Yes
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No
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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
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No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.
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Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
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Accelerated filer
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Non-accelerated filer
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Smaller reporting company
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
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No
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The aggregate market value of Common Stock held by non-affiliates as of June 30, 2014 was approximately
$22.2 billion
. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on June 30, 2014. Shares of Common Stock held by executive officers and directors of the registrant are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers to be affiliates.
There were
273,062,880
shares of Marathon Petroleum Corporation Common Stock outstanding as of
February 13, 2015
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Documents Incorporated By Reference
Portions of the registrant’s proxy statement relating to its 2015 Annual Meeting of Shareholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this Report.
MARATHON PETROLEUM CORPORATION
Unless otherwise stated or the context otherwise indicates, all references in this Annual Report on Form 10-K to “MPC,” “us,” “our,” “we” or “the Company” mean Marathon Petroleum Corporation and its consolidated subsidiaries, and for periods prior to its spinoff from Marathon Oil Corporation, the Refining, Marketing & Transportation Business of Marathon Oil Corporation.
Table of Contents
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Page
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PART I
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Item 1.
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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PART II
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Item 5.
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Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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Item 6.
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Item 7.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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PART III
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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PART IV
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Item 15.
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Disclosures Regarding Forward-Looking Statements
This Annual Report on Form 10-K, particularly Item 1. Business, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk, includes forward-looking statements. You can identify our forward-looking statements by words such as “anticipate,” “believe,” “potential,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “seek,” “target,” “could,” “may,” “should,” “will,” “would” or other similar expressions that convey the uncertainty of future events or outcomes. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.
Forward-looking statements include, but are not limited to, statements that relate to, or statements that are subject to risks, contingencies or uncertainties that relate to:
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future levels of revenues, refining and marketing gross margins, operating costs, retail gasoline and distillate gross margins, merchandise margins, income from operations, net income or earnings per share;
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anticipated volumes of feedstock, throughput, sales or shipments of refined products;
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anticipated levels of regional, national and worldwide prices of crude oil and refined products;
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anticipated levels of crude oil and refined product inventories;
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future levels of capital, environmental or maintenance expenditures, general and administrative and other expenses;
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the success or timing of completion of ongoing or anticipated capital or maintenance projects;
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business strategies, growth opportunities and expected investments, including planned equity investments in pipeline projects;
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expectations regarding the acquisition or divestiture of assets;
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our share repurchase authorizations, including the timing and amounts of any common stock repurchases;
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the effect of restructuring or reorganization of business components;
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the potential effects of judicial or other proceedings on our business, financial condition, results of operations and cash flows; and
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the anticipated effects of actions of third parties such as competitors, or federal, foreign, state or local regulatory authorities, or plaintiffs in litigation.
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We have based our forward-looking statements on our current expectations, estimates and projections about our industry and our company. We caution that these statements are not guarantees of future performance, and you should not rely unduly on them, as they involve risks, uncertainties, and assumptions that we cannot predict. In addition, we have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. While our management considers these assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, our actual results may differ materially from the future performance that we have expressed or forecast in our forward-looking statements. Differences between actual results and any future performance suggested in our forward-looking statements could result from a variety of factors, including the following:
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volatility or degradation in general economic, market, industry or business conditions;
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an easing or lifting of the U.S. crude oil export ban;
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availability and pricing of domestic and foreign supplies of crude oil and other feedstocks;
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the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to agree on and to influence crude oil price and production controls;
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availability and pricing of domestic and foreign supplies of refined products such as gasoline, diesel fuel, jet fuel, home heating oil and petrochemicals;
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foreign imports of refined products;
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refining industry overcapacity or under capacity;
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changes in the cost or availability of third-party vessels, pipelines and other means of transportation for crude oil, feedstocks and refined products;
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the price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such fuels or vehicles;
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fluctuations in consumer demand for refined products, including seasonal fluctuations;
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political and economic conditions in nations that consume refined products, including the United States, and in crude oil producing regions, including the Middle East, Africa, Canada and South America;
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actions taken by our competitors, including pricing adjustments, expansion of retail activities, and the expansion and retirement of refining capacity in response to market conditions;
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completion of pipeline projects within the U.S.;
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changes in fuel and utility costs for our facilities;
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failure to realize the benefits projected for capital projects, or cost overruns associated with such projects;
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modifications to MPLX LP earnings and distribution growth objectives;
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the ability to successfully implement growth opportunities;
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the ability to successfully integrate the acquired Hess Corporation retail operations and achieve the strategic and other expected objectives relating to the acquisition including any expected synergies;
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the ability to realize the strategic benefits of joint venture opportunities;
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accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines or equipment, or those of our suppliers or customers;
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unusual weather conditions and natural disasters, which can unforeseeably affect the price or availability of crude oil and other feedstocks and refined products;
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acts of war, terrorism or civil unrest that could impair our ability to produce or transport refined products or receive feedstocks;
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state and federal environmental, economic, health and safety, energy and other policies and regulations, including the cost of compliance with the Renewable Fuel Standard;
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rulings, judgments or settlements and related expenses in litigation or other legal, tax or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
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labor and material shortages;
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the maintenance of satisfactory relationships with labor unions and joint venture partners;
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the ability and willingness of parties with whom we have material relationships to perform their obligations to us;
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the market price of our common stock and its impact on our share repurchase authorizations;
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changes in the credit ratings assigned to our debt securities and trade credit, changes in the availability of unsecured credit and changes affecting the credit markets generally; and
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the other factors described in Item 1A. Risk Factors.
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We undertake no obligation to update any forward-looking statements except to the extent required by applicable law.
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PART I
Item 1. Business
Overview
Marathon Petroleum Corporation (“MPC”) was incorporated in Delaware on November 9, 2009. We have
127
years of experience in the energy business with roots tracing back to the formation of the Ohio Oil Company in 1887. We are one of the largest independent petroleum product refining, marketing, retail and transportation businesses in the United States and the largest east of the Mississippi. Our operations consist of three reportable operating segments: Refining & Marketing; Speedway; and Pipeline Transportation. Each of these segments is organized and managed based upon the nature of the products and services it offers.
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Refining & Marketing—refines crude oil and other feedstocks at our
seven
refineries in the Gulf Coast and Midwest regions of the United States, purchases refined products and ethanol for resale and distributes refined products through various means, including barges, terminals and trucks that we own or operate. We sell refined products to wholesale marketing customers domestically and internationally, buyers on the spot market, our Speedway
®
business segment and to independent entrepreneurs who operate Marathon
®
retail outlets.
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Speedway—sells transportation fuels and convenience products in the retail market in the Midwest, East Coast and Southeast.
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Pipeline Transportation—transports crude oil and other feedstocks to our refineries and other locations, delivers refined products to wholesale and retail market areas and includes the aggregated operations of MPLX LP.
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See Item 8. Financial Statements and Supplementary Data – Note
11
for operating segment and geographic financial information, which is incorporated herein by reference.
Corporate History and Structure
MPC was incorporated in 2009 in connection with an internal restructuring of Marathon Oil Corporation (“Marathon Oil”). On May 25, 2011, the Marathon Oil board of directors approved the spinoff of its Refining, Marketing & Transportation Business (“RM&T Business”) into an independent, publicly traded company, MPC, through the distribution of MPC common stock to the stockholders of Marathon Oil common stock on June 30, 2011 (the “Spinoff”). Following the Spinoff, Marathon Oil retained no ownership interest in MPC, and each company had separate public ownership, boards of directors and management. All subsidiaries and equity method investments not contributed by Marathon Oil to MPC remained with Marathon Oil and, together with Marathon Oil, are referred to as the “Marathon Oil Companies.” On July 1, 2011, our common stock began trading “regular-way” on the New York Stock Exchange (“NYSE”) under the ticker symbol “MPC.”
Recent Developments
On September 30, 2014, we acquired from Hess Corporation (“Hess”) all of its retail locations, transport operations and shipper history on various pipelines, including approximately
40
thousand barrels per day (“mbpd”) on Colonial Pipeline, for
$2.82 billion
. We refer to these assets as “Hess’ Retail Operations and Related Assets” and substantially all of these assets are part of our Speedway segment. This acquisition significantly expands our Speedway presence from
nine
to
22
states throughout the East Coast and Southeast and is aligned with our strategy to grow higher-valued, stable cash flow businesses. This acquisition also enables us to further leverage our integrated refining and transportation operations, providing an outlet for an incremental
200
mbpd of assured sales from our refining system. The transaction was funded with a combination of debt and available cash. Our financial results and operating statistics for the periods prior to the acquisition do not include amounts for Hess’ Retail Operations and Related Assets.
In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s Southern Access Extension (“SAX”) pipeline, which will run from Flanagan, Ill. to Patoka, Ill. and is expected to be operational in late 2015. This option resulted from our agreement to be the anchor shipper on the SAX pipeline and our commitment to the Sandpiper pipeline project as discussed below. During
2014
, we made contributions of
$120 million
to Illinois Extension Pipeline Company, LLC (“Illinois Extension Pipeline”) to fund our portion of the construction costs incurred-to-date on the SAX pipeline project.
On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for
$40 million
. The plant currently produces biodiesel, glycerin and other by-products. The capacity of the plant is approximately
60 million
gallons per year.
3
In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional
seven percent
interest in Explorer Pipeline Company (“Explorer”) for
$77 million
, bringing our ownership interest to
25 percent
. Explorer owns approximately 1,900 miles of refined products pipeline from Lake Charles, Louisiana to Hammond, Indiana.
In November 2013, we agreed with Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) to serve as an anchor shipper for the Sandpiper pipeline, which will run from Beaver Lodge, North Dakota to Superior, Wisconsin. We also agreed to fund
37.5 percent
of the construction of the Sandpiper pipeline project, which is currently estimated to cost $2.6 billion, of which approximately $1.0 billion is our share. We made contributions of
$192 million
during
2014
and have contributed
$216 million
since project inception. In exchange for our commitment to be an anchor shipper and our investment in the project, we will earn an approximate 27 percent equity interest in Enbridge Energy Partners’ North Dakota System when the Sandpiper pipeline is placed into service, which is expected to be in 2017. Enbridge Energy Partners’ North Dakota System currently includes approximately 240 miles of crude oil gathering pipelines connected to a transportation pipeline that is approximately 730 miles long. We will also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements.
On
August 1, 2013
, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in
three
ethanol companies for
$75 million
. Under the purchase agreement, we acquired an additional
24 percent
interest in The Andersons Clymers Ethanol LLC (“TACE”), bringing our ownership interest to
60 percent
; a
34 percent
interest in The Andersons Ethanol Investment LLC (“TAEI”), which holds a
50 percent
ownership in The Andersons Marathon Ethanol LLC (“TAME”), bringing our direct and indirect ownership interest in TAME to
67 percent
; and a
40 percent
interest in The Andersons Albion Ethanol LLC (“TAAE”), which owns an ethanol production facility in Albion, Michigan. On October 1, 2013, our ownership interest in TAAE increased to
43 percent
as a result of TAAE acquiring one of the owner’s interest.
On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc. (collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility and a 50 mbpd allocation of space on the Colonial Pipeline. We refer to these assets as the “Galveston Bay Refinery and Related Assets.” We paid $1.49 billion for these assets, which included $935 million for inventory. Pursuant to the purchase and sale agreement, we may also be required to pay BP a contingent earnout of up to an additional $700 million over six years, subject to certain conditions. In July 2014, we paid BP
$180 million
for the first period’s contingent earnout. These assets are part of our Refining & Marketing and Pipeline Transportation segments. Our financial results and operating statistics for the periods prior to the acquisition do not include amounts for the Galveston Bay Refinery and Related Assets.
See Item 8. Financial Statements and Supplementary Data – Note
5
for additional information on these acquisitions and investments. See Item 8. Financial Statements and Supplementary Data – Note
26
for information regarding our future contributions to the SAX pipeline project and the Sandpiper pipeline project.
MPLX LP
In 2012, we formed MPLX LP (“MPLX”), a master limited partnership, to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products. On October 31, 2012, MPLX completed its initial public offering of 19.9 million common units, which represented the sale by us of a 26.4 percent interest in MPLX.
As of
December 31, 2014
, we owned a
71.5 percent
interest in MPLX, including the
two percent
general partner interest, and we consolidate this entity for financial reporting purposes since we have a controlling financial interest.
MPLX’s initial assets consisted of a
51 percent
general partner interest in MPLX Pipe Line Holdings LP (“Pipe Line Holdings”), which owns a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States, and a
100 percent
interest in a butane storage cavern in West Virginia. We originally retained a 49 percent limited partner interest in Pipe Line Holdings.
On May 1, 2013, we sold a
five percent
interest in Pipe Line Holdings to MPLX for
$100 million
, which was financed by MPLX with cash on hand.
On March 1, 2014, we sold MPLX a
13 percent
interest in Pipe Line Holdings for
$310 million
. MPLX financed this transaction with
$40 million
of cash on-hand and
$270 million
of borrowings on its bank revolving credit agreement.
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On October 30, 2014, we announced plans to substantially accelerate the growth of MPLX, which is expected to provide unitholders an average annual distribution growth rate percentage in the mid-20s over the next five years as we build meaningful scale more quickly. We believe this increased scale provides MPLX greater flexibility to fund organic projects and to pursue acquisition opportunities.
On December 1, 2014, we sold and contributed interests in Pipe Line Holdings totaling
30.5 percent
to MPLX for
$600 million
in cash and
2.9 million
MPLX common units valued at
$200 million
. MPLX financed the sales portion of this transaction with
$600 million
of borrowings on its bank revolving credit facility.
On December 8, 2014, MPLX completed a public offering of
3.5 million
common units at a price to the public of
$66.68
per common unit, with net proceeds of
$221 million
. MPLX used the net proceeds from this offering to repay borrowings under its bank revolving credit facility and for general partnership purposes. On December 10, 2014, we exercised our right to maintain our two percent general partner interest in MPLX by purchasing
130 thousand
general partner units for
$9 million
.
On February 12, 2015, MPLX completed its initial underwritten public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 (the “Senior Notes”). The Senior Notes were offered at a price to the public of 99.64 percent of par. The net proceeds of this offering were used to repay the amounts outstanding under its bank revolving credit facility, as well as for general partnership purposes.
See Item 8. Financial Statements and Supplementary Data – Note
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for additional information on MPLX.
Our Competitive Strengths
High Quality Refining Assets
We believe we are the largest crude oil refiner in the Midwest and the fourth largest in the United States based on crude oil refining capacity. We own a
seven
-plant refinery network, with approximately
1.7
million barrels per calendar day (“mmbpcd”) of crude oil throughput capacity. Our refineries process a wide range of crude oils, including heavy and sour crude oils, which can generally be purchased at a discount to sweet crude oil, and produce transportation fuels such as gasoline and distillates, specialty chemicals and other refined products. While we have historically processed significant quantities of heavy and sour crude oils, our refineries have the ability to process up to 68 percent light sweet crude oils.
Strategic Location
The geographic locations of our refineries provide us with strategic advantages. Located in Petroleum Administration for Defense District (“PADD”) II and PADD III, which consist of states in the Midwest and the Gulf Coast regions of the United States, our refineries have the ability to procure crude oil from a variety of supply sources, including domestic, Canadian and other foreign sources, which provides us with flexibility to optimize crude supply costs. For example, geographic proximity to various United States shale oil regions and Canadian crude oil supply sources allows our refineries access to price-advantaged crude oils and lower transportation costs than certain of our competitors. Our refinery locations and midstream distribution system also allow us to access refined product export markets and to serve a broad range of key end-user markets across the United States quickly and cost-effectively.
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As of
December 31, 2014
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Extensive Midstream Distribution Networks
Our assets give us extensive flexibility and optionality to respond promptly to dynamic market conditions, including weather-related and marketplace disruptions. We believe the relative scale of our transportation and distribution assets and operations distinguishes us from other refining and marketing companies. We currently own, lease or have ownership interests in approximately
8,300
miles of crude oil and products pipelines. Through our ownership interests in MPLX, we are one of the largest petroleum pipeline companies in the United States on the basis of total volume delivered. We also own one of the largest
private domestic fleets of inland petroleum product barges and one of the largest terminal operations in the United States, as well as trucking and rail assets. We operate this system in coordination with our refining and marketing network, which enables us to optimize feedstock and other raw material supplies and refined product distribution, and further allows for important economies of scale across our system.
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General Partner and Sponsor of MPLX
Our investment in MPLX should allow us to enhance our share price through our limited partner and general partner interests which tend to receive higher market multiples. MPLX also provides us an efficient vehicle to invest in organic projects and pursue acquisitions of midstream assets. MPLX’s significant liquidity and access to the capital markets should provide us a strong foundation to execute our strategy for growing our midstream logistics business. Our role as the general partner allows us to maintain strategic control of the assets so we can continue to optimize our refinery feedstock and distribution networks. We have an extensive portfolio of midstream assets that can potentially be sold and/or contributed to MPLX, providing MPLX with a competitive advantage. As of
December 31, 2014
, these assets included:
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approximately
5,400
miles of crude oil and products pipelines that MPC owns, leases or has an ownership interest;
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19
owned or leased inland towboats and
211
owned or leased inland barges;
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63
owned and operated light product terminals with approximately
20 million
barrels of storage capacity and
192
loading lanes;
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18
owned and operated asphalt terminals with approximately
5 million
barrels of storage capacity and
65
loading lanes;
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one
leased and
two
non-operated, partially-owned light product terminals;
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2,210
owned or leased railcars;
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59 million
barrels of tank and cavern storage capacity at our refineries;
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25
rail and
24
truck loading racks at our refineries;
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seven
owned and
11
non-owned docks at our refineries;
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a condensate splitter at our Canton refinery; and
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approximately 20 billion gallons of fuels distribution.
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We continue to focus resources on growing this portfolio of midstream assets, including investments in the Sandpiper and SAX pipeline projects and a condensate splitter project at our Catlettsburg refinery. We broadly estimate these assets and growth projects can generate annual earnings before interest, tax, depreciation and amortization (“EBITDA”) of $1.6 billion. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information on these pipeline investments.
Competitively Positioned Marketing Operations
We are one of the largest wholesale suppliers of gasoline and distillates to resellers within our market area. We have two strong retail brands: Speedway
®
and Marathon
®
. We believe that Speedway LLC, a wholly-owned subsidiary, operates the second largest chain of company-owned and operated retail gasoline and convenience stores in the United States, with approximately
2,750
convenience stores in
22
states throughout the Midwest, East Coast and Southeast. The Marathon brand is an established motor fuel brand in the Midwest and Southeast regions of the United States, comprised of approximately
5,460
retail outlets operated by independent entrepreneurs in
19
states as of
December 31, 2014
. In addition, as part of the acquisition of the Galveston Bay Refinery and Related Assets in 2013 and Hess’ Retail Operations and Related Assets in 2014, we obtained retail marketing contracts that provide us with the opportunity to convert the associated retail outlets to the Marathon brand. As of
December 31, 2014
, we had outstanding retail marketing contract assignments for approximately
590
retail outlets. We believe our distribution system allows us to maximize the sales value of our products and minimize cost.
Attractive Growth Opportunities
We believe we have attractive growth opportunities. Our capital and investment budget for 2015 of
$2.53 billion
includes
$1.28 billion
for the Refining & Marketing segment (which includes
$234 million
for midstream investments),
$452 million
for the Speedway segment and
$659 million
for the Pipeline Transportation segment.
Our Refining & Marketing segment’s midstream investments include building condensate splitters at our Canton, Ohio and Catlettsburg, Kentucky refineries to increase our capacity to process condensate from the Utica Shale region. The condensate splitter at our Canton refinery began operation at the end of 2014 and we expect to complete the condensate splitter at our Catlettsburg refinery in 2015. Our Refining & Marketing segment’s investments also include refining margin enhancement projects, including projects to further capture synergies at our Galveston Bay refinery, increase our distillate production, expand our export capacity and increase our capacity to process condensates and light crude oils.
Our Speedway segment investments include converting and integrating Hess’ Retail Operations and Related Assets, constructing new convenience stores and rebuilding existing locations. We also anticipate acquiring high quality stores through opportunistic acquisitions.
7
Our Pipeline Transportation segment’s midstream investments include investments in equity interests in the Sandpiper and SAX pipeline projects that will transport crude oil from growing North American hydrocarbon production regions to our refineries. MPLX is also pursuing the Cornerstone pipeline project, which will connect the Utica Shale production to our Canton, Ohio refinery. There are also potential opportunities for additional build-out projects to provide transportation solutions from the Utica Shale region to a wide range of markets.
Established Track Record of Profitability and Diversified Income Stream
We have demonstrated an ability to achieve positive financial results throughout all stages of the refining cycle. We believe our business mix and strategies position us well to continue to achieve competitive financial results. Income generated by our Speedway segment, which was significantly expanded with the acquisition of Hess’ Retail Operations and Related Assets, and our Pipeline Transportation segment is less sensitive to business cycles while our Refining & Marketing segment enables us to generate significant income and cash flow when market conditions are more favorable.
Strong Financial Position
As of
December 31, 2014
, we had
$1.49 billion
in cash and cash equivalents and
$3.80 billion
in unused committed borrowing facilities, excluding MPLX’s credit facility. We had
$6.64 billion
of debt at year-end, which represented
37
percent of our total capitalization. This combination of strong liquidity and manageable leverage provides financial flexibility to fund our growth projects and to pursue our business strategies.
Our Business Strategies
Achieve and Maintain Top-Tier Safety and Environmental Performance
We remain committed to operating our assets in a safe and reliable manner and targeting continuous improvement in our safety record across all of our operations. We have a history of safe and reliable operations, which was demonstrated again in 2014 with a solid performance compared to the industry average. Four of our refineries have earned designation as a U.S. Occupational Safety and Health Administration (“OSHA”) Voluntary Protection Program (“VPP”) Star site. In addition, we remain committed to environmental stewardship by continuing to improve the efficiency and reliability of our operations. We proactively address our regulatory requirements and encourage our operations to improve their environmental performance, with our 2014 designated environmental incidents showing an additional 15 percent reduction over 2013 results. Our Robinson, Illinois refinery had no significant designated environmental incidents in 2014, and our Galveston Bay refinery achieved further reduction of approximately 87 percent in designated environmental incidents since we acquired it on February 1, 2013.
Grow Higher-Valued, Stable Cash Flow Businesses
We intend to allocate significantly more capital to grow our midstream and retail businesses. These businesses typically have more predictable and stable income and cash flows compared to our refining operations and we believe investors assign a higher value to businesses with stable cash flows. Our capital and investment budget for 2015 includes investments in both our Refining & Marketing and Pipeline Transportation segments related to midstream assets. We have budgeted
$234 million
for midstream assets that are part of the Refining & Marketing segment,
$659 million
for the Pipeline Transportation segment and
$452 million
for the Speedway segment.
We plan to substantially accelerate the growth of MPLX and intend to evolve it into a large cap, diversified MLP. We intend to increase revenue on the MPLX network of pipeline systems through higher utilization of existing assets, by capitalizing on organic investment opportunities that may arise from the growth of MPC’s operations and from increased third-party activity in MPLX’s areas of operations. We also plan to pursue acquisitions of midstream assets through MPLX, both within our existing geographic footprint and in new areas. We expect there will continue to be significant investments in infrastructure to connect growing North American crude oil production with existing refining assets and to move refined products to wholesale and retail marketing customers. We intend to aggressively participate in this infrastructure build-out and grow our midstream business primarily through MPLX.
We significantly expanded Speedway’s presence along the East Coast and Southeast through our acquisition of Hess’ Retail Operations and Related Assets. We intend to continue growing Speedway’s sales and profitability by focusing on the conversion and integration of these locations, from which we expect to realize increased merchandise sales and other synergies. We also remain focused on organic growth through constructing new stores, rebuilding old stores, acquiring high quality stores through opportunistic acquisitions and improving margins at our existing operations. We have identified numerous opportunities for new convenience stores or store rebuilds in our existing market, western Pennsylvania and Tennessee. In addition, our highly successful Speedy Rewards
®
customer loyalty program, which has more than
3.9 million
active members as of
December 31, 2014
, provides us with a unique competitive advantage and opportunity to increase our Speedway customer base with existing and new Speedway locations, including the stores recently acquired from Hess.
8
Deliver Top Quartile Refining Performance
Our refineries are well positioned to benefit from the growing crude oil and condensate production in North America, including the Bakken, Eagle Ford and Utica Shale regions, along with the Canadian oil sands. We are also well positioned to export distillates, gasoline and other products.
We intend to enhance our margins in the Refining & Marketing segment by capturing synergies at our Galveston Bay refinery, increasing our condensate and light crude oil processing capacity, growing our distillate production and expanding our exports. For example, we recently completed construction of a condensate splitter at our Canton refinery and we have a project underway to increase condensate processing capacity at our Catlettsburg refinery. We also have projects to increase light crude oil processing capacity at our Robinson refinery, to increase distillate production at our Garyville, Louisiana; Galveston Bay and Robinson refineries and to expand the export capacity at our Garyville and Galveston Bay refineries. We will continue to evaluate opportunities to expand our existing asset base, with an emphasis on increasing distillate production, light crude oil processing and export capabilities and synergistic opportunities at our Galveston Bay refinery.
Sustain Focus on Shareholder Returns
We intend to continue our focus on the return of capital to shareholders in the form of a strong and growing base dividend, supplemented by share repurchases. We have increased our quarterly dividend by
150
percent since becoming a stand-alone company in June 2011 and our board of directors has authorized share repurchases totaling
$8.0 billion
. Through open market purchases and two accelerated share repurchase (“ASR”) programs, we repurchased
89 million
shares of our common stock for approximately
$6.27 billion
, representing approximately
25
percent of our outstanding common shares when we became a stand-alone company in June 2011. After the effects of these repurchases,
$1.73 billion
of the
$8.0 billion
total authorization was available for future repurchases as of
December 31, 2014
.
Increase Assured Sales Volumes at our Marathon Brand and Speedway Locations
We consider assured sales as those sales we make to Marathon brand customers, our Speedway operations and to our wholesale customers with whom we have required minimum volume sales contracts. We believe having assured sales brings ratability to our distribution systems, provides a solid base to enhance our overall supply reliability and allows us to efficiently and effectively optimize our operations between our refineries, our pipelines and our terminals. The Marathon brand has been a consistent vehicle for sales volume growth in existing and contiguous markets. The acquisition of Hess’ Retail Operations and Related Assets significantly expands our Speedway presence from
nine
to
22
states throughout the East Coast and Southeast and enables us to further leverage our integrated refining and transportation operations, providing an outlet for an incremental
200
mbpd of assured sales from our refining system.
Utilize and Enhance our High Quality Employee Workforce
We utilize our high quality employee workforce by continuing to leverage our commercial skills. In addition, we continue to enhance our workforce through selective hiring practices and effective training programs on safety, environmental stewardship and other professional and technical skills.
The above discussion contains forward-looking statements with respect to our competitive strengths and business strategies, including our expected investments, share repurchase authorizations, pursuit of potential acquisitions and other growth opportunities as well as the earnings potential of our portfolio of midstream assets and growth projects that can potentially be sold and/or contributed to MPLX. There can be no assurance that we will be successful, in whole or in part, in carrying out our business strategies, including our expected investments, share repurchase program or pursuit of potential acquisitions and other growth opportunities, or that our portfolio of midstream assets and growth projects that can potentially be sold and/or contributed to MPLX will achieve expected earnings. Factors that could affect our investments include, but are not limited to, the actual amounts invested, which could differ materially from those estimated, and our success in making such investments. Factors that could affect the share repurchase authorizations and the timing of any repurchases include, but are not limited to, business conditions, availability of liquidity and the market price of our common stock. Factors that could affect the pursuit of potential acquisitions and other growth opportunities include, but are not limited to, our ability to implement and realize the benefits and synergies of our strategic initiatives, availability of liquidity, actions taken by competitors, regulatory approvals and operating performance. Factors that could affect the earnings of our portfolio of midstream assets and growth projects that can potentially be sold and/or contributed to MPLX include, but are not limited to, the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products and volatility in and/or degradation of market and industry conditions. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements. For additional information on forward-looking statements and risks that can affect our business, see “Disclosures Regarding Forward-Looking Statements” and Item 1A. Risk Factors in this Annual Report on Form 10-K.
9
Refining & Marketing
Refineries
We currently own and operate
seven
refineries in the Gulf Coast and Midwest regions of the United States with an aggregate crude oil refining capacity of
1,731
thousand barrels per calender day (“mbpcd”). During
2014
, our refineries processed
1,622
mbpd of crude oil and
184
mbpd of other charge and blendstocks. During
2013
, our refineries processed
1,589
mbpd of crude oil and
213
mbpd of other charge and blendstocks. The table below sets forth the location, crude oil refining capacity, tank storage capacity and number of tanks for each of our refineries as of
December 31, 2014
.
|
Refinery
|
Crude Oil Refining Capacity (
mbpcd
)
(a)
|
Tank Storage Capacity (
million barrels
)
|
Number
of Tanks
|
||||||
|
Garyville, Louisiana
|
522
|
|
16.8
|
|
78
|
|
|||
|
Galveston Bay, Texas City, Texas
|
451
|
|
16.3
|
|
156
|
|
|||
|
Catlettsburg, Kentucky
|
242
|
|
5.6
|
|
115
|
|
|||
|
Robinson, Illinois
|
212
|
|
6.3
|
|
95
|
|
|||
|
Detroit, Michigan
|
130
|
|
6.5
|
|
86
|
|
|||
|
Canton, Ohio
|
90
|
|
3.0
|
|
75
|
|
|||
|
Texas City, Texas
|
84
|
|
4.7
|
|
61
|
|
|||
|
Total
|
1,731
|
|
59.2
|
|
666
|
|
|||
|
(a)
|
Refining throughput can exceed crude oil capacity due to the processing of other charge and blendstocks in addition to crude oil and the timing of planned turnaround and major maintenance activity.
|
Our refineries include crude oil atmospheric and vacuum distillation, fluid catalytic cracking, hydrocracking, catalytic reforming, coking, desulfurization and sulfur recovery units. The refineries process a wide variety of light and heavy crude oils purchased from various domestic and foreign suppliers. We produce numerous refined products, ranging from transportation fuels, such as reformulated gasolines, blend-grade gasolines intended for blending with ethanol and ultra-low sulfur diesel (“ULSD”) fuel, to heavy fuel oil and asphalt. Additionally, we manufacture aromatics, propane, propylene, cumene and sulfur. See the Refined Product Marketing section for further information about the products we produce.
Our refineries are integrated with each other via pipelines, terminals and barges to maximize operating efficiency. The transportation links that connect our refineries allow the movement of intermediate products between refineries to optimize operations, produce higher margin products and efficiently utilize our processing capacity. For example, naphtha may be moved from Texas City to Robinson where excess reforming capacity is available. Also, shipping intermediate products between facilities during partial refinery shutdowns allows us to utilize processing capacity that is not directly affected by the shutdown work.
Garyville, Louisiana Refinery
. Our Garyville, Louisiana refinery is located along the Mississippi River in southeastern Louisiana between New Orleans and Baton Rouge. The Garyville refinery is configured to process a wide variety of crude oils into gasoline, distillates, fuel-grade coke, asphalt, polymer-grade propylene, propane, slurry, sulfur and dry gas. The refinery has access to the export market and multiple options to sell refined products. A major expansion project was completed in 2009 that increased Garyville’s crude oil refining capacity, making it one of the largest refineries in the U.S. Our Garyville refinery has earned designation as an OSHA VPP Star site.
Galveston Bay, Texas City, Texas Refinery
. Our Galveston Bay refinery, which we acquired on February 1, 2013, is located on the Texas Gulf Coast approximately 30 miles southeast of Houston, Texas. The refinery can process a wide variety of crude oils into gasoline, distillates, aromatics, refinery-grade propylene, heavy fuel oil, fuel-grade coke, dry gas and sulfur. The refinery has access to the export market and multiple options to sell refined products. Our cogeneration facility, which supplies the Galveston Bay refinery, currently has
1,055
megawatts of electrical production capacity and can produce
4.3 million
pounds of steam per hour. Approximately
45 percent
of the power generated in
2014
was used at the refinery, with the remaining electricity being sold into the electricity grid.
Catlettsburg, Kentucky Refinery
. Our Catlettsburg, Kentucky refinery is located in northeastern Kentucky on the western bank of the Big Sandy River, near the confluence with the Ohio River. The Catlettsburg refinery processes sweet and sour crude oils into gasoline, distillates, asphalt, aromatics, propane and refinery-grade propylene.
10
Robinson, Illinois Refinery
. Our Robinson, Illinois refinery is located in southeastern Illinois. The Robinson refinery processes sweet and sour crude oils into gasoline, distillates, propane, anode-grade coke, aromatics and slurry. The Robinson refinery has earned designation as an OSHA VPP Star site.
Detroit, Michigan Refinery
. Our Detroit, Michigan refinery is located in southwest Detroit. It is the only petroleum refinery currently operating in Michigan. The Detroit refinery processes sweet and heavy sour crude oils into gasoline, distillates, asphalt, fuel-grade coke, chemical-grade propylene, propane, slurry and sulfur. Our Detroit refinery earned designation as a Michigan VPP Star site in 2010. In the fourth quarter of 2012, we completed a heavy oil upgrading and expansion project that enabled the refinery to process up to an additional 80 mbpd of heavy sour crude oils, including Canadian crude oils.
Canton, Ohio Refinery
. Our Canton, Ohio refinery is located approximately 60 miles south of Cleveland, Ohio. The Canton refinery processes sweet and sour crude oils, including production from the nearby Utica Shale, into gasoline, distillates, asphalt, roofing flux, propane, refinery-grade propylene and slurry. In December 2014, we completed construction of a condensate splitter at our Canton refinery, which increased our capacity to process condensate from the Utica Shale region.
Texas City, Texas Refinery
. Our Texas City, Texas refinery is located on the Texas Gulf Coast adjacent to our Galveston Bay refinery, approximately 30 miles southeast of Houston, Texas. The refinery processes light sweet crude oils into gasoline, chemical-grade propylene, propane, aromatics, dry gas and slurry. Our Texas City refinery earned designation as an OSHA VPP Star site in 2012.
As of
December 31, 2014
, our refineries had
25
rail loading racks and
24
truck loading racks and
four
of our refineries had a total of
seven
owned and
11
non-owned docks. Total throughput in
2014
was
84
mbpd for the refinery loading racks and
911
mbpd for the refinery docks.
Planned maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units, are periodically performed at each refinery. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional detail.
Refined Product Yields
The following table sets forth our refinery production by product group for each of the last three years.
|
Refined Product Yields
(
mbpd
)
|
2014
|
2013
|
2012
|
||||||
|
Gasoline
|
869
|
|
921
|
|
738
|
|
|||
|
Distillates
|
580
|
|
572
|
|
433
|
|
|||
|
Propane
|
35
|
|
37
|
|
26
|
|
|||
|
Feedstocks and special products
|
276
|
|
221
|
|
109
|
|
|||
|
Heavy fuel oil
|
25
|
|
31
|
|
18
|
|
|||
|
Asphalt
|
54
|
|
54
|
|
62
|
|
|||
|
Total
|
1,839
|
|
1,836
|
|
1,386
|
|
|||
Crude Oil Supply
We obtain the crude oil we refine through negotiated term contracts and purchases or exchanges on the spot market. Our term contracts generally have market-related pricing provisions. The following table provides information on our sources of crude oil for each of the last three years. The crude oil sourced outside of North America was acquired from various foreign national oil companies, production companies and trading companies.
|
Sources of Crude Oil Refined
(
mbpd
)
|
2014
|
2013
|
2012
|
||||||
|
United States
|
1,120
|
|
946
|
|
649
|
|
|||
|
Canada
|
223
|
|
255
|
|
195
|
|
|||
|
Middle East and other international
|
279
|
|
388
|
|
351
|
|
|||
|
Total
|
1,622
|
|
1,589
|
|
1,195
|
|
|||
Our refineries receive crude oil and other feedstocks and distribute our refined products through a variety of channels, including pipelines, trucks, railcars, ships and barges. During 2012, we began transporting condensate and crude oil by truck from the Utica Shale region to our Canton refinery.
11
Renewable Fuels
We currently own a biofuel production facility in Cincinnati, Ohio that produces biodiesel, glycerin and other by-products. The capacity of the plant is approximately
60 million
gallons per year.
We hold interests in ethanol production facilities in Albion, Michigan; Clymers, Indiana and Greenville, Ohio. These plants have a combined ethanol production capacity of
275
million gallons per year (
18
mbpd) and are managed by a co-owner.
Refined Product Marketing
We believe we are one of the largest wholesale suppliers of gasoline and distillates to resellers and consumers within our
19
-state market area. Independent retailers, wholesale customers, our Marathon brand jobbers and Speedway brand convenience stores, airlines, transportation companies and utilities comprise the core of our customer base. In addition, we sell gasoline, distillates and asphalt for export, primarily out of our Garyville and Galveston Bay refineries. The following table sets forth our refined product sales destined for export by product group for the past three years.
|
Refined Product Sales Destined for Export
(
mbpd
)
|
2014
|
2013
|
2012
|
||||||
|
Gasoline
|
79
|
|
38
|
|
1
|
|
|||
|
Distillates
|
191
|
|
173
|
|
114
|
|
|||
|
Asphalt
|
5
|
|
6
|
|
8
|
|
|||
|
Other
|
—
|
|
1
|
|
—
|
|
|||
|
Total
|
275
|
|
218
|
|
123
|
|
|||
The following table sets forth, as a percentage of total refined product sales volume, the sales of refined products to our different customer types for the past three years.
|
Refined Product Sales by Customer Type
|
2014
|
2013
|
2012
|
||||||
|
Private-brand marketers, commercial and industrial customers, including spot market
|
73
|
%
|
75
|
%
|
72
|
%
|
|||
|
Marathon-branded independent entrepreneurs
|
15
|
%
|
16
|
%
|
17
|
%
|
|||
|
Speedway
®
convenience stores
|
12
|
%
|
9
|
%
|
11
|
%
|
|||
12
The following table sets forth the approximate number of retail outlets by state where independent entrepreneurs maintain Marathon-branded retail outlets, as of
December 31, 2014
.
|
State
|
Approximate Number of
Marathon
®
Retail Outlets
|
||
|
Alabama
|
202
|
|
|
|
Florida
|
523
|
|
|
|
Georgia
|
297
|
|
|
|
Illinois
|
344
|
|
|
|
Indiana
|
648
|
|
|
|
Kentucky
|
586
|
|
|
|
Louisiana
|
1
|
|
|
|
Maryland
|
1
|
|
|
|
Michigan
|
753
|
|
|
|
Minnesota
|
74
|
|
|
|
Mississippi
|
38
|
|
|
|
North Carolina
|
297
|
|
|
|
Ohio
|
857
|
|
|
|
Pennsylvania
|
60
|
|
|
|
South Carolina
|
129
|
|
|
|
Tennessee
|
328
|
|
|
|
Virginia
|
129
|
|
|
|
West Virginia
|
124
|
|
|
|
Wisconsin
|
64
|
|
|
|
Total
|
5,455
|
|
|
As of
December 31, 2014
, we also had branded marketing contract assignments for retail outlets, primarily in Florida, Mississippi, Tennessee and Alabama and branded lessee dealer marketing contract assignments, primarily in Connecticut, Maryland and New York, which we acquired as either part of the Galveston Bay Refinery and Related Assets acquisition in 2013 or the acquisition of Hess’ Retail Operations and Related Assets in 2014. As of
December 31, 2014
, we had outstanding retail marketing contract assignments for approximately
590
retail outlets.
The following table sets forth our refined product sales volumes by product group for each of the last three years.
|
Refined Product Sales by Product Group
(
mbpd
)
|
2014
|
2013
|
2012
|
||||||
|
Gasoline
|
1,116
|
|
1,126
|
|
916
|
|
|||
|
Distillates
|
623
|
|
615
|
|
463
|
|
|||
|
Propane
|
34
|
|
37
|
|
27
|
|
|||
|
Feedstocks and special products
|
268
|
|
214
|
|
112
|
|
|||
|
Heavy fuel oil
|
28
|
|
29
|
|
19
|
|
|||
|
Asphalt
|
56
|
|
54
|
|
62
|
|
|||
|
Total
|
2,125
|
|
2,075
|
|
1,599
|
|
|||
Gasoline and Distillates
. We sell gasoline, gasoline blendstocks and distillates (including No. 1 and No. 2 fuel oils, jet fuel, kerosene and diesel fuel) to wholesale customers, Marathon-branded independent entrepreneurs and our Speedway
®
convenience stores and on the spot market. In addition, we sell diesel fuel and gasoline for export to international customers. We sold
55
percent of our gasoline sales volumes and
89
percent of our distillates sales volumes on a wholesale or spot market basis in
2014
. The demand for gasoline and distillates is seasonal in many of our markets, with demand typically at its highest levels during the summer months.
13
We have blended ethanol into gasoline for more than 20 years and began expanding our blending program in 2007, in part due to federal regulations that require us to use specified volumes of renewable fuels. Ethanol volumes sold in blended gasoline were
78
mbpd in
2014
,
74
mbpd in
2013
and
68
mbpd in
2012
. We sell reformulated gasoline, which is also blended with ethanol, in
12
states in our marketing area. We also sell biodiesel-blended diesel fuel in
15
states in our marketing area. The future expansion or contraction of our ethanol and biodiesel blending programs will be driven by market economics and government regulations.
Propane
. We produce propane at most of our refineries. Propane is primarily used for home heating and cooking, as a feedstock within the petrochemical industry, for grain drying and as a fuel for trucks and other vehicles. Our propane sales are typically split evenly between the home heating market and industrial consumers.
Feedstocks and Special Products
. We are a producer and marketer of feedstocks and specialty products. Product availability varies by refinery and includes propylene, raffinate, butane, benzene, xylene, molten sulfur, cumene and toluene. We market these products domestically to customers in the chemical, agricultural and fuel-blending industries. In addition, we produce fuel-grade coke at our Garyville, Detroit and Galveston Bay refineries, which is used for power generation and in miscellaneous industrial applications, and anode-grade coke at our Robinson refinery, which is used to make carbon anodes for the aluminum smelting industry. Our feedstocks and special products sales increased to 268 mbpd in 2014 from 214 mbpd in 2013 and 112 mbpd in 2012 primarily due to our Galveston Bay refinery.
Heavy Fuel Oil
. We produce and market heavy residual fuel oil or related components, including slurry, at all of our refineries. Heavy residual fuel oil is primarily used in the utility and ship bunkering (fuel) industries, though there are other more specialized uses of the product.
Asphalt
. We have refinery-based asphalt production capacity of up to
101
mbpcd, which includes asphalt cements, polymer-modified asphalt, emulsified asphalt, industrial asphalts and roofing flux. We have a broad customer base, including asphalt-paving contractors, government entities (states, counties, cities and townships) and asphalt roofing shingle manufacturers. We sell asphalt in the domestic and export wholesale markets via rail, barge and vessel.
14
Terminals
As of
December 31, 2014
, we owned and operated
63
light product and
18
asphalt terminals. Our light product and asphalt terminals averaged
1,426
mbpd and
27
mbpd of throughput in
2014
, respectively. In addition, we distribute refined products through
one
leased light product terminal,
two
light product terminals in which we have partial ownership interests but do not operate and approximately
118
third-party light product and
10
third-party asphalt terminals in our market area. The following table sets forth additional details about our owned and operated terminals at
December 31, 2014
.
|
Owned and Operated Terminals
|
Number of
Terminals
|
Tank Storage
Capacity
(
million barrels
)
|
Number
of Tanks
|
Number of
Loading
Lanes
|
||||||||
|
Light Product Terminals:
|
||||||||||||
|
Alabama
|
2
|
|
0.4
|
|
20
|
|
4
|
|
||||
|
Florida
|
4
|
|
2.8
|
|
83
|
|
22
|
|
||||
|
Georgia
|
4
|
|
0.9
|
|
38
|
|
9
|
|
||||
|
Illinois
|
4
|
|
1.2
|
|
44
|
|
14
|
|
||||
|
Indiana
|
6
|
|
2.9
|
|
72
|
|
17
|
|
||||
|
Kentucky
|
6
|
|
2.3
|
|
68
|
|
24
|
|
||||
|
Louisiana
|
1
|
|
0.1
|
|
9
|
|
2
|
|
||||
|
Michigan
|
9
|
|
2.3
|
|
89
|
|
28
|
|
||||
|
North Carolina
|
4
|
|
1.1
|
|
50
|
|
13
|
|
||||
|
Ohio
|
13
|
|
3.6
|
|
156
|
|
33
|
|
||||
|
Pennsylvania
|
1
|
|
0.2
|
|
8
|
|
2
|
|
||||
|
South Carolina
|
1
|
|
0.3
|
|
9
|
|
3
|
|
||||
|
Tennessee
|
4
|
|
1.0
|
|
44
|
|
12
|
|
||||
|
West Virginia
|
2
|
|
0.1
|
|
10
|
|
2
|
|
||||
|
Wisconsin
|
2
|
|
0.8
|
|
19
|
|
7
|
|
||||
|
Subtotal light product terminals
|
63
|
|
20.0
|
|
719
|
|
192
|
|
||||
|
Asphalt Terminals:
|
||||||||||||
|
Florida
|
1
|
|
0.2
|
|
4
|
|
3
|
|
||||
|
Illinois
|
2
|
|
0.1
|
|
33
|
|
6
|
|
||||
|
Indiana
|
2
|
|
0.5
|
|
19
|
|
6
|
|
||||
|
Kentucky
|
4
|
|
0.5
|
|
60
|
|
14
|
|
||||
|
Louisiana
|
1
|
|
0.1
|
|
11
|
|
2
|
|
||||
|
Michigan
|
1
|
|
—
|
|
—
|
|
8
|
|
||||
|
Ohio
|
4
|
|
2.1
|
|
74
|
|
10
|
|
||||
|
Pennsylvania
|
1
|
|
0.5
|
|
22
|
|
8
|
|
||||
|
Tennessee
|
2
|
|
0.5
|
|
44
|
|
8
|
|
||||
|
Subtotal asphalt terminals
|
18
|
|
4.5
|
|
267
|
|
65
|
|
||||
|
Total owned and operated terminals
|
81
|
|
24.5
|
|
986
|
|
257
|
|
||||
15
Transportation
As of
December 31, 2014
, our marine transportation operations included
18
owned and
one
leased towboat, as well as
199
owned and
12
leased barges that transport refined products and crude oil on the Ohio, Mississippi and Illinois rivers and their tributaries and inter-coastal waterways. The following table sets forth additional details about our towboats and barges.
|
Class of Equipment
|
Number
in Class
|
Capacity
(
thousand barrels
)
|
||||
|
Inland tank barges:
(a)
|
||||||
|
Less than 25,000 barrels
|
61
|
|
886
|
|
||
|
25,000 barrels and over
|
150
|
|
4,392
|
|
||
|
Total
|
211
|
|
5,278
|
|
||
|
Inland towboats:
|
||||||
|
Less than 2,000 horsepower
|
2
|
|
||||
|
2,000 horsepower and over
|
17
|
|
||||
|
Total
|
19
|
|
||||
|
(a)
|
All of our barges are double-hulled.
|
As of
December 31, 2014
, we owned
142
transport trucks and
151
trailers with an aggregate capacity of
1.4 million
gallons for the movement of refined products and crude oil. In addition, we had
2,183
leased and
27
owned railcars of various sizes and capacities for movement and storage of refined products. The following table sets forth additional details about our railcars.
|
|
Number of Railcars
|
|
|||||||||
|
Class of Equipment
|
Owned
|
Leased
|
Total
|
Capacity per Railcar
|
|||||||
|
General service tank cars
|
—
|
|
794
|
|
794
|
|
20,000-30,000 gallons
|
||||
|
High pressure tank cars
|
—
|
|
1,171
|
|
1,171
|
|
33,500 gallons
|
||||
|
Open-top hoppers
|
27
|
|
218
|
|
245
|
|
4,000 cubic feet
|
||||
|
27
|
|
2,183
|
|
2,210
|
|
||||||
Speedway
Our Speedway segment sells gasoline, diesel and merchandise through convenience stores that it owns and operates, primarily under the Speedway and Hess brands. We have the right to use the Hess brand through September 30, 2017. We are in the process of converting convenience stores acquired from Hess to the Speedway brand, which we target to complete by the end of 2016. Speedway convenience stores offer a wide variety of merchandise, including prepared foods, beverages and non-food items. Speedway’s Speedy Rewards® loyalty program has been a highly successful loyalty program since its inception in 2004, with a consistently growing base of more than
3.9 million
active members as of
December 31, 2014
. Due to Speedway’s ability to capture and analyze member-specific transactional data, Speedway is able to offer the Speedy Rewards® members discounts and promotions specific to their buying behavior. We believe Speedy Rewards® is a key reason customers choose Speedway over competitors and it continues to drive significant value for both Speedway and our Speedy Rewards® members.
The demand for gasoline is seasonal, with the highest demand usually occurring during the summer driving season. Margins from the sale of merchandise tend to be less volatile than margins from the retail sale of gasoline and diesel fuel. Merchandise margin as a percent of total gross margin for Speedway decreased in 2014, primarily related to the convenience stores acquired from Hess. The following table sets forth Speedway merchandise statistics for the past three years.
|
Speedway Merchandise Statistics
|
2014
|
2013
|
2012
|
|||||||||
|
Merchandise sales (in millions)
|
$
|
3,611
|
|
$
|
3,135
|
|
$
|
3,058
|
|
|||
|
Merchandise gross margin (in millions)
|
975
|
|
825
|
|
795
|
|
||||||
|
Merchandise as a percent of total gross margin
|
57
|
%
|
65
|
%
|
67
|
%
|
||||||
16
As of
December 31, 2014
, Speedway had
2,746
convenience stores in
22
states. The following table sets forth the number of convenience stores by state owned by our Speedway segment as of
December 31, 2014
.
|
State
|
Number of
Convenience Stores
|
||
|
Alabama
|
2
|
|
|
|
Connecticut
|
1
|
|
|
|
Delaware
|
4
|
|
|
|
Florida
|
248
|
|
|
|
Georgia
|
6
|
|
|
|
Illinois
|
107
|
|
|
|
Indiana
|
307
|
|
|
|
Kentucky
|
144
|
|
|
|
Massachusetts
|
117
|
|
|
|
Michigan
|
303
|
|
|
|
New Hampshire
|
12
|
|
|
|
New Jersey
|
72
|
|
|
|
New York
|
243
|
|
|
|
North Carolina
|
288
|
|
|
|
Ohio
|
487
|
|
|
|
Pennsylvania
|
105
|
|
|
|
Rhode Island
|
20
|
|
|
|
South Carolina
|
61
|
|
|
|
Tennessee
|
26
|
|
|
|
Virginia
|
68
|
|
|
|
West Virginia
|
62
|
|
|
|
Wisconsin
|
63
|
|
|
|
Total
|
2,746
|
|
|
Pipeline Transportation
As of
December 31, 2014
, we owned, leased or had ownership interests in approximately
8,300
miles of crude oil and products pipelines, of which approximately
2,900
miles are owned through our investments in MPLX.
MPLX
In 2012, we formed MPLX, a master limited partnership, to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products. On October 31, 2012, MPLX completed its initial public offering. As of
December 31, 2014
, we owned a
71.5 percent
interest in MPLX, including the
two percent
general partner interest, and MPLX’s assets consisted of a 99.5 percent general partner interest in Pipe Line Holdings, which owns common carrier pipeline systems through Marathon Pipe Line LLC (“MPL”) and Ohio River Pipe Line LLC (“ORPL”), and a
100 percent
interest in a
one million
barrel butane storage cavern in West Virginia.
17
As of
December 31, 2014
, Pipe Line Holdings, through MPL and ORPL, owned or leased and operated
1,004
miles of common carrier crude oil lines and
1,902
miles of common carrier products lines located in
nine
states and
four
tank farms in Illinois and Indiana with available storage capacity of
3.29 million
barrels that is committed to MPC. The table below sets forth additional detail regarding these pipeline systems and storage assets as of
December 31, 2014
.
|
Pipeline System or Storage Asset
|
Origin
|
Destination
|
Diameter
(
inches
)
|
Length
(
miles
)
|
Capacity
(a)
|
Associated MPC refinery
|
||||||||
|
Crude oil pipeline systems (mbpd):
|
||||||||||||||
|
Patoka, IL to Lima, OH crude system
|
Patoka, IL
|
Lima, OH
|
20”-22”
|
302
|
|
249
|
|
Detroit, Canton
|
||||||
|
Catlettsburg, KY and Robinson, IL crude system
|
Patoka, IL
|
Catlettsburg, KY &
Robinson, IL
|
20”-24”
|
484
|
|
495
|
|
Catlettsburg, Robinson
|
||||||
|
Detroit, MI crude system
(b)
|
Samaria &
Romulus, MI
|
Detroit, MI
|
16”
|
61
|
|
197
|
|
Detroit
|
||||||
|
Wood River, IL to Patoka, IL crude system
(b)
|
Wood River &
Roxana, IL
|
Patoka, IL
|
12”-22”
|
115
|
|
314
|
|
All Midwest refineries
|
||||||
|
Inactive pipelines
|
42
|
|
N/A
|
|
||||||||||
|
Total
|
1,004
|
|
1,255
|
|
||||||||||
|
Products pipeline systems (mbpd):
|
||||||||||||||
|
Garyville, LA products system
|
Garyville, LA
|
Zachary, LA
|
20”-36”
|
72
|
|
389
|
|
Garyville
|
||||||
|
Texas City, TX products system
|
Texas City, TX
|
Pasadena, TX
|
16”-36”
|
42
|
|
215
|
|
Texas City, Galveston Bay
|
||||||
|
ORPL products system
|
Various
|
Various
|
6”-14”
|
518
|
|
244
|
|
Catlettsburg, Canton
|
||||||
|
Robinson, IL products system
(b)
|
Various
|
Various
|
10”-16”
|
1,171
|
|
548
|
|
Robinson
|
||||||
|
Louisville, KY Airport products system
|
Louisville, KY
|
Louisville, KY
|
6”-8”
|
14
|
|
29
|
|
Robinson
|
||||||
|
Inactive pipelines
(b)
|
85
|
|
N/A
|
|
||||||||||
|
Total
|
1,902
|
|
1,425
|
|
||||||||||
|
Wood River, IL barge dock (mbpd)
|
78
|
|
Garyville
|
|||||||||||
|
Storage assets (thousand barrels):
|
||||||||||||||
|
Neal, WV butane cavern
(c)
|
1,000
|
|
Catlettsburg
|
|||||||||||
|
Patoka, IL tank farm
|
1,386
|
|
All Midwest refineries
|
|||||||||||
|
Wood River, IL tank farm
|
419
|
|
All Midwest refineries
|
|||||||||||
|
Martinsville, IL tank farm
|
738
|
|
Detroit, Canton
|
|||||||||||
|
Lebanon, IN tank farm
|
750
|
|
Detroit, Canton
|
|||||||||||
|
Total
|
4,293
|
|
||||||||||||
|
(a)
|
All capacities reflect 100 percent of the pipeline systems’ and barge dock’s average capacity in thousands of barrels per day and 100 percent of the available storage capacity of our butane cavern and tank farms in thousand of barrels.
|
|
(b)
|
Includes pipelines leased from third parties.
|
|
(c)
|
The Neal, WV butane cavern is 100 percent owned by MPLX.
|
The Pipe Line Holdings common carrier pipeline network is one of the largest petroleum pipeline systems in the United States, based on total volume delivered. Third parties generated
12
percent of the crude oil and refined product shipments on these common carrier pipelines in
2014
, excluding volumes shipped by MPC under joint tariffs with third parties. These common carrier pipelines transported the volumes shown in the following table for each of the last three years.
|
Pipeline Throughput
(mbpd)
(a)(b)
|
2014
|
2013
|
2012
|
||||||
|
Crude oil pipelines
|
1,041
|
|
1,075
|
|
1,032
|
|
|||
|
Refined products pipelines
|
878
|
|
911
|
|
980
|
|
|||
|
Total
|
1,919
|
|
1,986
|
|
2,012
|
|
|||
|
(a)
|
MPLX predecessor volumes reported in MPLX’s filings include our undivided joint interest crude oil pipeline systems for periods prior to MPLX’s initial public offering, which were not contributed to MPLX. The undivided joint interest volumes are not included above.
|
|
(b)
|
Volumes represent 100 percent of the throughput through these pipelines.
|
18
MPC-Retained Assets and Investments
We retained ownership interests in several crude oil and products pipeline systems and pipeline companies. MPC consolidated volumes transported through our common carrier pipelines, which include MPLX and our undivided joint interests, are shown in the following table for each of the last three years.
|
MPC Consolidated Pipeline Throughput
(
mbpd
)
|
2014
|
2013
|
2012
|
||||||
|
Crude oil pipelines
|
1,241
|
|
1,293
|
|
1,191
|
|
|||
|
Refined products pipelines
|
878
|
|
911
|
|
980
|
|
|||
|
Total
|
2,119
|
|
2,204
|
|
2,171
|
|
|||
As of
December 31, 2014
, we owned undivided joint interests in the following common carrier crude oil pipeline systems.
|
Pipeline System
|
Origin
|
Destination
|
Diameter
(
inches
)
|
Length
(
miles
)
|
Ownership
Interest
|
Operated
by MPL
|
||||||||
|
Capline
|
St. James, LA
|
Patoka, IL
|
40”
|
643
|
|
33
|
%
|
Yes
|
||||||
|
Maumee
|
Lima, OH
|
Samaria, MI
|
22”
|
95
|
|
26
|
%
|
No
|
||||||
|
Total
|
738
|
|
||||||||||||
As of
December 31, 2014
, we had partial ownership interests in the following pipeline companies.
|
Pipeline Company
|
Origin
|
Destination
|
Diameter
(
inches
)
|
Length
(
miles
)
|
Ownership
Interest
|
Operated
by MPL
|
||||||||
|
Crude oil pipeline companies:
|
||||||||||||||
|
Illinois Extension Pipeline Company LLC
(a)
|
Flanagan, IL
|
Patoka, IL
|
TBD
|
TBD
|
|
35
|
%
|
No
|
||||||
|
LOCAP LLC
|
Clovelly, LA
|
St. James, LA
|
48”
|
57
|
|
59
|
%
|
No
|
||||||
|
LOOP LLC
|
Offshore Gulf of Mexico
|
Clovelly, LA
|
48”
|
48
|
|
51
|
%
|
No
|
||||||
|
North Dakota Pipeline Company LLC
(a)(b)
|
Plentywood, MT
|
Clearbrook, MN
|
TBD
|
TBD
|
|
38
|
%
|
No
|
||||||
|
Total
|
105
|
|
||||||||||||
|
Products pipeline companies:
|
||||||||||||||
|
Ascension Pipeline Company LLC
(a)
|
Riverside, LA
|
Garyville
|
TBD
|
TBD
|
|
50
|
%
|
No
|
||||||
|
Centennial Pipeline LLC
(c)
|
Beaumont, TX
|
Bourbon, IL
|
24”-26”
|
795
|
|
50
|
%
|
Yes
|
||||||
|
Explorer Pipeline Company
|
Lake Charles, LA
|
Hammond, IN
|
12”-28”
|
1,883
|
|
25
|
%
|
No
|
||||||
|
Muskegon Pipeline LLC
|
Griffith, IN
|
Muskegon, MI
|
10”
|
170
|
|
60
|
%
|
Yes
|
||||||
|
Wolverine Pipe Line Company
|
Chicago, IL
|
Bay City &
Ferrysburg, MI
|
6”-18”
|
743
|
|
6
|
%
|
No
|
||||||
|
Total
|
3,591
|
|
||||||||||||
|
(a)
|
The pipeline diameter and length for these companies will be determined when these pipeline projects are placed into service.
|
|
(b)
|
We own 38 percent of the Class B units in this entity. Upon completion of the Sandpiper pipeline project, which is to construct a pipeline running from Beaver Lodge, North Dakota to Superior, Wisconsin and targeted for completion in 2017, our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity.
|
|
(c)
|
Includes
491
miles of inactive pipeline.
|
19
We also own
183
miles of private crude oil pipelines and
760
miles of private refined products pipelines that are operated by MPL for the benefit of our Refining & Marketing segment on a cost recovery basis. The following table provides additional information on these assets.
|
Private Pipeline Systems
|
Diameter
(
inches
)
|
Length
(
miles
)
|
Capacity
(
mbpd
)
|
|||||
|
Crude oil pipeline systems:
|
||||||||
|
Lima, OH to Canton, OH
|
12”-16”
|
153
|
|
85
|
|
|||
|
St. James, LA to Garyville, LA
|
30”
|
20
|
|
620
|
|
|||
|
Other
|
6”-14”
|
2
|
|
15
|
|
|||
|
Inactive pipelines
|
8
|
|
N/A
|
|
||||
|
Total
|
183
|
|
720
|
|
||||
|
Products pipeline systems:
|
||||||||
|
Robinson, IL to Lima, OH
|
8”
|
250
|
|
18
|
|
|||
|
Louisville, KY to Lexington, KY
(a)
|
8”
|
87
|
|
37
|
|
|||
|
Woodhaven, MI to Detroit, MI
|
4”
|
26
|
|
12
|
|
|||
|
Illinois pipeline systems
|
4”-12”
|
118
|
|
39
|
|
|||
|
Texas pipeline systems
|
8”
|
103
|
|
45
|
|
|||
|
Ohio pipeline systems
|
4”-12”
|
57
|
|
32
|
|
|||
|
Inactive pipelines
|
119
|
|
N/A
|
|
||||
|
Total
|
760
|
|
183
|
|
||||
|
(a)
|
We own a
65
percent undivided joint interest in the Louisville, KY to Lexington, KY system.
|
As of
December 31, 2014
, we owned or leased
60
private tanks with storage capacity of approximately
6.5 million
barrels, which are located along MPL and ORPL pipelines.
Competition, Market Conditions and Seasonality
The downstream petroleum business is highly competitive, particularly with regard to accessing crude oil and other feedstock supply and the marketing of refined products. We compete with a large number of other companies to acquire crude oil for refinery processing and in the distribution and marketing of a full array of petroleum products. Based upon the “The Oil & Gas Journal
2014
Worldwide Refinery Survey,” we ranked fourth among U.S. petroleum companies on the basis of U.S. crude oil refining capacity as of
December 31, 2014
. We compete in four distinct markets for the sale of refined products—wholesale, spot, branded and retail distribution. We believe we compete with about
60
companies in the sale of refined products to wholesale marketing customers, including private-brand marketers and large commercial and industrial consumers; about
90
companies in the sale of refined products in the spot market;
12
refiners or marketers in the supply of refined products to refiner-branded independent entrepreneurs; and approximately
910
retailers in the retail sale of refined products. In addition, we compete with producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and retail consumers. We do not produce any of the crude oil we refine.
We also face strong competition for sales of retail gasoline, diesel fuel and merchandise. Our competitors include service stations and convenience stores operated by fully integrated major oil companies and their independent entrepreneurs and other well-recognized national or regional convenience stores and travel centers, often selling gasoline, diesel fuel and merchandise at competitive prices. Non-traditional retailers, such as supermarkets, club stores and mass merchants, have affected the convenience store industry with their entrance into sales of retail gasoline and diesel fuel. Energy Analysts International, Inc. estimated such retailers had approximately
14
percent of the U.S. gasoline market in mid-
2014
.
Our pipeline transportation operations are highly regulated, which affects the rates that our common carrier pipelines can charge for transportation services and the return we obtain from such pipelines.
Market conditions in the oil and gas industry are cyclical and subject to global economic and political events and new and changing governmental regulations. Our operating results are affected by price changes in crude oil, natural gas and refined products, as well as changes in competitive conditions in the markets we serve. Price differentials between sweet and sour crude oils, West Texas Intermediate (“WTI”) and Light Louisiana Sweet (“LLS”) crude oils and other market structure differentials also affect our operating results.
20
Demand for gasoline, diesel fuel and asphalt is higher during the spring and summer months than during the winter months in most of our markets, primarily due to seasonal increases in highway traffic and construction. As a result, the operating results for each of our segments for the first and fourth quarters may be lower than for those in the second and third quarters of each calendar year.
Environmental Matters
Our management is responsible for ensuring that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations, and for reviewing our overall environmental performance. We also have a Corporate Emergency Response Team that oversees our response to any major environmental or other emergency incident involving us or any of our facilities.
We believe it is likely that the scientific and political attention to issues concerning the extent and causes of climate change will continue, with the potential for further regulations that could affect our operations. Currently, legislative and regulatory measures to address greenhouse gases are in various phases of review, discussion or implementation. The cost to comply with these laws and regulations cannot be estimated at this time, but could be significant. For additional information, see Item 1A. Risk Factors. We estimate and publicly report greenhouse gas emissions from our operations and products. Additionally, we continuously strive to improve operational and energy efficiencies through resource and energy conservation where practicable.
Our operations are subject to numerous other laws and regulations relating to the protection of the environment. Such laws and regulations include, among others, the Clean Air Act (“CAA”) with respect to air emissions, the Clean Water Act (“CWA”) with respect to water discharges, the Resource Conservation and Recovery Act (“RCRA”) with respect to solid and hazardous waste treatment, storage and disposal, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) with respect to releases and remediation of hazardous substances and the Oil Pollution Act of 1990 (“OPA-90”) with respect to oil pollution and response. In addition, many states where we operate have similar laws. New laws are being enacted and regulations are being adopted on a continuing basis, and the costs of compliance with such new laws and regulations are very difficult to estimate until finalized.
For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
-
Environmental Matters and Compliance Costs.
Air
We are subject to many requirements in connection with air emissions from our operations. The U.S. Environmental Protection Agency (“EPA”) issued an “endangerment finding” in 2009 that greenhouse gas emissions contribute to air pollution that endangers public health and welfare. Related to this endangerment finding, in April 2010, the EPA finalized a greenhouse gas emissions standard for mobile sources (cars and other light duty vehicles). The endangerment finding along with the mobile source standard and the EPA’s determination that greenhouse gases are subject to regulation under the CAA, and the EPA’s so-called “tailoring rule” led to permitting of larger stationary sources of greenhouse gas emissions, including refineries. Legal challenges filed against these EPA actions were overruled by the D.C. Circuit Court of Appeals. In June 2014, the Supreme Court limited the EPA’s greenhouse gas permitting authority to only those sources that also trigger Prevention of Significant Deterioration (“PSD”) conventional pollutants. A few MPC projects triggered greenhouse gas permitting requirements but any additional capital spend will likely not be significant. Legal challenges continue in the wake of the Supreme Court decision. The EPA has proposed New Source Performance Standards for greenhouse gas emissions for new and existing electric utility generating units. This could impact electric and natural gas rates for all our operations and could impose new requirements on the combined heat and power unit we operate. Congress may again consider legislation on greenhouse gas emissions or a carbon tax. Private parties have sued utilities and other emitters of greenhouse gas emissions, but such suits have been largely unsuccessful. We have not been named in any of those lawsuits. Private-party litigation is also pending against federal and certain state governmental entities seeking additional greenhouse gas emission reductions beyond those currently being undertaken. In sum, requiring reductions in greenhouse gas emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas emissions programs, including acquiring emission credits or allotments. These requirements may also significantly affect MPC’s refinery operations and may have an indirect effect on our business, financial condition and results of operations. The extent and magnitude of the impact from greenhouse gas regulation or legislation cannot be reasonably estimated due to the uncertainty regarding the additional measures and how they will be implemented.
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In 2013, the Obama administration developed the social cost of carbon (“SCC”). The SCC is to be used by the EPA and other federal agencies in regulatory cost-benefit analyses to take into account alleged broad economic consequences associated with changes to emissions of greenhouse gases. The SCC was first issued in 2010. In 2013, the Obama administration significantly increased the estimate to $36 per ton. In response to the regulated community and Congress’ critiques of how the SCC was developed, the Office of Management and Budget provided an opportunity to comment on the SCC, but ultimately did not make any significant revisions. In December 2014, the White House Council on Environmental Quality (“CEQ”) issued new draft guidance for assessing greenhouse gas emissions under the National Environmental Policy Act (“NEPA”), adding for the first time language that requires the analyses to also include the impact of climate change on projects, including using the SCC when analyzing costs and benefits of a project. While the impact of a higher SCC in future regulations is not known at this time, it may result in increased costs to our operations.
The EPA has reviewed and has revised, or will propose to revise, the National Ambient Air Quality Standards (“NAAQS”) for criteria air pollutants. The NAAQS are subject to multiple court challenges, making compliance planning uncertain. The EPA promulgated a revised ozone standard in March 2008 and commenced a multi-year process to develop the implementing rules required by the CAA. On December 17, 2014, the EPA proposed to revise the NAAQS for ozone. If the ozone standard is revised, it is expected to be effective in December 2015 after which states will begin developing implementation plans that will take several years to receive final EPA approval. The impact of a stricter standard cannot be accurately estimated due to the present uncertainty regarding the final standard and the additional requirements that states may impose. Also, in 2010, the EPA adopted new short-term standards for nitrogen dioxide and sulfur dioxide, and in December 2012 issued a more stringent fine particulate matter standard (“PM 2.5”). In December 2014, the EPA finalized the non-attainment areas for PM 2.5. None of our refineries are located in the non-attainment areas for PM 2.5, however, our Cincinnati Renewable Fuels LLC facility is located in Cincinnati, OH, which was designated as a non-attainment area. We cannot reasonably estimate the final financial impact of these proposed and revised NAAQS standards until the standards are finalized, individual state implementing rules are established and judicial challenges are resolved.
The EPA finalized the Boiler and Process Heater Maximum Achievable Control Technology (“Boiler MACT”) in March 2011 with work practice standards that are applicable to refinery and natural gas fired equipment. Subsequently, in January 2013 the EPA made certain revisions to the March 2011 final rule in response to petitions for reconsideration. In December 2014, the EPA proposed reconsideration of limited issues and proposed to delete rule provisions for an affirmative defense for malfunctions. Currently, litigation is pending in the D.C. Circuit Court on both the 2011 and 2013 rule-makings. We anticipate litigation to continue through 2015. We are in the process of implementing the work practice standards. Final financial impacts of the Boiler MACT rule cannot be determined at this time because the ongoing litigation could affect the final rule.
On June 30, 2014, the EPA proposed to revise existing refinery air emissions standards. The final rule is expected to be issued by June 17, 2015 and allows for implementation through June 2018. EPA’s periodic review and possible revision of these standards is required under the CAA. This rule may require additional controls, lower emission standards and ambient air monitoring. Due to the present uncertainty regarding final standards, we cannot reasonably estimate the cost associated with this rule.
Water
We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the CWA and have implemented systems to oversee our compliance with these permits. In addition, we are regulated under OPA-90, which among other things, requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. Also, in case of any such release, OPA-90 requires the responsible company to pay resulting removal costs and damages. OPA-90 also provides for civil penalties and imposes criminal sanctions for violations of its provisions. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we have established Spill Prevention, Control and Countermeasures plans for all facilities subject to such requirements.
Additionally, OPA-90 requires that new tank vessels entering or operating in U.S. waters be double-hulled and that existing tank vessels that are not double-hulled be retrofitted or removed from U.S. service. All barges used for river transport of our raw materials and refined products meet the double-hulled requirements of OPA-90. We operate facilities at which spills of oil and hazardous substances could occur. Some coastal states in which we operate have passed state laws similar to OPA-90, but with expanded liability provisions, that include provisions for cargo owner responsibility as well as ship owner and operator responsibility.
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In 2013, the EPA and the US Army Corps of Engineers proposed significant changes to the definition of the term “waters of the US” (WOTUS) used in numerous programs under the CWA. The proposed changes have the potential to expand permitting, planning and reporting obligations and extend the timing to secure permits for pipeline and fixed asset construction and maintenance activities. Some man-made water bodies on our plant sites (firewater ponds, stormwater systems, and green infrastructure systems) may become WOTUS, which may require new permits requiring the control of liquids entering and exiting these water bodies. A final rule is anticipated in early 2015.
In May 2014, the EPA issued the final rule regarding cooling water intake structures which impacts three of our refineries. The final rule established closed-loop cooling as one of eight required technologies. The final rule also requires company engagement with Fish and Wildlife to determine if any endangered species are at risk in the locations during the next NPDES permit cycle. This rule will apply with the next NPDES renewal at our Catlettsburg, Garyville, and Robinson refineries. This rule is not anticipated to have a material impact on our operations.
Solid Waste
We continue to seek methods to minimize the generation of hazardous wastes in our operations. RCRA establishes standards for the management of solid and hazardous wastes. Besides affecting waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal operations, the recycling of wastes and the regulation of underground storage tanks (“USTs”) containing regulated substances. We have ongoing RCRA treatment and disposal operations at two of our facilities and primarily utilize offsite third-party treatment and disposal facilities. Ongoing RCRA-related costs, however, are not expected to be material to our results of operations or cash flows.
Remediation
We own or operate, or have owned or operated, certain convenience stores and other locations where, during the normal course of operations, releases of refined products from USTs have occurred. Federal and state laws require that contamination caused by such releases at these sites be assessed and remediated to meet applicable standards. The enforcement of the UST regulations under RCRA has been delegated to the states, which administer their own UST programs. Our obligation to remediate such contamination varies, depending on the extent of the releases and the stringency of the applicable state laws and regulations. A portion of these remediation costs may be recoverable from the appropriate state UST reimbursement funds once the applicable deductibles have been satisfied. We also have ongoing remediation projects at a number of our current and former refinery, terminal and pipeline locations. Penalties or other sanctions may be imposed for noncompliance.
Claims under CERCLA and similar state acts have been raised with respect to the clean-up of various waste disposal and other sites. CERCLA is intended to facilitate the clean-up of hazardous substances without regard to fault. Potentially responsible parties for each site include present and former owners and operators of, transporters to and generators of the hazardous substances at the site. Liability is strict and can be joint and several. Because of various factors including the difficulty of identifying the responsible parties for any particular site, the complexity of determining the relative liability among them, the uncertainty as to the most desirable remediation techniques and the amount of damages and clean-up costs and the time period during which such costs may be incurred, we are unable to reasonably estimate our ultimate cost of compliance with CERCLA; however, we do not believe such costs will be material to our business, financial condition, results of operations or cash flows.
Mileage Standards, Renewable Fuels and Other Fuels Requirements
In 2007, the U.S. Congress passed the Energy Independence and Security Act (“EISA”), which, among other things, set a target of 35 miles per gallon for the combined fleet of cars and light trucks in the United States by model year 2020, and contains a second Renewable Fuel Standard (“RFS2”). In August 2012, the EPA and the National Highway Traffic Safety Administration jointly adopted regulations that establish average industry fleet fuel economy standards for passenger cars and light trucks of up to 41 miles per gallon by model year 2021 and average fleet fuel economy standards of up to 49.7 miles per gallon by model year 2025 (the standards from 2022 to 2025 are the government’s current estimate but will require further rulemaking). New or alternative transportation fuels such as compressed natural gas could also pose a competitive threat to our operations.
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The RFS2 required the total volume of renewable transportation fuels sold or introduced annually in the U.S. to reach 16.55 billion gallons in 2013 and increases to 36.0 billion gallons by 2022. EPA has not finalized the 2014 volumes at this time. In the near term, the RFS2 will be satisfied primarily with ethanol blended into gasoline. Vehicle, regulatory and infrastructure constraints limit the blending of significantly more than 10 percent ethanol into gasoline (“E10”), but blending more than E10 could be required if the RFS2 standards are not modified. The RFS2 has required, and may in the future continue to require, additional capital expenditures or expenses by us to accommodate increased renewable fuels use. Within the overall 36.0 billion gallon RFS2, EISA established an advanced biofuel RFS2 volume of 2.0 billion gallons in 2012 increasing to 21.0 billion gallons in 2022. Subsets within the advanced biofuel RFS2 include biomass-based diesel, which was set at 1.0 billion gallons in 2012, 1.28 billion gallons in 2013, and at least 1.0 billion gallons in 2014 through 2022 (to be determined by the EPA through future rulemaking), and cellulosic biofuel, which was set at 0.5 billion gallons in 2012 and 1.0 billion gallons in 2013, increasing to 16.0 billion gallons by 2022. In 2013, the EPA used its waiver authority under the CAA to reduce the amount of cellulosic biofuel required under the statute from 1.0 billion gallons to 6.0 million gallons. Currently, litigation is on-going in the D.C. Circuit Court of Appeals with respect to the EPA’s determination of the 2013 cellulosic biofuel requirement. Subsequently, industry has requested the EPA to use its waiver authority for 2014, requesting reductions for total renewable fuel, advanced biofuels and cellulosic biofuels volumetric obligations.
On November 29, 2013, the EPA issued a proposed rule for the 2014 renewal fuel volume requirements. On November 21, 2014, the EPA announced the rule would not become final until sometime in 2015. This continues the lack of clarity and timeliness that has become common place with the EPA’s administration of the RFS2 requirements. This proposed rule has substantially reduced the RFS2 requirements from the statutory numbers as follows: total renewables has been reduced from 18.15 to 15.21 billion gallons, the advanced requirement has been reduced from 3.75 to 2.20 billion gallons, the biomass-based diesel requirement has remained flat from 2013 at 1.28 billion gallons, and the cellulosic requirement has been reduced from 1.75 billion to 17 million gallons. If these proposed requirements become final, it will allow the obligated parties to comply in 2014 without needing any substantial volumes of 85 percent ethanol-blended or 15 percent ethanol-blended (“E15”) gasolines and postpone the issues and concerns of having to blend ethanol past the E10 “blendwall” at least for 2014. Likewise, the EPA has not finalized the 2015 renewable fuel volumes as required by the November 30, 2014 statutory deadline. As a result, the future of the RFS still remains undecided and is in need of a legislative re-write or repeal to provide a stable business platform for the obligated parties.
With potentially uncertain supplies, the advanced biofuels programs may present specific challenges in that we may have to enter into arrangements with other parties or purchase credits from the EPA to meet our obligations to use advanced biofuels, including biomass-based diesel and cellulosic biofuel. Additionally, the EPA did not finalize the 2013 RFS2 renewable fuel obligations until August 2013. Therefore, it is uncertain how industry will comply with meeting the advanced biofuels obligation. The continued delay of the final rule for 2014 has also delayed the day when compliance reports are due for 2013. In 2012 and 2013, the EPA also discovered that 173 million biodiesel renewable identification numbers (“RINs”) used to meet the annual requirement for that fuel had been fraudulently created and sold to unsuspecting third parties, including MPC. The EPA finalized a rule establishing a quality assurance program for RINs purchased to help meet the annual biofuel requirements under the RFS2 program. The program is aimed at reducing the risks that RINs are fraudulently created or sold. We have already instituted internal procedures to help mitigate that risk.
We made investments in infrastructure capable of expanding biodiesel blending capability to help comply with the biodiesel RFS2 requirement by buying and blending biodiesel into our refined diesel product, and by buying needed biodiesel RINs in the EPA-created biodiesel RINs market. On April 1, 2014, we purchased a facility in Cincinnati, Ohio, which currently produces biodiesel, glycerin and other by-products. The capacity of the plant is approximately
60 million
gallons per year. As a producer of biodiesel, we now generate RINs, thereby reducing our reliance on the external RIN market.
On October 13, 2010, the EPA issued a partial waiver decision under the CAA to allow for an increase in the amount of ethanol permitted to be blended into gasoline from E10 to E15 for 2007 and newer light-duty motor vehicles. On January 21, 2011, the EPA issued a second waiver for the use of E15 in vehicles model year 2001-2006. There are numerous issues, including state and federal regulatory issues, which need to be addressed before E15 can be marketed for use in traditional gasoline engines.
There will be compliance costs and uncertainties regarding how we will comply with the various requirements contained in EISA and related regulations. We may experience a decrease in demand for refined petroleum products due to an increase in combined fleet mileage or due to refined petroleum products being replaced by renewable fuels.
On March 3, 2014, the EPA signed the final Tier 3 fuel standards. The final Tier 3 fuel standards require, among other things, a lower annual average sulfur level in gasoline to no more than 10 parts per million (“ppm”) beginning in calendar year 2017. In addition, gasoline refiners and importers may not exceed a maximum per-gallon sulfur standard of 80 ppm while retailers may not exceed a maximum per-gallon sulfur standard of 95 ppm. We anticipate that we will spend an estimated $750 million to $1 billion between 2014 and 2019 for capital expenditures necessary to comply with these standards.
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Trademarks, Patents and Licenses
Our Marathon trademark is material to the conduct of our refining and marketing operations, and our Speedway trademark is material to the conduct of our retail marketing operations. We currently hold a number of U.S. and foreign patents and have various pending patent applications. Although in the aggregate our patents and licenses are important to us, we do not regard any single patent or license or group of related patents or licenses as critical or essential to our business as a whole. In general, we depend on our technological capabilities and the application of know-how rather than patents and licenses in the conduct of our operations.
Employees
We had approximately
45,340
regular employees as of
December 31, 2014
, which includes approximately
35,400
employees of Speedway.
Certain hourly employees at our Canton, Catlettsburg, Galveston Bay and Texas City refineries are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers Union. The labor agreements for our Canton, Catlettsburg and Galveston Bay refineries expired on January 31, 2015 and no successor agreements have been negotiated. As of February 1, 2015 our Catlettsburg and Galveston Bay refineries are experiencing work stoppages. The labor agreement for our Canton refinery was extended on a rolling 24-hour notice of expiration basis. The impacted refineries continue to operate as normal. The labor agreement for our Texas City refinery is due to expire on March 31, 2015. The International Brotherhood of Teamsters represents certain hourly employees at our Detroit refinery under a labor agreement that is scheduled to expire in 2019. In addition, they represent certain hourly employees at Speedway under agreements that cover certain outlets in New York and New Jersey that expire between September 14, 2015 and June 30, 2016.
Executive and Corporate Officers of the Registrant
The executive and corporate officers of MPC and their ages as of February 1,
2015
, are as follows:
|
Name
|
Age
|
Position with MPC
|
||
|
Gary R. Heminger
|
61
|
President and Chief Executive Officer
|
||
|
Pamela K.M. Beall
|
58
|
Senior Vice President, Corporate Planning, Government & Public Affairs
|
||
|
Richard D. Bedell
|
60
|
Senior Vice President, Refining
|
||
|
Timothy T. Griffith
|
45
|
Vice President, Finance and Investor Relations, and Treasurer
|
||
|
John R. Haley
(a)
|
58
|
Vice President, Tax
|
||
|
Thomas M. Kelley
|
55
|
Senior Vice President, Marketing
|
||
|
Anthony R. Kenney
|
61
|
President, Speedway LLC
|
||
|
Rodney P. Nichols
|
62
|
Senior Vice President, Human Resources and Administrative Services
|
||
|
C. Michael Palmer
|
61
|
Senior Vice President, Supply, Distribution and Planning
|
||
|
John J. Quaid
|
43
|
Vice President and Controller
|
||
|
George P. Shaffner
|
55
|
Senior Vice President, Transportation and Logistics
|
||
|
John S. Swearingen
(a)
|
55
|
Vice President, Health, Environment, Safety & Security
|
||
|
Donald C. Templin
|
51
|
Senior Vice President and Chief Financial Officer
|
||
|
Donald W. Wehrly
(a)
|
55
|
Vice President and Chief Information Officer
|
||
|
J. Michael Wilder
|
62
|
Vice President, General Counsel and Secretary
|
||
|
(a)
|
Corporate officer.
|
Mr. Heminger was appointed president and chief executive officer effective June 30, 2011. Prior to this appointment, Mr. Heminger was president of Marathon Petroleum Company LP (formerly known as Marathon Ashland Petroleum LLC and Marathon Petroleum Company LLC), currently a wholly owned subsidiary of MPC and prior to the Spinoff, a wholly owned subsidiary of Marathon Oil. He assumed responsibility as president of Marathon Petroleum Company LP in September 2001.
Ms. Beall was appointed senior vice president, Corporate Planning, Government & Public Affairs effective January 1, 2014. Prior to this appointment, Ms. Beall was vice president, Investor Relations and Government & Public Affairs beginning June 30, 2011 and was vice president, Products Supply and Optimization of Marathon Petroleum Company LP beginning in June 2010. She served as vice president of Global Procurement for Marathon Oil Company between 2007 and 2010 and prior to that as organizational vice president, Business Development—Downstream.
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Mr. Bedell was appointed senior vice president, Refining effective June 30, 2011. Prior to this appointment, Mr. Bedell served in the same capacity for Marathon Petroleum Company LP beginning in June 2010 and as manager, Louisiana Refining Division beginning in 2001.
Mr. Griffith was appointed vice president, Finance and Investor Relations, and treasurer effective January 1, 2014. Prior to this appointment, Mr. Griffith was vice president of Finance and treasurer beginning August 1, 2011. Mr. Griffith was vice president Investor Relations and treasurer of Smurfit-Stone Container Corporation, a packaging manufacturer, in St. Louis, Missouri, from 2008 to 2011.
Mr. Haley was appointed vice president, Tax effective June 1, 2013. Prior to this appointment, Mr. Haley served as director of Tax beginning in July 2011 and as a tax manager for Marathon Oil Company beginning in 1996.
Mr. Kelley was appointed senior vice president, Marketing effective June 30, 2011. Prior to this appointment, Mr. Kelley served in the same capacity for Marathon Petroleum Company LP beginning in January 2010. Previously, he served as director of Crude Supply and Logistics for Marathon Petroleum Company LP from January 2008, and as a Brand Marketing manager for eight years prior to that.
Mr. Kenney has served as president of Speedway LLC since August 2005.
Mr. Nichols was appointed senior vice president, Human Resources and Administrative Services effective March 1, 2012. Prior to this appointment, Mr. Nichols served as vice president, Human Resources and Administrative Services beginning on June 30, 2011 and served in the same capacity for Marathon Petroleum Company LP beginning in April 1998.
Mr. Palmer was appointed senior vice president, Supply, Distribution and Planning effective June 30, 2011. Prior to this appointment, Mr. Palmer served as vice president, Supply, Distribution & Planning for Marathon Petroleum Company LP beginning in June 2010. He served as Crude Supply and Logistics director for Marathon Petroleum Company LP beginning in February 2010, and as senior vice president, Oil Sands Operations and Commercial Activities for Marathon Oil Canada Corporation beginning in 2007.
Mr. Quaid was appointed vice president and controller effective June 23, 2014. Prior to this appointment, Mr. Quaid was vice president of Iron Ore at United States Steel Corporation (“U. S. Steel”), an integrated steel producer, beginning in January 2014. Previously, Mr. Quaid served in various leadership positions at U. S. Steel since February 2002, including vice president and treasurer beginning in August 2011, controller, North American Flat-Rolled Operations beginning in July 2010 and assistant corporate controller beginning in 2008.
Mr. Shaffner was appointed senior vice president, Transportation and Logistics effective June 30, 2011. Prior to this appointment, Mr. Shaffner served in the same capacity for Marathon Petroleum Company LP beginning in June 2010. Previously, Mr. Shaffner served as Michigan Refining Division manager beginning in October 2006.
Mr. Swearingen was appointed vice president of Health, Environmental, Safety & Security effective June 30, 2011. Prior to this appointment, Mr. Swearingen was president of Marathon Pipe Line LLC beginning in 2009 and the Illinois Refining Division manager beginning in November 2001.
Mr. Templin was appointed senior vice president and chief financial officer effective June 30, 2011. Prior to this appointment, Mr. Templin was a partner at PricewaterhouseCoopers LLP, an audit, tax and advisory services provider, with various audit and management responsibilities beginning in 1996.
Mr. Wehrly was appointed vice president and chief information officer effective June 30, 2011. Prior to this appointment, Mr. Wehrly was the manager of Information Technology Services for Marathon Petroleum Company LP beginning in 2003.
Mr. Wilder was appointed vice president, general counsel and secretary effective June 30, 2011. Prior to this appointment, Mr. Wilder was associate general counsel of Marathon Oil Company beginning in 2010 and general counsel and secretary of Marathon Petroleum Company LP beginning in 1997.
Michael G. Braddock, who was vice president and controller since June 30, 2011, retired effective October 1, 2014.
Garry L. Peiffer, who was executive vice president of Corporate Planning and Investor & Government Relations since June 30, 2011, retired effective January 1, 2014.
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Available Information
General information about MPC, including Corporate Governance Principles and Charters for the Audit Committee, Compensation Committee and Corporate Governance and Nominating Committee, can be found at
http://ir.marathonpetroleum.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are also available in this same location.
MPC uses its website,
www.marathonpetroleum.com
, as a channel for routine distribution of important information, including news releases, analyst presentations, financial information and market data. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after the reports are filed or furnished with the Securities and Exchange Commission. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. In addition, our website allows investors and other interested persons to sign up to automatically receive email alerts when we post news releases and financial information on our website. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.
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Item 1A. Risk Factors
You should carefully consider each of the following risks and all of the other information contained in this Annual Report on Form 10-K in evaluating us and our common stock. Some of these risks relate principally to our business and the industry in which we operate, while others relate to the ownership of our common stock.
Our business, financial condition, results of operations or cash flows could be materially and adversely affected by any of these risks, and, as a result, the trading price of our common stock could decline.
Risks Relating to our Business
A substantial or extended decline in refining and marketing gross margins would reduce our operating results and cash flows and could materially and adversely impact our future rate of growth, the carrying value of our assets and our ability to execute share repurchases and continue the payment of our base dividend.
Our operating results, cash flows, future rate of growth, the carrying value of our assets and our ability to execute share repurchases and continue the payment of our base dividend are highly dependent on the margins we realize on our refined products. The measure of the difference between market prices for refined products and crude oil, or crack spread, is commonly used by the industry as a proxy for refining and marketing gross margins. Historically, refining and marketing gross margins have been volatile, and we believe they will continue to be volatile. Our margins from the sale of gasoline and other refined products are influenced by a number of conditions, including the price of crude oil. We do not produce crude oil and must purchase all of the crude oil we refine. The price of crude oil and the price at which we can sell our refined products may fluctuate independently due to a variety of regional and global market conditions. Any overall change in crack spreads will impact our refining and marketing gross margins. Many of the factors influencing a change in crack spreads and refining and marketing gross margins are beyond our control. These factors include:
|
•
|
worldwide and domestic supplies of and demand for crude oil and refined products;
|
|
•
|
the cost of crude oil and other feedstocks to be manufactured into refined products;
|
|
•
|
the prices realized for refined products;
|
|
•
|
utilization rates of refineries;
|
|
•
|
natural gas and electricity supply costs incurred by refineries;
|
|
•
|
the ability of the members of OPEC to agree to and maintain production controls;
|
|
•
|
political instability or armed conflict in oil and natural gas producing regions;
|
|
•
|
local weather conditions;
|
|
•
|
seasonality of demand in our marketing area due to increased highway traffic in the spring and summer months;
|
|
•
|
natural disasters such as hurricanes and tornadoes;
|
|
•
|
the price and availability of alternative and competing forms of energy;
|
|
•
|
domestic and foreign governmental regulations and taxes; and
|
|
•
|
local, regional, national and worldwide economic conditions.
|
Some of these factors can vary by region and may change quickly, adding to market volatility, while others may have longer-term effects. The longer-term effects of these and other factors on refining and marketing gross margins are uncertain. We purchase our crude oil and other refinery feedstocks weeks before we refine them and sell the refined products. Price level changes during the period between purchasing feedstocks and selling the refined products from these feedstocks could have a significant effect on our financial results. We also purchase refined products manufactured by others for resale to our customers. Price changes during the periods between purchasing and reselling those refined products also could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Lower refining and marketing gross margins may reduce the amount of refined products we produce, which may reduce our revenues, income from operations and cash flows. Significant reductions in refining and marketing gross margins could require us to reduce our capital expenditures, impair the carrying value of our assets (such as property, plant and equipment, inventory or goodwill), decrease or eliminate our share repurchase activity and our base dividend.
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Our operations are subject to business interruptions and casualty losses. Failure to manage risks associated with business interruptions could adversely impact our operations, financial condition, results of operations and cash flows.
Our operations are subject to business interruptions due to scheduled refinery turnarounds, unplanned maintenance or unplanned events such as explosions, fires, refinery or pipeline releases or other incidents, power outages, severe weather, labor disputes, or other natural or man-made disasters, such as acts of terrorism. For example, pipelines provide a nearly-exclusive form of transportation of crude oil to, or refined products from, some of our refineries. In such instances, a prolonged interruption in service of such a pipeline could materially and adversely affect the operations, profitability and cash flows of the impacted refinery.
Explosions, fires, refinery or pipeline releases or other incidents involving our assets or operations could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses to us. Damages resulting from an incident involving any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting potentially substantial claims or in our being assessed potentially substantial fines by governmental authorities.
We do not insure against all potential losses, and, therefore, our business, financial condition, results of operations and cash flows could be adversely affected by unexpected liabilities and increased costs.
We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential liabilities arising from operating hazards. Uninsured liabilities arising from operating hazards, including but not limited to, explosions, fires, refinery or pipeline releases or other incidents involving our assets or operations, could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we also have maintained insurance coverage for physical damage and resulting business interruption to our major facilities, with significant self-insured retentions. In the future, we may not be able to maintain insurance of the types and amounts we desire at reasonable rates.
We rely on the performance of our information technology systems, the failure of which could have an adverse effect on our business, financial condition, results of operations and cash flows.
We are heavily dependent on our information technology systems and network infrastructure and maintain and rely upon certain critical information systems for the effective operation of our business. These information systems involve data network and telecommunications, Internet access and website functionality, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our business. These systems and infrastructure are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. We also face various other cyber-security threats, including threats to gain unauthorized access to sensitive information or to render data or systems unusable. To protect against such attempts of unauthorized access or attack, we have implemented infrastructure protection technologies and disaster recovery plans. There can be no guarantee such plans, to the extent they are in place, will be effective.
The retail market is diverse and highly competitive, and very aggressive competition could adversely impact our business.
We face strong competition in the market for the sale of retail gasoline, diesel fuel and merchandise. Our competitors include outlets owned or operated by fully integrated major oil companies or their dealers or jobbers, and other well-recognized national or regional retail outlets, often selling gasoline or merchandise at very competitive prices. Several non-traditional retailers such as supermarkets, club stores and mass merchants are in the retail business. These non-traditional gasoline retailers have obtained a significant share of the transportation fuels market and we expect their market share to grow. Because of their diversity, integration of operations, experienced management and greater financial resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability in the retail segment of the market. In addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. These activities by our competitors could pressure us to offer similar discounts, adversely affecting our profit margins. Additionally, the loss of market share by our convenience stores to these and other retailers relating to either gasoline or merchandise could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The development, availability and marketing of alternative and competing fuels in the retail market could adversely impact our business. We compete with other industries that provide alternative means to satisfy the energy and fuel needs of our consumers. Increased competition from these alternatives as a result of governmental regulations, technological advances and consumer demand could have an impact on pricing and demand for our products and our profitability.
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We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products.
We utilize the services of third parties to transport crude oil and refined products to and from our refineries. In addition to our own operational risks discussed above, we could experience interruptions of supply or increases in costs to deliver refined products to market if the ability of the pipelines, railways or vessels to transport crude oil or refined products is disrupted because of weather events, accidents, governmental regulations or third-party actions. A prolonged disruption of the ability of the pipelines, railways or vessels to transport crude oil or refined products to or from one or more of our refineries could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may incur losses to our business as a result of our forward-contract activities and derivative transactions.
We currently use commodity derivative instruments, and we expect to enter into these types of transactions in the future. A failure of a futures commission merchant or counterparty to perform would affect these transactions. To the extent the instruments we utilize to manage these exposures are not effective, we may incur losses related to the ineffective portion of the derivative transaction or costs related to moving the derivative positions to another futures commission merchant or counterparty once a failure has occurred.
We have significant debt obligations; therefore our business, financial condition, results of operations and cash flows could be harmed by a deterioration of our credit profile, a decrease in debt capacity or unsecured commercial credit available to us, or by factors adversely affecting credit markets generally.
At
December 31, 2014
, our total debt obligations for borrowed money and capital lease obligations were
$6.7 billion
. We may incur substantial additional debt obligations in the future.
Our indebtedness may impose various restrictions and covenants on us that could have material adverse consequences, including:
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increasing our vulnerability to changing economic, regulatory and industry conditions;
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limiting our ability to compete and our flexibility in planning for, or reacting to, changes in our business and the industry;
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limiting our ability to pay dividends to our stockholders;
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limiting our ability to borrow additional funds; and
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requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing funds available for working capital, capital expenditures, acquisitions, share repurchases, dividends and other purposes.
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A decrease in our debt or commercial credit capacity, including unsecured credit extended by third-party suppliers, or a deterioration in our credit profile could increase our costs of borrowing money and/or limit our access to the capital markets and commercial credit, which could materially and adversely affect our business, financial condition, results of operations and cash flows.
We have a trade receivables securitization facility that provides liquidity of up to $1.3 billion depending on the amount of eligible domestic trade accounts receivables. In periods of lower prices, we may not have sufficient eligible accounts receivables to support full availability of this facility.
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Historic or current operations could subject us to significant legal liability or restrict our ability to operate.
We currently are defending litigation and anticipate we will be required to defend new litigation in the future. Our operations and those of our predecessors could expose us to litigation and civil claims by private plaintiffs for alleged damages related to contamination of the environment or personal injuries caused by releases of hazardous substances from our facilities, products liability, consumer credit or privacy laws, product pricing or antitrust laws or any other laws or regulations that apply to our operations. While an adverse outcome in most litigation matters would not be expected to be material to us, in class-action litigation, large classes of plaintiffs may allege damages relating to extended periods of time or other alleged facts and circumstances that could increase the amount of potential damages. Attorneys general and other government officials may pursue litigation in which they seek to recover civil damages from companies on behalf of a state or its citizens for a variety of claims, including violation of consumer protection and product pricing laws or natural resources damages. We are defending litigation of that type and anticipate that we will be required to defend new litigation of that type in the future. If we are not able to successfully defend such litigation, it may result in liability to our company that could materially and adversely affect our business, financial condition, results of operations and cash flows. We do not have insurance covering all of these potential liabilities. In addition to substantial liability, plaintiffs in litigation may also seek injunctive relief which, if imposed, could have a material adverse effect on our future business, financial condition, results of operations and cash flows.
A portion of our workforce is unionized, and we may face labor disruptions that could materially and adversely affect our business, financial condition, results of operations and cash flows.
Approximately 38 percent of our refining employees are covered by collective bargaining agreements. The contracts for the hourly refinery workers at our Texas City and Detroit refineries are scheduled to expire in March 2015 and January 2019, respectively. The contracts for the hourly refinery workers at our Canton, Catlettsburg and Galveston Bay refineries expired on January 31, 2015 and no successor agreements have been negotiated. In addition, three agreements scheduled to expire on September 14, 2015, March 14, 2016 and June 30, 2016, respectively, cover certain Speedway LLC hourly employees at certain outlets in New York and New Jersey. These contracts may be renewed at an increased cost to us. In addition, we have experienced, or may experience, work stoppages as a result of labor disagreements. Any prolonged work stoppages disrupting operations could have a material adverse effect on our business, financial condition, results of operations and cash flows.
One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, MPLX, which may involve a greater exposure to certain legal liabilities than existed under our historic business operations.
One of our subsidiaries acts as the general partner of MPLX, a publicly traded master limited partnership. Our control of the general partner of MPLX may increase the possibility of claims of breach of fiduciary duties including claims of conflicts of interest related to MPLX. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.
If foreign ownership of our stock exceeds certain levels, we could be prohibited from operating inland river vessels, which could materially and adversely affect our business, financial condition, results of operations and cash flows.
The Shipping Act of 1916 and Merchant Marine Act of 1920, which we refer to collectively as the Maritime Laws, generally require that vessels engaged in U.S. coastwise trade be owned by U.S. citizens. Among other requirements to establish citizenship, corporations that own such vessels must be owned at least 75 percent by U.S. citizens. If we fail to maintain compliance with the Maritime Laws, we would be prohibited from operating vessels in the U.S. inland waters. Such a prohibition could materially and adversely affect our business, financial condition, results of operations and cash flows.
We are subject to certain continuing contingent liabilities of Marathon Oil relating to taxes and other matters and to potential liabilities pursuant to the tax sharing agreement we entered into with Marathon Oil that could materially and adversely affect our business, financial condition, results of operations and cash flows.
Although the Spinoff occurred in mid 2011, certain liabilities of Marathon Oil could become our obligations. For example, under the Internal Revenue Code of 1986 (the “Code”) and related rules and regulations, each corporation that was a member of the Marathon Oil consolidated tax reporting group during any taxable period or portion of any taxable period ending on or before the effective time of the Spinoff is jointly and severally liable for the federal income tax liability of the entire Marathon Oil consolidated tax reporting group for that taxable period. In connection with the Spinoff, we entered into a tax sharing agreement with Marathon Oil that allocates the responsibility for prior period taxes of the Marathon Oil consolidated tax reporting group between us and Marathon Oil. However, if Marathon Oil is unable to pay any prior period taxes for which it is responsible, we could be required to pay the entire amount of such taxes. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans as well as other contingent liabilities.
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Also pursuant to the tax sharing agreement, following the Spinoff we are responsible generally for all taxes attributable to us or any of our subsidiaries, whether accruing before, on or after the Spinoff. We also agreed to be responsible for, and indemnify Marathon Oil with respect to, all taxes arising as a result of the Spinoff (or certain internal restructuring transactions) failing to qualify as transactions under Sections 368(a) and 355 of the Code for U.S. federal income tax purposes to the extent such tax liability arises as a result of any breach of any representation, warranty, covenant or other obligation by us or certain affiliates made in connection with the issuance of the private letter ruling relating to the Spinoff or in the tax sharing agreement. In addition, we agreed to indemnify Marathon Oil for specified tax-related liabilities associated with our 2005 acquisition of the minority interest in our refining joint venture from Ashland Inc. Our indemnification obligations to Marathon Oil and its subsidiaries, officers and directors are not limited or subject to any cap. If we are required to indemnify Marathon Oil and its subsidiaries and their respective officers and directors under the tax sharing agreement, we may be subject to substantial liabilities. At this time, we cannot precisely quantify the amount of these liabilities that have been assumed pursuant to the tax sharing agreement, and there can be no assurances as to their final amounts. The tax liabilities described in this paragraph could have a material adverse effect on our business, financial condition, results of operation and cash flows.
The Spinoff could be determined not to qualify as a tax-free transaction, and Marathon Oil and its stockholders could be subject to material amounts of taxes and, in certain circumstances, we could be required to indemnify Marathon Oil for material taxes pursuant to indemnification obligations under the tax sharing agreement.
Marathon Oil received a private letter ruling from the Internal Revenue Service (the “IRS”), to the effect that, among other things, the distribution of shares of MPC common stock in the Spinoff qualifies as tax-free to Marathon Oil, us and Marathon Oil stockholders for U.S. federal income tax purposes under Sections 355 and 368(a) and related provisions of the Code. If the factual assumptions or representations made in the private letter ruling request are inaccurate or incomplete in any material respect, then Marathon Oil would not be able to continue to rely on the ruling. We are not aware of any facts or circumstances that would cause the assumptions or representations that were relied on in the private letter ruling to be inaccurate or incomplete in any material respect. If, notwithstanding receipt of the private letter ruling, the Spinoff were determined not to qualify under Section 355 of the Code, Marathon Oil would be subject to tax as if it had sold its shares of common stock of our company in a taxable sale for their fair market value and would recognize a taxable gain in an amount equal to the excess of the fair market value of such shares over its tax basis in such shares.
With respect to taxes and other liabilities that could be imposed on Marathon Oil in connection with the Spinoff (and certain related transactions) as a result of a final determination that is inconsistent with the anticipated tax consequences as set forth in the private letter ruling, we would be liable to Marathon Oil under the tax sharing agreement for any such taxes or liabilities attributable to actions taken by or with respect to us, any of our affiliates, or any person that, after the Spinoff, is our affiliate. We may be similarly liable if we breach specified representations or covenants set forth in the tax sharing agreement. If we are required to indemnify Marathon Oil for taxes incurred as a result of the Spinoff (or certain related transactions) being taxable to Marathon Oil, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.
We have potential liabilities pursuant to the separation and distribution agreement we entered into with Marathon Oil in connection with the Spinoff that could materially and adversely affect our business, financial condition, results of operations and cash flows.
In connection with the Spinoff, we entered into a separation and distribution agreement with Marathon Oil that provides for, among other things, the principal corporate transactions that were required to affect the Spinoff, certain conditions to the Spinoff and provisions governing the relationship between our company and Marathon Oil with respect to and resulting from the Spinoff. Among other things, the separation and distribution agreement provides for indemnification obligations designed to make us financially responsible for substantially all liabilities that may exist relating to our downstream business activities, whether incurred prior to or after the Spinoff, as well as certain obligations of Marathon Oil assumed by us. Our obligations to indemnify Marathon Oil under the circumstances set forth in the separation and distribution agreement could subject us to substantial liabilities. Marathon Oil also agreed to indemnify us for certain liabilities. However, third parties could seek to hold us responsible for any of the liabilities retained by Marathon Oil, and there can be no assurance that the indemnity from Marathon Oil will be sufficient to protect us against the full amount of such liabilities, that Marathon Oil will be able to fully satisfy its indemnification obligations or that Marathon Oil’s insurers will cover us for liabilities associated with occurrences prior to the Spinoff. Moreover, even if we ultimately succeed in recovering from Marathon Oil or its insurers any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. If Marathon Oil is unable to satisfy its indemnification obligations, the underlying liabilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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Significant acquisitions involve the integration of new assets or businesses and present substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows
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Significant transactions involving the addition of new assets or businesses present potential risks, which may include, among others:
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Inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;
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An inability to successfully integrate assets or businesses we acquire;
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A decrease in our liquidity resulting from using a portion of our available cash or borrowing capacity under our revolving credit agreement to finance transactions;
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A significant increase in our interest expense or financial leverage if we incur additional debt to finance transactions;
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The assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
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The diversion of management’s attention from other business concerns; and
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The incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
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Risks Relating to Our Industry
Changes in environmental or other laws or regulations may reduce our refining and marketing gross margin and may result in substantial capital expenditures and operating costs that could materially and adversely affect our business, financial condition, results of operations and cash flows.
Various laws and regulations are expected to impose increasingly stringent and costly requirements on our operations, which may reduce our refining and marketing gross margin. Laws and regulations expected to become more stringent relate to the following:
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the emission or discharge of materials into the environment,
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solid and hazardous waste management,
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pollution prevention,
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greenhouse gas emissions,
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characteristics and composition of gasoline and diesel fuels,
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public and employee safety and health, and
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facility security.
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The specific impact of laws and regulations on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities, marketing areas, crude oil and feedstock sources and production processes. We may be required to make expenditures to modify operations, install pollution control equipment, perform site cleanups or curtail operations that could materially and adversely affect our business, financial condition, results of operations and cash flows.
We believe the issue of climate change will likely continue to receive scientific and political attention, with the potential for further laws and regulations that could affect our operations. The U.S. pledge in 2009, as part of the Copenhagen Accord, to reduce greenhouse gas emissions 17 percent below 2005 levels by 2020 remains in effect and was reaffirmed in the President’s 2013 Climate Action Plan. Meetings of the United Nations Climate Change Conference, however, have produced no legally binding emission reduction requirements on the U.S. Also in 2009, the EPA issued an “endangerment finding” that greenhouse gas emissions contribute to air pollution that endangers public health and welfare. Related to the endangerment finding, in April 2010, the EPA finalized a greenhouse gas emission standard for mobile sources (cars and other light duty vehicles). The endangerment finding, the mobile source standard and the EPA’s determination that greenhouse gases are subject to regulation under the Clean Air Act resulted in permitting of greenhouse gas emissions at stationary sources, but as a result of the EPA’s “tailoring rule,” permit applicability was limited to larger sources such as refineries. Legal challenges were filed against these EPA actions. In June 2014, the U.S. Supreme Court ruled that the Clean Air Act Prevention of Significant Deterioration program for new and modified stationary sources is not triggered by greenhouse gas emissions alone. The U.S. Supreme Court did, however, uphold the requirement for new or modified stationary sources that will also emit a criteria pollutant to control greenhouse gas emissions through Best Available Control Technology. Implementing Best Available Control Technology may result in increased costs to our operations.
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In 2013, the Obama administration developed the social cost of carbon (“SCC”). The SCC is to be used by the EPA and other federal agencies in regulatory cost-benefit analyses to take into account alleged broad economic consequences associated with changes to emissions of greenhouse gases. The SCC was first issued in 2010. In 2013, the Obama administration significantly increased the estimate to $36 per ton. In response to the regulated community and Congress’ critiques of how the SCC was developed, the Office of Management and Budget provided an opportunity to comment on the SCC, but ultimately did not make any significant revisions. In December 2014, the White House Council on Environmental Quality (“CEQ”) issued new draft guidance for assessing greenhouse gas emissions under the National Environmental Policy Act (“NEPA”), adding for the first time language that requires that analyses also include the impact of climate change on projects, including using the SCC when analyzing costs and benefits of a project. While the impact of a higher SCC in future regulations is not known at this time, it may result in increased costs to our operations.
In 2013, the EPA proposed carbon emission standards for new power plants built in the future. In June 2014, the EPA proposed the Clean Power Plan, which would reduce carbon emissions from existing power plants. Through the Plan, the EPA proposes to reduce nationwide carbon emissions from the power generation sector by 30 percent below 2005 levels. These standards, if finalized, could increase our electricity costs and potentially reduce the reliability of our electricity supply.
In the future, Congress may again consider legislation on greenhouse gas emissions or a carbon tax. Other measures to address greenhouse gas emissions are in various phases of review or implementation in the U.S. These measures include state actions to develop statewide or regional programs to impose emission reductions. Private party litigation is pending against federal and certain state governmental entities seeking additional greenhouse gas emission reductions beyond those currently being undertaken. These actions could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls and costs to administer any carbon trading or tax programs implemented. Although uncertain, these developments could increase our costs, reduce the demand for the products we sell and create delays in our obtaining air pollution permits for new or modified facilities.
In November 2014, the EPA proposed a tightening of the primary (health) ozone National Ambient Air Quality Standards (“NAAQS”) to within the range of 65 to 70 parts per billion (“ppb”), while accepting comments on levels as low as 60 ppb and an option of maintaining the current ozone level of 75 ppb. In addition, the EPA is asking for comment on a new secondary (welfare) ozone NAAQS using a three-month seasonal index. The final rule is expected to be promulgated in late 2015. If timely finalized, the EPA would then implement a revised ozone NAAQS with attainment and nonattainment designations by late 2017, using 2014-2016 air quality monitor data. A lower primary ozone standard may not by attainable in many areas and could result in the cancellation or delay of capital projects at our facilities.
The EISA, among other things, sets a target of 35 miles per gallon for the combined fleet of cars and light trucks in the U.S. by model year 2020 and contains a second Renewable Fuel Standard commonly referred to as RFS2. In August 2012, the EPA and the National Highway Traffic Safety Administration jointly adopted regulations that establish average industry fleet fuel economy standards for passenger cars and light trucks of up to 41 miles per gallon by model year 2021 and average fleet fuel economy standards of up to 49.7 miles per gallon by model year 2025 (the standards from 2022 to 2025 are the government’s current estimate but will require further rulemaking). Increases in fuel mileage standards and the increased use of renewable fuels (including ethanol and advanced biofuels) may reduce demand for refined products. Governmental regulations encouraging the use of new or alternative fuels could also pose a competitive threat to our operations.
The RFS2 required the total volume of renewable transportation fuels sold or introduced annually in the U.S. to reach 16.55 billion gallons in 2013 and increases to 36.0 billion gallons by 2022. The RFS2 presents production and logistics challenges for both the renewable fuels and petroleum refining industries, and may continue to require additional capital expenditures or expenses by us to accommodate increased renewable fuels use. Gasoline consumption has been lower than forecasted by the EPA, which has led to concerns that the renewable fuel volumes may not be met. As a result, the EPA delayed issuance of the 2014 RFS2 standards and has not finalized the 2015 renewable fuel volumes as required by the November 30, 2014 statutory deadline. The advanced biofuels program, a subset of the RFS2 requirements, creates uncertainties and presents challenges of supply, and may require that we and other refiners and other obligated parties purchase credits from the EPA to meet our obligations.
Tax incentives and other subsidies have also made renewable fuels more competitive with refined products than they otherwise would have been, which may further reduce refined product margins.
On March 3, 2014, the EPA signed the final Tier 3 fuel standards. The final Tier 3 fuel standards require, among other things, a lower annual average sulfur level in gasoline to no more than 10 parts per million (“ppm”) beginning in calendar year 2017. In addition, gasoline refiners and importers may not exceed a maximum per-gallon sulfur standard of 80 ppm, while retailers may not exceed a maximum per-gallon sulfur standard of 95 ppm. We anticipate that we will spend an estimated $750 million to $1 billion between 2014 and 2019 for capital expenditures necessary to comply with these standards.
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We have in the past owned or operated, and currently own and operate, convenience stores and other locations with USTs in various states. The operation of USTs poses risks, including soil and groundwater contamination, at our previously or currently operated locations. Such contamination could result in substantial cleanup costs, fines or civil liabilities.
We have in the past and will continue to dispose of various wastes at lawful disposal sites. Environmental laws, including CERCLA, and similar state laws can impose liability for the entire cost of cleanup on any responsible party, without regard to negligence or fault, and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when performed.
Any failure by us to comply with existing or future laws or regulations could result in the imposition of administrative, civil or criminal penalties, injunctions limiting our operations, investigatory or remedial liabilities or impediments to construction of additional facilities or equipment.
Plans we may have to expand existing assets or construct new assets are subject to risks associated with societal and political pressures and other forms of opposition to the future development, transportation and use of carbon-based fuels. Such risks could adversely impact our business and ability to realize certain growth strategies.
Our anticipated growth and planned expenditures are based upon the assumption that societal sentiment will continue to enable and existing regulations will remain intact to allow for the future development, transportation and use of carbon-based fuels. A portion of our growth strategy is dependent on our ability to expand existing assets and to construct additional assets. However, policy decisions relating to the production, refining, transportation and marketing of carbon-based fuels are subject to political pressures and the influence of environmental and other special interest groups. The construction of new refinery processing units or crude oil or refined products pipelines, or the extension or expansion of existing assets, involve numerous political and legal uncertainties, many of which may cause significant delays or cost increases and most of which are beyond our control. Delays or cost increases related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results, thereby limiting our ability to grow and generate cash flows.
Large capital projects can take many years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns. If we are unable to complete capital projects at their expected costs and in a timely manner, or if the market conditions assumed in our project economics deteriorate, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving engineering, procurement and construction of facilities could materially adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may arise as a result of unpredictable factors, many of which are beyond our control, including:
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denial of or delay in receiving requisite regulatory approvals and/or permits;
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unplanned increases in the cost of construction materials or labor;
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disruptions in transportation of components or construction materials;
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adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
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market-related increases in a project’s debt or equity financing costs; and
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nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
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Any one or more of these factors could have a significant impact on our ongoing capital projects. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our business, financial condition, results of operations and cash flows.
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The availability of crude oil and increases in crude oil prices may reduce profitability and refining and marketing gross margins.
The profitability of our operations depends largely on the difference between the cost of crude oil and other feedstocks we refine and the selling prices we obtain for refined products. A portion of our crude oil is purchased from various foreign national oil companies, producing companies and trading companies, including suppliers from Canada, the Middle East and various other international locations. The market for crude oil and other feedstocks is largely a world market. We are, therefore, subject to the attendant political, geographic and economic risks of such a market. If one or more major supply sources were temporarily or permanently eliminated, we believe adequate alternative supplies of crude oil would be available, but it is possible we would be unable to find alternative sources of supply. If we are unable to obtain adequate crude oil volumes or are able to obtain such volumes only at unfavorable prices, our operations, sales of refined products and refining and marketing gross margins could be adversely affected, materially and adversely impacting our business, financial condition, results of operations and cash flows.
Worldwide political and economic developments could materially and adversely impact our business, financial condition, results of operations and cash flows.
In addition to impacting crude oil and other feedstock supplies, political and economic factors in global markets could have a material adverse effect on us in other ways. Hostilities in the Middle East or the occurrence or threat of future terrorist attacks could adversely affect the economies of the U.S. and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects. These risks could lead to increased volatility in prices for refined products. Additionally, these risks could increase instability in the financial and insurance markets and make it more difficult and/or costly for us to access capital and to obtain the insurance coverage that we consider adequate. Additionally, tax policy, legislative or regulatory action and commercial restrictions could reduce our operating profitability. For example, the U.S. government could prevent or restrict exports of refined products or the conduct of business with certain foreign countries.
Compliance with and changes in tax laws could materially and adversely impact our financial condition, results of operations and cash flows.
We are subject to extensive tax liabilities, including federal and state income taxes and transactional taxes such as excise, sales and use, payroll, franchise, withholding and property taxes. New tax laws and regulations and changes in existing tax laws and regulations could result in increased expenditures by us for tax liabilities in the future and could materially and adversely impact our financial condition, results of operations and cash flows. Additionally, many tax liabilities are subject to periodic audits by taxing authorities, and such audits could subject us to interest and penalties.
Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could adversely affect our business.
The U.S. government has issued warnings that energy assets in general, including the nation’s refining, pipeline and terminal infrastructure, may be future targets of terrorist organizations. The threat of terrorist attacks has subjected our operations to increased risks. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business. Similarly, any future terrorist attacks that severely disrupt the markets we serve could materially and adversely affect our results of operations, financial position and cash flows.
An easing or lifting of the U.S. crude oil export ban could adversely affect crack spreads or crude oil price differentials and have a material adverse effect on our business, financial condition, results of operations and cash flows.
Since the 1970s, the U.S. has restricted the ability of producers to export domestic crude oil. As total crude oil production has increased in the U.S. in recent years, primarily due to the increase in shale crude oil production, there have been increasing calls by crude oil producers and others for an easing or lifting of the crude oil export ban. If the export ban were to be significantly eased or lifted, the price of domestic crude oil would likely rise, potentially impacting crack spreads and price differentials between domestic and foreign crude oils. A deterioration of crack spreads or price differentials between domestic and foreign crude oils could have a material adverse effect on our business, financial condition, results or operations and cash flows.
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Risks Relating to Ownership of Our Common Stock
Provisions in our corporate governance documents could operate to delay or prevent a change in control of our company, dilute the voting power or reduce the value of our capital stock or affect its liquidity.
The existence of some provisions within our restated certificate of incorporation and amended and restated bylaws could discourage, delay or prevent a change in control of us that a stockholder may consider favorable. These include provisions:
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providing that our board of directors fixes the number of members of the board;
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providing for the division of our board of directors into three classes with staggered terms;
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providing that only our board of directors may fill board vacancies;
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limiting who may call special meetings of stockholders;
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prohibiting stockholder action by written consent, thereby requiring stockholder action to be taken at a meeting of the stockholders;
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establishing advance notice requirements for nominations of candidates for election to our board of directors or for proposing matters that can be acted on by stockholders at stockholder meetings;
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establishing supermajority vote requirements for certain amendments to our restated certificate of incorporation and stockholder proposals for amendments to our amended and restated bylaws;
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providing that our directors may only be removed for cause;
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authorizing a large number of shares of common stock that are not yet issued, which would allow our board of directors to issue shares to persons friendly to current management, thereby protecting the continuity of our management, or which could be used to dilute the stock ownership of persons seeking to obtain control of us; and
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authorizing the issuance of “blank check” preferred stock, which could be issued by our board of directors to increase the number of outstanding shares and thwart a takeover attempt.
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We believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors time to assess any acquisition proposal, and are not intended to make us immune from takeovers. However, these provisions apply even if the offer may be considered beneficial by some stockholders and could delay or prevent an acquisition.
Our restated certificate of incorporation also authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designation, powers, preferences and relative, participating, optional and other special rights, including preferences over our common stock respecting dividends and distributions, as our board of directors generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock. For example, we could grant holders of preferred stock the right to elect some number of our board of directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of our common stock.
Finally, to facilitate compliance with the Maritime Laws, our restated certificate of incorporation limits the aggregate percentage ownership by non-U.S. citizens of our common stock or any other class of our capital stock to 23 percent of the outstanding shares. We may prohibit transfers that would cause ownership of our common stock or any other class of our capital stock by non-U.S. citizens to exceed 23 percent. Our restated certificate of incorporation also authorizes us to effect any and all measures necessary or desirable to monitor and limit foreign ownership of our common stock or any other class of our capital stock. These limitations could have an adverse impact on the liquidity of the market for our common stock if holders are unable to transfer shares to non-U.S. citizens due to the limitations on ownership by non-U.S. citizens. Any such limitation on the liquidity of the market for our common stock could adversely impact the market price of our common stock.
37
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The location and general character of our refineries, convenience stores, pipeline systems and other important physical properties have been described by segment under Item 1. Business and are incorporated herein by reference. The plants and facilities have been constructed or acquired over a period of years and vary in age and operating efficiency. In addition, we believe that our properties and facilities are adequate for our operations and that our facilities are adequately maintained. As of
December 31, 2014
, we were the lessee under a number of cancellable and noncancellable leases for certain properties, including land and building space, office equipment, storage facilities and transportation equipment. See Item 8. Financial Statements and Supplementary Data – Note
25
for additional information regarding our leases.
Item 3. Legal Proceedings
We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below.
Litigation
We are a party to a number of lawsuits and other proceedings and cannot predict the outcome of every such matter with certainty. While it is possible that an adverse result in one or more of the lawsuits or proceedings in which we are a defendant could be material to us, based upon current information and our experience as a defendant in other matters, we believe that these lawsuits and proceedings, individually or in the aggregate, will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Kentucky Emergency Pricing Litigation
In May 2007, the Kentucky attorney general filed a lawsuit against us and Marathon Oil in state court in Franklin County, Kentucky for alleged violations of Kentucky’s emergency pricing and consumer protection laws following Hurricanes Katrina and Rita in 2005. The lawsuit alleges that we overcharged customers by $89 million during September and October 2005. The complaint seeks disgorgement of these sums, as well as penalties, under Kentucky’s emergency pricing and consumer protection laws. We are vigorously defending this litigation. We believe that this is the first lawsuit for damages and injunctive relief under the Kentucky emergency pricing laws to progress this far and it contains many novel issues. In May 2011, the Kentucky attorney general amended his complaint to include a request for immediate injunctive relief as well as unspecified damages and penalties related to our wholesale gasoline pricing in April and May 2011 under statewide price controls that were activated by the Kentucky governor on April 26, 2011 and which have since expired. The court denied the attorney general’s request for immediate injunctive relief, and the remainder of the 2011 claims likely will be resolved along with those dating from 2005. If the lawsuit is resolved unfavorably in its entirety, it could materially impact our consolidated results of operations, financial position or cash flows. However, management does not believe the ultimate resolution of this litigation will have a material adverse effect.
Environmental Proceedings
During 2001, we entered into a New Source Review consent decree and settlement of alleged Clean Air Act and other violations with the EPA covering our refineries. The settlement committed us to specific control technologies and implementation schedules for environmental expenditures and improvements to our refineries, which are now complete. We are working with the EPA to terminate the New Source Review consent decree.
In January 2011, the EPA notified us of alleged violations of various statutory and regulatory provisions related to motor fuels, some of which we had previously self-reported to the EPA. Subsequently, we self-reported four additional alleged Clean Air Act violations related to motor fuels to the EPA. In July 2014, we tentatively agreed to pay a $2.75 million civil penalty as well as undertake certain projects to reduce emissions. In August and December 2014, we self-reported three similar alleged violations to the EPA. The EPA has agreed to include these incidents in the consent decree and increased the civil penalty demand to $2.9 million. We believe the ultimate resolution of this matter will not have a material impact on our consolidated results of operations, financial position or cash flows.
We have been subject to a pending enforcement matter with the Illinois Environmental Protection Agency and the Illinois attorney general’s office since 2002 concerning self-reporting of possible emission exceedences and permitting issues related to storage tanks at the Robinson, Illinois refinery. As a result of these allegations, we tentatively agreed to pay $150,000 civil penalty and undertake a supplemental environmental project involving the installation of ambient air monitors at the refinery.
38
The consent order is not yet finalized, but the ultimate resolution of this matter will not have a material impact on our consolidated results of operations, financial position or cash flows.
On January 3, 2013, the Louisiana Department of Environmental Quality (“LDEQ”) issued a consolidated compliance order and notice of potential penalty alleging violations related to self-reported air emission events occurring at our Garyville, Louisiana refinery between the years of 2005 and 2011. It is possible the LDEQ could seek penalties in excess of $100,000 in connection with this matter.
We are involved in a number of other environmental proceedings arising in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, we believe the resolution of these environmental proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Item 4. Mine Safety Disclosures
Not applicable.
39
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the NYSE and traded under the symbol “MPC.” As of
February 13, 2015
, there were
37,906
registered holders of our common stock.
The following table reflects intraday high and low sales prices of and dividends declared on our common stock by quarter:
|
|
2014
|
2013
|
|||||||||||||||||||||
|
Dollars per share
|
High Price
|
Low Price
|
Dividends
|
High Price
|
Low Price
|
Dividends
|
|||||||||||||||||
|
Quarter 1
|
$
|
94.88
|
|
$
|
80.68
|
|
$
|
0.42
|
|
$
|
92.73
|
|
$
|
60.04
|
|
$
|
0.35
|
|
|||||
|
Quarter 2
|
97.70
|
|
77.94
|
|
0.42
|
|
90.54
|
|
69.31
|
|
0.35
|
|
|||||||||||
|
Quarter 3
|
92.89
|
|
75.68
|
|
0.50
|
|
76.58
|
|
62.51
|
|
0.42
|
|
|||||||||||
|
Quarter 4
|
97.94
|
|
74.64
|
|
0.50
|
|
91.95
|
|
61.32
|
|
0.42
|
|
|||||||||||
|
Year
|
97.94
|
|
74.64
|
|
1.84
|
|
92.73
|
|
60.04
|
|
1.54
|
|
|||||||||||
Dividends
Our board of directors intends to declare and pay dividends on our common stock based on our financial condition and consolidated results of operations. On
January 31, 2015
, our board of directors approved a
50 cent
per share dividend, payable
March 10, 2015
to stockholders of record at the close of business on
February 18, 2015
.
Dividends on our common stock are limited to our legally available funds.
Issuer Purchases of Equity Securities
The following table sets forth a summary of our purchases during the quarter ended
December 31, 2014
, of equity securities that are registered by MPC pursuant to Section 12 of the Securities Exchange Act of 1934, as amended:
|
Period
|
Total Number
of Shares
Purchased
(a)
|
Average
Price Paid
per Share
(b)
|
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans
or Programs
|
Maximum Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans
or Programs
(c)
|
|||||||||
|
10/01/14-10/31/14
|
835,416
|
|
$
|
82.41
|
|
834,500
|
|
$
|
2,339,234,812
|
|
|||
|
11/01/14-11/30/14
|
4,948,398
|
|
93.36
|
|
4,948,217
|
|
1,877,249,784
|
|
|||||
|
12/01/14-12/31/14
|
1,657,786
|
|
91.42
|
|
1,656,562
|
|
1,725,807,942
|
|
|||||
|
Total
|
7,441,600
|
|
91.70
|
|
7,439,279
|
|
|
||||||
|
(a)
|
The amounts in this column include
916
,
181
and
1,224
shares of our common stock delivered by employees to MPC, upon vesting of restricted stock, to satisfy tax withholding requirements in
October
,
November
and
December
, respectively.
|
|
(b)
|
Amounts in this column reflect the weighted average price paid for shares purchased under our share repurchase authorizations and for shares tendered to us in satisfaction of employee tax withholding obligations upon the vesting of restricted stock granted under our stock plans. The weighted average price includes commissions paid to brokers on shares purchased under our share repurchase authorizations.
|
|
(c)
|
The $2.0 billion share repurchase authorization announced on September 26, 2013 was exhausted during the fourth quarter of 2014. On July 30, 2014, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization through July 31, 2016, resulting in $8.0 billion of total share repurchase authorizations since January 1, 2012. As of December 31, 2014, we have purchased a total of
$6.27 billion
of our common stock under repurchase authorizations since January 1, 2012, leaving
$1.73 billion
available for repurchases.
|
40
Item 6. Selected Financial Data
Selected financial data for periods subsequent to our June 2011 Spinoff from Marathon Oil were derived from our consolidated financial statements. Selected financial data for periods prior to the Spinoff were derived from the results of the RM&T Business, which represented a combined reporting entity. The following table should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.
|
|
Year Ended December 31,
|
||||||||||||||||||
|
(In millions, except per share data)
|
2014
(a)
|
2013
(a)
|
2012
|
|
2011
|
2010
(b)
|
|||||||||||||
|
Statements of Income Data
|
|||||||||||||||||||
|
Revenues
|
$
|
97,817
|
|
$
|
100,160
|
|
$
|
82,243
|
|
$
|
78,638
|
|
$
|
62,487
|
|
||||
|
Income from operations
|
4,051
|
|
3,425
|
|
5,347
|
|
3,745
|
|
1,011
|
|
|||||||||
|
Net income
|
2,555
|
|
2,133
|
|
3,393
|
|
2,389
|
|
623
|
|
|||||||||
|
Net income attributable to MPC
|
2,524
|
|
2,112
|
|
3,389
|
|
2,389
|
|
623
|
|
|||||||||
|
Per Share Data
(c)
|
|||||||||||||||||||
|
Basic:
|
|||||||||||||||||||
|
Net income attributable to MPC per share
|
$
|
8.84
|
|
$
|
6.69
|
|
$
|
9.95
|
|
$
|
6.70
|
|
$
|
1.75
|
|
||||
|
Diluted:
|
|||||||||||||||||||
|
Net income attributable to MPC per share
|
$
|
8.78
|
|
$
|
6.64
|
|
$
|
9.89
|
|
$
|
6.67
|
|
$
|
1.74
|
|
||||
|
Dividends per share
|
$
|
1.84
|
|
$
|
1.54
|
|
$
|
1.20
|
|
0.45
|
|
—
|
|
||||||
|
Statements of Cash Flows Data
|
|||||||||||||||||||
|
Net cash provided by operating activities
|
$
|
3,110
|
|
$
|
3,405
|
|
$
|
4,492
|
|
$
|
3,309
|
|
$
|
2,217
|
|
||||
|
Additions to property, plant and equipment
|
1,480
|
|
1,206
|
|
1,369
|
|
1,185
|
|
1,217
|
|
|||||||||
|
Common stock repurchased
|
2,131
|
|
2,793
|
|
1,350
|
|
—
|
|
—
|
|
|||||||||
|
Dividends paid
|
524
|
|
484
|
|
407
|
|
160
|
|
—
|
|
|||||||||
|
|
December 31,
|
||||||||||||||||||
|
(In millions)
|
2014
(a)
|
2013
(a)
|
2012
|
2011
|
2010
|
||||||||||||||
|
Balance Sheets Data
|
|||||||||||||||||||
|
Total assets
|
$
|
30,460
|
|
$
|
28,385
|
|
$
|
27,223
|
|
$
|
25,745
|
|
$
|
23,232
|
|
||||
|
Long-term debt, including capitalized leases
(d)
|
6,637
|
|
3,396
|
|
3,361
|
|
3,307
|
|
279
|
|
|||||||||
|
Long-term debt payable to Marathon Oil and subsidiaries
(e)
|
—
|
|
—
|
|
—
|
|
—
|
|
3,618
|
|
|||||||||
|
(a)
|
On September 30, 2014, we acquired Hess’ Retail Operations and Related Assets. On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets. Data presented subsequent to these acquisitions include amounts for these operations.
|
|
(b)
|
On December 1, 2010, we disposed of our Minnesota assets. The period prior to the disposition includes amounts for those operations.
|
|
(c)
|
The number of weighted average shares for 2014, 2013 and 2012 reflect the impacts of shares of common stock repurchased under our share repurchase plans. For comparative purposes and to provide a more meaningful calculation, for basic weighted average shares we assumed the 356 million shares of common stock distributed to Marathon Oil stockholders in conjunction with the Spinoff were outstanding as of the beginning of each period prior to the Spinoff. In addition, for dilutive weighted average share calculations, we assumed the 358 million dilutive securities outstanding at June 30, 2011 were also outstanding for each period prior to the Spinoff.
|
|
(d)
|
Includes amounts due within one year. During 2011, we issued $3.0 billion aggregate principal amount of senior notes, which replaced a portion of the debt payable to Marathon Oil and subsidiaries. During 2014, we issued $1.95 billion aggregate principal amount of senior notes and entered into a $700 million term loan agreement to fund a portion of the Hess’ Retail Operations and Related Assets acquisition. Also during 2014, MPLX entered into a $250 million term loan agreement and drew upon their credit facility to fund a portion of its purchase of additional interest in Pipe Line Holdings from MPC.
|
|
(e)
|
Includes amounts due within one year owed to Marathon Oil and subsidiaries, which were repaid prior to the Spinoff.
|
41
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information included under Item 1. Business, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data.
Management’s Discussion and Analysis of Financial Condition and Results of Operations includes various forward-looking statements concerning trends or events potentially affecting our business. You can identify our forward-looking statements by words such as “anticipate,” “believe,” “estimate,” “objective,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “potential,” “seek,” “target,” “could,” “may,” “should,” “would,” “will” or other similar expressions that convey the uncertainty of future events or outcomes. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in forward-looking statements.
Corporate Overview
We are an independent petroleum refining and marketing, retail and pipeline transportation company. We currently own and operate
seven
refineries, all located in the United States, with an aggregate crude oil refining capacity of approximately
1.7
mmbpcd. Our refineries supply refined products to resellers and consumers within our market areas, including the Midwest, Gulf Coast, East Coast and Southeast regions of the United States. We distribute refined products to our customers through one of the largest private domestic fleets of inland petroleum product barges, one of the largest terminal operations in the United States, and a combination of MPC-owned and third-party-owned trucking and rail assets. We are one of the largest wholesale suppliers of gasoline and distillates to resellers within our market area.
We have two strong retail brands: Speedway
®
and Marathon
®
. We believe that Speedway LLC, a wholly-owned subsidiary, operates the second largest chain of company-owned and operated retail gasoline and convenience stores in the United States, with approximately
2,750
convenience stores in
22
states throughout the Midwest, East Coast and Southeast. The Marathon brand is an established motor fuel brand in the Midwest and Southeast regions of the United States, and is available through approximately
5,460
retail outlets operated by independent entrepreneurs in
19
states.
As of
December 31, 2014
, we owned, leased or had ownership interests in approximately
8,300
miles of crude oil and refined product pipelines to deliver crude oil to our refineries and other locations and refined products to wholesale and retail market areas. We are one of the largest petroleum pipeline companies in the United States on the basis of total volumes delivered. Overall, we are one of the largest independent petroleum product refining, marketing, retail and transportation businesses in the United States and the largest east of the Mississippi.
Our operations consist of three reportable operating segments: Refining & Marketing; Speedway; and Pipeline Transportation. Each of these segments is organized and managed based upon the nature of the products and services they offer. See Item 1. Business for additional information on our segments.
|
•
|
Refining & Marketing—refines crude oil and other feedstocks at our
seven
refineries in the Gulf Coast and Midwest regions of the United States, purchases refined products and ethanol for resale and distributes refined products through various means, including barges, terminals and trucks that we own or operate. We sell refined products to wholesale marketing customers domestically and internationally, buyers on the spot market, our Speedway business segment and to independent entrepreneurs who operate Marathon
®
retail outlets.
|
|
•
|
Speedway—sells transportation fuels and convenience products in the retail market in the Midwest, East Coast and Southeast.
|
|
•
|
Pipeline Transportation—transports crude oil and other feedstocks to our refineries and other locations, delivers refined products to wholesale and retail market areas and includes the aggregated operations of MPLX.
|
42
Executive Summary
Results
Select results for
2014
and
2013
are reflected in the following table.
|
(In millions, except per share data)
|
2014
|
2013
|
||||||
|
Income from Operations by segment
|
||||||||
|
Refining & Marketing
|
$
|
3,609
|
|
$
|
3,206
|
|
||
|
Speedway
|
544
|
|
375
|
|
||||
|
Pipeline Transportation
|
280
|
|
210
|
|
||||
|
Net income attributable to MPC
|
$
|
2,524
|
|
$
|
2,112
|
|
||
|
Net income attributable to MPC per diluted share
|
$
|
8.78
|
|
$
|
6.64
|
|
||
Net income attributable to MPC
increased $412 million, or $2.14 per diluted share,
in
2014
compared to
2013
, primarily due to our Refining & Marketing segment.
Refining & Marketing segment income from operations
increased $403 million
in
2014
compared to
2013
, primarily due to more favorable net product price realizations and higher U.S. Gulf Coast (“USGC”) and Chicago crack spreads, partially offset by narrower crude oil differentials and higher turnaround and other direct operating costs.
Speedway segment income from operations
increased $169 million
in
2014
compared to
2013
, primarily due to increases in gasoline and distillate gross margin and merchandise gross margin, partially offset by higher operating expenses. These increases were primarily attributable to the acquisition of convenience stores from Hess.
Pipeline Transportation segment income from operations
increased $70 million
in
2014
compared to
2013
, primarily due to
higher
pipeline transportation revenue and
an increase
in income from our pipeline affiliates, partially offset by
an increase
in operating expenses.
MPLX LP
In 2012, we formed MPLX, a master limited partnership, to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products. On October 31, 2012, MPLX completed its initial public offering of 19.9 million common units, which represented the sale by us of a 26.4 percent interest in MPLX.
As of
December 31, 2014
, we owned a
71.5 percent
interest in MPLX, including the
two percent
general partner interest, and we consolidate this entity for financial reporting purposes since we have a controlling financial interest.
MPLX’s initial assets consisted of a
51 percent
general partner interest in Pipe Line Holdings, which owns a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States, and a
100 percent
interest in a butane storage cavern in West Virginia. We originally retained a 49 percent limited partner interest in Pipe Line Holdings.
On May 1, 2013, we sold a
five percent
interest in Pipe Line Holdings to MPLX for
$100 million
, which was financed by MPLX with cash on hand.
On March 1, 2014, we sold MPLX a
13 percent
interest in Pipe Line Holdings for
$310 million
. MPLX financed this transaction with
$40 million
of cash on-hand and
$270 million
of borrowings on its bank revolving credit agreement.
On October 30, 2014, we announced plans to substantially accelerate the growth of MPLX, which is expected to provide unitholders an average annual distribution growth rate percentage in the mid-20s over the next five years as we build meaningful scale more quickly. We believe this increased scale provides MPLX greater flexibility to fund organic projects and to pursue acquisition opportunities.
On December 1, 2014, we sold and contributed interests in Pipe Line Holdings totaling
30.5 percent
to MPLX for
$600 million
in cash and
2.9 million
MPLX common units valued at
$200 million
. MPLX financed the sales portion of this transaction with
$600 million
of borrowings on its bank revolving credit facility.
The sales and contribution of our interests in Pipe Line Holdings to MPLX resulted in a change of our ownership in Pipe Line Holdings, but not a change in control. We accounted for these sales as transactions between entities under common control and did not record a gain or loss.
43
On December 8, 2014, MPLX completed a public offering of
3.5 million
common units at a price to the public of
$66.68
per common unit, with net proceeds of
$221 million
. MPLX used the net proceeds from this offering to repay borrowings under its bank revolving credit facility and for general partnership purposes. On December 10, 2014, we exercised our right to maintain our two percent general partner interest in MPLX by purchasing
130 thousand
general partner units for
$9 million
.
On February 12, 2015, MPLX completed its initial underwritten public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 (the “Senior Notes”). The Senior Notes were offered at a price to the public of 99.64 percent of par. The net proceeds of this offering were used to repay the amounts outstanding under its bank revolving credit facility, as well as for general partnership purposes.
The following table summarizes the cash distributions we received from MPLX during
2014
and
2013
.
|
(In millions)
|
2014
|
2013
|
||||||
|
Cash distributions received from MPLX:
|
||||||||
|
General partner distributions, including incentive distribution rights
|
$
|
4
|
|
$
|
1
|
|
||
|
Limited partner distributions
|
72
|
|
56
|
|
||||
|
Total
|
$
|
76
|
|
$
|
57
|
|
||
The market value of the
19,980,619
MPLX common units and
36,951,515
MPLX subordinated units we owned at
December 31, 2014
was
$4.18 billion
based on the
December 31, 2014
closing unit price of
$73.49
. Over time, we also believe there will be substantial value attributable to our general partnership interests.
See Item 8. Financial Statements and Supplementary Data – Note
4
for additional information on MPLX.
Acquisitions and Investments
On September 30, 2014, we acquired from Hess all of its retail locations, transport operations and shipper history on various pipelines, including approximately
40
mbpd on Colonial Pipeline, for
$2.82 billion
. We refer to these assets as “Hess’ Retail Operations and Related Assets” and substantially all of these assets are part of our Speedway segment. This acquisition significantly expands our Speedway presence from
nine
to
22
states throughout the East Coast and Southeast and is aligned with our strategy to grow higher-valued, stable cash flow businesses. This acquisition also enables us to further leverage our integrated refining and transportation operations, providing an outlet for an incremental
200
mbpd of assured sales from our refining system. The transaction was funded with a combination of debt and available cash. Our financial results and operating statistics for the periods prior to the acquisition do not include amounts for Hess’ Retail Operations and Related Assets.
In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s SAX pipeline, which will run from Flanagan, Ill. to Patoka, Ill. and is expected to be operational in late 2015. This option resulted from our agreement to be the anchor shipper on the SAX pipeline and our commitment to the Sandpiper pipeline project. During
2014
, we made contributions of
$120 million
to Illinois Extension Pipeline to fund our portion of the construction costs incurred-to-date on the SAX pipeline project.
On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for
$40 million
. The plant currently produces biodiesel, glycerin and other by-products. The capacity of the plant is approximately
60 million
gallons per year.
In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional
seven percent
interest in Explorer for
$77 million
, bringing our ownership interest to
25 percent
. Due to this increase in our ownership percentage, we now account for our investment in Explorer using the equity method of accounting and report Explorer as a related party. Explorer owns approximately 1,900 miles of refined products pipeline from Lake Charles, Louisiana to Hammond, Indiana.
In November 2013, we agreed with Enbridge Energy Partners to serve as an anchor shipper for the Sandpiper pipeline, which will run from Beaver Lodge, North Dakota to Superior, Wisconsin. We also agreed to fund
37.5 percent
of the construction of the Sandpiper pipeline project, which is currently estimated to cost $2.6 billion, of which approximately $1.0 billion is our share. We made contributions of
$192 million
during
2014
and have contributed
$216 million
since project inception. In exchange for our commitment to be an anchor shipper and our investment in the project, we will earn an approximate 27 percent equity interest in Enbridge Energy Partners’ North Dakota System when the Sandpiper pipeline is placed into service, which is expected to be in 2017. Enbridge Energy Partners’ North Dakota System currently includes approximately 240 miles of crude oil gathering pipelines connected to a transportation pipeline that is approximately 730 miles long. We will also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements.
44
On
August 1, 2013
, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in
three
ethanol companies for
$75 million
. Under the purchase agreement, we acquired an additional
24 percent
interest in TACE, bringing our ownership interest to
60 percent
; a
34 percent
interest in TAEI, which holds a
50 percent
ownership in TAME, bringing our direct and indirect ownership interest in TAME to
67 percent
; and a
40 percent
interest in TAAE, which owns an ethanol production facility in Albion, Michigan. On October 1, 2013, our ownership interest in TAAE increased to
43 percent
as a result of TAAE acquiring one of the owner’s interest. We hold a noncontrolling interest in each of these entities and account for them using the equity method of accounting since the minority owners have substantive participating rights.
On February 1, 2013, we acquired from BP the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility and a 50 mbpd allocation of space on the Colonial Pipeline. We refer to these assets as the “Galveston Bay Refinery and Related Assets.” We paid $1.49 billion for these assets, which included $935 million for inventory. Pursuant to the purchase and sale agreement, we may also be required to pay BP a contingent earnout of up to an additional $700 million over six years, subject to certain conditions. In July 2014, we paid BP
$180 million
for the first period’s contingent earnout. These assets are part of our Refining & Marketing and Pipeline Transportation segments. Our financial results and operating statistics for the periods prior to the acquisition do not include amounts for the Galveston Bay Refinery and Related Assets.
See Item 8. Financial Statements and Supplementary Data – Note
5
for additional information on these acquisitions and investments. See Item 8. Financial Statements and Supplementary Data – Note
26
for information regarding our future contributions to the SAX pipeline project and the Sandpiper pipeline project.
Share Repurchases
On July 30, 2014, our board of directors approved an additional
$2.0 billion
share repurchase authorization expiring in
July 2016
. As of
December 31, 2014
, our board of directors had approved
$8.0 billion
in total share repurchase authorizations since January 1, 2012 and we have repurchased a total of
$6.27 billion
of our common stock under these authorizations, leaving
$1.73 billion
available for repurchases. Under these authorizations, we have acquired
89 million
shares at an average cost per share of
$70.35
.
Liquidity
As of
December 31, 2014
, we had cash and cash equivalents of
$1.49 billion
and no borrowings or letters of credit outstanding under our
$2.5 billion
revolving credit agreement or
$1.3 billion
trade receivables securitization facility. As of January 31, 2015, eligible trade receivables supported borrowings of
$700 million
. MPLX had
$385 million
of borrowings outstanding under its
$1 billion
revolving credit agreement as of
December 31, 2014
.
The above discussion contains forward-looking statements with respect to the estimated construction costs, timing and completion of the Sandpiper and SAX pipeline projects and the share repurchase authorizations. Factors that could affect the estimated construction costs, timing and completion of the Sandpiper and SAX pipeline projects, include, but are not limited to, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects. Factors that could affect the share repurchase authorizations and the timing of any repurchases include, but are not limited to, business conditions, availability of liquidity and the market price of our common stock. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements.
Overview of Segments
Refining & Marketing
Refining & Marketing segment income from operations depends largely on our Refining & Marketing gross margin and refinery throughputs.
Our Refining & Marketing gross margin is the difference between the prices of refined products sold and the costs of crude oil and other charge and blendstocks refined, including the costs to transport these inputs to our refineries and the costs of products purchased for resale. The crack spread is a measure of the difference between market prices for refined products and crude oil, commonly used by the industry as a proxy for the refining margin. Crack spreads can fluctuate significantly, particularly when prices of refined products do not move in the same relationship as the cost of crude oil. As a performance benchmark and a comparison with other industry participants, we calculate Midwest (Chicago) and USGC crack spreads that we believe most closely track our operations and slate of products. LLS prices and a 6-3-2-1 ratio of products (6 barrels of LLS crude oil producing 3 barrels of unleaded regular gasoline, 2 barrels of ultra-low sulfur diesel and 1 barrel of three percent residual fuel oil) are used for these crack-spread calculations.
45
Refined product prices have historically moved relative to international crude oil prices like Brent crude. In recent years, domestic U.S. crude oils, such as WTI and LLS, traded at prices less than Brent due to the growth in U.S. crude oil production, logistical constraints and other market factors. These price discounts compared to Brent favorably impacted the LLS 6-3-2-1 crack spread. During 2011 and continuing through the first half of 2013, WTI traded at prices significantly less than Brent and LLS, which favorably impacted our Refining & Marketing gross margin. The differential between WTI and LLS significantly narrowed during the second half of 2013 with a further narrowing broadly continuing through 2014. In addition, the differential between LLS and Brent narrowed significantly during the second half of 2014. The spread between domestic crude oils and Brent could remain narrow if there is a change in existing U.S. energy policy regarding crude oil exports, or if low crude oil prices reduce U.S. crude oil production growth substantially. If either were to occur, it could reduce our Refining & Marketing gross margin.
Our refineries can process significant amounts of sour crude oil, which typically can be purchased at a discount to sweet crude oil. The amount of this discount, the sweet/sour differential, can vary significantly, causing our Refining & Marketing gross margin to differ from crack spreads based on sweet crude oil. In general, a larger sweet/sour differential will enhance our Refining & Marketing gross margin.
Future crude oil differentials will be dependent on a variety of market and economic factors, as well as U.S. energy policy.
The following table provides sensitivities showing an estimated change in annual net income due to potential changes in market conditions.
|
(In millions, after-tax)
|
|
|||
|
LLS 6-3-2-1 crack spread sensitivity
(a)
(per $1.00/barrel change)
|
$
|
450
|
|
|
|
Sweet/sour differential sensitivity
(b)
(per $1.00/barrel change)
|
200
|
|
||
|
LLS-WTI differential sensitivity
(c)
(per $1.00/barrel change)
|
100
|
|
||
|
Natural gas price sensitivity
(per $1.00/million British thermal unit change)
|
140
|
|
||
|
(a)
|
Weighted 38 percent Chicago and 62 percent USGC LLS 6-3-2-1 crack spreads and assumes all other differentials and pricing relationships remain unchanged.
|
|
(b)
|
LLS (prompt) – [delivered cost of sour crude oil: Arab Light, Kuwait, Maya, Western Canadian Select and Mars].
|
|
(c)
|
Assumes 20 percent of crude oil throughput volumes are WTI-based domestic crude oil.
|
In addition to the market changes indicated by the crack spreads, the sweet/sour differential and the discount of WTI to LLS, our Refining & Marketing gross margin is impacted by factors such as:
|
•
|
the types of crude oil and other charge and blendstocks processed;
|
|
•
|
our refinery yields;
|
|
•
|
the selling prices realized for refined products;
|
|
•
|
the impact of commodity derivative instruments used to hedge price risk;
|
|
•
|
the cost of products purchased for resale; and
|
|
•
|
the potential impact of lower of cost or market adjustments to inventories in periods of declining prices.
|
Inventories are stated at the lower of cost or market. The cost of our crude oil and refined product inventories is determined under the last in, first out (“LIFO”) method. During periods of rapidly declining prices, the LIFO cost basis of our crude oil and refined product inventories may have to be written down to market value. Despite a significant drop in refined product prices in 2014, we determined that the LIFO cost basis of our crude oil and refined product inventories was recoverable as of
December 31, 2014
. If prices decrease further in 2015, we may be required to recognize a lower of cost or market adjustment to these inventories, which totaled approximately 96 million barrels as of
December 31, 2014
.
Refining & Marketing segment income from operations is also affected by changes in refinery direct operating costs, which include turnaround and major maintenance, depreciation and amortization and other manufacturing expenses. Changes in manufacturing costs are primarily driven by the cost of energy used by our refineries, including purchased natural gas, and the level of maintenance costs. Planned major maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units, are periodically performed at each refinery. The following table lists the refineries that had significant planned turnaround and major maintenance activities for each of the last three years.
|
Year
|
Refinery
|
|
|
2014
|
Catlettsburg, Galveston Bay, Garyville and Robinson
|
|
|
2013
|
Canton, Catlettsburg, Galveston Bay, Garyville and Robinson
|
|
|
2012
|
Catlettsburg, Detroit, Garyville and Robinson
|
|
46
The table below sets forth the location and daily crude oil refining capacity of each of our refineries at December 31 of each year.
|
|
Crude Oil Refining Capacity (mbpcd)
|
||||||||
|
Refinery
|
2014
|
2013
|
2012
|
||||||
|
Garyville, Louisiana
|
522
|
|
522
|
|
522
|
|
|||
|
Galveston Bay, Texas City, Texas
(a)
|
451
|
|
451
|
|
N/A
|
|
|||
|
Catlettsburg, Kentucky
|
242
|
|
242
|
|
240
|
|
|||
|
Robinson, Illinois
|
212
|
|
212
|
|
206
|
|
|||
|
Detroit, Michigan
|
130
|
|
123
|
|
120
|
|
|||
|
Canton, Ohio
|
90
|
|
80
|
|
80
|
|
|||
|
Texas City, Texas
|
84
|
|
84
|
|
80
|
|
|||
|
Total
|
1,731
|
|
1,714
|
|
1,248
|
|
|||
|
(a)
|
We acquired the Galveston Bay refinery on February 1, 2013.
|
Speedway
Our retail marketing gross margin for gasoline and distillate, which is the price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, impacts the Speedway segment profitability. Numerous factors impact gasoline and distillate demand throughout the year, including local competition, seasonal demand fluctuations, the available wholesale supply, the level of economic activity in our marketing areas and weather conditions. Gasoline demand in PADD 2 is estimated to have grown by about half a percent in 2014 after climbing by 1.4 percent in 2013. Meanwhile, gasoline demand in PADD 1 is estimated to have grown by 1.5 percent in 2014 after a 1.5 percent decline in 2013, reversing a three-year trend of declines and returning to 2012 levels. Strong economic growth in the last three quarters of 2014 and strongly falling prices throughout the second half supported gasoline demand. Distillate demand was supported by severe winter temperatures in early 2014 and a very strong harvest season. PADD 2 distillate demand is estimated to have grown by 3.7 percent in 2014 after climbing by 1.6 percent in 2013. PADD 1 estimated distillate demand grew over five percent after climbing by 8.8 percent in 2013. Market demand increases for gasoline and distillate generally increase the product margin we can realize. The gross margin on merchandise sold at convenience stores historically has been less volatile and has contributed substantially to Speedway’s gross margin. More than half of Speedway’s gross margin was derived from merchandise sales in
2014
. Speedway’s convenience stores offer a wide variety of merchandise, including prepared foods, beverages and non-food items.
Pipeline Transportation
The profitability of our pipeline transportation operations primarily depends on tariff rates and the volumes shipped through the pipelines. A majority of the crude oil and refined product shipments on our common carrier pipelines serve our Refining & Marketing segment. In 2012, new transportation services agreements were entered into between MPC and MPLX, which resulted in higher tariff rates. The volume of crude oil that we transport is directly affected by the supply of, and refiner demand for, crude oil in the markets served directly by our crude oil pipelines. Key factors in this supply and demand balance are the production levels of crude oil by producers in various regions or fields, the availability and cost of alternative modes of transportation, the volumes of crude oil processed at refineries and refinery and transportation system maintenance levels. The volume of refined products that we transport is directly affected by the production levels of, and user demand for, refined products in the markets served by our refined product pipelines. In most of our markets, demand for gasoline and distillate peaks during the summer driving season, which extends from May through September of each year, and declines during the fall and winter months. As with crude oil, other transportation alternatives and system maintenance levels influence refined product movements.
47
Results of Operations
Consolidated Results of Operations
|
(In millions)
|
2014
|
2013
|
2014 vs. 2013 Variance
|
2012
|
2013 vs. 2012 Variance
|
|||||||||||||||
|
Revenues and other income:
|
||||||||||||||||||||
|
Sales and other operating revenues (including consumer excise taxes)
|
$
|
97,817
|
|
$
|
100,160
|
|
$
|
(2,343
|
)
|
$
|
82,243
|
|
$
|
17,917
|
|
|||||
|
Income from equity method investments
|
153
|
|
36
|
|
117
|
|
26
|
|
10
|
|
||||||||||
|
Net gain on disposal of assets
|
21
|
|
6
|
|
15
|
|
177
|
|
(171
|
)
|
||||||||||
|
Other income
|
111
|
|
52
|
|
59
|
|
46
|
|
6
|
|
||||||||||
|
Total revenues and other income
|
98,102
|
|
100,254
|
|
(2,152
|
)
|
82,492
|
|
17,762
|
|
||||||||||
|
Costs and expenses:
|
||||||||||||||||||||
|
Cost of revenues (excludes items below)
|
83,770
|
|
87,401
|
|
(3,631
|
)
|
68,668
|
|
18,733
|
|
||||||||||
|
Purchases from related parties
|
505
|
|
357
|
|
148
|
|
280
|
|
77
|
|
||||||||||
|
Consumer excise taxes
|
6,685
|
|
6,263
|
|
422
|
|
5,709
|
|
554
|
|
||||||||||
|
Depreciation and amortization
|
1,326
|
|
1,220
|
|
106
|
|
995
|
|
225
|
|
||||||||||
|
Selling, general and administrative expenses
|
1,375
|
|
1,248
|
|
127
|
|
1,223
|
|
25
|
|
||||||||||
|
Other taxes
|
390
|
|
340
|
|
50
|
|
270
|
|
70
|
|
||||||||||
|
Total costs and expenses
|
94,051
|
|
96,829
|
|
(2,778
|
)
|
77,145
|
|
19,684
|
|
||||||||||
|
Income from operations
|
4,051
|
|
3,425
|
|
|
626
|
|
5,347
|
|
(1,922
|
)
|
|||||||||
|
Net interest and other financial income (costs)
|
(216
|
)
|
(179
|
)
|
(37
|
)
|
(109
|
)
|
(70
|
)
|
||||||||||
|
Income before income taxes
|
3,835
|
|
3,246
|
|
589
|
|
5,238
|
|
(1,992
|
)
|
||||||||||
|
Provision for income taxes
|
1,280
|
|
1,113
|
|
167
|
|
1,845
|
|
(732
|
)
|
||||||||||
|
Net income
|
2,555
|
|
2,133
|
|
422
|
|
3,393
|
|
(1,260
|
)
|
||||||||||
|
Less net income attributable to noncontrolling interests
|
31
|
|
21
|
|
10
|
|
4
|
|
17
|
|
||||||||||
|
Net income attributable to MPC
|
$
|
2,524
|
|
$
|
2,112
|
|
$
|
412
|
|
$
|
3,389
|
|
$
|
(1,277
|
)
|
|||||
Net income attributable to MPC
increased $412 million in 2014 compared to 2013 and decreased $1.28 billion in 2013 compared to 2012
, primarily due to our Refining & Marketing segment income from operations, which
increased $403 million in 2014 compared to 2013 and decreased $1.89 billion in 2013 compared to 2012
. The
increase
in Refining & Marketing segment income from operations in
2014
was primarily due to
more favorable net product price realizations and higher USGC and Chicago crack spreads, partially offset by narrower crude oil differentials and higher turnaround and other direct operating costs
.
The decrease in 2013 was primarily due to
narrower crude oil differentials and lower net product price realizations, partially offset by higher refinery throughput and sales volumes
.
Sales and other operating revenues (including consumer excise taxes)
decreased $2.34 billion in 2014 compared to 2013 and increased $17.92 billion in 2013 compared to 2012
.
The decrease in 2014 was primarily due to
lower refined product sales prices, partially offset by an increase in refined product sales volumes and higher merchandise sales for our Speedway segment primarily attributable to the convenience stores acquired from Hess.
The increase in 2013 was primarily due to
higher refined product sales volumes, which were primarily associated with the acquisition of the Galveston Bay refinery in February 2013, partially offset by
a decrease
in refined product sales prices. Consolidated refined product sales
increased 52 mbpd in 2014 compared to 2013 and 468 mbpd in 2013 compared to 2012
.
Income from equity method investments
increased $117 million in 2014 compared to 2013 and $10 million in 2013 compared to 2012
.
The increase in 2014 was primarily due to
increases in income from our ethanol affiliates of $68 million and income from our pipeline affiliates of $49 million. The increase in income from our ethanol affiliates includes the affects of our acquisition of interests in TAAE, TACE and TAEI in August 2013. The higher income from our pipeline affiliates is primarily due to increases from LOOP LLC (“LOOP”) and Explorer, which is now accounted for as an equity method investment following our acquisition of an increased ownership interest in this pipeline company.
The increase in 2013 was primarily due to
an increase in income from our ethanol investments of $34 million, partially offset by a decrease in income from our investment in LOOP of $17 million. The increase in income from ethanol investments was primarily due to higher income in 2013 compared to 2012 and the acquisition of interests in TAAE, TACE and TAEI in 2013.
48
Net gain on disposal of assets
increased $15 million in 2014 compared to 2013 and decreased $171 million in 2013 compared to 2012
, primarily due to the sale of two terminals and terminal assets in 2014 and a $171 million gain recognized in the third quarter of 2012 associated with the settlement agreement with the buyer of our Minnesota assets. See Item 8. Financial Statements and Supplementary Data – Note
6
for additional information on the Minnesota assets sale and subsequent settlement agreement with the buyer.
Other income
increased $59 million in 2014 compared to 2013 and $6 million in 2013 compared to 2012
.
The increase in 2014 was primarily due to
higher gains on sales of excess Renewable Identification Numbers (“RINs”) of $74 million, partially offset by an $11 million impairment in 2014 of an investment in a company accounted for using the cost method.
The increase in 2013 was primarily due to
higher gains on sales of excess RINs and dividends received from a pipeline affiliate, partially offset by the absence of $12 million of dividends received from our preferred equity interest in the buyer of our Minnesota assets during the third quarter of 2012.
Cost of revenues
decreased $3.63 billion in 2014 compared to 2013 and increased $18.73 billion in 2013 compared to 2012
.
The decrease in 2014 was primarily due to
:
|
•
|
a decrease in refined product cost of sales of $5.01 billion, primarily due to a decrease in our average crude oil costs of $9.30 per barrel, partially offset by an increase in refined product sales volumes;
|
|
•
|
partially offset by
an increase
in refinery direct operating costs of
$913 million
, or
$1.37
per barrel of total refinery throughput, which included costs associated with significant planned turnaround activity; and
|
|
•
|
an increase in merchandise cost of sales for our Speedway segment of $327 million, primarily attributable to the convenience stores acquired from Hess.
|
The increase in 2013 was primarily due to
:
|
•
|
an increase in refined product cost of sales of $17.09 billion, primarily due to an increase in refined product sales volumes attributable to the acquisition of the Galveston Bay refinery; and
|
|
•
|
an increase
in refinery direct operating costs of
$1.62 billion
, or
$1.11
per barrel of total refinery throughput, primarily attributable to the addition of the Galveston Bay refinery, which had higher operating costs per barrel of throughput than the average of our other six refineries.
|
Purchases from related parties
increased $148 million in 2014 compared to 2013 and $77 million in 2013 compared to 2012
.
The increase in 2014 was primarily due to
acquisitions of ownership interests in TAAE in August 2013 and Explorer in March 2014, resulting in purchases from these companies totaling
$118 million
in
2014
and
$24 million
in
2013
, being reported as purchases from related parties while purchases from these companies prior to these acquisitions were reported as cost of revenues. In addition, we also had an increase in purchases from LOOP of
$45 million
in
2014
.
The increase in 2013 was primarily due to
higher ethanol volumes purchased from our ethanol investments, partially offset by lower ethanol prices and decreases in purchases from pipeline affiliates, including Centennial Pipeline LLC (“Centennial”).
Consumer excise taxes
increased $422 million in 2014 compared to 2013 and $554 million in 2013 compared to 2012
, primarily due to increases in taxable refined product sales volumes, including the effects of the acquisitions of the Galveston Bay Refinery and Related Assets and Hess’ Retail Operations and Related Assets.
Depreciation and amortization
increased $106 million in 2014 compared to 2013 and $225 million in 2013 compared to 2012
.
The increase in 2014 was primarily due to
completion of certain capital investments at our Galveston Bay refinery, an increase in the number of convenience stores in our Speedway segment and the implementation of corporate-level information technology projects, partially offset by an impairment of a light products terminal in 2013.
The increase in 2013 was primarily due to
the completion of the heavy oil upgrading and expansion project at our Detroit, Michigan refinery in late 2012 and our acquisition of the Galveston Bay Refinery and Related Assets in February 2013.
Selling, general and administrative expenses
increased $127 million in 2014 compared to 2013
, primarily due to increases in contract services, employee compensation and benefit expenses and credit card processing fees.
49
Other taxes
increased $50 million in 2014 compared to 2013 and $70 million in 2013 compared to 2012
.
The increase in 2014 was primarily due to
increases in property taxes of $30 million, payroll taxes of $27 million and environmental taxes of $11 million, partially offset by decreases in other tax expenses. These increases were attributable to a number of factors including the acquisitions of the Galveston Bay Refinery and Related Assets and Hess’ Retail Operations and Related Assets and the absence of a Federal Oil Spill Tax refund received in 2013.
The increase in 2013 was primarily due to
increases in property taxes of $41 million, payroll taxes of $21 million and sales and use tax expense of $13 million. The increases in 2013 were attributable to a number of factors including the completion of the heavy oil upgrading and expansion project at our Detroit refinery, the acquisition of the Galveston Bay Refinery and Related Assets and Speedway’s acquisition of 97 convenience stores in 2012.
Net interest and other financial costs
increased $37 million in 2014 compared to 2013 and $70 million in 2013 compared to 2012
.
The increase in 2014 was primarily due to
an increase in long-term debt related to the acquisition of Hess’ Retail Operations and Related Assets and MPLX’s acquisition of additional interest in Pipe Line Holdings.
The increase in 2013 was primarily due to
a decrease
in capitalized interest in 2013 due to the completion of the Detroit refinery heavy oil upgrading and expansion project in late 2012. We capitalized interest of
$27 million
in
2014
,
$28 million
in
2013
and
$101 million
in
2012
.
Provision for income taxes
increased $167 million in 2014 compared to 2013 and decreased $732 million in 2013 compared to 2012
, primarily due to our income before income taxes, which
increased $589 million in 2014 compared to 2013 and decreased $1.99 billion in 2013 compared to 2012
. The effective tax rates in
2014
,
2013
and
2012
are equivalent to or slightly less than the U.S. statutory rate of 35 percent primarily due to certain permanent benefit differences, including the domestic manufacturing deduction, partially offset by state and local tax expense. See Item 8. Financial Statements and Supplementary Data – Note
13
for further details.
Segment Results
Revenues are summarized by segment in the following table.
|
(In millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Refining & Marketing
|
$
|
91,734
|
|
$
|
94,910
|
|
$
|
76,710
|
|
|||
|
Speedway
|
16,932
|
|
14,475
|
|
14,243
|
|
||||||
|
Pipeline Transportation
|
597
|
|
537
|
|
459
|
|
||||||
|
Segment revenues
|
$
|
109,263
|
|
$
|
109,922
|
|
$
|
91,412
|
|
|||
|
Items included in both revenues and costs:
|
||||||||||||
|
Consumer excise taxes
|
$
|
6,685
|
|
$
|
6,263
|
|
$
|
5,709
|
|
|||
Refining & Marketing segment revenues
decreased $3.18 billion in 2014 compared to 2013 and increased $18.20 billion in 2013 compared to 2012
.
The decrease in 2014 was primarily due to
lower
refined product sales prices, partially offset by
an increase
in refined product sales volumes.
The increase in 2013 was primarily due to
an increase in refined product sales volumes related to the Galveston Bay refinery acquired in February 2013, partially offset by lower refined product selling prices. The table below shows our Refining & Marketing segment refined product sales volumes and prices.
|
|
2014
|
2013
|
2012
|
||||||||
|
Refining & Marketing segment:
|
|||||||||||
|
Refined product sales volumes (thousands of barrels per day)
(a)
|
2,125
|
|
2,075
|
|
1,599
|
|
|||||
|
Refined product sales destined for export (thousands of barrels per day)
|
275
|
|
218
|
|
123
|
|
|||||
|
Average refined product sales prices (dollars per gallon)
|
$
|
2.71
|
|
$
|
2.87
|
|
$
|
3.00
|
|
||
|
(a)
|
Includes intersegment sales and sales destined for export.
|
The table below shows the average refined product benchmark prices for our marketing areas.
|
(Dollars per gallon)
|
2014
|
2013
|
2012
|
|||||||||
|
Chicago spot unleaded regular gasoline
|
$
|
2.55
|
|
$
|
2.76
|
|
$
|
2.84
|
|
|||
|
Chicago spot ultra-low sulfur diesel
|
2.80
|
|
3.01
|
|
3.01
|
|
||||||
|
USGC spot unleaded regular gasoline
|
2.49
|
|
2.69
|
|
2.81
|
|
||||||
|
USGC spot ultra-low sulfur diesel
|
2.71
|
|
2.97
|
|
3.05
|
|
||||||
50
Refining & Marketing intersegment sales to our Speedway segment
increased $1.62 billion in 2014 compared to 2013 and $512 million in 2013 compared to 2012
, primarily due to
increases
in intersegment refined product sales volumes, partially offset by
lower
refined product sales prices. The
increase
in intersegment refined product sales volumes for 2014 was primarily due to the acquisition of convenience stores from Hess.
|
|
2014
|
2013
|
2012
|
||||||||
|
Refining & Marketing intersegment sales to Speedway:
|
|||||||||||
|
Intersegment sales (in millions)
|
$
|
10,912
|
|
$
|
9,294
|
|
$
|
8,782
|
|
||
|
Refined product sales volumes (millions of gallons)
|
3,766
|
|
2,976
|
|
2,727
|
|
|||||
|
Average refined product sales prices (dollars per gallon)
|
$
|
2.89
|
|
$
|
3.11
|
|
$
|
3.21
|
|
||
Speedway segment revenues
increased $2.46 billion in 2014 compared to 2013 and $232 million in 2013 compared to 2012
, primarily due to
increases
in gasoline and distillate sales of
$1.98 billion
and
$138 million
, respectively, and
increases
in merchandise sales of
$476 million
and
$77 million
, respectively. The
increases
in gasoline and distillate sales were primarily due to volume
increases
of
796 million gallons
and
119 million gallons
, respectively, primarily due to
increases
in the number of convenience stores, partially offset by
decreases
in gasoline and distillate selling prices of
$0.20 per gallon
and
$0.09 per gallon
, respectively. The
increases
in merchandise sales were primarily due to
increases
in the number of convenience stores and higher same store sales. The increase in the number of convenience stores for 2014 was primarily due to the acquisition of convenience stores from Hess.
The following table includes certain revenue statistics for the Speedway segment.
|
2014
|
2013
|
2012
|
|||||||||
|
Convenience stores at period-end
|
2,746
|
|
1,478
|
|
1,464
|
|
|||||
|
Gasoline & distillate sales (millions of gallons)
|
3,942
|
|
3,146
|
|
3,027
|
|
|||||
|
Average gasoline & distillate sales prices (dollars per gallon)
|
$
|
3.25
|
|
$
|
3.45
|
|
$
|
3.54
|
|
||
|
Merchandise sales (in millions)
|
$
|
3,611
|
|
$
|
3,135
|
|
$
|
3,058
|
|
||
|
Same store gasoline sales volume (period over period)
|
(0.7
|
)%
|
0.5
|
%
|
(0.8
|
)%
|
|||||
|
Same store merchandise sales (period over period)
(a)
|
5.0
|
%
|
4.3
|
%
|
7.0
|
%
|
|||||
|
(a)
|
Excludes cigarettes.
|
Pipeline Transportation segment revenue
increased $60 million in 2014 compared to 2013 and $78 million in 2013 compared to 2012
.
The increase in 2014 was primarily due to
an increase
in revenue related to volume deficiency credits and higher average tariffs received on crude oil and refined products shipped, partially offset by lower refined products and crude oil pipeline throughput volumes.
The increase in 2013 was primarily due to
higher average tariffs received on the volumes of crude oil and products shipped, higher crude oil throughput volumes and an increase in storage fees and other revenue.
The following table includes throughput volumes for the Pipeline Transportation segment.
|
|
2014
|
2013
|
2012
|
|||||
|
Pipeline Throughputs (thousands of barrels per day):
(a)
|
||||||||
|
Crude oil pipelines
|
1,241
|
|
1,293
|
|
1,191
|
|
||
|
Refined products pipelines
|
878
|
|
911
|
|
980
|
|
||
|
Total
|
2,119
|
|
2,204
|
|
2,171
|
|
||
|
(a)
|
On owned common-carrier pipelines, excluding equity method investments.
|
51
Income before income taxes and income from operations by segment are summarized in the following table.
|
(In millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Income from operations by segment:
|
||||||||||||
|
Refining & Marketing
|
$
|
3,609
|
|
$
|
3,206
|
|
$
|
5,098
|
|
|||
|
Speedway
|
544
|
|
375
|
|
310
|
|
||||||
|
Pipeline Transportation
(a)
|
280
|
|
210
|
|
216
|
|
||||||
|
Items not allocated to segments:
|
||||||||||||
|
Corporate and other unallocated items
(a)
|
(286
|
)
|
(271
|
)
|
(336
|
)
|
||||||
|
Minnesota Assets sale settlement gain
|
—
|
|
—
|
|
183
|
|
||||||
|
Pension settlement expenses
(b)
|
(96
|
)
|
(95
|
)
|
(124
|
)
|
||||||
|
Income from operations
|
4,051
|
|
3,425
|
|
5,347
|
|
||||||
|
Net interest and other financial income (costs)
|
(216
|
)
|
(179
|
)
|
(109
|
)
|
||||||
|
Income before income taxes
|
$
|
3,835
|
|
$
|
3,246
|
|
$
|
5,238
|
|
|||
|
(a)
|
Included in the Pipeline Transportation segment for
2014
,
2013
and
2012
are
$19 million
,
$20 million
and
$4 million
of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.
|
|
(b)
|
See Item 8. Financial Statements and Supplementary Data – Note
23
.
|
Refining & Marketing segment income from operations
increased $403 million in 2014 compared to 2013 and decreased $1.89 billion in 2013 compared to 2012
.
The increase in 2014 was primarily due to
more favorable net product price realizations and higher USGC and Chicago crack spreads, partially offset by narrower crude oil differentials and higher turnaround and other direct operating costs
.
The decrease in 2013 was primarily due to
narrower crude oil differentials and lower net product price realizations, partially offset by higher refinery throughput and sales volumes
.
The following table presents certain market indicators that we believe are helpful in understanding the results of our Refining & Marketing segment’s business.
|
(Dollars per barrel)
|
2014
|
2013
|
2012
|
|||||||||
|
Chicago LLS 6-3-2-1
(a)(b)
|
$
|
9.56
|
|
$
|
8.16
|
|
$
|
6.74
|
|
|||
|
USGC LLS 6-3-2-1
(a)
|
7.23
|
|
6.24
|
|
6.67
|
|
||||||
|
Blended 6-3-2-1
(a)(c)
|
8.11
|
|
6.97
|
|
6.71
|
|
||||||
|
LLS
|
96.90
|
|
107.38
|
|
111.67
|
|
||||||
|
WTI
|
92.91
|
|
98.05
|
|
94.15
|
|
||||||
|
LLS – WTI crude oil differential
(a)
|
3.99
|
|
9.33
|
|
17.52
|
|
||||||
|
Sweet/Sour crude oil differential
(a)(d)
|
6.97
|
|
8.53
|
|
12.47
|
|
||||||
|
(a)
|
All spreads and differentials are measured against prompt LLS.
|
|
(b)
|
Calculation utilizes USGC three percent residual fuel oil price as a proxy for Chicago three percent residual fuel oil price.
|
|
(c)
|
Blended Chicago/USGC crack spread is
38
/
62 percent
in
2014
,
38
/
62 percent
in
2013
and
52
/
48 percent
in
2012
based on MPC’s refining capacity by region in each period.
|
|
(d)
|
LLS (prompt) – [delivered cost of sour crude oil: Arab Light, Kuwait, Maya, Western Canadian Select and Mars].
|
Based on the market indicators above and our refinery throughputs, we estimate the following impacts on Refining & Marketing segment income from operations for
2014
compared to
2013
and for
2013
compared to
2012
:
|
•
|
The Chicago LLS 6-3-2-1 crack spread
increased $1.40 per barrel in 2014 compared to 2013 and $1.42 per barrel in 2013 compared to 2012
, which had
positive impacts on segment income of $354 million and $291 million, respectively
.
|
|
•
|
The USGC LLS 6-3-2-1 crack spread increased $0.99 per barrel in 2014 compared to 2013 which had a positive impact on segment income of $407 million. The USGC LLS 6-3-2-1 crack spread decreased $0.43 per barrel in 2013 compared to 2012. This decrease was offset by an increase in refinery throughput volumes, primarily due to the acquisition of the Galveston Bay refinery, which resulted in a positive impact to segment income of $949 million in 2013 compared to 2012.
|
52
|
•
|
The LLS-WTI crude oil differential
narrowed $5.34 per barrel in 2014 compared to 2013 and $8.19 per barrel in 2013 compared to 2012
, which had
negative impacts on segment income of $695 million and $978 million, respectively
.
|
|
•
|
The sweet/sour crude oil differential
narrowed $1.56 per barrel in 2014 compared to 2013 and $3.94 per barrel in 2013 compared to 2012
, which had
negative impacts on segment income of $489 million and $273 million, respectively
. The unfavorable impact from 2013 compared to 2012 was partially offset by higher refinery throughput and sales volumes.
|
The market indicators shown above use spot market values and an estimated mix of crude purchases and products sold. Differences in our results compared to these market indicators, including product price realizations, mix and crude costs as well as other items like refinery yields and other feedstock variances, had estimated positive impacts on Refining & Marketing segment income of
$1.73 billion
in
2014
compared to
2013
and
$298 million
in
2013
compared to
2012
. We estimate the
positive
impact for
2014
was primarily due to more favorable net product price realizations as compared to spot market values and a favorable effect from valuing year end inventories using the LIFO method of accounting. We estimate the
positive
impact for
2013
was primarily due to favorable crude oil and feedstock acquisition costs compared to market indicators, partially offset by lower product price realizations.
In the fourth quarter of 2014, we recognized a build in our crude oil and refined products inventories. For purposes of our annual LIFO inventory costing, this increase in inventory is recorded based on pricing at the beginning of 2014, which was substantially higher than fourth quarter prices. As a result, Refining & Marketing segment income for the fourth quarter reflects a favorable effect of approximately $240 million. Comparing 2014 to 2013, the favorable LIFO impact was approximately $130 million.
The following table summarizes our refinery throughputs.
|
2014
|
2013
|
2012
|
||||||
|
Refinery throughputs (
thousands of barrels per day
):
|
||||||||
|
Crude oil refined
|
1,622
|
|
1,589
|
|
1,195
|
|
||
|
Other charge and blendstocks
|
184
|
|
213
|
|
168
|
|
||
|
Total
|
1,806
|
|
1,802
|
|
1,363
|
|
||
|
Sour crude oil throughput percent
|
52
|
|
53
|
|
53
|
|
||
|
WTI-priced crude oil throughput percent
|
19
|
|
21
|
|
28
|
|
||
Total refinery throughputs
increased 439 mbpd in 2013 compared to 2012
, primarily due to the Galveston Bay refinery, which we acquired on February 1, 2013.
The following table includes certain key operating statistics for the Refining & Marketing segment.
|
2014
|
2013
|
2012
|
|||||||||
|
Refining & Marketing gross margin (dollars per barrel)
(a)
|
$
|
15.05
|
|
$
|
13.24
|
|
$
|
17.85
|
|
||
|
Refinery direct operating costs (dollars per barrel):
(b)
|
|||||||||||
|
Planned turnaround and major maintenance
|
$
|
1.80
|
|
$
|
1.20
|
|
$
|
1.00
|
|
||
|
Depreciation and amortization
|
1.41
|
|
1.36
|
|
1.44
|
|
|||||
|
Other manufacturing
(c)
|
4.86
|
|
4.14
|
|
3.15
|
|
|||||
|
Total
|
$
|
8.07
|
|
$
|
6.70
|
|
$
|
5.59
|
|
||
|
(a)
|
Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs.
|
|
(b)
|
Per barrel of total refinery throughputs.
|
|
(c)
|
Includes utilities, labor, routine maintenance and other operating costs.
|
53
Refinery direct operating costs
increased $1.37 per barrel in 2014 compared to 2013 and $1.11 per barrel in 2013 compared to 2012
, which include
increases
in planned turnaround and major maintenance costs of
$0.60
per barrel and
$0.20
per barrel, respectively, and
increases
in other manufacturing costs of
$0.72
per barrel and
$0.99
per barrel, respectively. The
increase
in planned turnaround and major maintenance costs for
2014
was primarily attributable to the Galveston Bay, Robinson and Catlettsburg refineries, partially offset by decreases at the Garyville and Canton refineries. The
increase
in planned turnaround and major maintenance costs for
2013
was primarily attributable to the Galveston Bay refinery. The
increases
in other manufacturing costs were primarily attributable to higher energy costs, catalyst expenses and routine maintenance costs for 2014 and the addition of the Galveston Bay refinery for 2013, which had higher operating costs per barrel of throughput than the average of our other six refineries.
We purchase RINs to satisfy a portion of our RFS2 compliance. Our expenses associated with purchased RINs were
$141 million
in
2014
,
$264 million
in
2013
and
$105 million
in
2012
.
The decrease in 2014 was primarily due to
decreases in the average cost of ethanol and biomass-based biodiesel RINs and decreases in our estimated advanced biofuel and ethanol obligation volumes.
The increase in 2013 was primarily due to
increases in the average cost of ethanol and biodiesel RINs.
Speedway segment income from operations
increased $169 million in 2014 compared to 2013 and $65 million in 2013 compared to 2012
, primarily due to
increases
in our gasoline and distillate gross margin of
$246 million
and
$54 million
, respectively, and
increases
in our merchandise gross margin of
$150 million
and
$30 million
, respectively, partially offset by higher operating expenses. The increases were primarily attributable to increases in the number of convenience stores, which for 2014 was primarily due to the acquisition of convenience stores from Hess. The increases in merchandise gross margin were related to a combination of higher merchandise and food sales and improved margins. The convenience stores acquired from Hess contributed $113 million to Speedway segment income from operations in 2014.
The following table includes margin statistics for the Speedway segment.
|
2014
|
2013
|
2012
|
|||||||||
|
Gasoline & distillate gross margin (dollars per gallon)
(a)
|
$
|
0.1775
|
|
$
|
0.1441
|
|
$
|
0.1318
|
|
||
|
Merchandise gross margin (in millions)
|
$
|
975
|
|
$
|
825
|
|
$
|
795
|
|
||
|
Merchandise gross margin percent
|
27.0
|
%
|
26.3
|
%
|
26.0
|
%
|
|||||
|
(a)
|
The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillate sales volume.
|
Pipeline Transportation segment income from operations
increased $70 million in 2014 compared to 2013 and decreased $6 million in 2013 compared to 2012
.
The increase in 2014 was primarily due to
higher
pipeline transportation revenue and
an increase
in income from our pipeline affiliates, which was primarily attributable to our investment in LOOP, partially offset by
an increase
in operating expenses primarily attributable to the proposed Cornerstone pipeline project and pipeline maintenance costs.
The decrease in 2013 was primarily due to
higher operating expenses and depreciation and lower pipeline affiliate income, partially offset by higher transportation revenue. The higher expenses and revenues were primarily attributable to the formation of MPLX.
Corporate and other unallocated expenses
increased $15 million in 2014 compared to 2013 and decreased $65 million in 2013 compared to 2012
, primarily due to costs incurred in connection with the acquisition of Hess’ Retail Operations and Related Assets in 2014 and lower unallocated employee benefit expenses and lower employee incentive compensation expenses in 2013 compared to 2012.
We recognized a gain of $183 million in 2012 associated with the settlement agreement with the buyer of our Minnesota assets, which included $86 million of the deferred gain that was recorded when the sale transaction was originally closed. See Item 8. Financial Statements and Supplementary Data – Note
6
for additional information on the Minnesota assets sale and subsequent settlement with the buyer.
We recorded pretax pension settlement expenses of
$96 million
in
2014
,
$95 million
in
2013
and
$124 million
in
2012
resulting from the level of employee lump sum retirement distributions that occurred during these years.
54
Liquidity and Capital Resources
Cash Flows
Our cash and cash equivalents balance was
$1.49 billion
at
December 31, 2014
compared to
$2.29 billion
at
December 31, 2013
. Net cash provided by (used in) operating activities, investing activities and financing activities for the past three years is presented in the following table.
|
(In millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Net cash provided by (used in):
|
||||||||||||
|
Operating activities
|
$
|
3,110
|
|
$
|
3,405
|
|
$
|
4,492
|
|
|||
|
Investing activities
|
(4,543
|
)
|
(2,756
|
)
|
(1,452
|
)
|
||||||
|
Financing activities
|
635
|
|
(3,217
|
)
|
(1,259
|
)
|
||||||
|
Total
|
$
|
(798
|
)
|
$
|
(2,568
|
)
|
$
|
1,781
|
|
|||
Net cash provided by operating activities
decreased
$295 million
in
2014
compared to
2013
, primarily due to
unfavorable
changes in working capital of
$892 million
compared to 2013, partially offset by an
increase
in net income of
$422 million
and non-cash income adjustments of
$175 million
. Net cash provided by operating activities decreased $1.09 billion in 2013 compared to 2012, primarily due to decreases in net income of $1.26 billion and non-cash income adjustments of $453 million, partially offset by favorable changes in working capital of $626 million compared to 2012.
For
2014
, changes in working capital were a net
$694 million
use
of cash, primarily due to
a decrease
in accounts payable and accrued liabilities and
an increase
in inventories, partially offset by
a decrease
in current receivables. Changes from
December 31, 2013
to
December 31, 2014
per the consolidated balance sheets, excluding the impact of acquisitions, were as follows:
|
•
|
Accounts payable
decreased
$1.65 billion
from year-end
2013
, primarily due to lower crude oil payable prices, partially offset by higher crude oil payable volumes.
|
|
•
|
Inventories
increased
$796 million from year-end
2013
, primarily due to higher refined product and crude oil inventory volumes.
|
|
•
|
Current receivables
decreased
$1.63 billion from year-end
2013
, primarily due to lower refined product and crude oil receivable prices.
|
For 2013, changes in working capital were a net $198 million source of cash, primarily due to an increase in accounts payable and accrued liabilities, partially offset by increases in current receivables and inventory volumes. Accounts payable increased $1.45 billion from year-end 2012, primarily due to higher crude oil payable volumes, and current receivables increased $949 million from year-end 2012, primarily due to higher refined product receivable volumes attributable to an increase in refined product sales volumes. Both of these increases are associated with the Galveston Bay refinery acquired in February 2013. Changes in inventories were a $305 million use of cash in 2013, primarily due to higher refined product and crude oil inventory volumes.
For 2012, changes in working capital were a net $428 million use of cash, primarily due to a decrease in accounts payable and accrued liabilities resulting primarily from reductions in crude oil prices and payable volumes, partially offset by a decrease in current receivables resulting primarily from reductions in crude oil prices and receivable volumes.
Cash flows used in investing activities increased
$1.79 billion
in
2014
compared to
2013
and
$1.30 billion
in
2013
compared to 2012. The investing activity is further discussed below.
55
The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. A reconciliation of additions to property, plant and equipment to total capital expenditures and investments follows for each of the last three years.
|
(In millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Additions to property, plant and equipment per consolidated statements of cash flows
|
$
|
1,480
|
|
$
|
1,206
|
|
$
|
1,369
|
|
|||
|
Non-cash additions to property, plant and equipment
|
4
|
|
—
|
|
—
|
|
||||||
|
Asset retirement expenditures
|
2
|
|
—
|
|
—
|
|
||||||
|
Increase (decrease) in capital accruals
|
95
|
|
73
|
|
(117
|
)
|
||||||
|
Investments in equity method investees
|
413
|
|
124
|
|
28
|
|
||||||
|
Total capital expenditures and investments before acquisitions
|
1,994
|
|
1,403
|
|
1,280
|
|
||||||
|
Acquisitions
(a)
|
2,744
|
|
1,386
|
|
180
|
|
||||||
|
Total capital expenditures and investments
|
$
|
4,738
|
|
$
|
2,789
|
|
$
|
1,460
|
|
|||
|
(a)
|
The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment and intangibles. See Item 8. Financial Statements and Supplementary Data – Note
5
for further details.
|
Capital expenditures and investments for each of the last three years are summarized by segment below.
|
(In millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Capital expenditures and investments:
(a)(b)
|
||||||||||||
|
Refining & Marketing
|
$
|
1,104
|
|
$
|
2,094
|
|
$
|
705
|
|
|||
|
Speedway
|
2,981
|
|
296
|
|
340
|
|
||||||
|
Pipeline Transportation
|
543
|
|
234
|
|
211
|
|
||||||
|
Corporate and Other
(c)
|
110
|
|
165
|
|
204
|
|
||||||
|
Total
|
$
|
4,738
|
|
$
|
2,789
|
|
$
|
1,460
|
|
|||
|
(a)
|
Capital expenditures include changes in capital accruals.
|
|
(b)
|
Includes
$2.71 billion
in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and
$1.36 billion
in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Item 8. Financial Statements and Supplementary Data – Note
5
.
|
|
(c)
|
Includes capitalized interest of
$27 million
,
$28 million
and
$101 million
for
2014
,
2013
and
2012
, respectively.
|
The acquisition of Hess’ Retail Operations and Related Assets comprised
58 percent
of our total capital spending in 2014. The acquisition of the Galveston Bay Refinery and Related Assets comprised
49 percent
of our total capital spending in 2013. The Detroit refinery heavy oil upgrading and expansion project, which we completed in 2012, comprised 46 percent (excluding capitalized interest associated with this project) of our Refining & Marketing segment capital spending in 2012.
Cash provided by disposal of assets totaled
$27 million
,
$16 million
and
$53 million
in
2014
,
2013
and
2012
, respectively. The $53 million of cash from asset disposals in 2012 primarily included proceeds from a settlement agreement with the buyer of our Minnesota assets.
Net investments were a
$404 million
use
of cash in
2014
compared to a
$74 million
use
of cash in
2013
and a
$51 million
source
of cash in
2012
. The change in
2014
compared to
2013
was primarily due to increases in contributions to the Sandpiper and SAX pipeline projects of $287 million and our investment in Explorer of
$77 million
, partially offset by a return of capital from our ethanol affiliates of $9 million. The change in
2013
compared to
2012
was primarily due to investments in our ethanol affiliates of
$75 million
and the Sandpiper pipeline project of $24 million.
Financing activities were a
$635 million
source
of cash in
2014
, a
$3.22 billion
use
of cash in
2013
and a
$1.26 billion
use
of cash in
2012
. The sources of cash primarily consisted of net long-term debt borrowings in 2014 and proceeds from the issuance of MPLX common units in 2014 and 2012. The uses of cash in all three years primarily consisted of common stock repurchases through open market purchases and our ASR programs and dividend payments.
Long-term debt borrowings and repayments were a net
$3.25 billion
source
of cash in
2014
compared to a
$21 million
use
of cash in
2013
and a
$17 million
use
of cash in
2012
. During
2014
, we issued
$1.95 billion
aggregate principal amount of senior unsecured notes and borrowed
$700 million
under a term loan credit agreement to finance the acquisition of Hess’ Retail Operations and Related Assets. In addition, MPLX had net borrowings of $635 million under its revolving credit agreement and term loan agreement. See Item 8. Financial Statements and Supplementary Data – Note
20
for additional information on our long-term debt.
56
Cash used in common stock repurchases totaled
$2.13 billion
in
2014
,
$2.79 billion
in
2013
and
$1.35 billion
in
2012
associated with the share repurchase plans authorized by our board of directors. The table below summarizes our total share repurchases. See Item 8. Financial Statements and Supplementary Data – Note
10
for further discussion of the share repurchase plans.
|
(In millions, except per share data)
|
2014
|
2013
|
2012
|
||||||||
|
Number of shares repurchased
(a)
|
24
|
|
37
|
|
28
|
|
|||||
|
Cash paid for shares repurchased
|
$
|
2,131
|
|
$
|
2,793
|
|
$
|
1,350
|
|
||
|
Effective average cost per delivered share
|
$
|
88.63
|
|
$
|
76.14
|
|
$
|
46.73
|
|
||
|
(a)
|
Shares repurchased in 2013 includes
1 million
shares received under the November 2012 ASR program, which were paid for in 2012.
|
Cash used in dividend payments totaled
$524 million
in
2014
,
$484 million
in
2013
and
$407 million
in
2012
. The increases were primarily due to increases in our base dividend, partially offset by a decrease in the number of outstanding shares of our common stock as a result of share repurchases. Dividends per share were
$1.84
in
2014
,
$1.54
in
2013
and
$1.20
in 2012.
Cash proceeds from the issuance of MPLX common units were $221 million in 2014 and $407 million in 2012. The initial public offering in 2012 represented the sale of a 26.4 percent interest in MPLX. See Item 8. Financial Statements and Supplementary Data – Note
4
for further discussion of MPLX.
Derivative Instruments
See Item 7A. Quantitative and Qualitative Disclosures about Market Risk for a discussion of derivative instruments and associated market risk.
Capital Resources
Our liquidity totaled
$5.27 billion
at
December 31, 2014
consisting of:
|
December 31, 2014
|
||||||||||||
|
(In millions)
|
Total Capacity
|
Outstanding Borrowings
|
Available
Capacity
|
|||||||||
|
Revolving credit agreement
(a)
|
$
|
2,500
|
|
$
|
—
|
|
$
|
2,500
|
|
|||
|
Trade receivables securitization facility
(b)
|
1,280
|
|
—
|
|
1,280
|
|
||||||
|
Total
|
$
|
3,780
|
|
$
|
—
|
|
$
|
3,780
|
|
|||
|
Cash and cash equivalents
|
1,494
|
|
||||||||||
|
Total liquidity
|
$
|
5,274
|
|
|||||||||
|
(a)
|
Excludes MPLX’s
$1 billion
revolving credit agreement, which had
$385 million
of borrowings outstanding as of
December 31, 2014
.
|
|
(b)
|
Availability under our $1.3 billion trade receivables securitization facility is a function of refined product selling prices, which will be lower in a sustained lower price environment. As of January 31, 2015, eligible trade receivables supported borrowings of
$700 million
.
|
Because of the alternatives available to us, including internally generated cash flow and access to capital markets, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements, including capital spending programs, the repurchase of shares of our common stock, dividend payments, defined benefit plan contributions, repayment of debt maturities and other amounts that may ultimately be paid in connection with contingencies.
MPC Revolving Credit Agreement
– We have a
$2.5 billion
unsecured revolving credit agreement (“Credit Agreement”) in place with a maturity date of September 14, 2017. The Credit Agreement includes letter of credit issuing capacity of up to
$2.0 billion
and swingline loan capacity of up to
$100 million
. We may increase our borrowing capacity under the Credit Agreement by up to an additional
$500 million
, subject to certain conditions including the consent of the lenders whose commitments would be increased. In addition, the maturity date may be extended for up to
two
additional
one
-year periods subject to the approval of lenders holding greater than
50 percent
of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.
Borrowings under the Credit Agreement bear interest at either the Adjusted LIBO Rate (as defined in the Credit Agreement) plus a margin or the Alternate Base Rate (as defined in the Credit Agreement) plus a margin. We are charged various fees and expenses in connection with the Credit Agreement, including administrative agent fees, commitment fees on the unused portion of our borrowing capacity and fees related to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based on the credit ratings in effect from time to time on our long-term debt.
57
There were no borrowings or letters of credit outstanding at
December 31, 2014
.
Trade receivables securitization facility
– On
December 18, 2013
, we entered into a
three
-year,
$1.3 billion
trade receivables securitization facility with a group of financial institutions that act as committed purchasers, conduit purchasers, letter of credit issuers and managing agents under the facility. The facility is evidenced by a Receivables Purchase Agreement and a Second Amended and Restated Receivables Sale Agreement and replaces the previously existing accounts receivable facility that was set to expire on
June 30, 2014
.
The facility consists of one of our wholly-owned subsidiaries, Marathon Petroleum Company LP (“MPC LP”), selling or contributing on an on-going basis all of its trade receivables (including trade receivables acquired from Marathon Petroleum Trading Canada LLC, a wholly-owned subsidiary of MPC LP), together with all related security and interests in the proceeds thereof, without recourse, to another wholly-owned, bankruptcy-remote special purpose subsidiary, MPC Trade Receivables Company LLC (“TRC”), in exchange for a combination of cash, equity or a subordinated note issued by TRC to MPC LP. TRC, in turn, has the ability to finance its purchase of the receivables from MPC LP by selling undivided ownership interests in qualifying trade receivables, together with all related security and interests in the proceeds thereof, without recourse, to the purchasing group in exchange for cash proceeds. The facility also provides for the issuance of letters of credit of up to an initial amount of
$1.25 billion
, provided that the aggregate credit exposure of the purchasing group is limited to no more than
$1.3 billion
at any one time.
To the extent that TRC retains an ownership interest in the receivables it has purchased or received from MPC LP, such interest will be included in our consolidated financial statements solely as a result of the consolidation of the financial statements of TRC with those of MPC. The receivables sold or contributed to TRC are available first and foremost to satisfy claims of the creditors of TRC and are not available to satisfy the claims of creditors of MPC. TRC has granted a security interest in all of its assets to the purchasing group to secure its obligations under the Receivables Purchase Agreement.
Proceeds from the sale of undivided percentage ownership interests in qualifying receivables under the facility will be reflected as debt on our consolidated balance sheet. We will remain responsible for servicing the receivables sold to the purchasing group. TRC pays floating-rate interest charges and usage fees on amounts outstanding under the facility, if any, and certain other fees related to the administration of the facility and letters of credit that are issued and outstanding under the facility.
As of
December 31, 2014
, eligible trade receivables supported borrowings of
$1.28 billion
. There were no borrowings outstanding at
December 31, 2014
. Availability under our trade receivables securitization facility is a function of refined product selling prices, which will be lower in a sustained lower price environment. As of January 31, 2015, eligible trade receivables supported borrowings of
$700 million
.
MPLX Credit Agreement
– On November 20, 2014, MPLX entered into a credit agreement with a syndicate of lenders (“MPLX Credit Agreement”), which provides for a
five
-year
$1 billion
bank revolving credit facility and a
$250 million
term loan facility. The maturity date on both facilities is November 20, 2019.
The bank revolving credit facility includes letter of credit issuing capacity of up to
$250 million
and swingline loan capacity of up to
$100 million
. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional
$500 million
, subject to certain conditions, including the consent of the lenders whose commitments would increase. In addition, the maturity date may be extended up to
two
additional
one
-year periods subject to the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the original maturity date.
The term loan facility was drawn in full on November 20, 2014. The maturity date for the term loan facility may be extended for up to
two
additional
one
-year periods subject to the consent of the lenders holding a majority of the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any non-consenting lenders will continue to be due and payable on the original maturity date. The borrowings under this facility during
2014
were at an average interest rate of
1.4 percent
.
Borrowings under the MPLX Credit Agreement bear interest at either the
Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX Credit Agreement)
plus a specified margin. MPLX is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the bank revolving credit facility and fees with respect to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based the credit ratings in effect from time to time on MPLX’s long-term debt.
58
In connection with entering into this new credit agreement, MPLX terminated its previously existing
$500 million
five
-year MPLX Operations LLC bank revolving credit agreement, dated as of September 14, 2012. During
2014
, MPLX borrowed
$280 million
under the MPLX Operations LLC bank revolving credit agreement, at an average interest rate of
1.5 percent
, per annum, and repaid all of these borrowings.
During
2014
, MPLX borrowed
$630 million
under the new revolving credit agreement, at an average interest rate of
1.4 percent
, per annum, and repaid
$245 million
of these borrowings. At
December 31, 2014
, MPLX had
$385 million
of borrowings and
no
letters of credit outstanding under the MPLX Credit Agreement, resulting in total unused loan availability of
$615 million
, or
61.5 percent
of the borrowing capacity.
Debt-to-Total-Capital Ratio
As described in further detail below, the increase in debt as of year-end 2014 compared to year-end 2013 was primarily related to financing a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. Our debt-to-total capital ratio (total debt to total debt-plus-equity) was
37
percent and
23
percent at
December 31, 2014
and
2013
, respectively.
|
|
December 31,
|
|||||||
|
(In millions)
|
2014
|
2013
|
||||||
|
Long-term debt due within one year
|
$
|
27
|
|
$
|
23
|
|
||
|
Long-term debt
|
6,610
|
|
3,373
|
|
||||
|
Total debt
|
$
|
6,637
|
|
$
|
3,396
|
|
||
|
Calculation of debt-to-total capital ratio:
|
||||||||
|
Total debt
|
$
|
6,637
|
|
$
|
3,396
|
|
||
|
Plus equity
|
11,390
|
|
11,332
|
|
||||
|
Total debt plus equity
|
$
|
18,027
|
|
$
|
14,728
|
|
||
|
Debt-to-total capital ratio
|
37
|
%
|
23
|
%
|
||||
MPC Term Loan Agreement
– On
August 26, 2014
, we entered into a
$700 million
five
-year senior unsecured term loan credit agreement (the “Term Loan Agreement”) with a syndicate of lenders to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. The Term Loan Agreement matures on September 24, 2019 and may be prepaid at any time without premium or penalty. We are obligated to pay certain customary fees under the Term Loan Agreement, including an annual administrative fee.
Amounts outstanding under the Term Loan Agreement bear interest at either of the following rates at our election (i) the sum of the
Adjusted LIBO Rate (as defined in the Term Loan Agreement)
, plus a margin ranging between
0.875 percent
to
1.75 percent
, depending on our credit ratings, or (ii) the sum of the Base Rate (as defined in the Term Loan Agreement), plus a margin ranging between
zero percent
to
0.75 percent
, depending on our credit ratings. The borrowings under this facility during
2014
were at an average interest rate of
1.3 percent
.
Senior Notes
– On September 5, 2014, we completed a public offering of
$1.95 billion
aggregate principal amount of senior unsecured notes (the “Senior Notes”), consisting of
$750 million
aggregate principal amount of our Senior Notes due 2024,
$800 million
aggregate principal amount of our Senior Notes due 2044 and
$400 million
aggregate principal amount of our Senior Notes due 2054. The net proceeds from the offering of the Senior Notes were approximately
$1.92 billion
, after deducting underwriting discounts and estimated offering expenses. The net proceeds were used to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. Interest on each series of Senior Notes is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2015.
The Senior Notes are unsecured and unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated indebtedness.
The Term Loan Agreement, the Credit Agreement and the MPLX Credit Agreement contain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for agreements of these types. The financial covenant included in the Term Loan Agreement and the MPC Credit Agreement requires us to maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt to Total Capitalization (as defined in the Term Loan Agreement and the MPC Credit Agreement) of no greater than 0.65 to 1.00. As of
December 31, 2014
, we were in compliance with this debt covenant with a ratio of Consolidated Net Debt to Total Capitalization of
0.33
to 1.00, as well as the other covenants contained in the Term Loan Agreement and the MPC Credit Agreement.
59
The MPLX Credit Agreement includes certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for an agreement of this type. The MPLX Credit Agreement includes a financial covenant that requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior
four
fiscal quarters of no greater than
5.0
to 1.0 (or
5.5
to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict MPLX from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of
December 31, 2014
, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement, including a ratio of Consolidated Total Debt to Consolidated EBITDA of
2.8
to 1.0.
Our intention is to maintain an investment grade credit profile. As of February 9, 2015, the credit ratings on our senior unsecured debt were at or above investment grade level as follows.
|
Rating Agency
|
Rating
|
|
Moody’s
|
Baa2 (stable outlook)
|
|
Standard & Poor’s
|
BBB (stable outlook)
|
|
Fitch
|
BBB (stable outlook)
|
The ratings reflect the respective views of the rating agencies. Although it is our intention to maintain a credit profile that supports an investment grade rating, there is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant.
Neither the Credit Agreement, the MPLX Credit Agreement nor our trade receivables securitization facility contains credit rating triggers that would result in the acceleration of interest, principal or other payments in the event that our credit ratings are downgraded. However, any downgrades of our senior unsecured debt to below investment grade ratings would increase the applicable interest rates, yields and other fees payable under the Credit Agreement and our trade receivables securitization facility. In addition, a downgrade of our senior unsecured debt rating to below investment grade levels could, under certain circumstances, decrease the amount of trade receivables that are eligible to be sold under our trade receivables securitization facility, impact our ability to purchase crude oil on an unsecured basis and could result in us having to post letters of credit under existing transportation services agreements.
Capital Requirements
We have a capital and investment budget for
2015
of
$2.53 billion
, excluding capitalized interest. Additional details related to the
2015
capital and investment budget are discussed in the Capital Budget Outlook section below.
Pursuant to the purchase and sale agreement for the Galveston Bay Refinery and Related Assets, we may be required to pay the seller a contingent earnout of up to an additional $700 million over six years, subject to certain conditions. In July 2014, we paid
$180 million
for the first period’s contingent earnout. See Item 8. Financial Statements and Supplementary Data
–
Notes
5
and
18
.
While we have no required contributions to our pension plans for 2015, we may make voluntary contributions at our discretion.
On
January 31, 2015
, our board of directors approved a
50 cents
per share dividend, payable
March 10, 2015
to stockholders of record at the close of business on
February 18, 2015
.
On July 30, 2014, our board of directors approved an additional
$2.0 billion
share repurchase authorization expiring in
July 2016
. As of
December 31, 2014
, our board of directors had approved
$8.0 billion
in total share repurchase authorizations since January 1, 2012 and we have repurchased a total of
$6.27 billion
of our common stock under these authorizations, leaving
$1.73 billion
available for repurchases. Under these authorizations, we have acquired
89 million
shares at an average cost per share of
$70.35
.
We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated share repurchases or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.
The above discussion contains forward-looking statements with respect to share repurchase authorizations. Factors that could affect the share repurchase authorizations and the timing of any repurchases include, but are not limited to business conditions, availability of liquidity and the market price of our common stock. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements.
60
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of
December 31, 2014
. The contractual obligations detailed below do not include our contractual obligations to MPLX under various fee-based commercial agreements as these transactions are eliminated in the consolidated financial statements.
|
(In millions)
|
Total
|
2015
|
2016-2017
|
2018-2019
|
Later Years
|
|||||||||||||||
|
Long-term debt
(a)
|
$
|
11,141
|
|
$
|
276
|
|
$
|
1,256
|
|
$
|
1,809
|
|
$
|
7,800
|
|
|||||
|
Capital lease obligations
(b)
|
470
|
|
47
|
|
90
|
|
84
|
|
249
|
|
||||||||||
|
Operating lease obligations
|
1,326
|
|
249
|
|
359
|
|
250
|
|
468
|
|
||||||||||
|
Purchase obligations:
(c)
|
||||||||||||||||||||
|
Crude oil, feedstock, refined product and renewable fuel contracts
(d)
|
10,379
|
|
7,500
|
|
800
|
|
1,023
|
|
1,056
|
|
||||||||||
|
Transportation and related contracts
|
4,336
|
|
257
|
|
656
|
|
840
|
|
2,583
|
|
||||||||||
|
Contracts to acquire property, plant and equipment
(e)(f)
|
1,727
|
|
784
|
|
943
|
|
—
|
|
—
|
|
||||||||||
|
Service, materials and other contracts
(g)
|
2,047
|
|
478
|
|
532
|
|
402
|
|
635
|
|
||||||||||
|
Total purchase obligations
|
18,489
|
|
9,019
|
|
|
2,931
|
|
2,265
|
|
4,274
|
|
|||||||||
|
Other long-term liabilities reported in the consolidated balance sheet
(h)
|
1,111
|
|
77
|
|
181
|
|
235
|
|
618
|
|
||||||||||
|
Total contractual cash obligations
|
$
|
32,537
|
|
$
|
9,668
|
|
$
|
4,817
|
|
$
|
4,643
|
|
$
|
13,409
|
|
|||||
|
(a)
|
Includes interest payments for our senior notes, term loans and the MPLX Credit Agreement and commitment and administrative fees for our Credit Agreement, the MPLX Credit Agreement and our trade receivables securitization facility.
|
|
(b)
|
Capital lease obligations represent future minimum payments.
|
|
(c)
|
Includes both short- and long-term purchases obligations.
|
|
(d)
|
These contracts include variable price arrangements with estimated prices to be paid primarily based on futures curves.
|
|
(e)
|
Includes
$703 million
to fund
37.5 percent
of the construction of the Sandpiper pipeline project and
$185 million
to fund
35 percent
of the construction of the SAX pipeline project.
|
|
(f)
|
Includes
$520 million
of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets. See Item 8. Financial Statements and Supplementary Data – Note
5
for additional information on this acquisition.
|
|
(g)
|
Primarily includes contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
|
|
(h)
|
Primarily includes obligations for pension and other postretirement benefits including medical and life insurance, which we have estimated through
2024
. See Item 8. Financial Statements and Supplementary Data – Note
23
.
|
Off-Balance Sheet Arrangements
Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under accounting principles generally accepted in the United States. Our off-balance sheet arrangements are limited to indemnities and guarantees that are described below. Although these arrangements serve a variety of our business purposes, we are not dependent on them to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.
We have provided various guarantees related to equity method investees. In conjunction with the Spinoff, we entered into various indemnities and guarantees to Marathon Oil. These arrangements are described in Item 8. Financial Statements and Supplementary Data – Note
26
.
Capital Budget Outlook
We have a capital and investment budget for
2015
of
$2.53 billion
, excluding capitalized interest and any acquisitions we may make. This represents a
27
percent
increase
from our
2014
spending, excluding the acquisition of Hess’ Retail Operations and Related Assets. The budget includes spending on refining, retail marketing, transportation, logistics and brand marketing projects as well as amounts designated for corporate activities. We continuously evaluate our capital budget and make changes as conditions warrant.
Refining & Marketing
The Refining & Marketing segment’s
2015
capital budget is
$1.28 billion
, which includes
$234 million
for midstream assets, approximately
$370 million
for refining margin enhancement projects and approximately
$675 million
for refinery-sustaining capital. A number of these projects span multiple years.
61
The
$234 million
budgeted for midstream assets includes projects that will allow us to process condensate from the Utica Shale region and grow Gulf Coast export capabilities. We have a project to build a condensate splitter at our Catlettsburg refinery to allow it to process up to
35
mbpcd of condensate from the Utica Shale region that we expect to complete in 2015. We began operation of a condensate splitter at our Canton refinery at the end of 2014 to allow it to process up to
25
mbpcd of condensate. We have projects at our Galveston Bay and Garyville refineries to increase export capabilities by
165
mbpd by 2018. In 2015, we expect to complete projects representing 50 mbpd of that total.
The
$370 million
budgeted for refining margin enhancement projects includes projects that will allow us to increase our diesel production and to process light crude oil from the Utica Shale region. At our Garyville refinery, we completed a hydrocracker expansion in the first quarter of 2014 that increased the hydrocracker capacity to 110 mbpcd and we expect to complete a project to expand the distillate hydrotreater by 10 mbpcd in the first quarter of 2015. At our Galveston Bay refinery, we have a hydrocracker project designed to increase our ULSD production by nine mbpd by shifting yields from gasoline, which we expect to complete in 2015. At our Robinson refinery, we have a similar project to revamp our distillate hydrocracker to improve margins by processing more feedstock at a lower conversion and shifting approximately five mbpd of light products to ULSD production and a project to increase the light crude oil processing capacity by
30
mbpcd, which will allow it to run 100 percent light crude oil. We expect to complete these projects in 2015 and 2016, respectively.
During 2014, we worked on a front-end engineering and design study for a residual fuel hydrocracker project at our Garyville refinery intended to increase margins by upgrading residual fuel to ULSD and gas oil. We are deferring a final investment decision on this project with estimated total costs of $2.2 billion to $2.5 billion as we further evaluate the implications of current market conditions on the project. As of December 31, 2014, we have capitalized $90 million of costs associated with this project. If a decision is made to not pursue this project, there could be a future impairment of the costs incurred for the project.
The remaining
$675 million
budget is primarily allocated to maintaining facilities and meeting regulatory requirements at our refineries.
Speedway
The Speedway segment’s
2015
capital budget of
$452 million
is focused on continued growth and integrating the convenience stores acquired from Hess into Speedway. The budget includes approximately
$240 million
for the Hess retail outlets primarily associated with store conversions and remodels, which will drive incremental merchandise sales. The remaining budget is primarily for new convenience store construction and land acquisition to expand our markets and remodeling and rebuilding projects to upgrade and enhance our existing facilities. We have identified numerous opportunities for new convenience stores or store rebuilds in our existing market, western Pennsylvania and Tennessee. Also included in the capital budget are expenditures for technology, equipment and dispenser upgrades.
Pipeline Transportation
The Pipeline Transportation segment’s
2015
capital budget of
$659 million
is focused on projects to support the changing energy landscape in the United States, including equity investments in major pipeline projects, new infrastructure and upgrades to replace or enhance our existing facilities. We expect to invest approximately
$310 million
in the Sandpiper and SAX pipeline projects in 2015 and
$1.5 billion in total.
In addition, pending the completion of a binding open season, MPLX is planning to construct the Cornerstone pipeline project to connect Utica Shale production in southeastern Ohio to our Canton refinery and related build-out opportunities, which is expected to cost approximately
$200 million
and is anticipated to be operational in 2016.
Corporate and Other
The remaining
2015
capital budget includes
$140 million
, primarily related to an expansion project for our corporate headquarters and upgrades to information technology systems.
62
Our opinions concerning liquidity and capital resources and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors, including cash provided by operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The discussion of liquidity and capital resources above also contains forward-looking statements regarding expected capital and investment spending, costs for projects under construction, project completion dates and expectations or projections about strategies and goals for growth, upgrades and expansion. The forward-looking statements about our capital and investment budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for crude oil and refinery feedstocks and refined products, actions of competitors, delays in obtaining necessary third-party approvals, changes in labor, materials, and equipment costs and availability, planned and unplanned outages, the delay of, cancellation of or failure to implement planned capital projects, project cost overruns, disruptions or interruptions of our refining operations due to the shortage of skilled labor and unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.
Transactions with Related Parties
We believe that transactions with related parties were conducted under terms comparable to those with unrelated parties. See Item 8. Financial Statements and Supplementary Data – Note
8
for discussion of activity with related parties.
Environmental Matters and Compliance Costs
We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.
Legislation and regulations pertaining to fuel specifications, climate change and greenhouse gas emissions have the potential to materially adversely impact our business, financial condition, results of operations and cash flows, including costs of compliance and permitting delays. The extent and magnitude of these adverse impacts cannot be reliably or accurately estimated at this time because specific regulatory and legislative requirements have not been finalized and uncertainty exists with respect to the measures being considered, the costs and the time frames for compliance, and our ability to pass compliance costs on to our customers. For additional information see Item 1A. Risk Factors.
Our environmental expenditures, including non-regulatory expenditures, for each of the last three years were:
|
(In millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Capital
|
$
|
102
|
|
$
|
50
|
|
$
|
115
|
|
|||
|
Compliance:
(a)
|
||||||||||||
|
Operating and maintenance
|
397
|
|
321
|
|
318
|
|
||||||
|
Remediation
(b)
|
36
|
|
22
|
|
24
|
|
||||||
|
Total
|
$
|
535
|
|
$
|
393
|
|
$
|
457
|
|
|||
|
(a)
|
Based on the American Petroleum Institute’s definition of environmental expenditures.
|
|
(b)
|
These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash provisions recorded for environmental remediation.
|
We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.
63
New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We believe we comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.
Our environmental capital expenditures accounted for
five
percent,
four
percent and
eight
percent of capital expenditures excluding the acquisitions of the Galveston Bay Refinery and Related Assets and Hess’ Retail Operations and Related Assets in
2014
,
2013
and
2012
, respectively. Our environmental capital expenditures are expected to approximate
$250 million
, or
ten
percent, of total capital expenditures in
2015
. Predictions beyond
2015
can only be broad-based estimates, which have varied, and will continue to vary, due to the ongoing evolution of specific regulatory requirements, the possible imposition of more stringent requirements and the availability of new technologies, among other matters. Based on currently identified projects, we anticipate that environmental capital expenditures will be approximately
$410 million
in
2016
; however, actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.
For more information on environmental regulations that impact us, or could impact us, see Item 1. Business
–
Environmental Matters, Item 1A. Risk Factors and Item 3. Legal Proceedings.
Critical Accounting Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States (“US GAAP”) requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.
Fair Value Estimates
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
|
•
|
Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
|
|
•
|
Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.
|
|
•
|
Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
|
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. We use a market or income approach for recurring fair value measurements and endeavor to use the best information available. See Item 8. Financial Statements and Supplementary Data – Note
18
for disclosures regarding our fair value measurements.
64
Significant uses of fair value measurements include:
|
•
|
assessment of impairment of long-lived assets;
|
|
•
|
assessment of impairment of goodwill;
|
|
•
|
assessment of impairment of equity method investments;
|
|
•
|
recorded values for acquisitions; and
|
|
•
|
recorded values of derivative instruments.
|
Impairment Assessments of Long-Lived Assets, Goodwill and Equity Method Investments
Fair value calculated for the purpose of testing our long-lived assets, goodwill and equity method investments for impairment is estimated using the expected present value of future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:
|
•
|
Future margins on products produced and sold
. Our estimates of future product margins are based on our analysis of various supply and demand factors, which include, among other things, industry-wide capacity, our planned utilization rate, end-user demand, capital expenditures and economic conditions. Such estimates are consistent with those used in our planning and capital investment reviews.
|
|
•
|
Future volumes.
Our estimates of future refinery and pipeline throughput volumes are based on internal forecasts prepared by our Refining & Marketing and Pipeline Transportation segments operations personnel.
|
|
•
|
Discount rate commensurate with the risks involved
. We apply a discount rate to our cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. A higher discount rate decreases the net present value of cash flows.
|
|
•
|
Future capital requirements
. These are based on authorized spending and internal forecasts.
|
We base our fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from these projections.
The need to test for impairment can be based on several indicators, including a significant reduction in prices of or demand for products produced, a poor outlook for profitability, a significant reduction in pipeline throughput volumes, significant reduction in refining margins, other changes to contracts or changes in the regulatory environment in which the asset or equity method investment is located.
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is the refinery and associated distribution system level for Refining & Marketing segment assets, site level for Speedway segment convenience stores or the pipeline system level for Pipeline Transportation segment assets. If the sum of the undiscounted estimated pretax cash flows is less than the carrying value of an asset group, fair value is calculated, and the carrying value is written down if greater than the calculated fair value.
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. At
December 31, 2014
, we had a total of
$1.57 billion
of goodwill recorded on our consolidated balance sheet. The fair value of our reporting units exceeded book value for each of our reporting units in
2014
.
Equity method investments are assessed for impairment whenever factors indicate an other than temporary loss in value. Factors providing evidence of such a loss include the fair value of an investment that is less than its carrying value, absence of an ability to recover the carrying value or the investee’s inability to generate income sufficient to justify our carrying value. At
December 31, 2014
, we had
$865 million
of investments in equity method investments recorded on our consolidated balance sheet.
An estimate of the sensitivity to net income resulting from impairment calculations is not practicable, given the numerous assumptions (e.g., pricing, volumes and discount rates) that can materially affect our estimates. That is, unfavorable adjustments to some of the above listed assumptions may be offset by favorable adjustments in other assumptions.
65
Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued through 2014. At
December 31, 2014
, Centennial was not shipping product. As a result, we continued to evaluate the carrying value of our equity investment in Centennial. We concluded that no impairment was required given our assessment of its fair value based on market participant assumptions for various potential uses and future cash flows of Centennial’s assets. If market conditions were to change and the owners of Centennial are unable to find an alternative use for the assets, there could be a future impairment of our Centennial interest. As of
December 31, 2014
, our equity investment in Centennial was
$36 million
and we had a
$38 million
guarantee associated with 50 percent of Centennial’s outstanding debt. See Item 8. Financial Statements and Supplementary Data – Note
26
for additional information on the debt guarantee.
The above discussion contains forward-looking statements with respect to the carrying value of our Centennial equity investment. Factors that could affect the carrying value of our Centennial equity investment include, but are not limited to, a change in business conditions, a further decline or improvement in the long-term outlook of the potential uses of Centennial’s assets and the pursuit of different strategic alternatives for such assets. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements.
Acquisitions
In accounting for business combinations, acquired assets and liabilities and contingent consideration are recorded based on estimated fair values as of the date of acquisition. The excess or shortfall of the purchase price when compared to the fair value of the net tangible and identifiable intangible assets acquired, if any, is recorded as goodwill or a bargain purchase gain, respectively. A significant amount of judgment is involved in estimating the individual fair values of property, plant and equipment, intangible assets, contingent consideration and other assets and liabilities. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance.
The fair value of assets and liabilities, including contingent consideration, as of the acquisition date are often estimated using a combination of approaches, including the income approach, which requires us to project related future cash inflows and outflows and apply an appropriate discount rate; the cost approach, which requires estimates of replacement costs and depreciation and obsolescence estimates; and the market approach which uses market data and adjusts for entity-specific differences. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value.
The fair value of the contingent consideration we expect to pay to BP is re-measured each quarter using an income approach, with changes in fair value recorded in cost of revenues. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. We used internal and external forecasts for the crack spread and internal forecasts for refinery throughput volumes and applied an appropriate risk-adjusted discount rate to the range of cash flows indicated by various scenarios to determine the fair value of the arrangement. See Item 8. Financial Statements and Supplementary Data – Note
5
for additional information on our acquisitions. See Item 8. Financial Statements and Supplementary Data – Note
18
for additional information on fair value measurements.
Derivatives
We record all derivative instruments at fair value. All of our commodity derivatives are cleared through exchanges which provide active trading information for identical derivatives and do not require any assumptions in arriving at fair value. Fair value estimation for all our derivative instruments is discussed in Item 8. Financial Statements and Supplementary Data – Note
18
. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Pension and Other Postretirement Benefit Obligations
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the following:
|
•
|
the discount rate for measuring the present value of future plan obligations;
|
|
•
|
the expected long-term return on plan assets;
|
|
•
|
the rate of future increases in compensation levels;
|
|
•
|
health care cost projections; and
|
|
•
|
the mortality table used in determining future plan obligations.
|
66
We utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our funded pension plans and our unfunded retiree health care plans due to the different projected benefit payment patterns. The selected rates are compared to various similar bond indexes for reasonableness. In determining the assumed discount rates, we use our third-party actuary’s discount rate model. This model calculates an equivalent single discount rate for the projected benefit plan cash flows using a yield curve derived from Aa bond yields. The yield curve represents a series of annualized individual spot discount rates from 0.5 to 99 years. The bonds used have an average rating of Aa or higher by a recognized rating agency and generally only non-callable bonds are included. Outlier bonds that have a yield to maturity that deviate significantly from the average yield within each maturity grouping are not included. Each issue is required to have at least $250 million par value outstanding.
Of the assumptions used to measure the year-end obligations and estimated annual net periodic benefit cost, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. Decreasing the discount rates of 3.65 percent for our pension plans and 4.15 percent for our other postretirement benefit plans by 0.25 percent would increase pension obligations and other postretirement benefit plan obligations by $42 million and $32 million, respectively, and would increase defined benefit pension expense and other postretirement benefit plan expense by $2 million and $4 million, respectively.
The long-term asset rate of return assumption considers the asset mix of the plans (currently targeted at approximately 51 percent equity securities and 49 percent fixed income securities for the primary funded pension plan), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation and returns. In addition, our long-term asset rate of return assumption is compared to those of other companies and to historical returns for reasonableness. After evaluating activity in the capital markets, along with the current and projected plan investments, we reduced the asset rate of return for our primary plan from 7.00 percent to 6.75 percent effective for 2015. We used the 7.00 percent long-term rate of return to determine our 2014 defined benefit pension expense. Decreasing the 6.75 percent asset rate of return assumption by 0.25 percent would increase our defined benefit pension expense by $4 million.
Compensation change assumptions are based on historical experience, anticipated future management actions and demographics of the benefit plans.
Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends.
We utilized the 2014 mortality tables from the U.S. Society of Actuaries.
Item 8. Financial Statements and Supplementary Data – Note
23
includes detailed information about the assumptions used to calculate the components of our annual defined benefit pension and other postretirement plan expense, as well as the obligations and accumulated other comprehensive loss reported on the year-end balance sheets.
Contingent Liabilities
We accrue contingent liabilities for legal actions, claims, litigation, environmental remediation, tax deficiencies related to operating taxes and third-party indemnities for specified tax matters when such contingencies are both probable and estimable. We regularly assess these estimates in consultation with legal counsel to consider resolved and new matters, material developments in court proceedings or settlement discussions, new information obtained as a result of ongoing discovery and past experience in defending and settling similar matters. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on degree of responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on the extent and nature of site contamination and improvements in technology.
We generally record losses related to these types of contingencies as cost of revenues or selling, general and administrative expenses in the consolidated statements of income, except for tax deficiencies unrelated to income taxes, which are recorded as other taxes. For additional information on contingent liabilities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Matters and Compliance Costs.
An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.
67
Accounting Standards Not Yet Adopted
In February 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the VIE consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The update is effective for annual periods beginning after December 15, 2015. Early adoption is permitted. At this point, we have not determined the impact of the new standards update on our consolidated financial statements and related disclosures.
In August 2014, the FASB issued an accounting standards update requiring management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Management will be required to assess if there is substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. Disclosures will be required if conditions give rise to substantial doubt and the type of disclosure will be determined based on whether management’s plans will be able to alleviate the substantial doubt. The accounting standards update will be effective for the first annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted.
In June 2014, the FASB issued an accounting standards update for the elimination of the concept of development stage entity (“DSE”) from U.S. GAAP and removes the related incremental reporting. The standards update eliminates the additional financial statement requirements specific to a DSE. In addition, it amends the consolidation model by eliminating the special provisions in the variable interest entity rules for assessing the sufficiency of the equity of a DSE. The portion of the accounting standards update related to the amendment to the consolidation guidance will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2015, and interim periods within those years, with early adoption permitted. The portion of the accounting standards update related to the removal of the DSE reporting requirements will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2014, and interim periods within those years, with early adoption permitted. Adoption of this standards update in the first quarters of 2015 and 2016 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.
In May 2014, the FASB issued an accounting standards update for revenue recognition that is aligned with the International Accounting Standards Board’s revenue recognition standard issued on the same day. The guidance in the update states that revenue is recognized when a customer obtains control of a good or service. Recognition of the revenue will involve a multiple step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and then recognizing the revenue as the obligations are satisfied. Additional disclosures will be required to provide adequate information to understand the nature, amount, timing and uncertainty of reported revenues and revenues expected to be recognized. The accounting standards update will be effective on a retrospective or modified retrospective basis for annual reporting periods beginning after December 15, 2016, and interim periods within those years, with no early adoption permitted. At this point, we have not determined the impact of the new standard on our consolidated financial statements.
In April 2014, the FASB issued an accounting standards update that redefines the criteria for determining discontinued operations and introduces new disclosures related to these disposals. The updated definition of a discontinued operation is the disposal of a component (or components) of an entity or the classification of a component (or components) of an entity as held for sale that represents a strategic shift for an entity and has (or will have) a major impact on an entity’s operations and financial results. The standard requires disclosure of additional financial information for discontinued operations and individually material components not qualifying for discontinued operation presentation, as well as information regarding an entity’s continuing involvement with the discontinued operation. The accounting standards update is effective prospectively for annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted. Adoption of this standards update in the first quarter of 2015 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.
68
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
General
We are exposed to market risks related to the volatility of crude oil and refined product prices. We employ various strategies, including the use of commodity derivative instruments, to hedge the risks related to these price fluctuations. We are also exposed to market risks related to changes in interest rates and foreign currency exchange rates. As of
December 31, 2014
, we did not have any financial derivative instruments to hedge the risks related to interest rate fluctuations; however, we have used them in the past, and we continually monitor the market and our exposure and may enter into these agreements again in the future. We are at risk for changes in fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the underlying commodity or financial transaction.
We believe that our use of derivative instruments, along with our risk assessment procedures and internal controls, does not expose us to material adverse consequences. While the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods, we believe that the use of these instruments will not have a material adverse effect on our financial position or liquidity.
See Item 8. Financial Statements and Supplementary Data – Notes
18
and
19
for more information about the fair value measurement of our derivatives, as well as the amounts recorded in our consolidated balance sheets and statements of income. We do not designate any of our commodity derivative instruments as hedges for accounting purposes.
Commodity Price Risk
Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We use a variety of commodity derivative instruments, including futures and options, as part of an overall program to hedge commodity price risk. We also authorize the use of the market knowledge gained from these activities to do a limited amount of trading not directly related to our physical transactions.
We use commodity derivative instruments on crude oil and refined product inventories to hedge price risk associated with inventories above or below last-in, first-out inventory targets. We also use derivative instruments related to the acquisition of foreign-sourced crude oil and ethanol blended with refined petroleum products to hedge price risk associated with market volatility between the time we purchase the product and when we use it in the refinery production process or it is blended. In addition, we may use commodity derivative instruments on fixed price contracts for the sale of refined products to hedge risk by converting the refined product sales to market-based prices. The majority of these derivatives are exchange-traded contracts for crude oil, refined products and ethanol.
We closely monitor and hedge our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Our positions are monitored daily by a risk control group to ensure compliance with our stated risk management policy.
Open Derivative Positions and Sensitivity Analysis
The table below sets forth information relating to our significant open commodity derivative contracts as of
December 31, 2014
.
|
|
December 31, 2014
|
||||||
|
Position
|
Total Barrels
(In thousands)
|
Weighted Average Price
(Per barrel)
|
Benchmark
|
||||
|
Crude Oil
(a)
|
|||||||
|
Exchange-traded
|
Long
|
15,678
|
$61.53
|
CME and ICE Crude
(c)(d)
|
|||
|
Exchange-traded
|
Short
|
(25,257)
|
$65.39
|
CME and ICE Crude
(c)(d)
|
|||
|
Refined Products
(b)
|
|||||||
|
Exchange-traded
|
Long
|
2,948
|
$1.74
|
CME Heating Oil and RBOB
(c)(e)
|
|||
|
Exchange-traded
|
Short
|
(3,804)
|
$1.71
|
CME Heating Oil and RBOB
(c)(e)
|
|||
(a)
97 percent
of these contracts expire in the first quarter of 2015.
(b)
100
percent of these contracts expire in the first quarter of 2015.
(c)
Chicago Mercantile Exchange (“CME”).
(d)
Intercontinental Exchange (“ICE”).
(e)
Reformulated gasoline Blendstock for Oxygenate Blending (“RBOB”).
69
Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent increases and decreases in commodity prices for open commodity derivative instruments as of
December 31, 2014
is provided in the following table.
|
|
Change in IFO from a
Hypothetical Price Increase of |
Change in IFO from a
Hypothetical Price Decrease of |
|||||||||||||
|
(In millions)
|
10%
|
25%
|
10%
|
25%
|
|||||||||||
|
As of December 31, 2014
|
|||||||||||||||
|
Crude
|
$
|
(58
|
)
|
$
|
(145
|
)
|
$
|
62
|
|
$
|
157
|
|
|||
|
Refined products
|
(2
|
)
|
(4
|
)
|
2
|
|
4
|
|
|||||||
We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not reflected in the above sensitivity analysis.
We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. Changes to the portfolio after
December 31, 2014
would cause future IFO effects to differ from those presented above.
Interest Rate Risk
We are impacted by interest rate fluctuations related to our debt obligations. At
December 31, 2014
, our debt was primarily comprised of the
$3.0 billion
aggregate principal amount of fixed rate senior notes issued on February 1, 2011 and the
$1.95 billion
aggregate principal amount of fixed rate senior notes issued September 5, 2014. Additionally, we have $950 million of variable rate term debt.
Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on long-term debt as of
December 31, 2014
is provided in the following table. Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
|
(In millions)
|
Fair
Value (b) |
Change in
Fair Value |
Change in Net Income for the Twelve Months Ended December 31, 2014
|
|
||||||||
|
Long-term debt
(a)
|
||||||||||||
|
Fixed-rate
|
$
|
5,236
|
|
$
|
563
|
|
(c)
|
n/a
|
|
|||
|
Variable-rate
|
1,338
|
|
n/a
|
|
4
|
|
(d)
|
|||||
|
(a)
|
Excludes capital leases.
|
|
(b)
|
Fair value was based on market prices, where available, or current borrowing rates for financings with similar terms and maturities.
|
|
(c)
|
Assumes a 100-basis point decrease in the weighted average yield-to-maturity at
December 31, 2014
.
|
|
(d)
|
Assumes a 100-basis-point change in interest rates. The change in net income was based on the weighted average balance of debt outstanding for the year ended
December 31, 2014
.
|
At
December 31, 2014
, our portfolio of long-term debt was comprised of fixed-rate instruments and variable-rate borrowings under the Term Loan Agreement and the MPLX Credit Agreement. The fair value of our fixed-rate debt is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value. Interest rate fluctuations generally do not impact the fair value of borrowings under the Term Loan Agreement and the MPLX Credit Agreement, but will affect our results of operations and cash flows.
Foreign Currency Exchange Rate Risk
We are impacted by foreign exchange rate fluctuations related to some of our purchases of crude oil denominated in Canadian dollars. We did not utilize derivatives to hedge our market risk exposure to these foreign exchange rate fluctuations in
2014
.
70
Counterparty Risk
We are also exposed to financial risk in the event of nonperformance by counterparties or futures commission merchants. We regularly review the creditworthiness of counterparties and futures commission merchants and enter into master netting agreements when appropriate.
Forward-Looking Statements
These quantitative and qualitative disclosures about market risk include forward-looking statements with respect to management’s opinion about risks associated with the use of derivative instruments. These statements are based on certain assumptions with respect to market prices and industry supply of and demand for crude oil, other refinery feedstocks, refined products and ethanol. If these assumptions prove to be inaccurate, future outcomes with respect to our use of derivative instruments may differ materially from those discussed in the forward-looking statements.
71
Item 8. Financial Statements and Supplementary Data
Index
|
|
Page
|
|
Audited Consolidated Financial Statements:
|
|
72
Management’s Responsibilities for Financial Statements
The accompanying consolidated financial statements of Marathon Petroleum Corporation and its subsidiaries (“MPC”) are the responsibility of management and have been prepared in conformity with accounting principles generally accepted in the United States of America. They necessarily include some amounts that are based on best judgments and estimates. The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.
MPC seeks to assure the objectivity and integrity of its financial records by careful selection of its managers, by organizational arrangements that provide an appropriate division of responsibility and by communications programs aimed at assuring that its policies and methods are understood throughout the organization.
The board of directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit Committee. This committee, composed solely of independent directors, regularly meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated financial statements.
|
/s/ Gary R. Heminger
|
/s/ Donald C. Templin
|
/s/ John J. Quaid
|
||
|
Gary R. Heminger
President and
Chief Executive Officer
|
Donald C. Templin
Senior Vice President
and Chief Financial
Officer
|
John J. Quaid
Vice President and
Controller
|
||
Management’s Report on Internal Control over Financial Reporting
MPC’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934). An evaluation of the design and effectiveness of our internal control over financial reporting, based on the framework in
Internal Control
–
Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission, was conducted under the supervision and with the participation of management, including our chief executive officer and chief financial officer. Based on the results of this evaluation, MPC’s management concluded that its internal control over financial reporting was effective as of
December 31, 2014
.
Management has excluded Hess’ Retail Operations and Related Assets (as defined in footnote 5) from the Company’s assessment of internal control over financial reporting as of
December 31, 2014
as it was acquired by the Company in a business combination on September 30, 2014. Hess’ Retail Operations and Related Assets represents approximately 8% of consolidated total assets as of
December 31, 2014
and 2% of total revenues and other income for the year ended
December 31, 2014
. We plan to fully integrate the acquired businesses into our internal control over financial reporting in 2015.
The effectiveness of MPC’s internal control over financial reporting as of
December 31, 2014
has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
|
/s/ Gary R. Heminger
|
/s/ Donald C. Templin
|
|||
|
Gary R. Heminger
President and
Chief Executive Officer
|
Donald C. Templin
Senior Vice President
and Chief Financial
Officer
|
|||
73
Report of Independent Registered Public Accounting Firm
To the Stockholders of Marathon Petroleum Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, equity, and cash flows present fairly, in all material respects, the financial position of Marathon Petroleum Corporation and its subsidiaries
at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014
in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in
Internal Control – Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, 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 opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Hess’ Retail Operations and Related Assets (as defined in footnote 5) from the Company’s assessment of internal control over financial reporting as of December 31, 2014 as it was acquired by the Company in a business combination on September 30, 2014. We have also excluded Hess’ Retail Operations and Related Assets from our audit of internal control over financial reporting. Hess’ Retail Operations and Related Assets represents approximately 8% of consolidated total assets as of December 31, 2014 and 2% of total revenue and other income for the year ended December 31, 2014.
/s/PricewaterhouseCoopers LLP
Toledo, Ohio
February 27, 2015
74
Marathon Petroleum Corporation
Consolidated Statements of Income
|
(In millions, except per share data)
|
2014
|
2013
|
2012
|
||||||||
|
Revenues and other income:
|
|||||||||||
|
Sales and other operating revenues (including consumer excise taxes)
|
$
|
97,817
|
|
$
|
100,160
|
|
$
|
82,243
|
|
||
|
Income from equity method investments
|
153
|
|
36
|
|
26
|
|
|||||
|
Net gain on disposal of assets
|
21
|
|
6
|
|
177
|
|
|||||
|
Other income
|
111
|
|
52
|
|
46
|
|
|||||
|
Total revenues and other income
|
98,102
|
|
100,254
|
|
82,492
|
|
|||||
|
Costs and expenses:
|
|||||||||||
|
Cost of revenues (excludes items below)
|
83,770
|
|
87,401
|
|
68,668
|
|
|||||
|
Purchases from related parties
|
505
|
|
357
|
|
280
|
|
|||||
|
Consumer excise taxes
|
6,685
|
|
6,263
|
|
5,709
|
|
|||||
|
Depreciation and amortization
|
1,326
|
|
1,220
|
|
995
|
|
|||||
|
Selling, general and administrative expenses
|
1,375
|
|
1,248
|
|
1,223
|
|
|||||
|
Other taxes
|
390
|
|
340
|
|
270
|
|
|||||
|
Total costs and expenses
|
94,051
|
|
96,829
|
|
77,145
|
|
|||||
|
Income from operations
|
4,051
|
|
3,425
|
|
5,347
|
|
|||||
|
Net interest and other financial income (costs)
|
(216
|
)
|
(179
|
)
|
(109
|
)
|
|||||
|
Income before income taxes
|
3,835
|
|
3,246
|
|
5,238
|
|
|||||
|
Provision for income taxes
|
1,280
|
|
1,113
|
|
1,845
|
|
|||||
|
Net income
|
2,555
|
|
2,133
|
|
3,393
|
|
|||||
|
Less net income attributable to noncontrolling interests
|
31
|
|
21
|
|
4
|
|
|||||
|
Net income attributable to MPC
|
$
|
2,524
|
|
$
|
2,112
|
|
$
|
3,389
|
|
||
|
Per Share Data (See Note 9)
|
|||||||||||
|
Basic:
|
|||||||||||
|
Net income attributable to MPC per share
|
$
|
8.84
|
|
$
|
6.69
|
|
$
|
9.95
|
|
||
|
Weighted average shares outstanding
|
285
|
|
315
|
|
340
|
|
|||||
|
Diluted:
|
|||||||||||
|
Net income attributable to MPC per share
|
$
|
8.78
|
|
$
|
6.64
|
|
$
|
9.89
|
|
||
|
Weighted average shares outstanding
|
287
|
|
317
|
|
342
|
|
|||||
|
Dividends paid
|
$
|
1.84
|
|
$
|
1.54
|
|
$
|
1.20
|
|
||
The accompanying notes are an integral part of these consolidated financial statements.
75
Marathon Petroleum Corporation
Consolidated Statements of Comprehensive Income
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Net income
|
$
|
2,555
|
|
$
|
2,133
|
|
$
|
3,393
|
|
||
|
Other comprehensive income (loss):
|
|||||||||||
|
Defined benefit postretirement and post-employment plans:
|
|||||||||||
|
Actuarial changes, net of tax of ($47), $174 and $47
|
(78
|
)
|
294
|
|
78
|
|
|||||
|
Prior service costs, net of tax of ($19), ($19) and $203
|
(31
|
)
|
(34
|
)
|
337
|
|
|||||
|
Other comprehensive income (loss)
|
(109
|
)
|
260
|
|
415
|
|
|||||
|
Comprehensive income
|
2,446
|
|
2,393
|
|
3,808
|
|
|||||
|
Less comprehensive income attributable to noncontrolling interests
|
31
|
|
21
|
|
4
|
|
|||||
|
Comprehensive income attributable to MPC
|
$
|
2,415
|
|
$
|
2,372
|
|
$
|
3,804
|
|
||
The accompanying notes are an integral part of these consolidated financial statements.
76
Marathon Petroleum Corporation
Consolidated Balance Sheets
|
|
December 31,
|
||||||
|
(In millions, except share data)
|
2014
|
2013
|
|||||
|
Assets
|
|||||||
|
Current assets:
|
|||||||
|
Cash and cash equivalents
|
$
|
1,494
|
|
$
|
2,292
|
|
|
|
Receivables, less allowance for doubtful accounts of $13 and $9
|
4,058
|
|
5,559
|
|
|||
|
Inventories
|
5,642
|
|
4,689
|
|
|||
|
Other current assets
|
145
|
|
197
|
|
|||
|
Total current assets
|
11,339
|
|
12,737
|
|
|||
|
Equity method investments
|
865
|
|
463
|
|
|||
|
Property, plant and equipment, net
|
16,261
|
|
13,921
|
|
|||
|
Goodwill
|
1,566
|
|
938
|
|
|||
|
Other noncurrent assets
|
429
|
|
326
|
|
|||
|
Total assets
|
$
|
30,460
|
|
$
|
28,385
|
|
|
|
Liabilities
|
|||||||
|
Current liabilities:
|
|||||||
|
Accounts payable
|
$
|
6,661
|
|
$
|
8,234
|
|
|
|
Payroll and benefits payable
|
427
|
|
406
|
|
|||
|
Consumer excise taxes payable
|
463
|
|
373
|
|
|||
|
Accrued taxes
|
647
|
|
513
|
|
|||
|
Long-term debt due within one year
|
27
|
|
23
|
|
|||
|
Other current liabilities
|
354
|
|
275
|
|
|||
|
Total current liabilities
|
8,579
|
|
9,824
|
|
|||
|
Long-term debt
|
6,610
|
|
3,373
|
|
|||
|
Deferred income taxes
|
2,014
|
|
2,304
|
|
|||
|
Defined benefit postretirement plan obligations
|
1,099
|
|
771
|
|
|||
|
Deferred credits and other liabilities
|
768
|
|
781
|
|
|||
|
Total liabilities
|
19,070
|
|
17,053
|
|
|||
|
Commitments and contingencies (see Note 26)
|
|
|
|
|
|||
|
Equity
|
|||||||
|
MPC stockholders’ equity:
|
|||||||
|
Preferred stock, no shares issued and outstanding (par value $0.01 per share, 30 million shares authorized)
|
—
|
|
—
|
|
|||
|
Common stock:
|
|||||||
|
Issued – 363 million and 362 million shares (par value $0.01 per share, 1 billion shares authorized)
|
4
|
|
4
|
|
|||
|
Held in treasury, at cost – 89 million and 65 million shares
|
(6,299
|
)
|
(4,155
|
)
|
|||
|
Additional paid-in capital
|
9,844
|
|
9,768
|
|
|||
|
Retained earnings
|
7,515
|
|
5,507
|
|
|||
|
Accumulated other comprehensive loss
|
(313
|
)
|
(204
|
)
|
|||
|
Total MPC stockholders’ equity
|
10,751
|
|
10,920
|
|
|||
|
Noncontrolling interests
|
639
|
|
412
|
|
|||
|
Total equity
|
11,390
|
|
11,332
|
|
|||
|
Total liabilities and equity
|
$
|
30,460
|
|
$
|
28,385
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
77
Marathon Petroleum Corporation
Consolidated Statements of Cash Flows
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Increase (decrease) in cash and cash equivalents
|
|||||||||||
|
Operating activities:
|
|||||||||||
|
Net income
|
$
|
2,555
|
|
$
|
2,133
|
|
$
|
3,393
|
|
||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|||||||||||
|
Depreciation and amortization
|
1,326
|
|
1,220
|
|
995
|
|
|||||
|
Pension and other postretirement benefits, net
|
151
|
|
(124
|
)
|
153
|
|
|||||
|
Deferred income taxes
|
(242
|
)
|
23
|
|
492
|
|
|||||
|
Net gain on disposal of assets
|
(21
|
)
|
(6
|
)
|
(177
|
)
|
|||||
|
Equity method investments, net
|
17
|
|
(18
|
)
|
11
|
|
|||||
|
Changes in the fair value of derivative instruments
|
(3
|
)
|
(21
|
)
|
59
|
|
|||||
|
Changes in:
|
|||||||||||
|
Current receivables
|
1,642
|
|
(940
|
)
|
851
|
|
|||||
|
Inventories
|
(786
|
)
|
(305
|
)
|
(115
|
)
|
|||||
|
Current accounts payable and accrued liabilities
|
(1,547
|
)
|
1,464
|
|
(1,223
|
)
|
|||||
|
All other, net
|
18
|
|
(21
|
)
|
53
|
|
|||||
|
Net cash provided by operating activities
|
3,110
|
|
3,405
|
|
4,492
|
|
|||||
|
Investing activities:
|
|||||||||||
|
Additions to property, plant and equipment
|
(1,480
|
)
|
(1,206
|
)
|
(1,369
|
)
|
|||||
|
Acquisitions, net of cash acquired
|
(2,821
|
)
|
(1,515
|
)
|
(190
|
)
|
|||||
|
Disposal of assets
|
27
|
|
16
|
|
53
|
|
|||||
|
Investments – acquisitions, loans and contributions
|
(413
|
)
|
(151
|
)
|
(57
|
)
|
|||||
|
– redemptions, repayments and return of capital
|
9
|
|
77
|
|
108
|
|
|||||
|
All other, net
|
135
|
|
23
|
|
3
|
|
|||||
|
Net cash used in investing activities
|
(4,543
|
)
|
(2,756
|
)
|
(1,452
|
)
|
|||||
|
Financing activities:
|
|||||||||||
|
Long-term debt – borrowings
|
3,793
|
|
—
|
|
—
|
|
|||||
|
– repayments
|
(548
|
)
|
(21
|
)
|
(17
|
)
|
|||||
|
Debt issuance costs
|
(22
|
)
|
(4
|
)
|
(6
|
)
|
|||||
|
Issuance of common stock
|
26
|
|
48
|
|
108
|
|
|||||
|
Common stock repurchased
|
(2,131
|
)
|
(2,793
|
)
|
(1,350
|
)
|
|||||
|
Dividends paid
|
(524
|
)
|
(484
|
)
|
(407
|
)
|
|||||
|
Net proceeds from issuance of MPLX LP common units
|
221
|
|
—
|
|
407
|
|
|||||
|
Distributions to noncontrolling interests
|
(27
|
)
|
(21
|
)
|
—
|
|
|||||
|
Tax settlement with Marathon Oil Corporation
|
—
|
|
39
|
|
—
|
|
|||||
|
Contingent consideration payment
|
(172
|
)
|
—
|
|
—
|
|
|||||
|
All other, net
|
19
|
|
19
|
|
6
|
|
|||||
|
Net cash provided by (used in) financing activities
|
635
|
|
(3,217
|
)
|
(1,259
|
)
|
|||||
|
Net increase (decrease) in cash and cash equivalents
|
(798
|
)
|
(2,568
|
)
|
1,781
|
|
|||||
|
Cash and cash equivalents at beginning of period
|
2,292
|
|
4,860
|
|
3,079
|
|
|||||
|
Cash and cash equivalents at end of period
|
$
|
1,494
|
|
$
|
2,292
|
|
$
|
4,860
|
|
||
The accompanying notes are an integral part of these consolidated financial statements.
78
Marathon Petroleum Corporation
Consolidated Statements of Equity
|
MPC Stockholders’ Equity
|
|
|
|||||||||||||||||||||||||
|
(In millions)
|
Common
Stock |
Treasury
Stock |
Additional
Paid-in Capital |
Retained
Earnings |
Accumulated
Other Comprehensive Income (Loss) |
Noncontrolling
Interests |
Total
Equity |
||||||||||||||||||||
|
Balance as of December 31, 2011
|
$
|
4
|
|
$
|
—
|
|
$
|
9,482
|
|
$
|
898
|
|
$
|
(879
|
)
|
$
|
—
|
|
$
|
9,505
|
|
||||||
|
Net income
|
—
|
|
—
|
|
—
|
|
3,389
|
|
—
|
|
4
|
|
3,393
|
|
|||||||||||||
|
Dividends declared
|
—
|
|
—
|
|
—
|
|
(407
|
)
|
—
|
|
—
|
|
(407
|
)
|
|||||||||||||
|
Other comprehensive income
|
—
|
|
—
|
|
—
|
|
—
|
|
415
|
|
—
|
|
415
|
|
|||||||||||||
|
Shares repurchased
|
—
|
|
(1,250
|
)
|
(100
|
)
|
—
|
|
—
|
|
—
|
|
(1,350
|
)
|
|||||||||||||
|
Shares issued (returned) – stock-based compensation
|
—
|
|
(3
|
)
|
108
|
|
—
|
|
—
|
|
—
|
|
105
|
|
|||||||||||||
|
Stock-based compensation
|
—
|
|
—
|
|
46
|
|
—
|
|
—
|
|
—
|
|
46
|
|
|||||||||||||
|
Issuance of MPLX LP common units
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
407
|
|
407
|
|
|||||||||||||
|
Other
|
—
|
|
—
|
|
(9
|
)
|
—
|
|
—
|
|
—
|
|
(9
|
)
|
|||||||||||||
|
Balance as of December 31, 2012
|
$
|
4
|
|
$
|
(1,253
|
)
|
$
|
9,527
|
|
$
|
3,880
|
|
$
|
(464
|
)
|
$
|
411
|
|
$
|
12,105
|
|
||||||
|
Net income
|
—
|
|
—
|
|
—
|
|
2,112
|
|
—
|
|
21
|
|
2,133
|
|
|||||||||||||
|
Dividends declared
|
—
|
|
—
|
|
—
|
|
(485
|
)
|
—
|
|
—
|
|
(485
|
)
|
|||||||||||||
|
Distributions to noncontrolling interests
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(21
|
)
|
(21
|
)
|
|||||||||||||
|
Other comprehensive income
|
—
|
|
—
|
|
—
|
|
—
|
|
260
|
|
—
|
|
260
|
|
|||||||||||||
|
Shares repurchased
|
—
|
|
(2,893
|
)
|
100
|
|
—
|
|
—
|
|
—
|
|
(2,793
|
)
|
|||||||||||||
|
Shares issued (returned) – stock-based compensation
|
—
|
|
(9
|
)
|
47
|
|
—
|
|
—
|
|
—
|
|
38
|
|
|||||||||||||
|
Stock-based compensation
|
—
|
|
—
|
|
55
|
|
—
|
|
—
|
|
1
|
|
56
|
|
|||||||||||||
|
Tax settlement with Marathon Oil Corporation
|
—
|
|
—
|
|
39
|
|
—
|
|
—
|
|
—
|
|
39
|
|
|||||||||||||
|
Balance as of December 31, 2013
|
$
|
4
|
|
$
|
(4,155
|
)
|
$
|
9,768
|
|
$
|
5,507
|
|
$
|
(204
|
)
|
$
|
412
|
|
$
|
11,332
|
|
||||||
|
Net income
|
—
|
|
—
|
|
—
|
|
2,524
|
|
—
|
|
31
|
|
2,555
|
|
|||||||||||||
|
Dividends declared
|
—
|
|
—
|
|
—
|
|
(525
|
)
|
—
|
|
—
|
|
(525
|
)
|
|||||||||||||
|
Distributions to noncontrolling interests
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(27
|
)
|
(27
|
)
|
|||||||||||||
|
Other comprehensive loss
|
—
|
|
—
|
|
—
|
|
—
|
|
(109
|
)
|
—
|
|
(109
|
)
|
|||||||||||||
|
Shares repurchased
|
—
|
|
(2,131
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
(2,131
|
)
|
|||||||||||||
|
Shares issued (returned) – stock-based compensation
|
—
|
|
(13
|
)
|
26
|
|
—
|
|
—
|
|
—
|
|
13
|
|
|||||||||||||
|
Stock-based compensation
|
—
|
|
—
|
|
50
|
|
—
|
|
—
|
|
2
|
|
52
|
|
|||||||||||||
|
Issuance of MPLX LP common units
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
221
|
|
221
|
|
|||||||||||||
|
Other
|
—
|
|
—
|
|
—
|
|
9
|
|
—
|
|
—
|
|
9
|
|
|||||||||||||
|
Balance as of December 31, 2014
|
$
|
4
|
|
$
|
(6,299
|
)
|
$
|
9,844
|
|
$
|
7,515
|
|
$
|
(313
|
)
|
$
|
639
|
|
$
|
11,390
|
|
||||||
|
(Shares in millions)
|
Common
Stock |
Treasury
Stock |
|||
|
Balance as of December 31, 2011
|
357
|
|
—
|
|
|
|
Shares repurchased
|
—
|
|
(28
|
)
|
|
|
Shares issued – stock-based compensation
|
4
|
|
—
|
|
|
|
Balance as of December 31, 2012
|
361
|
|
(28
|
)
|
|
|
Shares repurchased
|
—
|
|
(37
|
)
|
|
|
Shares issued – stock-based compensation
|
1
|
|
—
|
|
|
|
Balance as of December 31, 2013
|
362
|
|
(65
|
)
|
|
|
Shares repurchased
|
—
|
|
(24
|
)
|
|
|
Shares issued – stock-based compensation
|
1
|
|
—
|
|
|
|
Balance as of December 31, 2014
|
363
|
|
(89
|
)
|
|
The accompanying notes are an integral part of these consolidated financial statements.
79
Notes to Consolidated Financial Statements
|
1.
|
Description of the Business and Basis of Presentation
|
Description of the Business –
As used in this report, the terms “MPC,” “we,” “us,” “the Company” or “our” may refer to Marathon Petroleum Corporation, one or more of its consolidated subsidiaries or all of them taken as a whole.
Our business consists of refining and marketing, retail and pipeline transportation operations conducted primarily in the Midwest, Gulf Coast, East Coast and Southeast regions of the United States, through subsidiaries, including Marathon Petroleum Company LP, Speedway LLC and its subsidiaries (“Speedway”) and MPLX LP and its subsidiaries (“MPLX”).
See Note
11
for additional information about our operations.
Spinoff
–
On May 25, 2011, the Marathon Oil board of directors approved the spinoff of its Refining, Marketing & Transportation Business (“RM&T Business”) into an independent, publicly traded company, MPC, through the distribution of MPC common stock to the stockholders of Marathon Oil common stock (the “Spinoff”). MPC became an independent, publicly traded company on July 1, 2011.
Basis of Presentation –
Our results of operations and cash flows consist of consolidated MPC activities. All significant intercompany transactions and accounts have been eliminated.
During the first quarter of 2014, we recorded an out-of-period adjustment for additional expenses related to the prior year’s bonus programs of
$29 million
, included in total costs and expenses on the consolidated statements of income. The impact to our consolidated results of operations for the year ended
December 31, 2014
and for the year ended
December 31, 2013
was immaterial.
|
2.
|
Summary of Principal Accounting Policies
|
Principles applied in consolidation
– These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries. We consolidate MPLX, in which we own a
71.5 percent
controlling financial interest, and we record a noncontrolling interest for the
28.5 percent
interest owned by the public.
Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority shareholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees.
Equity method investments are generally carried at our share of net assets plus loans and advances. Such investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset values of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill.
Use of estimates
– The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.
Revenue recognition
– Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues. Shipping and other transportation costs billed to our customers are presented on a gross basis in revenues and cost of revenues.
Rebates from vendors are recognized as a reduction of cost of revenues when the initiating transaction occurs. Incentives that are derived from contractual provisions are accrued based on past experience and recognized in cost of revenues. Rebates to customers are reflected as a reduction of revenue and are accrued for in accounts payable on the consolidated balance sheets.
80
Crude oil and refined product exchanges and matching buy/sell transactions
–
We enter into exchange contracts and matching buy/sell arrangements whereby we agree to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty the same commodity at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash. The matching buy/sell purchase and sale transactions are settled in cash. Both exchange and matching buy/sell transactions are accounted for as exchanges of inventory and no revenues are recorded. The exchange transactions are recognized at the carrying amount of the inventory transferred.
Consumer excise taxes
– We are required by various governmental authorities, including countries, states and municipalities, to collect and remit taxes on certain consumer products. Such taxes are presented on a gross basis in revenues and costs and expenses in the consolidated statements of income.
Cash and cash equivalents
– Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less.
Restricted cash
– Restricted cash consists of cash advances to be used for the operation and maintenance of an operated pipeline system. At
December 31, 2014
and
2013
, the amount of restricted cash included in other current assets on the consolidated balance sheets were
$4 million
and
$7 million
, respectively.
Accounts receivable and allowance for doubtful accounts
– Our receivables primarily consist of customer accounts receivable. The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in customer accounts receivable and is based on historical write-off experience. We review the allowance quarterly and past-due balances over
180 days
are reviewed individually for collectability. All other customer receivables are recorded at the invoiced amounts and generally do not bear interest. Account balances for these customer receivables are generally charged directly to bad debt expense when it becomes probable the receivable will not be collected.
Approximately
41 percent
and
38 percent
of our accounts receivable balances at
December 31, 2014
and
2013
, respectively, are related to sales of crude oil or refinery feedstocks to customers with whom we have master netting agreements. We have master netting agreements with more than
100
companies engaged in the crude oil or refinery feedstock trading and supply business or the petroleum refining industry. A master netting agreement generally provides for a once per month net cash settlement of the accounts receivable from and the accounts payable to a particular counterparty.
Inventories
– Inventories are carried at the lower of cost or market value. Cost of inventories is determined primarily under the last-in, first-out (“LIFO”) method. Costs for crude oil and refined product inventories are aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may have to be written down to market value.
Derivative instruments
– We use derivatives to economically hedge a portion of our exposure to commodity price risk and, historically, to interest rate risk. We also have limited authority to use selective derivative instruments that assume market risk. All derivative instruments are recorded at fair value. Commodity derivatives are reflected on the consolidated balance sheets on a net basis by futures commission merchant, as they are governed by master netting agreements. Cash flows related to derivatives used to hedge commodity price risk and interest rate risk are classified in operating activities with the underlying transactions.
Fair value accounting hedges
– We used interest rate swaps to hedge our exposure to interest rate risk associated with fixed interest rate debt in our portfolio. Changes in the fair values of both the hedged item and the related derivative were recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect was to report in net income the extent to which the accounting hedge was not effective in achieving offsetting changes in fair value. We terminated our interest rate swap agreements during 2012. There was a gain on the termination of the agreements, which has been accounted for as an adjustment to our long-term debt balance. The gain is being amortized over the remaining life of the associated debt, which reduces our interest expense.
Derivatives not designated as accounting hedges –
Derivatives that are not designated as accounting hedges may include commodity derivatives used to hedge price risk on (1) inventories, (2) fixed price sales of refined products, (3) the acquisition of foreign-sourced crude oil and (4) the acquisition of ethanol for blending with refined products. Changes in the fair value of derivatives not designated as accounting hedges are recognized immediately in net income.
Concentrations of credit risk
– All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on an assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.
81
Property, plant and equipment
– Property, plant and equipment are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from
four
to
42
years. Such assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset.
When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale.
Interest expense is capitalized for qualifying assets under construction. Capitalized interest costs are included in property, plant and equipment and are depreciated over the useful life of the related asset.
Goodwill
– Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, the implied fair value of goodwill is calculated. The excess, if any, of the book value over the implied fair value of goodwill is charged to net income.
Major maintenance activities
– Costs for planned turnaround, major maintenance and engineered project activities are expensed in the period incurred. These types of costs include contractor repair services, materials and supplies, equipment rentals and our labor costs.
Environmental costs
– Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. We recognize remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted when the estimated amount is reasonably fixed and determinable.
Asset retirement obligations
– The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining facilities have been recognized. The fair values recorded for such obligations are based on the most probable current cost projections. The recorded asset retirement obligations are not material to the consolidated financial statements.
Asset retirement obligations have not been recognized for some assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate. Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates. The asset retirement obligations principally include the removal of underground storage tanks at our leased convenience stores at or near the time of closure and hazardous material disposal and removal or dismantlement requirements associated with the closure of certain refining, terminal and pipeline assets.
Our practice is to keep our assets in good operating condition through routine repair and maintenance of component parts in the ordinary course of business and by continuing to make improvements based on technological advances. As a result, we believe that these assets have no expected settlement date for purposes of estimating asset retirement obligations since the dates or ranges of dates upon which we would retire these assets cannot be reasonably estimated at this time.
Income taxes
– Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate sufficient future taxable income.
82
Stock-based compensation arrangements
– The fair value of stock options granted to our employees is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the vesting period of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. The average expected life is based on our historical employee exercise behavior. The assumption for expected volatility of our stock price reflects a weighting of
50 percent
of our common stock implied volatility and
50 percent
of MPC’s common stock historical volatility.
The fair value of restricted stock awards granted to our employees is determined based on the fair market value of our common stock on the date of grant. The fair value of performance unit awards granted to our employees is estimated on the date of grant using a Monte Carlo valuation model.
Our stock-based compensation expense is recognized based on management’s estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Unearned stock-based compensation is charged to equity when restricted stock awards are granted. Compensation expense is recognized over the vesting period and is adjusted if conditions of the restricted stock award are not met.
Renewable fuel identification numbers (“RINs”)
– We purchase RINs to satisfy a portion of our Renewable Fuel Standard (“RFS2”) compliance. We record a short-term intangible asset, included in other current assets on the balance sheet, for RINs owned in excess of our anticipated current period compliance requirements. The asset value is based on the product of the excess RINs as of the balance sheet date, if any, and the average cost of our RINs. We record a current liability, included in other current liabilities on the balance sheet, when we are deficient RINs based on the product of the deficient RINs as of the balance sheet date, if any, and the market price of the RINs at the balance sheet date. The cost of RINs used for compliance is reflected in cost of revenues.
Any gains or losses on the sale or expiration of RINs are classified as other income.
|
3.
|
Accounting Standards
|
Not Yet Adopted
In February 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the VIE consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The update is effective for annual periods beginning after December 15, 2015. Early adoption is permitted. At this point, we have not determined the impact of the new standards update on our consolidated financial statements and related disclosures.
In August 2014, the FASB issued an accounting standards update requiring management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Management will be required to assess if there is substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. Disclosures will be required if conditions give rise to substantial doubt and the type of disclosure will be determined based on whether management’s plans will be able to alleviate the substantial doubt. The accounting standards update will be effective for the first annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted.
In June 2014, the FASB issued an accounting standards update for the elimination of the concept of development stage entity (“DSE”) from U.S. GAAP and removes the related incremental reporting. The standards update eliminates the additional financial statement requirements specific to a DSE. In addition, it amends the consolidation model by eliminating the special provisions in the variable interest entity rules for assessing the sufficiency of the equity of a DSE. The portion of the accounting standards update related to the amendment to the consolidation guidance will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2015, and interim periods within those years, with early adoption permitted. The portion of the accounting standards update related to the removal of the DSE reporting requirements will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2014, and interim periods within those years, with early adoption permitted. Adoption of this standards update in the first quarters of 2015 and 2016 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.
83
In May 2014, the FASB issued an accounting standards update for revenue recognition that is aligned with the International Accounting Standards Board’s revenue recognition standard issued on the same day. The guidance in the update states that revenue is recognized when a customer obtains control of a good or service. Recognition of the revenue will involve a multiple step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and then recognizing the revenue as the obligations are satisfied. Additional disclosures will be required to provide adequate information to understand the nature, amount, timing and uncertainty of reported revenues and revenues expected to be recognized. The accounting standards update will be effective on a retrospective or modified retrospective basis for annual reporting periods beginning after December 15, 2016, and interim periods within those years, with no early adoption permitted. At this point, we have not determined the impact of the new standard on our consolidated financial statements.
In April 2014, the FASB issued an accounting standards update that redefines the criteria for determining discontinued operations and introduces new disclosures related to these disposals. The updated definition of a discontinued operation is the disposal of a component (or components) of an entity or the classification of a component (or components) of an entity as held for sale that represents a strategic shift for an entity and has (or will have) a major impact on an entity’s operations and financial results. The standard requires disclosure of additional financial information for discontinued operations and individually material components not qualifying for discontinued operation presentation, as well as information regarding an entity’s continuing involvement with the discontinued operation. The accounting standards update is effective prospectively for annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted. Adoption of this standards update in the first quarter of 2015 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.
|
4.
|
MPLX LP
|
MPLX is a publicly traded master limited partnership that was formed by us to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products. In
October 2012
, MPLX completed its initial public offering of
19.9 million
common units. Net proceeds to MPLX from the sale of the units were
$407 million
.
As of
December 31, 2014
, we owned a
71.5 percent
interest in MPLX, including the
two percent
general partner interest. We consolidate this entity for financial reporting purposes since we have a controlling financial interest, and we record a noncontrolling interest for the interest owned by the public.
MPLX’s initial assets consisted of a
51 percent
general partner interest in MPLX Pipe Line Holdings LP (“Pipe Line Holdings”), which owns a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States, and a
100 percent
interest in a butane storage cavern in West Virginia. On May 1, 2013, we sold a
five percent
interest in Pipe Line Holdings to MPLX for
$100 million
of cash on-hand.
On March 1, 2014, we sold MPLX a
13 percent
interest in Pipe Line Holdings for
$310 million
. MPLX financed this transaction with
$40 million
of cash on-hand and
$270 million
of borrowings on its bank revolving credit agreement.
On December 1, 2014, we sold and contributed interests in Pipe Line Holdings totaling
30.5 percent
to MPLX for
$600 million
in cash and
2.9 million
MPLX common units valued at
$200 million
. MPLX financed the sales portion of this transaction with
$600 million
of borrowings on its bank revolving credit facility.
The sales and contribution of our interests in Pipe Line Holdings to MPLX resulted in a change of our ownership in Pipe Line Holdings, but not a change in control. We accounted for these sales as transactions between entities under common control and did not record a gain or loss.
On December 8, 2014, MPLX completed a public offering of
3.5 million
common units at a price to the public of
$66.68
per common unit, with net proceeds of
$221 million
. MPLX used the net proceeds from this offering to repay borrowings under its bank revolving credit facility and for general partnership purposes. On December 10, 2014, we exercised our right to maintain our two percent general partner interest in MPLX by purchasing
130 thousand
general partner units for
$9 million
.
Agreements
MPLX generates revenue primarily by charging tariffs for transporting crude oil, refined products and other hydrocarbon-based products through their pipelines and at their barge dock and fees for storing crude oil and products at their storage facilities. They are also the operator of additional crude oil and product pipelines owned by us and third parties for which they are paid operating fees. They do not take ownership of the crude oil or products that they transport and store for their customers, and they do not engage in the trading of any commodities.
84
We have various long-term, fee-based transportation and storage services agreements with MPLX. Under these agreements, MPLX provides transportation and storage services to us, and we commit to provide MPLX with minimum quarterly throughput volumes on crude oil and products systems and minimum storage volumes of crude oil, products and butane. We also have agreements with MPLX which establish fees for operational and management services provided between us and MPLX and for executive management services and certain general and administrative services provided by us to MPLX. These transactions are eliminated in consolidation.
|
5.
|
Acquisitions and Investments
|
Acquisition of Hess’ Retail Operations and Related Assets
On
September 30, 2014
, we acquired from Hess Corporation (“Hess”) all of Hess’ retail locations, transport operations and shipper history on various pipelines, including approximately
40,000
barrels per day on Colonial Pipeline, for
$2.82 billion
. We refer to these assets as “Hess’ Retail Operations and Related Assets.” The transaction was funded with a combination of debt and available cash.
The transaction provides for an adjustment for working capital, which has not been finalized with Hess. If a change is made for working capital, the fair value of the assets acquired and liabilities assumed will be revised.
The components of the fair value of consideration transferred are as follows:
|
(In millions)
|
|||
|
Cash
|
$
|
2,824
|
|
|
Net working capital adjustment estimate
|
(3
|
)
|
|
|
Total fair value of consideration transferred
|
$
|
2,821
|
|
During the fourth quarter of 2014, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. Updates to the preliminary fair value measurements of assets acquired and liabilities assumed were made during the fourth quarter of 2014. The following table summarizes the amounts assigned to the assets acquired and liabilities assumed as of the acquisition date.
|
(In millions)
|
|||
|
Cash and cash equivalents
|
$
|
49
|
|
|
Receivables
|
123
|
|
|
|
Inventories
|
165
|
|
|
|
Other current assets
|
8
|
|
|
|
Property, plant and equipment, net
|
2,063
|
|
|
|
Other noncurrent assets
|
111
|
|
|
|
Total assets acquired
|
2,519
|
|
|
|
Accounts payable
|
77
|
|
|
|
Payroll and benefits payable
|
15
|
|
|
|
Consumer excise taxes payable
|
64
|
|
|
|
Accrued taxes
|
4
|
|
|
|
Other current liabilities
|
10
|
|
|
|
Defined benefit postretirement plan obligations
|
2
|
|
|
|
Deferred credits and other liabilities
|
155
|
|
|
|
Total liabilities assumed
|
327
|
|
|
|
Net assets acquired excluding goodwill
|
2,192
|
|
|
|
Goodwill
|
629
|
|
|
|
Net assets acquired
|
$
|
2,821
|
|
85
The purchase price allocation resulted in the recognition of
$629 million
in goodwill by our Speedway segment, which is deductible for tax purposes. Goodwill recognized for the acquisition primarily relates to the expected benefits of a significantly expanded retail platform that should enable growth in new markets, as well as the potential for higher merchandise sales at the acquired locations. We also expect strategic benefits from the financial and operational scale we expect to realize across our entire retail network. This acquisition significantly expands our Speedway presence from
nine
to
22
states throughout the East Coast and Southeast and is aligned with our strategy to grow higher-valued, stable cash flow businesses. This acquisition also enables us to further leverage our integrated refining and transportation operations, providing an outlet for an incremental
200,000
barrels per day of assured sales from our refining system.
Other noncurrent assets includes a
$22 million
intangible asset related to a trade name and
$72 million
related to favorable lease contract terms. Deferred credits and other liabilities includes
$90 million
related to unfavorable lease contract terms. The trade name is being amortized over its estimated useful life of
two
years based on the utilization of the assets. The favorable and unfavorable lease contract amounts are being amortized over the terms of the leases.
We recognized
$14 million
of acquisition-related costs associated with Hess’ Retail Operations and Related Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses.
The amounts of revenue and income from operations associated with Hess’ Retail Operations and Related Assets included in our consolidated statements of income for 2014 are as follows:
|
(In millions)
|
2014
|
||
|
Sales and other operating revenues (including consumer excise taxes)
|
$
|
2,403
|
|
|
Income from operations
|
113
|
|
|
Acquisition of Refinery and Related Logistics and Marketing Assets
On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc. (collectively, “BP”) the
451,000
barrel per calendar day refinery in Texas City, Texas,
three
intrastate natural gas liquid pipelines originating at the refinery,
four
light product terminals, branded-jobber marketing contract assignments for the supply of approximately
1,200
branded sites, a
1,040
megawatt electric cogeneration facility and a
50,000
barrel per day allocation of space on the Colonial Pipeline. We refer to these assets as the “Galveston Bay Refinery and Related Assets.” We paid
$1.49 billion
for these assets, which included
$935 million
for inventory. The transaction was funded with cash on hand. Pursuant to the purchase and sale agreement, we may also be required to pay to BP a contingent earnout of up to an additional
$700 million
over
six years
. During 2014, we paid BP
$180 million
for the first period’s contingent earnout. On the consolidated statements of cash flows,
$172 million
of the contingent earnout payment is included as a financing activity with the remainder included as an operating activity. See Note
18
for additional information on the contingent consideration.
The transaction provided for a post-closing adjustment for inventory, which was finalized for
$9 million
, reducing our total consideration.
The components of the fair value of consideration transferred are as follows:
|
(In millions)
|
|||
|
Cash
|
$
|
1,491
|
|
|
Fair value of contingent consideration as of acquisition date
|
600
|
|
|
|
Payable to seller
|
6
|
|
|
|
Post-closing adjustment
|
(9
|
)
|
|
|
Total fair value of consideration transferred
|
$
|
2,088
|
|
86
During the fourth quarter of 2013, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. The following table summarizes the final amounts assigned to the assets acquired and liabilities assumed as of the acquisition date.
|
(In millions)
|
|||
|
Inventories
|
$
|
935
|
|
|
Other current assets
|
1
|
|
|
|
Property, plant and equipment, net
|
1,274
|
|
|
|
Other noncurrent assets
|
88
|
|
|
|
Total assets acquired
|
2,298
|
|
|
|
Accounts payable
|
12
|
|
|
|
Payroll and benefits payable
|
14
|
|
|
|
Long-term debt due within one year
(a)
|
2
|
|
|
|
Other current liabilities
|
6
|
|
|
|
Long-term debt
(a)
|
58
|
|
|
|
Defined benefit postretirement plan obligations
|
43
|
|
|
|
Deferred credits and other liabilities
|
75
|
|
|
|
Total liabilities assumed
|
210
|
|
|
|
Net assets acquired
|
$
|
2,088
|
|
|
(a)
|
Represents a capital lease obligation assumed.
|
Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the Galveston Bay Refinery and Related Assets acquisition.
Other noncurrent assets consist of a
$20 million
intangible asset related to customer relationships and a
$68 million
intangible asset related to prepaid licensed refinery technology agreements. The intangible assets related to customer relationships and prepaid licensed refinery technology agreements are being amortized on a straight-line basis over
four
and
15 years
, respectively. The weighted average life over which these acquired intangibles are being amortized is approximately
13 years
.
We recognized
$7 million
of acquisition-related costs associated with the Galveston Bay Refinery and Related Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses.
Our refineries and related assets are operated as an integrated system. As the information is not available by refinery, it is not practicable to disclose the revenues and net income associated with the acquisition that were included in our consolidated statements of income for 2013.
Unaudited Pro Forma Financial Information
The following unaudited pro forma financial information presents consolidated results assuming Hess’ Retail Operations and Related Assets acquisition occurred on January 1, 2013 and the Galveston Bay Refinery and Related Assets acquisition occurred on January 1, 2012. The pro forma financial information does not give effect to potential synergies that could result from the acquisitions and is not necessarily indicative of the results of future operations.
|
(In millions, except per share data)
|
2014
|
2013
|
|||||
|
Sales and other operating revenues (including consumer excise taxes)
|
$
|
106,482
|
|
$
|
114,148
|
|
|
|
Net income attributable to MPC
|
2,547
|
|
2,142
|
|
|||
|
Net income attributable to MPC per share – basic
|
$
|
8.94
|
|
$
|
6.80
|
|
|
|
Net income attributable to MPC per share – diluted
|
8.87
|
|
6.76
|
|
|||
The pro forma information includes adjustments to align accounting policies, an adjustment to depreciation expense to reflect the fair value of property, plant and equipment, increased amortization expense related to identifiable intangible assets, additional interest expense related to financing the acquisition of Hess’ Retail Operations and Related Assets, as well as the related income tax effects.
87
Acquisitions of Convenience Stores
During 2013, Speedway acquired
nine
convenience stores located in Tennessee, western Indiana and western Pennsylvania. In connection with these acquisitions, our Speedway segment recorded
$8 million
of goodwill.
In July 2012, Speedway acquired
10
convenience stores located in the northern Kentucky and southwestern Ohio regions from Road Ranger LLC in exchange for cash and a truck stop location in the Chicago metropolitan area. In connection with this acquisition, our Speedway segment recorded
$5 million
of goodwill.
In May 2012, Speedway acquired
87
convenience stores situated throughout Indiana and Ohio from GasAmerica Services, Inc., along with the associated inventory, intangible assets and
two
parcels of undeveloped real estate. In connection with this acquisition, our Speedway segment recorded
$83 million
of goodwill.
The goodwill associated with these acquisitions is deductible for income tax purposes.
These acquisitions support our strategic initiative to increase our Speedway segment sales and profitablity. The principal factors contributing to a purchase price resulting in goodwill included the acquired stores complementing our existing network in our Midwest market, access to our refined product transportation systems and the potential for higher merchandise sales.
Acquisition of Biodiesel Facility
On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for
$40 million
. The plant currently produces biodiesel, glycerin and other by-products. The production capacity of the plant is approximately
60 million
gallons per year.
Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the biodiesel facility acquisition.
Assuming the acquisitions of the convenience stores in 2013 and 2012 and the biodiesel facility in 2014 had been made at the beginning of any period presented, the consolidated pro forma results would not be materially different from reported results.
Investments in Ethanol Companies
On
August 1, 2013
, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in
three
ethanol companies for
$75 million
. Under the purchase agreement, we acquired an additional
24 percent
interest in The Andersons Clymers Ethanol LLC (“TACE”), bringing our ownership interest to
60 percent
; a
34 percent
interest in The Andersons Ethanol Investment LLC (“TAEI”), which holds a
50 percent
ownership in The Andersons Marathon Ethanol LLC (“TAME”), bringing our direct and indirect ownership interest in TAME to
67 percent
; and a
40 percent
interest in The Andersons Albion Ethanol LLC (“TAAE”), which owns an ethanol production facility in Albion, Michigan. On October 1, 2013, our ownership interest in TAAE increased to
43 percent
as a result of TAAE acquiring one of the owner’s interest. We hold a noncontrolling interest in each of these entities and account for them using the equity method of accounting since the minority owners have substantive participating rights.
Investment in Pipeline Companies
In July 2014, we exercised our option to acquire a
35 percent
ownership interest in Enbridge Inc.’s Southern Access Extension pipeline (“SAX”) through our investment in Illinois Extension Pipeline Company, LLC (“Illinois Extension Pipeline”). During
2014
, we made contributions of
$120 million
to Illinois Extension Pipeline to fund our portion of the construction costs incurred-to-date on the SAX project. We account for our ownership interest in Illinois Extension Pipeline as an equity method investment. See Note
26
for information on future contributions to Illinois Extension Pipeline.
In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional
seven percent
interest in Explorer Pipeline Company (“Explorer”) for
$77 million
, bringing our ownership interest to
25 percent
. As a result of this increase in our ownership, we now account for our investment in Explorer using the equity method of accounting rather than the cost method. The cumulative impact of the change was applied as an adjustment to 2014 retained earnings.
In November 2013, we agreed to serve as an anchor shipper for the Sandpiper pipeline project and fund
37.5 percent
of the construction costs of the project, which will become part of Enbridge Energy Partners L.P.’s (“Enbridge Energy Partners”) North Dakota System. In exchange for these commitments, we will earn an approximate
27 percent
equity interest in Enbridge Energy Partners’ North Dakota System when the Sandpiper pipeline is placed into service, which is expected to be in 2017. We also have the option to increase our ownership interest to approximately
30 percent
through additional investments in future system improvements. We made contributions of
$192 million
to North Dakota Pipeline Company LLC (“North Dakota Pipeline”) during
2014
. We have contributed
$216 million
since project inception. We account for our interest in North Dakota Pipeline using the equity method of accounting. See Note
26
for information on future contributions to North Dakota Pipeline.
88
|
6.
|
Disposition
|
On December 1, 2010, we completed the sale of most of our Minnesota assets. These assets included the
74,000
barrel per calendar day St. Paul Park refinery and associated terminals,
166
convenience stores primarily branded SuperAmerica
®
(including
six
stores in Wisconsin), along with the SuperMom’s bakery (a baked goods and sandwich supply operation) and certain associated trademarks, SuperAmerica Franchising LLC, interests in pipeline assets in Minnesota and associated inventories. We refer to these assets as the “Minnesota Assets.”
In July 2012, the buyer of our Minnesota Assets successfully completed an initial public offering (“IPO”). The successful completion of this IPO triggered the provisions in our May 4, 2012 settlement agreement with the buyer to be effective. Under the settlement agreement, we were released from our obligation to pay margin support and the buyer was released from its obligation to pay us under the earnout provision contained in the original sales agreement. Also, the buyer redeemed our
$80 million
preferred equity interest, paid us
$12 million
for dividends accrued on our preferred equity interest and paid us
$40 million
of cash, for total cash receipts of
$132 million
. In addition, the buyer issued us a new preferred security valued at
$45 million
. As a result, we recognized income before income taxes of approximately
$183 million
during 2012, which included
$86 million
of the deferred gain that was recorded when the sale transaction was originally closed.
During 2013, the buyer redeemed the second preferred security for
$49 million
, which included
$4 million
of accrued distributions.
|
7.
|
Variable Interest Entity
|
As stated in Note
5
, we have a 35 percent ownership interest in Illinois Extension Pipeline through our contributions to the SAX project. Illinois Extension Pipeline Company LLC is considered a variable interest entity (“VIE”) because it is a development stage entity and the equity in the entity is not sufficient to fund the current stage of development, which is the construction of the SAX pipeline. Our maximum exposure to loss due to this VIE at
December 31, 2014
was
$120 million
, which equates to our contributions to-date to fund our portion of the construction costs for the project.
We are not the primary beneficiary of this VIE and, therefore, do not consolidate it because we do not have the power to control the activities that significantly influence the economic activities of the entity. The activities that most significantly impact the VIE’s economic performance during the construction phase are the actual construction costs and risks associated with the construction process. Through our vote, we have shared power to direct the construction activities, but do not have the sole ability to control the construction activities.
|
8.
|
Related Party Transactions
|
Our related parties included:
|
•
|
Centennial Pipeline LLC (“Centennial”), in which we have a
50 percent
noncontrolling interest. Centennial owns a refined products pipeline and storage facility.
|
|
•
|
Explorer, in which we have a
25 percent
interest. Explorer owns and operates a refined products pipeline.
|
|
•
|
LOCAP LLC (“LOCAP”), in which we have a
59 percent
noncontrolling interest. LOCAP owns and operates a crude oil pipeline.
|
|
•
|
LOOP LLC (“LOOP”), in which we have a
51 percent
noncontrolling interest. LOOP owns and operates the only U.S. deepwater oil port.
|
|
•
|
TAAE, in which we have a
43 percent
interest, TACE, in which we have a
60 percent
noncontrolling interest, and TAME, in which we have a
67 percent
direct and indirect noncontrolling interest. These companies each own an ethanol production facility.
|
|
•
|
Other equity method investees.
|
We believe that transactions with related parties were conducted on terms comparable to those with unaffiliated parties.
89
Sales to related parties, which are included in sales and other operating revenues (including consumer excise taxes) on the consolidated statements of income, were as follows:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Centennial
|
$
|
—
|
|
$
|
—
|
|
$
|
1
|
|
||
|
Other equity method investees
|
7
|
|
8
|
|
7
|
|
|||||
|
Total
|
$
|
7
|
|
$
|
8
|
|
$
|
8
|
|
||
Related party sales to Centennial consist primarily of petroleum products.
The fees received for operating Centennial’s pipeline, which are included in other income on the consolidated statements of income, were
$1 million
in
2014
,
2013
and
2012
.
Purchases from related parties were as follows:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Centennial
|
$
|
7
|
|
$
|
3
|
|
$
|
7
|
|
||
|
Explorer
|
39
|
|
—
|
|
—
|
|
|||||
|
LOCAP
|
21
|
|
17
|
|
24
|
|
|||||
|
LOOP
|
88
|
|
43
|
|
44
|
|
|||||
|
TAAE
|
79
|
|
24
|
|
—
|
|
|||||
|
TACE
|
121
|
|
130
|
|
73
|
|
|||||
|
TAME
|
141
|
|
131
|
|
124
|
|
|||||
|
Other equity method investees
|
9
|
|
9
|
|
8
|
|
|||||
|
Total
|
$
|
505
|
|
$
|
357
|
|
$
|
280
|
|
||
Related party purchases from Centennial consist primarily of refinery feedstocks and refined product transportation costs. Related party purchases from Explorer consist primarily of refined product transportation costs. Related party purchases from LOCAP, LOOP and other equity method investees consist primarily of crude oil transportation costs. Related party purchases from TAAE, TACE and TAME consist of ethanol purchases.
Receivables from related parties, which are included in receivables, less allowance for doubtful accounts on the consolidated balance sheets, were as follows:
|
December 31,
|
|||||||
|
(In millions)
|
2014
|
2013
|
|||||
|
Centennial
|
$
|
2
|
|
$
|
1
|
|
|
|
Explorer
|
2
|
|
—
|
|
|||
|
TAME
|
3
|
|
1
|
|
|||
|
Total
|
$
|
7
|
|
$
|
2
|
|
|
Long-term receivable from Centennial, which is included in other noncurrent assets on the consolidated balance sheet, was less than
$1 million
at
December 31, 2014
and
$2 million
at
December 31, 2013
.
90
Payables to related parties, which are included in accounts payable on the consolidated balance sheets, were as follows:
|
December 31,
|
|||||||
|
(In millions)
|
2014
|
2013
|
|||||
|
Explorer
|
$
|
3
|
|
$
|
—
|
|
|
|
LOCAP
|
2
|
|
2
|
|
|||
|
LOOP
|
4
|
|
3
|
|
|||
|
TAAE
|
2
|
|
2
|
|
|||
|
TACE
|
2
|
|
4
|
|
|||
|
TAME
|
5
|
|
5
|
|
|||
|
Total
|
$
|
18
|
|
$
|
16
|
|
|
|
9.
|
Income per Common Share
|
We compute basic earnings per share by dividing net income attributable to MPC by the weighted average number of shares of common stock outstanding. Diluted income per share assumes exercise of certain stock based compensation awards, provided the effect is not anti-dilutive.
MPC grants certain incentive compensation awards to employees and non-employee directors that are considered to be participating securities. Due to the presence of participating securities, we have calculated our earnings per share using the two-class method.
|
(In millions, except per share data)
|
2014
|
2013
|
2012
|
||||||||
|
Basic earnings per share:
|
|||||||||||
|
Allocation of earnings:
|
|||||||||||
|
Net income attributable to MPC
|
$
|
2,524
|
|
$
|
2,112
|
|
$
|
3,389
|
|
||
|
Income allocated to participating securities
|
4
|
|
4
|
|
6
|
|
|||||
|
Income available to common stockholders – basic
|
$
|
2,520
|
|
$
|
2,108
|
|
$
|
3,383
|
|
||
|
Weighted average common shares outstanding
|
285
|
|
315
|
|
340
|
|
|||||
|
Basic earnings per share
|
$
|
8.84
|
|
$
|
6.69
|
|
$
|
9.95
|
|
||
|
Diluted earnings per share:
|
|||||||||||
|
Allocation of earnings:
|
|||||||||||
|
Net income attributable to MPC
|
$
|
2,524
|
|
$
|
2,112
|
|
$
|
3,389
|
|
||
|
Income allocated to participating securities
|
4
|
|
4
|
|
6
|
|
|||||
|
Income available to common stockholders – diluted
|
$
|
2,520
|
|
$
|
2,108
|
|
$
|
3,383
|
|
||
|
Weighted average common shares outstanding
|
285
|
|
315
|
|
340
|
|
|||||
|
Effect of dilutive securities
|
2
|
|
2
|
|
2
|
|
|||||
|
Weighted average common shares, including dilutive effect
|
287
|
|
317
|
|
342
|
|
|||||
|
Diluted earnings per share
|
$
|
8.78
|
|
$
|
6.64
|
|
$
|
9.89
|
|
||
The following table summarizes the shares that were anti-dilutive, and therefore, were excluded from the diluted share calculation.
|
(In millions)
|
2014
|
2013
|
2012
|
|||||
|
Shares issued under stock-based compensation plans
|
—
|
|
—
|
|
2
|
|
||
91
|
10.
|
Equity
|
On July 30, 2014, our board of directors approved an additional
$2.0 billion
share repurchase authorization expiring in
July 2016
. As of
December 31, 2014
, our board of directors had approved
$8.0 billion
in total share repurchase authorizations since January 1, 2012 and we have repurchased a total of
$6.27 billion
of our common stock under these authorizations, leaving
$1.73 billion
available for repurchases. Under these authorizations, we have acquired
89 million
shares at an average cost per share of
$70.35
.
We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated share repurchases or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.
In February 2012 and November 2012, we entered into
$850 million
and
$500 million
accelerated share repurchase (“ASR”) programs, respectively, to repurchase shares of MPC common stock under the approved share repurchase plan authorized by our board of directors. The total number of shares repurchased under these ASR programs was based generally on the volume-weighted average price of our common stock during the repurchase periods. The shares repurchased under the ASR programs were accounted for as treasury stock purchase transactions, reducing the weighted average number of basic and diluted common shares outstanding by the shares repurchased, and as forward contracts indexed to our common stock. The forward contracts were accounted for as equity instruments.
Total share repurchases were as follows for the respective periods:
|
(In millions, except per share data)
|
2014
|
2013
|
2012
|
||||||||
|
Number of shares repurchased
(a)
|
24
|
|
37
|
|
28
|
|
|||||
|
Cash paid for shares repurchased
|
$
|
2,131
|
|
$
|
2,793
|
|
$
|
1,350
|
|
||
|
Effective average cost per delivered share
|
$
|
88.63
|
|
$
|
76.14
|
|
$
|
46.73
|
|
||
|
(a)
|
Shares repurchased in 2013 includes
1 million
shares received under the November 2012 ASR program, which were paid for in 2012.
|
At
December 31, 2014
, we had agreements to acquire
99,084
common shares for
$9 million
, which were settled in early January 2015.
|
11.
|
Segment Information
|
We have
three
reportable segments: Refining & Marketing; Speedway; and Pipeline Transportation. Each of these segments is organized and managed based upon the nature of the products and services it offers.
|
•
|
Refining & Marketing – refines crude oil and other feedstocks at our refineries in the Gulf Coast and Midwest regions of the United States, purchases ethanol and refined products for resale and distributes refined products through various means, including barges, terminals and trucks that we own or operate. We sell refined products to wholesale marketing customers domestically and internationally, buyers on the spot market, our Speedway segment and to independent entrepreneurs who operate Marathon
®
retail outlets.
|
|
•
|
Speedway – sells transportation fuels and convenience products in retail markets in the Midwest, East Coast and Southeast.
|
|
•
|
Pipeline Transportation – transports crude oil and other feedstocks to our refineries and other locations, delivers refined products to wholesale and retail market areas and includes the aggregated operations of MPLX.
|
On September 30, 2014, we acquired Hess’ Retail Operations and Related Assets, which are part of the Speedway and Refining & Marketing segments. On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets, which are part of the Refining & Marketing and Pipeline Transportation segments. Segment information for periods prior to each acquisition does not include amounts for these operations. See Note
5
.
Segment income represents income from operations attributable to the reportable segments. Corporate administrative expenses and costs related to certain non-operating assets are not allocated to the reportable segments. In addition, certain items that affect comparability (as determined by the chief operating decision maker) are not allocated to the reportable segments.
92
|
(In millions)
|
Refining & Marketing
|
Speedway
|
Pipeline Transportation
|
Total
|
|||||||||||
|
Year Ended December 31, 2014
|
|||||||||||||||
|
Revenues:
|
|||||||||||||||
|
Customer
|
$
|
80,822
|
|
$
|
16,927
|
|
$
|
70
|
|
$
|
97,819
|
|
|||
|
Intersegment
(a)
|
10,912
|
|
5
|
|
527
|
|
11,444
|
|
|||||||
|
Segment revenues
|
$
|
91,734
|
|
$
|
16,932
|
|
$
|
597
|
|
$
|
109,263
|
|
|||
|
Segment income from operations
(b)
|
$
|
3,609
|
|
$
|
544
|
|
$
|
280
|
|
$
|
4,433
|
|
|||
|
Income from equity method investments
|
96
|
|
—
|
|
57
|
|
153
|
|
|||||||
|
Depreciation and amortization
(c)
|
1,045
|
|
152
|
|
77
|
|
1,274
|
|
|||||||
|
Capital expenditures and investments
(d)(e)
|
1,104
|
|
2,981
|
|
543
|
|
4,628
|
|
|||||||
|
(In millions)
|
Refining & Marketing
|
Speedway
|
Pipeline Transportation
|
Total
|
|||||||||||
|
Year Ended December 31, 2013
|
|||||||||||||||
|
Revenues:
|
|||||||||||||||
|
Customer
|
$
|
85,616
|
|
$
|
14,471
|
|
$
|
79
|
|
$
|
100,166
|
|
|||
|
Intersegment
(a)
|
9,294
|
|
4
|
|
458
|
|
9,756
|
|
|||||||
|
Segment revenues
|
$
|
94,910
|
|
$
|
14,475
|
|
$
|
537
|
|
$
|
109,922
|
|
|||
|
Segment income from operations
(b)
|
$
|
3,206
|
|
$
|
375
|
|
$
|
210
|
|
$
|
3,791
|
|
|||
|
Income from equity method investments
|
28
|
|
—
|
|
8
|
|
36
|
|
|||||||
|
Depreciation and amortization
(c)
|
1,011
|
|
112
|
|
74
|
|
1,197
|
|
|||||||
|
Capital expenditures and investments
(d)(f)
|
2,094
|
|
296
|
|
234
|
|
2,624
|
|
|||||||
|
(In millions)
|
Refining & Marketing
|
Speedway
|
Pipeline Transportation
|
Total
|
|||||||||||
|
Year Ended December 31, 2012
|
|||||||||||||||
|
Revenues:
|
|||||||||||||||
|
Customer
|
$
|
67,928
|
|
$
|
14,239
|
|
$
|
78
|
|
$
|
82,245
|
|
|||
|
Intersegment
(a)
|
8,782
|
|
4
|
|
381
|
|
9,167
|
|
|||||||
|
Segment revenues
|
$
|
76,710
|
|
$
|
14,243
|
|
$
|
459
|
|
$
|
91,412
|
|
|||
|
Segment income from operations
(b)
|
$
|
5,098
|
|
$
|
310
|
|
$
|
216
|
|
$
|
5,624
|
|
|||
|
Income (loss) from equity method investments
|
(6
|
)
|
—
|
|
32
|
|
26
|
|
|||||||
|
Depreciation and amortization
(c)
|
804
|
|
114
|
|
54
|
|
972
|
|
|||||||
|
Capital expenditures and investments
(d)
|
705
|
|
340
|
|
211
|
|
1,256
|
|
|||||||
|
(a)
|
Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties.
|
|
(b)
|
Included in the Pipeline Transportation segment for
2014
,
2013
and
2012
are
$19 million
,
$20 million
and
$4 million
of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments.
|
|
(c)
|
Differences between segment totals and MPC totals represent amounts related to unallocated items and are included in “Items not allocated to segments” in the reconciliation below.
|
|
(d)
|
Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates.
|
|
(e)
|
The Speedway and Refining & Marketing segments include
$2.66 billion
and
$52 million
, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. See Note
5
.
|
|
(f)
|
The Refining & Marketing and Pipeline Transportation segments include
$1.29 billion
and
$70 million
, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note
5
.
|
93
The following reconciles segment income from operations to income before income taxes as reported in the consolidated statements of income:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Segment income from operations
|
$
|
4,433
|
|
$
|
3,791
|
|
$
|
5,624
|
|
||
|
Items not allocated to segments:
|
|||||||||||
|
Corporate and other unallocated items
(a)(b)
|
(286
|
)
|
(271
|
)
|
(336
|
)
|
|||||
|
Minnesota Assets sale settlement gain
(c)
|
—
|
|
—
|
|
183
|
|
|||||
|
Pension settlement expenses
(d)
|
(96
|
)
|
(95
|
)
|
(124
|
)
|
|||||
|
Net interest and other financial income (costs)
|
(216
|
)
|
(179
|
)
|
(109
|
)
|
|||||
|
Income before income taxes
|
$
|
3,835
|
|
$
|
3,246
|
|
$
|
5,238
|
|
||
|
(a)
|
Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets.
|
|
(b)
|
Corporate overhead expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments.
|
|
(c)
|
See Note
6
.
|
|
(d)
|
See Note
23
.
|
The following reconciles segment capital expenditures and investments to total capital expenditures:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Segment capital expenditures and investments
|
$
|
4,628
|
|
$
|
2,624
|
|
$
|
1,256
|
|
||
|
Less: Investments in equity method investees
|
413
|
|
124
|
|
28
|
|
|||||
|
Plus: Items not allocated to segments:
|
|||||||||||
|
Capital expenditures not allocated to segments
|
83
|
|
137
|
|
103
|
|
|||||
|
Capitalized interest
|
27
|
|
28
|
|
101
|
|
|||||
|
Total capital expenditures
(a)(b)
|
$
|
4,325
|
|
$
|
2,665
|
|
$
|
1,432
|
|
||
|
(a)
|
Capital expenditures include changes in capital accruals.
|
|
(b)
|
See Note
21
for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.
|
The following reconciles total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Customer revenues
|
$
|
97,819
|
|
$
|
100,166
|
|
$
|
82,245
|
|
||
|
Corporate and other unallocated items
|
(2
|
)
|
(6
|
)
|
(2
|
)
|
|||||
|
Sales and other operating revenues (including consumer excise taxes)
|
$
|
97,817
|
|
$
|
100,160
|
|
$
|
82,243
|
|
||
Revenues by product line were:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Refined products
|
$
|
90,702
|
|
$
|
93,520
|
|
$
|
76,234
|
|
||
|
Merchandise
|
3,817
|
|
3,308
|
|
3,229
|
|
|||||
|
Crude oil and refinery feedstocks
|
2,917
|
|
2,988
|
|
2,514
|
|
|||||
|
Transportation and other
|
381
|
|
344
|
|
266
|
|
|||||
|
Sales and other operating revenues (including consumer excise taxes)
|
$
|
97,817
|
|
$
|
100,160
|
|
$
|
82,243
|
|
||
No single customer accounted for more than
10 percent
of annual revenues for the years ended
December 31, 2014
and
2012
. Revenue from BP p.l.c. included in the Refining & Marketing segment represented
10 percent
of our total annual revenues for the year ended
December 31, 2013
.
We do not have significant operations in foreign countries. Therefore, revenues in foreign countries and long-lived assets located in foreign countries, including property, plant and equipment and investments, are not material to our operations.
94
Total assets by reportable segment were:
|
December 31,
|
|||||||
|
(In millions)
|
2014
|
2013
|
|||||
|
Refining & Marketing
|
$
|
19,751
|
|
$
|
19,573
|
|
|
|
Speedway
|
5,296
|
|
2,064
|
|
|||
|
Pipeline Transportation
|
2,407
|
|
1,947
|
|
|||
|
Corporate and Other
|
3,006
|
|
4,801
|
|
|||
|
Total consolidated assets
|
$
|
30,460
|
|
$
|
28,385
|
|
|
|
12.
|
Other Items
|
Net interest and other financial income (costs) was:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Interest income
|
$
|
7
|
|
$
|
9
|
|
$
|
6
|
|
||
|
Interest expense
|
(229
|
)
|
(195
|
)
|
(191
|
)
|
|||||
|
Interest capitalized
|
27
|
|
28
|
|
101
|
|
|||||
|
Other financial costs
|
(21
|
)
|
(21
|
)
|
(25
|
)
|
|||||
|
Net interest and other financial income (costs)
|
$
|
(216
|
)
|
$
|
(179
|
)
|
$
|
(109
|
)
|
||
|
13.
|
Income Taxes
|
Income tax provisions (benefits) were:
|
|
2014
|
2013
|
2012
|
||||||||||||||||||||||||||||||||
|
(In millions)
|
Current
|
Deferred
|
Total
|
Current
|
Deferred
|
Total
|
Current
|
Deferred
|
Total
|
||||||||||||||||||||||||||
|
Federal
|
$
|
1,382
|
|
$
|
(199
|
)
|
$
|
1,183
|
|
$
|
954
|
|
$
|
20
|
|
$
|
974
|
|
$
|
1,185
|
|
$
|
432
|
|
$
|
1,617
|
|
||||||||
|
State and local
|
135
|
|
(37
|
)
|
98
|
|
131
|
|
8
|
|
139
|
|
169
|
|
57
|
|
226
|
|
|||||||||||||||||
|
Foreign
|
5
|
|
(6
|
)
|
(1
|
)
|
5
|
|
(5
|
)
|
—
|
|
(1
|
)
|
3
|
|
2
|
|
|||||||||||||||||
|
Total
|
$
|
1,522
|
|
$
|
(242
|
)
|
$
|
1,280
|
|
$
|
1,090
|
|
$
|
23
|
|
$
|
1,113
|
|
$
|
1,353
|
|
$
|
492
|
|
$
|
1,845
|
|
||||||||
A reconciliation of the federal statutory income tax rate (
35 percent
) applied to income before income taxes to the provision for income taxes follows:
|
2014
|
2013
|
2012
|
||||||
|
Statutory rate applied to income before income taxes
|
35
|
%
|
35
|
%
|
35
|
%
|
||
|
State and local income taxes, net of federal income tax effects
|
2
|
|
3
|
|
2
|
|
||
|
Domestic manufacturing deduction
|
(2
|
)
|
(2
|
)
|
(1
|
)
|
||
|
Other
|
(2
|
)
|
(2
|
)
|
(1
|
)
|
||
|
Provision for income taxes
|
33
|
%
|
34
|
%
|
35
|
%
|
||
95
Deferred tax assets and liabilities resulted from the following:
|
December 31,
|
|||||||
|
(In millions)
|
2014
|
2013
|
|||||
|
Deferred tax assets:
|
|||||||
|
Employee benefits
|
$
|
616
|
|
$
|
483
|
|
|
|
Environmental
|
54
|
|
37
|
|
|||
|
Investments in subsidiaries and affiliates
|
24
|
|
—
|
|
|||
|
Other
|
70
|
|
49
|
|
|||
|
Total deferred tax assets
|
764
|
|
569
|
|
|||
|
Deferred tax liabilities:
|
|||||||
|
Property, plant and equipment
|
2,411
|
|
2,290
|
|
|||
|
Inventories
|
614
|
|
614
|
|
|||
|
Investments in subsidiaries and affiliates
|
—
|
|
267
|
|
|||
|
Other
|
101
|
|
70
|
|
|||
|
Total deferred tax liabilities
|
3,126
|
|
3,241
|
|
|||
|
Net deferred tax liabilities
|
$
|
2,362
|
|
$
|
2,672
|
|
|
Net deferred tax liabilities were classified in the consolidated balance sheets as follows:
|
December 31,
|
|||||||
|
(In millions)
|
2014
|
2013
|
|||||
|
Assets:
|
|||||||
|
Other noncurrent assets
|
$
|
7
|
|
$
|
2
|
|
|
|
Liabilities:
|
|||||||
|
Accrued taxes
|
355
|
|
370
|
|
|||
|
Deferred income taxes
|
2,014
|
|
2,304
|
|
|||
|
Net deferred tax liabilities
|
$
|
2,362
|
|
$
|
2,672
|
|
|
Tax carryforwards
– At December 31, 2014, our federal operating loss carryforwards included
$11 million
acquired with the biodiesel facility acquisition, which expire in
2022
through
2034
. State and local operating loss carryforwards of
$1 million
expire in
2015
through
2029
.
Valuation allowances
– As of December 31, 2014 and 2013,
$4 million
and
$3 million
of valuation allowances were recognized related to income taxes. A federal valuation allowance was established for both
December 31, 2014
and
2013
of
$3 million
, primarily due to the expected realizability of foreign tax credits. A state and local valuation allowance was established as of
December 31, 2014
of
$1 million
, based on estimates of future financial income and expected realizability of state and local tax operating losses.
MPC is continuously undergoing examination of its U.S. federal income tax returns by the Internal Revenue Service. Such audits have been completed through the 2009 tax year. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. Further, we are routinely involved in U.S. state income tax audits. We believe all other audits will be resolved with the amounts paid and/or provided for these liabilities. As of
December 31, 2014
, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:
|
United States Federal
|
2010
|
-
|
2013
|
|
States
|
2004
|
-
|
2013
|
96
As a result of the Spinoff and pursuant to the tax sharing agreement by Marathon Oil and MPC, the unrecognized tax benefits related to MPC operations for which Marathon Oil was the taxpayer remain the responsibility of Marathon Oil and MPC has indemnified Marathon Oil. During 2013, we settled with Marathon Oil our U.S. federal and related state return liabilities for the 2008-2009 tax years, resulting in a reduction in unrecognized tax benefits of
$21 million
, which are also reflected in the table below as settlements.
During 2013, we settled with Marathon Oil for the 2011 period prior to the spinoff based on filed tax returns and in accordance with the tax sharing agreement, resulting in a
$39 million
increase to additional paid-in capital.
The following table summarizes the activity in unrecognized tax benefits:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
January 1 balance
|
$
|
13
|
|
$
|
40
|
|
$
|
20
|
|
||
|
Additions for tax positions of prior years
|
7
|
|
30
|
|
32
|
|
|||||
|
Reductions for tax positions of prior years
|
(10
|
)
|
(25
|
)
|
(6
|
)
|
|||||
|
Settlements
|
2
|
|
(30
|
)
|
(6
|
)
|
|||||
|
Statute of limitations
|
—
|
|
(2
|
)
|
—
|
|
|||||
|
December 31 balance
|
$
|
12
|
|
$
|
13
|
|
$
|
40
|
|
||
If the unrecognized tax benefits as of
December 31, 2014
were recognized,
$5 million
would affect our effective income tax rate. There were
$4 million
of uncertain tax positions as of
December 31, 2014
for which it is reasonably possible that the amount of unrecognized tax benefits would significantly decrease during the next twelve months.
Interest and penalties related to income taxes are recorded as part of the provision for income taxes. Such interest and penalties were net receipts (expenses) of less than
$1 million
, (
$11 million
) and
$1 million
in
2014
,
2013
and
2012
, respectively. As of
December 31, 2014
and
2013
,
$14 million
and
$15 million
of interest and penalties were accrued related to income taxes.
|
14.
|
Inventories
|
|
December 31,
|
|||||||
|
(In millions)
|
2014
|
2013
|
|||||
|
Crude oil and refinery feedstocks
|
$
|
2,219
|
|
$
|
1,797
|
|
|
|
Refined products
|
2,955
|
|
2,367
|
|
|||
|
Materials and supplies
|
302
|
|
425
|
|
|||
|
Merchandise
|
166
|
|
100
|
|
|||
|
Total (at cost)
|
$
|
5,642
|
|
$
|
4,689
|
|
|
The LIFO method accounted for
94 percent
and
90 percent
of total inventory value at
December 31, 2014
and
2013
, respectively. Current acquisition costs of inventories were estimated to exceed the LIFO inventory value at
December 31, 2014
and
2013
by
$684 million
and
$4,084 million
, respectively. There were no liquidations of LIFO inventories in
2014
,
2013
and
2012
.
97
|
15.
|
Equity Method Investments
|
|
Ownership as of
|
Carrying value at
|
||||||||
|
December 31,
|
December 31,
|
||||||||
|
(In millions)
|
2014
|
2014
|
2013
|
||||||
|
Centennial
|
50%
|
$
|
36
|
|
$
|
29
|
|
||
|
Explorer
|
25%
|
95
|
|
—
|
|
||||
|
Illinois Extension Pipeline
|
35%
|
120
|
|
—
|
|
||||
|
LOCAP
|
59%
|
23
|
|
24
|
|
||||
|
LOOP
|
51%
|
230
|
|
214
|
|
||||
|
North Dakota Pipeline
(a)
|
38%
|
216
|
|
24
|
|
||||
|
TAAE
|
43%
|
22
|
|
29
|
|
||||
|
TACE
|
60%
|
61
|
|
70
|
|
||||
|
TAEI
|
34%
|
19
|
|
23
|
|
||||
|
TAME
(b)
|
50%
|
24
|
|
35
|
|
||||
|
Other
|
19
|
|
15
|
|
|||||
|
Total
|
$
|
865
|
|
$
|
463
|
|
|||
|
(a)
|
We own a
38
percent interest in the Class B units of this entity. Our Class B units will be converted to an approximate
27
percent ownership interest in the Class A units of this entity upon completion of the Sandpiper pipeline construction project, which is expected to be in 2017.
|
|
(b)
|
Excludes TAEI’s investment in TAME.
|
Summarized financial information for equity method investees is as follows:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Income statement data:
|
|||||||||||
|
Revenues and other income
|
$
|
1,430
|
|
$
|
1,067
|
|
$
|
1,025
|
|
||
|
Income from operations
|
379
|
|
87
|
|
73
|
|
|||||
|
Net income
|
316
|
|
63
|
|
47
|
|
|||||
|
Balance sheet data – December 31:
|
|||||||||||
|
Current assets
|
$
|
990
|
|
$
|
339
|
|
|||||
|
Noncurrent assets
|
2,166
|
|
1,238
|
|
|||||||
|
Current liabilities
|
280
|
|
145
|
|
|||||||
|
Noncurrent liabilities
|
957
|
|
618
|
|
|||||||
As of
December 31, 2014
, the carrying value of our equity method investments was
$110 million
higher than the underlying net assets of investees. This basis difference is being amortized or accreted into net income over the remaining estimated useful lives of the underlying net assets, except for
$55 million
of excess related to goodwill.
Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued through 2014. At December 31, 2014, Centennial was not shipping product. As a result, we continued to evaluate the carrying value of our equity investment in Centennial and concluded that no impairment was required given our assessment of its fair value based on market participant assumptions for various potential uses of Centennial’s assets. If market conditions were to change and the owners of Centennial are unable to find an alternative use for the assets, there could be a future impairment of our Centennial interest. As of
December 31, 2014
, our equity investment in Centennial was
$36 million
and we had a
$38 million
guarantee associated with
50 percent
of Centennial’s outstanding debt. See Note
26
for additional information on the debt guarantee.
Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were
$170 million
,
$18 million
and
$37 million
in
2014
,
2013
and
2012
.
98
|
16.
|
Property, Plant and Equipment
|
|
(In millions)
|
Estimated
Useful Lives
|
December 31,
|
|||||||
|
2014
|
2013
|
||||||||
|
Refining & Marketing
|
4 - 25 years
|
$
|
18,001
|
|
$
|
16,982
|
|
||
|
Speedway
|
4 - 25 years
|
4,639
|
|
2,344
|
|
||||
|
Pipeline Transportation
|
16 - 42 years
|
2,044
|
|
1,921
|
|
||||
|
Corporate and Other
|
4 - 40 years
|
618
|
|
546
|
|
||||
|
Total
|
25,302
|
|
21,793
|
|
|||||
|
Less accumulated depreciation
|
9,041
|
|
7,872
|
|
|||||
|
Property, plant and equipment, net
|
$
|
16,261
|
|
$
|
13,921
|
|
|||
Property, plant and equipment includes gross assets acquired under capital leases of
$510 million
at both
December 31, 2014
and
2013
, with related amounts in accumulated depreciation of
$144 million
and
$111 million
at
December 31, 2014
and
2013
. Property, plant and equipment includes construction in progress of
$1,043 million
and
$747 million
at
December 31, 2014
and
2013
, which primarily relates to refinery projects.
Construction in progress at
December 31, 2014
includes
$90 million
of costs associated with a residual fuel hydrocracker project at our Garyville refinery, intended to increase margins by upgrading residual fuel to ultra-low sulfur diesel and gas oil. We are deferring a final investment decision on this project with estimated total costs of
$2.2 billion
to
$2.5 billion
as we further evaluate the implications of current market conditions on the project. If a decision is made to not pursue this project, there could be a future impairment of the costs incurred for the project.
|
17.
|
Goodwill
|
Goodwill is tested for impairment on an annual basis and when events or changes in circumstances indicate the fair value of a reporting unit with goodwill has been reduced below the carrying value. We performed our annual impairment tests for
2014
and
2013
, and no impairment was required.
The changes in the carrying amount of goodwill for
2014
and
2013
were as follows:
|
(In millions)
|
Refining & Marketing
|
Speedway
|
Pipeline Transportation
|
Total
|
|||||||||||
|
2013
|
|||||||||||||||
|
Beginning balance
|
$
|
551
|
|
$
|
217
|
|
$
|
162
|
|
$
|
930
|
|
|||
|
Acquisitions
(a)
|
—
|
|
8
|
|
—
|
|
8
|
|
|||||||
|
Ending balance
|
$
|
551
|
|
$
|
225
|
|
$
|
162
|
|
$
|
938
|
|
|||
|
2014
|
|||||||||||||||
|
Beginning balance
|
$
|
551
|
|
$
|
225
|
|
$
|
162
|
|
$
|
938
|
|
|||
|
Acquisitions
(a)
|
—
|
|
629
|
|
—
|
|
629
|
|
|||||||
|
Disposition
|
(1
|
)
|
—
|
|
—
|
|
(1
|
)
|
|||||||
|
Ending balance
|
$
|
550
|
|
$
|
854
|
|
$
|
162
|
|
|
$
|
1,566
|
|
||
|
(a)
|
See Note
5
for information on the acquisitions.
|
99
|
18.
|
Fair Value Measurements
|
Fair Values – Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of
December 31, 2014
and
2013
by fair value hierarchy level. We have elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty, including any related cash collateral as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the following tables.
|
December 31, 2014
|
|||||||||||||||||||||||
|
Fair Value Hierarchy
|
|||||||||||||||||||||||
|
(In millions)
|
Level 1
|
Level 2
|
Level 3
|
Netting and Collateral
(a)
|
Net Carrying Value on Balance Sheet
(b)
|
Collateral Pledged Not Offset
|
|||||||||||||||||
|
Commodity derivative instruments, assets
|
$
|
317
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(258
|
)
|
$
|
59
|
|
$
|
—
|
|
|||||
|
Other assets
|
2
|
|
—
|
|
—
|
|
N/A
|
|
2
|
|
—
|
|
|||||||||||
|
Total assets at fair value
|
$
|
319
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(258
|
)
|
$
|
61
|
|
$
|
—
|
|
|||||
|
Commodity derivative instruments, liabilities
|
$
|
180
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(180
|
)
|
$
|
—
|
|
$
|
—
|
|
|||||
|
Contingent consideration, liability
(c)
|
—
|
|
—
|
|
478
|
|
N/A
|
|
478
|
|
—
|
|
|||||||||||
|
Total liabilities at fair value
|
$
|
180
|
|
$
|
—
|
|
$
|
478
|
|
$
|
(180
|
)
|
$
|
478
|
|
$
|
—
|
|
|||||
|
December 31, 2013
|
|||||||||||||||||||||||
|
Fair Value Hierarchy
|
|||||||||||||||||||||||
|
(In millions)
|
Level 1
|
Level 2
|
Level 3
|
Netting and Collateral
(a)
|
Net Carrying Value on Balance Sheet
(b)
|
Collateral Pledged Not Offset
|
|||||||||||||||||
|
Commodity derivative instruments, assets
|
$
|
21
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(21
|
)
|
$
|
—
|
|
$
|
61
|
|
|||||
|
Other assets
|
2
|
|
—
|
|
—
|
|
N/A
|
|
2
|
|
—
|
|
|||||||||||
|
Total assets at fair value
|
$
|
23
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
(21
|
)
|
$
|
2
|
|
$
|
61
|
|
||||
|
Commodity derivative instruments, liabilities
|
$
|
53
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(53
|
)
|
$
|
—
|
|
$
|
—
|
|
|||||
|
Contingent consideration, liability
(c)
|
—
|
|
—
|
|
625
|
|
N/A
|
|
625
|
|
—
|
|
|||||||||||
|
Total liabilities at fair value
|
$
|
53
|
|
$
|
—
|
|
$
|
625
|
|
$
|
(53
|
)
|
$
|
625
|
|
$
|
—
|
|
|||||
|
(a)
|
Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of
December 31, 2014
, cash collateral of
$78 million
was netted with mark-to-market derivative assets. As of
December 31, 2013
, cash collateral of
$32 million
was netted with mark-to-market derivative liabilities.
|
|
(b)
|
We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.
|
|
(c)
|
Includes
$174 million
at
December 31, 2014
and
$159 million
at
December 31, 2013
classified as current.
|
Commodity derivatives in Level 1 are exchange-traded contracts for crude oil and refined products measured at fair value with a market approach using the close-of-day settlement prices for the market. Commodity derivatives are covered under master netting agreements with an unconditional right to offset. Collateral deposits in futures commission merchant accounts covered by master netting agreements related to Level 1 commodity derivatives are classified as Level 1 in the fair value hierarchy.
The contingent consideration represents the fair value as of
December 31, 2014
and
2013
of the amount we expect to pay to BP related to the earnout provision for the Galveston Bay Refinery and Related Assets acquisition. See Note
5
. The fair value of the contingent consideration was estimated using an income approach and is therefore a Level 3 liability. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. The earnout payment cannot exceed
$200 million
per year for the first three years of the arrangement or
$250 million
per year for the last three years of the arrangement, with the total cumulative payment capped at
$700 million
over the six-year period. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. The fair value calculation used significant unobservable inputs including: (1) an estimate of refinery throughput volumes; (2) a range of internal and external crack spread forecasts from
$13
to
$15
per barrel; and (3) a range of risk-adjusted discount rates from
5 percent
to
10 percent
. An increase or decrease in crack spread forecasts or refinery throughput volume expectations will result in a corresponding increase or decrease in the fair value. Increases to the fair value as a result of increasing forecasts for both of
100
these unobservable inputs, however, are limited as the earnout payment is subject to annual thresholds. An increase or decrease in the discount rate will result in a decrease or increase to the fair value, respectively. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues.
The following is a reconciliation of the net beginning and ending balances recorded for liabilities classified as Level 3 in the fair value hierarchy.
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Beginning balance
|
$
|
625
|
|
$
|
—
|
|
$
|
—
|
|
||
|
Contingent consideration agreement
|
—
|
|
600
|
|
—
|
|
|||||
|
Contingent consideration payment
|
(180
|
)
|
—
|
|
—
|
|
|||||
|
Unrealized and realized losses included in net income
|
33
|
|
25
|
|
2
|
|
|||||
|
Settlements of derivative instruments
|
—
|
|
—
|
|
(2
|
)
|
|||||
|
Ending balance
|
$
|
478
|
|
$
|
625
|
|
$
|
—
|
|
||
We did not hold any Level 3 derivative instruments during 2014, 2013 and 2012. See Note
19
for the income statement impacts of our derivative instruments. There was an unrealized loss of
$33 million
and
$25 million
in 2014 and 2013, respectively, related to the contingent consideration agreement.
Fair Values – Nonrecurring
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2014
|
2013
|
2012
|
||||||||||||||||||||
|
(In millions)
|
Fair Value
|
Impairment
|
Fair Value
|
Impairment
|
Fair Value
|
Impairment
|
|||||||||||||||||
|
Property, plant and equipment, net
|
$
|
—
|
|
$
|
—
|
|
$
|
1
|
|
$
|
8
|
|
$
|
—
|
|
$
|
—
|
|
|||||
|
Other noncurrent assets
|
—
|
|
11
|
|
—
|
|
—
|
|
—
|
|
14
|
|
|||||||||||
Based on the financial and operational status of a company in which we have an interest, we fully impaired our
$11 million
investment in that company in 2014. Our investment in this company was accounted for using the cost method and was included in our Refining & Marketing segment. The impairment is included in other income on the consolidated statements of income. The fair value of our investment in this cost company was measured using an income approach. This measurement is classified as Level 3.
Due to changing market conditions, we assessed one of our light products terminals for impairment. The terminal is operated by our Refining & Marketing segment. We recorded an impairment charge of
$8 million
for this terminal in 2013. The impairment is included in depreciation and amortization on the consolidated statements of income. The fair value of the terminal was measured using a market approach based on comparable area property values which are Level 3 inputs.
As a result of changing market conditions and declining throughput volumes, we impaired our Refining & Marketing segment’s prepaid tariff with Centennial by
$14 million
in 2012. The fair value measurement of the prepaid tariff was based on the income approach utilizing the probability of shipping sufficient volumes on Centennial’s pipeline over the remaining life of the throughput and deficiency credits, which expired March 31, 2014. This measurement is classified as Level 3.
101
Fair Values – Reported
The following table summarizes financial instruments on the basis of their nature, characteristics and risk at
December 31, 2014
and
2013
, excluding the derivative financial instruments and contingent consideration reported above.
|
|
December 31,
|
||||||||||||||
|
|
2014
|
2013
|
|||||||||||||
|
(In millions)
|
Fair Value
|
Carrying Value
|
Fair Value
|
Carrying Value
|
|||||||||||
|
Financial assets:
|
|||||||||||||||
|
Investments
|
$
|
26
|
|
$
|
2
|
|
$
|
336
|
|
$
|
14
|
|
|||
|
Other
|
32
|
|
32
|
|
31
|
|
30
|
|
|||||||
|
Total financial assets
|
$
|
58
|
|
$
|
34
|
|
$
|
367
|
|
$
|
44
|
|
|||
|
Financial liabilities:
|
|||||||||||||||
|
Long-term debt
(a)
|
$
|
6,571
|
|
$
|
6,265
|
|
$
|
3,306
|
|
$
|
3,001
|
|
|||
|
Deferred credits and other liabilities
|
17
|
|
17
|
|
21
|
|
21
|
|
|||||||
|
Total financial liabilities
|
$
|
6,588
|
|
|
$
|
6,282
|
|
$
|
3,327
|
|
$
|
3,022
|
|
||
|
(a)
|
Excludes capital leases
|
Our current assets and liabilities include financial instruments, the most significant of which are trade accounts receivable and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.
Fair values of our financial assets included in investments and other financial assets and of our financial liabilities included in deferred credits and other liabilities are measured primarily using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value. Other financial assets primarily consist of environmental remediation receivables. Deferred credits and other liabilities primarily consist of insurance liabilities and environmental remediation liabilities.
Fair value of fixed-rate long-term debt is measured using a market approach, based upon the average of quotes from major financial institutions and a third-party service for our debt. Because these quotes cannot be independently verified to the market, they are considered Level 3 inputs.
|
19.
|
Derivatives
|
For further information regarding the fair value measurement of derivative instruments, including any effect of master netting agreements or collateral, see Note
18
. See Note
2
for a discussion of the types of derivatives we use and the reasons for them. We do not designate any of our commodity derivative instruments as hedges for accounting purposes. Our interest rate derivative instruments were designated as fair value accounting hedges.
The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of
December 31, 2014
and
2013
:
|
|
December 31, 2014
|
|
|||||||
|
(In millions)
|
Asset
|
Liability
|
Balance Sheet Location
|
||||||
|
Commodity derivatives
|
$
|
317
|
|
$
|
180
|
|
Other current assets
|
||
|
|
December 31, 2013
|
|
|||||||
|
(In millions)
|
Asset
|
Liability
|
Balance Sheet Location
|
||||||
|
Commodity derivatives
|
$
|
21
|
|
$
|
53
|
|
Other current assets
|
||
102
Derivatives Designated as Fair Value Accounting Hedges
In 2012, we terminated interest rate swap agreements with a notional amount of
$500 million
that had been entered into as fair value accounting hedges on our
3.50 percent
senior notes due in
March 2016
. There was a
$20 million
gain on the termination of the transactions, which has been accounted for as an adjustment to our long-term debt balance. The gain is being amortized over the remaining life of the
3.50 percent
senior notes, which reduces our interest expense. The interest rate swaps had
no
accounting hedge ineffectiveness.
The following table summarizes the pretax effect of derivative instruments designated as accounting hedges of fair value in our consolidated statements of income in 2012:
|
|
|
Gain (Loss)
|
|||
|
(In millions)
|
Income Statement Location
|
2012
|
|||
|
Derivative
|
|||||
|
Interest rate
|
Net interest and other financial income (costs)
|
$
|
1
|
|
|
|
Hedged Item
|
|||||
|
Long-term debt
|
Net interest and other financial income (costs)
|
$
|
(1
|
)
|
|
Derivatives not Designated as Accounting Hedges
Derivatives that are not designated as accounting hedges may include commodity derivatives used to hedge price risk on (1) inventories, (2) fixed price sales of refined products, (3) the acquisition of foreign-sourced crude oil and (4) the acquisition of ethanol for blending with refined products.
The table below summarizes open commodity derivative contracts for crude oil and refined products as of
December 31, 2014
.
|
|
Position
|
Total Barrels
(In thousands)
|
|
|
Crude oil
(a)
|
|||
|
Exchange-traded
|
Long
|
15,678
|
|
|
Exchange-traded
|
Short
|
(25,257)
|
|
|
Refined Products
(b)
|
|||
|
Exchange-traded
|
Long
|
2,948
|
|
|
Exchange-traded
|
Short
|
(3,804)
|
|
|
(a )
|
97 percent
of these contracts expire in the first quarter of 2015.
|
|
(b)
|
100 percent
of these contracts expire in the first quarter of 2015.
|
The following table summarizes the effect of all commodity derivative instruments in our consolidated statements of income:
|
(In millions)
|
Gain (Loss)
|
||||||||||
|
Income Statement Location
|
2014
|
2013
|
2012
|
||||||||
|
Sales and other operating revenues
|
$
|
37
|
|
$
|
12
|
|
$
|
8
|
|
||
|
Cost of revenues
|
456
|
|
(180
|
)
|
65
|
|
|||||
|
Total
|
$
|
493
|
|
$
|
(168
|
)
|
$
|
73
|
|
||
103
|
20.
|
Debt
|
Our outstanding borrowings at
December 31, 2014
and
2013
consisted of the following:
|
|
December 31,
|
||||||
|
(In millions)
|
2014
|
2013
|
|||||
|
Marathon Petroleum Corporation:
|
|||||||
|
Revolving credit agreement due 2017
|
$
|
—
|
|
$
|
—
|
|
|
|
Term loan agreement due 2019
|
700
|
|
—
|
|
|||
|
3.500% senior notes due March 1, 2016
|
750
|
|
750
|
|
|||
|
5.125% senior notes due March 1, 2021
|
1,000
|
|
1,000
|
|
|||
|
3.625% senior notes due September 15, 2024
|
750
|
|
—
|
|
|||
|
6.500% senior notes due March 1, 2041
|
1,250
|
|
1,250
|
|
|||
|
4.750% senior notes due September 15, 2044
|
800
|
|
—
|
|
|||
|
5.000% senior notes due September 15, 2054
|
400
|
|
—
|
|
|||
|
Consolidated subsidiaries:
|
|||||||
|
Capital lease obligations due 2015-2028
|
372
|
|
395
|
|
|||
|
MPLX Operations LLC bank revolving credit agreement due 2017
|
—
|
|
—
|
|
|||
|
MPLX bank revolving credit facility due 2019
|
385
|
|
—
|
|
|||
|
MPLX term loan facility due 2019
|
250
|
|
—
|
|
|||
|
Trade receivables securitization facility due 2016
|
—
|
|
—
|
|
|||
|
Total
|
6,657
|
|
3,395
|
|
|||
|
Unamortized discount
|
(26
|
)
|
(10
|
)
|
|||
|
Fair value adjustments
(a)
|
6
|
|
11
|
|
|||
|
Amounts due within one year
|
(27
|
)
|
(23
|
)
|
|||
|
Total long-term debt due after one year
|
$
|
6,610
|
|
$
|
3,373
|
|
|
|
(a)
|
See Note
19
for information on interest rate swaps.
|
The following table shows five years of scheduled debt payments.
|
(In millions)
|
|||
|
2015
|
$
|
27
|
|
|
2016
|
777
|
|
|
|
2017
|
28
|
|
|
|
2018
|
30
|
|
|
|
2019
|
1,362
|
|
|
MPC Revolving Credit Agreement
– We have a
$2.5 billion
unsecured revolving credit agreement (“Credit Agreement”) in place with a maturity date of September 14, 2017. The Credit Agreement includes letter of credit issuing capacity of up to
$2.0 billion
and swingline loan capacity of up to
$100 million
. We may increase our borrowing capacity under the Credit Agreement by up to an additional
$500 million
, subject to certain conditions including the consent of the lenders whose commitments would be increased. In addition, the maturity date may be extended for up to
two
additional
one
-year periods subject to the approval of lenders holding greater than
50 percent
of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.
Borrowings under the Credit Agreement bear interest at either the Adjusted LIBO Rate (as defined in the Credit Agreement) plus a margin or the Alternate Base Rate (as defined in the Credit Agreement) plus a margin. We are charged various fees and expenses in connection with the Credit Agreement, including administrative agent fees, commitment fees on the unused portion of our borrowing capacity and fees related to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based on the credit ratings in effect from time to time on our long-term debt.
104
The Credit Agreement contains certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for arrangements of this type, including a financial covenant that requires us to maintain a ratio of Consolidated Net Debt (as defined in the Credit Agreement) to Total Capitalization (as defined in the Credit Agreement) of no greater than
0.65
to 1.00 as of the last day of each fiscal quarter. Other covenants, among other things, restrict our ability to incur debt, create liens on our assets or enter into transactions with affiliates. As of
December 31, 2014
, we were in compliance with the covenants contained in the Credit Agreement.
There were no borrowings or letters of credit outstanding at
December 31, 2014
.
MPC Term Loan Agreement
– On
August 26, 2014
, we entered into a
$700 million
five
-year senior unsecured term loan credit agreement (the “Term Loan Agreement”) with a syndicate of lenders to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. The Term Loan Agreement matures on September 24, 2019 and may be prepaid at any time without premium or penalty. We are obligated to pay certain customary fees under the Term Loan Agreement, including an annual administrative fee.
Amounts outstanding under the Term Loan Agreement bear interest at either of the following rates at our election (i) the sum of the
Adjusted LIBO Rate (as defined in the Term Loan Agreement)
, plus a margin ranging between
0.875 percent
to
1.75 percent
, depending on our credit ratings, or (ii) the sum of the Base Rate (as defined in the Term Loan Agreement), plus a margin ranging between
zero percent
to
0.75 percent
, depending on our credit ratings. The borrowings under this facility during
2014
were at an average interest rate of
1.3 percent
.
The Term Loan Agreement contains representation and warranties, covenants and events of default that are substantially similar to those contained in the MPC revolving credit agreement, including a financial covenant, which requires us to maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt to Total Capitalization (as defined in the Term Loan Agreement) of no greater than
0.65
to 1.00. As of
December 31, 2014
, we were in compliance with the covenants contained in the Credit Agreement.
Senior Notes
– On September 5, 2014, we completed a public offering of
$1.95 billion
aggregate principal amount of senior unsecured notes (the “Senior Notes”), consisting of
$750 million
aggregate principal amount of our Senior Notes due 2024,
$800 million
aggregate principal amount of our Senior Notes due 2044 and
$400 million
aggregate principal amount of our Senior Notes due 2054. The net proceeds from the offering of the Senior Notes were approximately
$1.92 billion
, after deducting underwriting discounts and estimated offering expenses. The net proceeds were used to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. Interest on each series of Senior Notes is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2015.
The Senior Notes are unsecured and unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated indebtedness.
MPLX Credit Agreement
– On November 20, 2014, MPLX entered into a credit agreement with a syndicate of lenders (“MPLX Credit Agreement”), which provides for a
five
-year
$1 billion
bank revolving credit facility and a
$250 million
term loan facility. The maturity date on both facilities is November 20, 2019.
The bank revolving credit facility includes letter of credit issuing capacity of up to
$250 million
and swingline loan capacity of up to
$100 million
. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional
$500 million
, subject to certain conditions, including the consent of the lenders whose commitments would increase. In addition, the maturity date may be extended up to
two
additional
one
-year periods subject to the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the original maturity date.
The term loan facility was drawn in full on November 20, 2014. The maturity date for the term loan facility may be extended for up to
two
additional
one
-year periods subject to the consent of the lenders holding a majority of the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any non-consenting lenders will continue to be due and payable on the original maturity date. The borrowings under this facility during
2014
were at an average interest rate of
1.4 percent
.
105
Borrowings under the MPLX Credit Agreement bear interest at either the
Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX Credit Agreement)
plus a specified margin. MPLX is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the bank revolving credit facility and fees with respect to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based on the credit ratings in effect from time to time on MPLX’s long-term debt.
The MPLX Credit Agreement includes certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for an agreement of this type. The MPLX Credit Agreement includes a financial covenant that requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior
four
fiscal quarters of no greater than
5.0
to 1.0 (or
5.5
to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict MPLX from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of
December 31, 2014
, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.
In connection with entering into this new credit agreement, MPLX terminated its previously existing
$500 million
five
-year MPLX Operations LLC bank revolving credit agreement, dated as of September 14, 2012. During
2014
, MPLX borrowed
$280 million
under the MPLX Operations LLC bank revolving credit agreement, at an average interest rate of
1.5 percent
, per annum, and repaid all of these borrowings.
During
2014
, MPLX borrowed
$630 million
under the new revolving credit agreement, at an average interest rate of
1.4 percent
, per annum, and repaid
$245 million
of these borrowings. At
December 31, 2014
, MPLX had
$385 million
of borrowings and
no
letters of credit outstanding under the MPLX Credit Agreement, resulting in total unused loan availability of
$615 million
, or
61.5 percent
of the borrowing capacity.
Trade receivables securitization facility
– On
December 18, 2013
, we entered into a
three
-year,
$1.3 billion
trade receivables securitization facility with a group of financial institutions that act as committed purchasers, conduit purchasers, letter of credit issuers and managing agents under the facility. The facility is evidenced by a Receivables Purchase Agreement and a Second Amended and Restated Receivables Sale Agreement and replaces the previously existing accounts receivable facility that was set to expire on
June 30, 2014
.
The facility consists of one of our wholly-owned subsidiaries, Marathon Petroleum Company LP (“MPC LP”), selling or contributing on an on-going basis all of its trade receivables (including trade receivables acquired from Marathon Petroleum Trading Canada LLC, a wholly-owned subsidiary of MPC LP), together with all related security and interests in the proceeds thereof, without recourse, to another wholly-owned, bankruptcy-remote special purpose subsidiary, MPC Trade Receivables Company LLC (“TRC”), in exchange for a combination of cash, equity or a subordinated note issued by TRC to MPC LP. TRC, in turn, has the ability to finance its purchase of the receivables from MPC LP by selling undivided ownership interests in qualifying trade receivables, together with all related security and interests in the proceeds thereof, without recourse, to the purchasing group in exchange for cash proceeds. The facility also provides for the issuance of letters of credit of up to an initial amount of
$1.25 billion
, provided that the aggregate credit exposure of the purchasing group is limited to no more than
$1.3 billion
at any one time.
To the extent that TRC retains an ownership interest in the receivables it has purchased or received from MPC LP, such interest will be included in our consolidated financial statements solely as a result of the consolidation of the financial statements of TRC with those of MPC. The receivables sold or contributed to TRC are available first and foremost to satisfy claims of the creditors of TRC and are not available to satisfy the claims of creditors of MPC. TRC has granted a security interest in all of its assets to the purchasing group to secure its obligations under the Receivables Purchase Agreement.
Proceeds from the sale of undivided percentage ownership interests in qualifying receivables under the facility will be reflected as debt on our consolidated balance sheet. We will remain responsible for servicing the receivables sold to the purchasing group. TRC pays floating-rate interest charges and usage fees on amounts outstanding under the facility, if any, and certain other fees related to the administration of the facility and letters of credit that are issued and outstanding under the facility.
106
The Receivables Purchase Agreement and Second Amended and Restated Receivables Sale Agreement include representations and covenants that we consider usual and customary for arrangements of this type. Trade receivables are subject to customary criteria, limits and reserves before being deemed to qualify for sale by TRC pursuant to the facility. In addition, further purchases of qualified trade receivables under the facility are subject to termination, and TRC may be subject to default fees, upon the occurrence of certain amortization events that are included in the Receivables Purchase Agreement, which we consider to be usual and customary for arrangements of this type. At December 31, 2014, we were in compliance with the covenants contained in the Receivables Purchase Agreement.
As of
December 31, 2014
, eligible trade receivables supported borrowings of
$1.28 billion
. There were no borrowings outstanding at
December 31, 2014
. As of January 31, 2015, eligible trade receivables supported borrowings of
$700 million
.
|
21.
|
Supplemental Cash Flow Information
|
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Net cash provided by operating activities included:
|
|||||||||||
|
Interest paid (net of amounts capitalized)
|
$
|
166
|
|
$
|
161
|
|
$
|
67
|
|
||
|
Net income taxes paid to taxing authorities
(a)
|
1,362
|
|
1,099
|
|
1,211
|
|
|||||
|
Non-cash investing and financing activities:
|
|||||||||||
|
Capital lease obligations increase
|
$
|
—
|
|
$
|
61
|
|
$
|
62
|
|
||
|
Property, plant and equipment sold
|
4
|
|
43
|
|
—
|
|
|||||
|
Property, plant and equipment acquired
|
4
|
|
—
|
|
—
|
|
|||||
|
Preferred equity interest received in contract settlement
(b)
|
—
|
|
—
|
|
45
|
|
|||||
|
Preferred equity interest dividend received in-kind
|
—
|
|
—
|
|
1
|
|
|||||
|
Acquisition:
|
|||||||||||
|
Contingent consideration
(c)
|
—
|
|
600
|
|
—
|
|
|||||
|
Payable to seller
(c)
|
—
|
|
6
|
|
—
|
|
|||||
|
Intangible asset acquired
|
—
|
|
—
|
|
3
|
|
|||||
|
Liability assumed
|
—
|
|
—
|
|
2
|
|
|||||
|
(a)
|
U.S. and most state income taxes, if incurred, were paid by Marathon Oil for periods prior to the Spinoff. The amount for 2012 includes payments of
$181 million
for 2011 return period income taxes made to Marathon Oil under our tax sharing agreement, and in return we received an equal amount of tax credits. See Note
26
.
|
|
(b)
|
See Note
6
.
|
|
(c)
|
See Note
5
.
|
The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Additions to property, plant and equipment per consolidated statements of cash flows
|
$
|
1,480
|
|
$
|
1,206
|
|
$
|
1,369
|
|
||
|
Non-cash additions to property, plant and equipment
|
4
|
|
—
|
|
—
|
|
|||||
|
Asset retirement expenditures
(a)
|
2
|
|
—
|
|
—
|
|
|||||
|
Increase (decrease) in capital accruals
|
95
|
|
73
|
|
(117
|
)
|
|||||
|
Total capital expenditures before acquisitions
|
1,581
|
|
1,279
|
|
1,252
|
|
|||||
|
Acquisitions
(b)
|
2,744
|
|
1,386
|
|
180
|
|
|||||
|
Total capital expenditures
|
$
|
4,325
|
|
$
|
2,665
|
|
$
|
1,432
|
|
||
|
(a)
|
Included in All other, net – Operating activities on the consolidated statements of cash flows.
|
|
(a)
|
The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment and intangibles. See Note
5
.
|
107
22. Accumulated Other Comprehensive Loss
The following table shows the changes in accumulated other comprehensive loss by component. Amounts in parentheses indicate debits.
|
(In millions)
|
Pension Benefits
|
Other Benefits
|
Gain on Cash Flow Hedge
|
Workers Compensation
|
Total
|
||||||||||||||
|
Balance as of December 31, 2012
|
(432
|
)
|
(36
|
)
|
4
|
|
—
|
|
$
|
(464
|
)
|
||||||||
|
Other comprehensive income before reclassifications
|
198
|
|
(13
|
)
|
—
|
|
4
|
|
189
|
|
|||||||||
|
Amounts reclassified from accumulated other comprehensive loss:
|
|||||||||||||||||||
|
Amortization – prior service credit
(a)
|
(45
|
)
|
(4
|
)
|
—
|
|
—
|
|
(49
|
)
|
|||||||||
|
– actuarial loss
(a)
|
66
|
|
3
|
|
—
|
|
—
|
|
69
|
|
|||||||||
|
– settlement loss
(a)
|
95
|
|
—
|
|
—
|
|
—
|
|
95
|
|
|||||||||
|
Other
(b)
|
—
|
|
—
|
|
—
|
|
(1
|
)
|
(1
|
)
|
|||||||||
|
Tax effect
|
(43
|
)
|
—
|
|
—
|
|
—
|
|
(43
|
)
|
|||||||||
|
Other comprehensive income (loss)
|
271
|
|
(14
|
)
|
—
|
|
3
|
|
260
|
|
|||||||||
|
Balance as of December 31, 2013
|
$
|
(161
|
)
|
$
|
(50
|
)
|
$
|
4
|
|
$
|
3
|
|
$
|
(204
|
)
|
||||
|
(In millions)
|
Pension Benefits
|
Other Benefits
|
Gain on Cash Flow Hedge
|
Workers Compensation
|
Total
|
||||||||||||||
|
Balance as of December 31, 2013
|
$
|
(161
|
)
|
$
|
(50
|
)
|
$
|
4
|
|
$
|
3
|
|
$
|
(204
|
)
|
||||
|
Other comprehensive income (loss) before reclassifications
|
(119
|
)
|
(53
|
)
|
—
|
|
2
|
|
(170
|
)
|
|||||||||
|
Amounts reclassified from accumulated other comprehensive loss:
|
|||||||||||||||||||
|
Amortization – prior service credit
(a)
|
(46
|
)
|
(4
|
)
|
—
|
|
—
|
|
(50
|
)
|
|||||||||
|
– actuarial loss
(a)
|
51
|
|
2
|
|
—
|
|
—
|
|
53
|
|
|||||||||
|
– settlement loss
(a)
|
96
|
|
—
|
|
—
|
|
—
|
|
96
|
|
|||||||||
|
Other
(b)
|
—
|
|
—
|
|
—
|
|
(1
|
)
|
(1
|
)
|
|||||||||
|
Tax effect
|
(38
|
)
|
1
|
|
—
|
|
—
|
|
(37
|
)
|
|||||||||
|
Other comprehensive income (loss)
|
(56
|
)
|
(54
|
)
|
—
|
|
1
|
|
(109
|
)
|
|||||||||
|
Balance as of December 31, 2014
|
$
|
(217
|
)
|
$
|
(104
|
)
|
$
|
4
|
|
$
|
4
|
|
$
|
(313
|
)
|
||||
|
(a)
|
These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note
23
.
|
|
(b)
|
This amount was reclassified out of accumulated other comprehensive loss and is included in selling, general and administrative expenses on the consolidated statements of income.
|
|
23.
|
Defined Benefit Pension and Other Postretirement Plans
|
We have noncontributory defined benefit pension plans covering substantially all employees. Benefits under these plans have been based primarily on age, years of service and final average pensionable earnings. The years of service component of this formula was frozen as of December 31, 2009. Benefits for service beginning January 1, 2010 are based on a cash balance formula with an annual percentage of eligible pay credited based upon age and years of service. Eligible Speedway employees accrue benefits under a defined contribution plan for service years beginning January 1, 2010.
We also have other postretirement benefits covering most employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Retiree life insurance benefits are provided to a closed group of retirees. Other postretirement benefits are not funded in advance.
108
Due to the Galveston Bay Refinery and Related Assets acquisition during 2013, we remeasured certain pension and retiree medical plans resulting in a
$122 million
decrease in liabilities. The decrease in liabilities was due to a
0.2 percent
increase in discount rates and an increase in pension plan asset value from December 31, 2012 to the remeasurement date. The net periodic benefit costs for 2013 reflect these remeasurements. The purchase accounting for the Galveston Bay Refinery and Related Assets acquisition includes a
$43 million
liability related to retiree medical assumed at the acquisition date. See Note
5
.
Obligations and funded status –
The accumulated benefit obligation for all defined benefit pension plans was
$2,009 million
and
$1,912 million
as of
December 31, 2014
and
2013
.
The following summarizes our defined benefit pension plans that have accumulated benefit obligations in excess of plan assets.
|
December 31,
|
|||||||
|
(In millions)
|
2014
|
2013
|
|||||
|
Projected benefit obligations
|
$
|
2,075
|
|
$
|
1,927
|
|
|
|
Accumulated benefit obligations
|
2,009
|
|
1,912
|
|
|||
|
Fair value of plan assets
|
1,744
|
|
1,800
|
|
|||
The following summarizes the projected benefit obligations and funded status for our defined benefit pension and other postretirement plans:
|
|
Pension Benefits
|
Other Benefits
|
|||||||||||||
|
(In millions)
|
2014
|
2013
|
2014
|
2013
|
|||||||||||
|
Change in benefit obligations:
|
|||||||||||||||
|
Benefit obligations at January 1
|
$
|
1,927
|
|
$
|
2,192
|
|
$
|
687
|
|
$
|
591
|
|
|||
|
Service cost
|
88
|
|
93
|
|
27
|
|
25
|
|
|||||||
|
Interest cost
|
74
|
|
73
|
|
33
|
|
26
|
|
|||||||
|
Actuarial (gain) loss
|
257
|
|
(183
|
)
|
86
|
|
17
|
|
|||||||
|
Benefits paid
|
(271
|
)
|
(248
|
)
|
(23
|
)
|
(20
|
)
|
|||||||
|
Other
(a)
|
—
|
|
—
|
|
2
|
|
48
|
|
|||||||
|
Benefit obligations at December 31
|
2,075
|
|
1,927
|
|
812
|
|
687
|
|
|||||||
|
Change in plan assets:
|
|||||||||||||||
|
Fair value of plan assets at January 1
|
1,800
|
|
1,478
|
|
—
|
|
—
|
|
|||||||
|
Actual return on plan assets
|
175
|
|
241
|
|
—
|
|
—
|
|
|||||||
|
Employer contributions
|
40
|
|
329
|
|
—
|
|
—
|
|
|||||||
|
Benefits paid from plan assets
|
(271
|
)
|
(248
|
)
|
—
|
|
—
|
|
|||||||
|
Fair value of plan assets at December 31
|
1,744
|
|
1,800
|
|
—
|
|
—
|
|
|||||||
|
Funded status of plans at December 31
|
$
|
(331
|
)
|
$
|
(127
|
)
|
$
|
(812
|
)
|
$
|
(687
|
)
|
|||
|
Amounts recognized in the consolidated balance sheets:
|
|||||||||||||||
|
Current liabilities
|
$
|
(17
|
)
|
$
|
(18
|
)
|
$
|
(27
|
)
|
$
|
(25
|
)
|
|||
|
Noncurrent liabilities
|
(314
|
)
|
(109
|
)
|
(785
|
)
|
(662
|
)
|
|||||||
|
Accrued benefit cost
|
$
|
(331
|
)
|
$
|
(127
|
)
|
$
|
(812
|
)
|
$
|
(687
|
)
|
|||
|
Pretax amounts recognized in accumulated other comprehensive loss:
(b)
|
|||||||||||||||
|
Net loss
|
$
|
710
|
|
$
|
668
|
|
$
|
191
|
|
$
|
107
|
|
|||
|
Prior service credit
|
(369
|
)
|
(415
|
)
|
(26
|
)
|
(30
|
)
|
|||||||
|
(a)
|
Includes adjustments related to Hess’ Retail Operations and Related Assets acquisition in 2014. For 2013, it includes adjustments related to plan amendments and adjustments related to the Galveston Bay Refinery and Related Assets acquisition.
|
|
(b)
|
Amounts exclude those related to LOOP and Explorer Pipeline, equity method investees with defined benefit pension and postretirement plans for which net losses of
$18 million
and
$1 million
were recorded in accumulated other comprehensive loss in
2014
, reflecting our ownership share.
|
109
Components of net periodic benefit cost and other comprehensive loss
– The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive loss for our defined benefit pension and other postretirement plans.
|
|
Pension Benefits
|
Other Benefits
|
|||||||||||||||||||||
|
(In millions)
|
2014
|
2013
|
2012
|
2014
|
2013
|
2012
|
|||||||||||||||||
|
Components of net periodic benefit cost:
|
|||||||||||||||||||||||
|
Service cost
|
$
|
88
|
|
$
|
93
|
|
$
|
66
|
|
$
|
27
|
|
$
|
25
|
|
$
|
20
|
|
|||||
|
Interest cost
|
74
|
|
73
|
|
94
|
|
33
|
|
26
|
|
24
|
|
|||||||||||
|
Expected return on plan assets
|
(107
|
)
|
(107
|
)
|
(104
|
)
|
—
|
|
—
|
|
—
|
|
|||||||||||
|
Amortization – prior service cost (credit)
|
(46
|
)
|
(45
|
)
|
(18
|
)
|
(4
|
)
|
(4
|
)
|
(2
|
)
|
|||||||||||
|
– actuarial loss
|
51
|
|
66
|
|
93
|
|
2
|
|
3
|
|
2
|
|
|||||||||||
|
– settlement loss
|
96
|
|
95
|
|
125
|
|
—
|
|
—
|
|
—
|
|
|||||||||||
|
Net periodic benefit cost
(a)
|
$
|
156
|
|
$
|
175
|
|
$
|
256
|
|
$
|
58
|
|
$
|
50
|
|
$
|
44
|
|
|||||
|
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
|
|||||||||||||||||||||||
|
Actuarial (gain) loss
|
$
|
188
|
|
$
|
(317
|
)
|
$
|
46
|
|
$
|
86
|
|
$
|
17
|
|
$
|
53
|
|
|||||
|
Prior service cost (credit)
(b)
|
—
|
|
—
|
|
(520
|
)
|
—
|
|
4
|
|
(40
|
)
|
|||||||||||
|
Amortization of actuarial loss
|
(147
|
)
|
(161
|
)
|
(218
|
)
|
(2
|
)
|
(3
|
)
|
(2
|
)
|
|||||||||||
|
Amortization of prior service cost
|
46
|
|
45
|
|
18
|
|
4
|
|
4
|
|
2
|
|
|||||||||||
|
Other
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||||||
|
Total recognized in other comprehensive loss
|
$
|
87
|
|
$
|
(433
|
)
|
$
|
(674
|
)
|
$
|
88
|
|
$
|
22
|
|
$
|
13
|
|
|||||
|
Total recognized in net periodic benefit cost and other comprehensive loss
|
$
|
243
|
|
$
|
(258
|
)
|
$
|
(418
|
)
|
$
|
146
|
|
$
|
72
|
|
$
|
57
|
|
|||||
|
(a)
|
Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
|
|
(b)
|
Includes adjustments due to plan amendments approved in 2013 and adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.
|
Lump sum payments to employees retiring in
2014
,
2013
and
2012
exceeded the plan’s total service and interest costs expected for those years. Settlement losses are required to be recorded when lump sum payments exceed total service and interest costs. As a result, pension settlement expenses were recorded in
2014
,
2013
and
2012
related to our cumulative lump sum payments made during those years.
The estimated net gain/loss and prior service credit for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in
2015
are
$51 million
and
$46 million
. The estimated net loss and prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in
2015
is
$9 million
and
$4 million
, respectively.
110
Plan assumptions
– The following summarizes the assumptions used to determine the benefit obligations at
December 31,
and net periodic benefit cost for the defined benefit pension and other postretirement plans for
2014
,
2013
and
2012
.
|
|
Pension Benefits
|
Other Benefits
|
|||||||||||||||
|
|
2014
|
2013
|
2012
|
2014
|
2013
|
2012
|
|||||||||||
|
Weighted-average assumptions used to determine benefit obligation:
|
|||||||||||||||||
|
Discount rate
|
3.65
|
%
|
4.30
|
%
|
3.45
|
%
|
4.15
|
%
|
4.95
|
%
|
4.05
|
%
|
|||||
|
Rate of compensation increase
|
3.70
|
%
|
3.70
|
%
|
5.00
|
%
|
3.70
|
%
|
3.70
|
%
|
5.00
|
%
|
|||||
|
Weighted-average assumptions used to determine net periodic benefit cost:
|
|||||||||||||||||
|
Discount rate
|
4.05
|
%
|
3.88
|
%
|
4.06
|
%
|
4.95
|
%
|
4.11
|
%
|
4.54
|
%
|
|||||
|
Expected long-term return on plan assets
(a)
|
7.00
|
%
|
7.50
|
%
|
7.50
|
%
|
—
|
%
|
—
|
%
|
—
|
%
|
|||||
|
Rate of compensation increase
|
3.70
|
%
|
5.00
|
%
|
5.00
|
%
|
3.70
|
%
|
5.00
|
%
|
5.00
|
%
|
|||||
|
(a)
|
Effective January 1, 2015, the expected long-term rate of return on plan assets is
6.75 percent
due to a continuation of a change in our primary plan investment strategy, which began January 1, 2014.
|
Expected long-term return on plan assets
The overall expected long-term return on plan assets assumption is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our asset allocation to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.
Assumed health care cost trend
The following summarizes the assumed health care cost trend rates.
|
|
December 31,
|
|||||||
|
|
2014
|
2013
|
2012
|
|||||
|
Health care cost trend rate assumed for the following year:
|
||||||||
|
Medical Pre-65
|
8.00
|
%
|
8.00
|
%
|
8.00
|
%
|
||
|
Prescription drugs
|
7.00
|
%
|
7.00
|
%
|
7.00
|
%
|
||
|
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):
|
||||||||
|
Medical Pre-65
|
5.00
|
%
|
5.00
|
%
|
5.00
|
%
|
||
|
Prescription drugs
|
5.00
|
%
|
5.00
|
%
|
5.00
|
%
|
||
|
Year that the rate reaches the ultimate trend rate:
|
||||||||
|
Medical Pre-65
|
2021
|
|
2020
|
|
2020
|
|
||
|
Prescription drugs
|
2021
|
|
2018
|
|
2018
|
|
||
Effective 2013, as a result of changes in the post-65 medical plan coverage of the Marathon Petroleum Health Plan and the Marathon Petroleum Retiree Health Plan, increases are the lower of the trend rate or
four percent
.
111
Assumed health care cost trend rates have a significant effect on the amounts reported for defined benefit retiree health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
|
1-Percentage-
|
1-Percentage-
|
||||||
|
(In millions)
|
Point Increase
|
Point Decrease
|
|||||
|
Effect on total of service and interest cost components
|
$
|
5
|
|
$
|
(4
|
)
|
|
|
Effect on other postretirement benefit obligations
|
45
|
|
(39
|
)
|
|||
Plan investment policies and strategies
The investment policies for our pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) diversify plan investments across asset classes to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation; and (3) source benefit payments primarily through existing plan assets and anticipated future returns.
The investment goals are implemented to manage the plans’ funded status volatility and minimize future cash contributions. The asset allocation strategy will change over time in response to changes primarily in funded status, which is dictated by current and anticipated market conditions, the independent actions of our investment committee, required cash flows to and from the plans and other factors deemed appropriate. Such changes in asset allocation are intended to allocate additional assets to the fixed income asset class should the funded status improve. The fixed income asset class shall be invested in such a manner that its interest rate sensitivity correlates highly with that of the plans’ liabilities. Other asset classes are intended to provide additional return with associated higher levels of risk. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies. At
December 31, 2014
, the primary plan’s targeted asset allocation was
51 percent
equity, private equity, real estate, and timber securities and
49 percent
fixed income securities.
Fair value measurements
Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset category at
December 31, 2014
and
2013
.
Cash and cash equivalents
– Cash and cash equivalents include a collective fund serving as the investment vehicle for the cash reserves and cash held by third-party investment managers. The collective fund is valued at net asset value (“NAV”) on a scheduled basis using a cost approach, and is considered a Level 2 asset. Cash and cash equivalents held by third-party investment managers are valued using a cost approach and are considered Level 2.
Equity
– Equity investments includes common stock, mutual and pooled funds. Common stock investments are valued using a market approach, which are priced daily in active markets and are considered Level 1. Mutual and pooled equity funds are well diversified portfolios, representing a mix of strategies in domestic, international and emerging market strategies. Mutual funds are publicly registered, valued at NAV on a daily basis using a market approach and are considered Level 1 assets. Pooled funds are valued at NAV using a market approach and are considered Level 2 assets.
Fixed Income
– Fixed income investments include corporate bonds, U.S. dollar treasury bonds and municipal bonds. These securities are priced on observable inputs using a combination of market, income and cost approaches. These securities are considered Level 2 assets. Fixed income also includes a well diversified bond portfolio structured as a pooled fund. This fund is valued at NAV on a daily basis using a combination of market, income and cost approaches. It is considered a Level 2 asset.
Private Equity
– Private equity investments include interests in limited partnerships which are valued using information provided by external managers for each individual investment held in the fund. These holdings are considered Level 3.
Real Estate
– Real estate investments consist of interests in limited partnerships. These holdings are either appraised or valued using investment manager’s assessment of assets held. These holdings are considered Level 3.
Other
– Other investments include two limited liability companies (“LLCs”) with no public market. The LLCs were formed to acquire timberland in the northwest United States. These holdings are either appraised or valued using investment manager’s assessment of assets held. These holdings are considered Level 3.
112
The following tables present the fair values of our defined benefit pension plans’ assets, by level within the fair value hierarchy, as of
December 31, 2014
and
2013
.
|
|
December 31, 2014
|
||||||||||||||
|
(In millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
|||||||||||
|
Cash and cash equivalents
|
$
|
—
|
|
$
|
29
|
|
$
|
—
|
|
$
|
29
|
|
|||
|
Equity:
|
|||||||||||||||
|
Common stocks
|
63
|
|
—
|
|
—
|
|
63
|
|
|||||||
|
Mutual funds
|
155
|
|
—
|
|
—
|
|
155
|
|
|||||||
|
Pooled funds
|
—
|
|
442
|
|
—
|
|
442
|
|
|||||||
|
Fixed income:
|
|||||||||||||||
|
Corporate
|
—
|
|
554
|
|
—
|
|
554
|
|
|||||||
|
Government
|
—
|
|
99
|
|
—
|
|
99
|
|
|||||||
|
Pooled funds
|
—
|
|
254
|
|
—
|
|
254
|
|
|||||||
|
Private equity
|
—
|
|
—
|
|
66
|
|
66
|
|
|||||||
|
Real estate
|
—
|
|
—
|
|
57
|
|
57
|
|
|||||||
|
Other
|
2
|
|
2
|
|
21
|
|
25
|
|
|||||||
|
Total investments, at fair value
|
$
|
220
|
|
$
|
1,380
|
|
$
|
144
|
|
$
|
1,744
|
|
|||
|
|
December 31, 2013
|
||||||||||||||
|
(In millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
|||||||||||
|
Cash and cash equivalents
|
$
|
—
|
|
$
|
189
|
|
$
|
—
|
|
$
|
189
|
|
|||
|
Equity:
|
|||||||||||||||
|
Common stocks
|
69
|
|
—
|
|
—
|
|
69
|
|
|||||||
|
Mutual funds
|
217
|
|
—
|
|
—
|
|
217
|
|
|||||||
|
Pooled funds
|
—
|
|
590
|
|
—
|
|
590
|
|
|||||||
|
Fixed income:
|
|||||||||||||||
|
Corporate
|
—
|
|
356
|
|
—
|
|
356
|
|
|||||||
|
Government
|
—
|
|
22
|
|
—
|
|
22
|
|
|||||||
|
Pooled funds
|
—
|
|
218
|
|
—
|
|
218
|
|
|||||||
|
Private equity
|
—
|
|
—
|
|
57
|
|
57
|
|
|||||||
|
Real estate
|
—
|
|
—
|
|
60
|
|
60
|
|
|||||||
|
Other
|
2
|
|
—
|
|
20
|
|
22
|
|
|||||||
|
Total investments, at fair value
|
$
|
288
|
|
$
|
1,375
|
|
$
|
137
|
|
$
|
1,800
|
|
|||
113
The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy:
|
|
2014
|
||||||||||||||
|
(In millions)
|
Private Equity
|
Real Estate
|
Other
|
Total
|
|||||||||||
|
Beginning balance
|
$
|
57
|
|
$
|
60
|
|
$
|
20
|
|
$
|
137
|
|
|||
|
Actual return on plan assets:
|
|
|
|||||||||||||
|
Realized
|
6
|
|
4
|
|
—
|
|
10
|
|
|||||||
|
Unrealized
|
6
|
|
4
|
|
1
|
|
11
|
|
|||||||
|
Purchases
|
10
|
|
5
|
|
—
|
|
15
|
|
|||||||
|
Sales
|
(13
|
)
|
(16
|
)
|
—
|
|
(29
|
)
|
|||||||
|
Ending balance
|
$
|
66
|
|
$
|
57
|
|
$
|
21
|
|
$
|
144
|
|
|||
|
|
2013
|
||||||||||||||
|
(In millions)
|
Private
Equity
|
Real
Estate
|
Other
|
Total
|
|||||||||||
|
Beginning balance
|
$
|
56
|
|
$
|
54
|
|
$
|
17
|
|
$
|
127
|
|
|||
|
Actual return on plan assets:
|
|
|
|||||||||||||
|
Realized
|
13
|
|
3
|
|
—
|
|
16
|
|
|||||||
|
Unrealized
|
3
|
|
10
|
|
3
|
|
16
|
|
|||||||
|
Purchases
|
7
|
|
5
|
|
—
|
|
12
|
|
|||||||
|
Sales
|
(22
|
)
|
(12
|
)
|
—
|
|
(34
|
)
|
|||||||
|
Ending balance
|
$
|
57
|
|
$
|
60
|
|
$
|
20
|
|
$
|
137
|
|
|||
Cash Flows
Contributions to defined benefit plans –
Our funding policy with respect to the funded pension plans is to contribute amounts necessary to satisfy minimum pension funding requirements, including requirements of the Pension Protection Act of 2006, plus such additional, discretionary, amounts from time to time as determined appropriate by management. In 2014, we made pension contributions totaling
$16 million
. We have no required funding for 2015, but may make voluntary contributions at our discretion. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are estimated to be approximately
$18 million
and
$27 million
in
2015
.
Estimated future benefit payments –
The following gross benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated.
|
(In millions)
|
Pension Benefits
|
Other Benefits
|
|||||
|
2015
|
$
|
179
|
|
$
|
27
|
|
|
|
2016
|
181
|
|
30
|
|
|||
|
2017
|
181
|
|
33
|
|
|||
|
2018
|
181
|
|
37
|
|
|||
|
2019
|
179
|
|
40
|
|
|||
|
2020 through 2024
|
810
|
|
236
|
|
|||
Contributions to defined contribution plans –
We also contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled
$86 million
,
$76 million
and
$60 million
in
2014
,
2013
and
2012
, respectively.
114
Multiemployer Pension Plan
We contribute to
one
multiemployer defined benefit pension plan under the terms of a collective-bargaining agreement that covers some of our union-represented employees. The risks of participating in this multiemployer plan are different from single-employer plans in the following aspects:
|
•
|
Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers.
|
|
•
|
If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers.
|
|
•
|
If we choose to stop participating in the multiemployer plan, we may be required to pay that plan an amount based on the underfunded status of the plan, referred to as a withdrawal liability.
|
Our participation in this plan for
2014
,
2013
and
2012
is outlined in the table below. The “EIN” column provides the Employee Identification Number for the plan. The most recent Pension Protection Act zone status available in 2014 and 2013 is for the plan’s year ended December 31, 2013 and December 31, 2012, respectively. The zone status is based on information that we received from the plan and is certified by the plan’s actuary. Among other factors, plans in the red zone are generally less than
65 percent
funded. The “FIP/RP Status Pending/Implemented” column indicates a financial improvement plan or a rehabilitation plan has been implemented. The last column lists the expiration date of the collective-bargaining agreement to which the plan is subject. There have been no significant changes that affect the comparability of
2014
,
2013
and
2012
contributions. Our portion of the contributions does not make up more than
five percent
of total contributions to the plan.
|
|
|
Pension Protection
Act Zone Status
|
FIP/RP Status
Pending/Implemented
|
MPC Contributions (In millions)
|
Surcharge
Imposed |
Expiration Date of
Collective – Bargaining
Agreement |
||||||||||||||||||
|
Pension Fund
|
EIN
|
2014
|
2013
|
2014
|
2013
|
2012
|
||||||||||||||||||
|
Central States, Southeast and Southwest Areas Pension Plan
(a)
|
36-6044243
|
Red
|
Red
|
Implemented
|
$
|
4
|
|
$
|
3
|
|
$
|
4
|
|
No
|
January 31, 2019
|
|||||||||
|
(a)
|
This agreement has a minimum contribution requirement of
$280
per week per employee for
2015
. A total of
267
employees participated in the plan as of
December 31, 2014
.
|
Multiemployer Health and Welfare Plan
We contribute to
one
multiemployer health and welfare plan that covers both active employees and retirees. Through the health and welfare plan employees receive medical, dental, vision, prescription and disability coverage. Our contributions to this plan totaled
$6 million
,
$5 million
and
$5 million
for
2014
,
2013
and
2012
.
|
24.
|
Stock-Based Compensation Plans
|
Description of the Plans
Effective April 26, 2012, our employees and non-employee directors became eligible to receive equity awards under the Marathon Petroleum Corporation 2012 Incentive Compensation Plan (“MPC 2012 Plan”). The MPC 2012 Plan authorizes the Compensation Committee of our board of directors (“Committee”) to grant non-qualified or incentive stock options, stock appreciation rights, stock awards (including restricted stock and restricted stock unit awards), cash awards and performance awards to our employees and non-employee directors. Under the MPC 2012 Plan, no more than
25 million
shares of our common stock may be delivered and no more than
10 million
shares of our common stock may be the subject of awards that are not stock options or stock appreciation rights. In the sole discretion of the Committee,
10 million
shares of our common stock may be granted as incentive stock options. Shares issued as a result of awards granted under these plans are funded through the issuance of new MPC common shares.
Prior to April 26, 2012, our employees and non-employee directors were eligible to receive equity awards under the Marathon Petroleum Corporation 2011 Second Amended and Restated Incentive Compensation Plan (“MPC 2011 Plan”).
115
Stock-based awards under the Plans
We expense all share-based payments to employees and non-employee directors based on the grant date fair value of the awards over the requisite service period, adjusted for estimated forfeitures.
Stock Options –
We grant stock options to certain officer and non-officer employees. All of the stock options granted in 2014 fell under the MPC 2012 Plan. Stock options awarded under the MPC 2011 Plan and the MPC 2012 Plan represent the right to purchase shares of our common stock at its fair market value, which is the closing price of MPC’s common stock on the date of grant. Stock options have a maximum term of
ten years
from the date they are granted, and vest over a requisite service period of
three years
. We use the Black Scholes option-pricing model to estimate the fair value of stock options granted, which requires the input of subjective assumptions.
Stock Appreciation Rights (“SARs”)
– SARs were granted under the Marathon Oil Corporation incentive compensation plan in effect prior to the Spinoff. No SARs have been granted under the MPC 2011 Plan or the MPC 2012 Plan. Similar to stock options, SARs represent the right to receive a payment equal to the excess of the fair market value of shares of MPC or Marathon Oil common stock on the date the right is exercised over the grant price. SARs have a maximum term of
ten years
from the date they are granted and generally vest over a requisite service period of
three years
. We use the Black Scholes option-pricing model to estimate the fair value of SARs granted, which requires the input of subjective assumptions. All outstanding SAR’s expired or were exercised in 2014.
Restricted Stock and Restricted Stock Units
– We grant restricted stock and restricted stock units to employees and non-employee directors. In general, restricted stock and restricted stock units granted to employees vest over a requisite service period of
three years
. Restricted stock and restricted stock unit awards granted after 2011 to officers are subject to an additional
one year
holding period after the completion of the three-year requisite service period. Prior to vesting, restricted stock recipients who received grants prior to 2012 have the right to vote such stock and receive dividends at the same time regular shareholders are paid. Restricted stock recipients who received grants in 2012 and after have the right to vote such stock; however, dividends are accrued and will be paid upon vesting. Restricted stock units granted to non-employee directors are considered to vest immediately at the time of the grant for accounting purposes, as they are non-forfeitable, but are not issued until the director’s departure from the board of directors. Restricted stock unit recipients do not have the right to vote such shares and receive dividend equivalents. The non-vested shares are not transferable and are held by our transfer agent. The fair values of restricted stock are equal to the market price of our common stock on the grant date.
Performance Units
– We grant performance unit awards to certain officer employees. The target value of all performance units is
$1.00
, with actual payout up to
$2.00
per unit (up to
200%
of target). Performance units issued under the MPC 2011 and MPC 2012 Plans have a
36
-month requisite service period. The payout value of these awards will be determined by the relative ranking of the total shareholder return (“TSR”
)
of MPC common stock compared to the TSR of a select group of peer companies, as well as the Standard & Poor’s 500 Energy Index fund over an average of four measurement periods. These awards will be settled
25 percent
in MPC common stock and
75 percent
in cash. The number of shares actually distributed will be determined by dividing 25 percent of the final payout by the closing price of MPC common stock on the day the Committee certifies the final TSR rankings, or the next trading day if the certification is made outside of normal trading hours. The performance units paying out in cash are accounted for as liability awards and recorded at fair value with a mark-to-market adjustment made each quarter. The performance units that settle in shares are accounted for as equity awards.
Total Stock-Based Compensation Expense
The following table reflects activity related to our stock-based compensation arrangements:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Stock-based compensation expense
|
$
|
40
|
|
$
|
42
|
|
$
|
35
|
|
||
|
Tax benefit recognized on stock-based compensation expense
|
15
|
|
15
|
|
13
|
|
|||||
|
Cash received by MPC upon exercise of stock option awards
|
26
|
|
48
|
|
108
|
|
|||||
|
Tax benefit received for tax deductions for stock awards exercised
|
19
|
|
18
|
|
16
|
|
|||||
116
Stock Option Awards
The Black Scholes option-pricing model values used to value stock option awards granted were determined based on the following weighted average assumptions:
|
2014
|
2013
|
2012
|
|||||||||
|
Weighted average exercise price per share
|
$
|
85.02
|
|
$
|
84.65
|
|
$
|
42.02
|
|
||
|
Expected life in years
|
5.8
|
|
6.0
|
|
5.8
|
|
|||||
|
Expected volatility
|
36
|
%
|
40
|
%
|
47
|
%
|
|||||
|
Expected dividend yield
|
1.9
|
%
|
2.0
|
%
|
2.6
|
%
|
|||||
|
Risk-free interest rate
|
1.8
|
%
|
1.0
|
%
|
1.1
|
%
|
|||||
|
Weighted average grant date fair value of stock option awards granted
|
$
|
25.37
|
|
$
|
27.13
|
|
$
|
14.45
|
|
||
The expected life of stock options granted is based on historical data and represents the period of time that options granted are expected to be held prior to exercise. The 2014 assumption for expected volatility of our stock price reflects a weighting of
50 percent
of our common stock implied volatility and
50 percent
of MPC’s common stock historical volatility. Prior to 2014, we used a weighting of our common stock implied volatility and the historical volatility of a selected group of peers. Expected dividend yield is based on annualized dividends at the date of grant. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant.
The following is a summary of our common stock option activity in
2014
:
|
Number of
of Shares
(a)
|
Weighted Average Exercise Price
|
Weighted Average Remaining Contractual Terms (in years)
|
Aggregate Intrinsic Value (in millions)
|
|||||||||
|
Outstanding at December 31, 2013
|
5,147,837
|
|
$
|
40.08
|
|
|||||||
|
Granted
|
446,310
|
|
85.02
|
|
||||||||
|
Exercised
|
(821,948
|
)
|
33.04
|
|
||||||||
|
Forfeited, canceled or expired
|
(20,761
|
)
|
49.67
|
|
||||||||
|
Outstanding at December 31, 2014
|
4,751,438
|
|
45.47
|
|
||||||||
|
Vested and expected to vest at December 31, 2014
|
4,746,653
|
|
45.43
|
|
5.7
|
$
|
213
|
|
||||
|
Exercisable at December 31, 2014
|
3,795,031
|
|
38.30
|
|
5.0
|
197
|
|
|||||
|
(a)
|
Includes an immaterial number of stock appreciation rights.
|
The intrinsic value of options exercised by MPC employees during
2014
,
2013
and
2012
was
$48 million
,
$60 million
and
$37 million
, respectively.
As of
December 31, 2014
, unrecognized compensation cost related to stock option awards was
$5 million
, which is expected to be recognized over a weighted average period of
1.1
years.
117
Restricted Stock Awards
The following is a summary of restricted stock award activity of our common stock in
2014
:
|
|
Shares of Restricted Stock (“RS”)
|
Restricted Stock Units (“RSU”)
|
|||||||||||
|
|
Number of Shares
|
Weighted Average Grant Date Fair Value
|
Number of Units
|
Weighted Average Grant Date Fair Value
|
|||||||||
|
Outstanding at December 31, 2013
|
624,122
|
|
$
|
61.11
|
|
385,079
|
|
$
|
33.96
|
|
|||
|
Granted
|
251,351
|
|
87.64
|
|
26,725
|
|
85.90
|
|
|||||
|
RS’s Vested/RSU’s Issued
|
(330,971
|
)
|
55.36
|
|
(578
|
)
|
51.99
|
|
|||||
|
Forfeited
|
(29,429
|
)
|
70.29
|
|
(133
|
)
|
76.10
|
|
|||||
|
Outstanding at December 31, 2014
|
515,073
|
|
77.23
|
|
411,093
|
|
37.30
|
|
|||||
Of the
411,093
restricted stock units outstanding,
409,805
are vested and have a weighted average grant date fair value of
$37.16
. These vested but unissued units are held by our non-employee directors, are non-forfeitable and are issuable upon the director’s departure from our board of directors.
The following is a summary of the values related to restricted stock and restricted stock unit awards held by MPC employees and non-employee directors:
|
Restricted Stock
|
Restricted Stock Units
|
||||||||||||||
|
Intrinsic Value of Awards Vested During the Period (in millions)
|
Weighted Average Grant Date Fair Value of Awards Granted During the Period
|
Intrinsic Value of Awards Vested During the Period (in millions)
|
Weighted Average Grant Date Fair Value of Awards Granted During the Period
|
||||||||||||
|
2014
|
$
|
28
|
|
|
$
|
87.64
|
|
|
$
|
—
|
|
|
$
|
85.90
|
|
|
2013
|
20
|
|
|
87.06
|
|
|
—
|
|
|
73.48
|
|
||||
|
2012
|
5
|
|
43.11
|
|
—
|
|
44.38
|
|
|||||||
As of
December 31, 2014
, unrecognized compensation cost related to restricted stock awards was
$26 million
, which is expected to be recognized over a weighted average period of
1.1
years. There was no material unrecognized compensation cost related to restricted stock unit awards.
Performance Unit Awards
The following table presents a summary of the
2014
activity for performance unit awards to be settled in shares:
|
|
Number of Units
|
Weighted Average Grant Date Fair Value
|
||||
|
Outstanding at December 31, 2013
|
3,822,500
|
|
$
|
0.90
|
|
|
|
Granted
|
2,033,700
|
|
0.85
|
|
||
|
Canceled
|
(64,375
|
)
|
0.87
|
|
||
|
Outstanding at December 31, 2014
|
5,791,825
|
|
0.88
|
|
||
The number of shares that would be issued upon target vesting, using the closing price of our common stock on
December 31, 2014
would be
64,168
shares.
As of
December 31, 2014
, unrecognized compensation cost related to equity-classified performance unit awards was
$2 million
, which is expected to be recognized over a weighted average period of
1.5
years.
118
Performance units paying out in units have a grant date fair value calculated using a Monte Carlo valuation model, which requires the input of subjective assumptions. The following table provides a summary of these assumptions:
|
2014
|
2013
|
2012
|
|||||||||
|
Risk-free interest rate
|
0.63
|
%
|
0.35
|
%
|
0.41
|
%
|
|||||
|
Look-back period
|
2.84 years
|
|
2.84 years
|
|
2.84 years
|
|
|||||
|
Expected volatility
|
38.51
|
%
|
41.67
|
%
|
56.06
|
%
|
|||||
|
Grant date fair value of performance units granted
|
$
|
0.85
|
|
$
|
0.95
|
|
$
|
0.80
|
|
||
The risk-free interest rate for the remaining performance period as of the grant date is based on the U.S. Treasury yield curve in effect at the time of the grant. The look-back period reflects the remaining performance period at the grant date. The assumption for the expected volatility of our stock price reflects the average MPC common stock historical volatility.
MPLX Awards
Our wholly-owned subsidiary and the general partner of MPLX, MPLX GP LLC (“MXGP”), maintains a unit-based compensation plan for officers, directors and employees (including any other individual who may be considered an “employee” under a Registration Statement on Form S-8 or any successor form) of MXGP.
The MPLX 2012 Incentive Compensation Plan (“MPLX Plan”) permits various types of equity awards including but not limited to grants of restricted phantom units and performance units. Awards granted under the MPLX Plan will be settled with MPLX units. Compensation expense for these awards was not material to our consolidated financial statements for the years ended
December 31, 2014
,
2013
and
2012
.
|
25.
|
Leases
|
We lease a wide variety of facilities and equipment under operating leases, including land and building space, office equipment, storage facilities and transportation equipment. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments as of
December 31, 2014
, for capital lease obligations and for operating lease obligations having initial or remaining non-cancelable lease terms in excess of one year are as follows:
|
(In millions)
|
Capital
Lease
Obligations
|
Operating
Lease
Obligations
|
|||||
|
2015
|
$
|
52
|
|
$
|
249
|
|
|
|
2016
|
51
|
|
209
|
|
|||
|
2017
|
50
|
|
150
|
|
|||
|
2018
|
49
|
|
136
|
|
|||
|
2019
|
45
|
|
114
|
|
|||
|
Later years
|
300
|
|
468
|
|
|||
|
Total minimum lease payments
|
547
|
|
$
|
1,326
|
|
||
|
Less imputed interest costs
|
176
|
|
|||||
|
Present value of net minimum lease payments
|
$
|
371
|
|
||||
Operating lease rental expense was:
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Rental expense
|
$
|
256
|
|
$
|
213
|
|
$
|
139
|
|
||
119
|
26.
|
Commitments and Contingencies
|
We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below, including those resulting from the acquisition of Hess’ Retail Operations and Related Assets. For matters for which we have not recorded an accrued liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings and discovery. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.
Environmental matters
– We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites and certain other locations including presently or formerly owned or operated retail marketing sites. Penalties may be imposed for noncompliance.
At
December 31, 2014
and
2013
, accrued liabilities for remediation totaled
$185 million
and
$123 million
. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties if any that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in clean-up efforts related to underground storage tanks at presently or formerly owned or operated retail marketing sites, were
$67 million
and
$51 million
at
December 31, 2014
and
2013
, respectively.
We are involved in a number of environmental enforcement matters arising in the ordinary course of business. While the outcome and impact on us cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Lawsuits
– In May 2007, the Kentucky attorney general filed a lawsuit against us and Marathon Oil in state court in Franklin County, Kentucky for alleged violations of Kentucky’s emergency pricing and consumer protection laws following Hurricanes Katrina and Rita in 2005. The lawsuit alleges that we overcharged customers by
$89 million
during September and October 2005
. The complaint seeks disgorgement of these sums, as well as penalties, under Kentucky’s emergency pricing and consumer protection laws. We are vigorously defending this litigation. We believe that this is the first lawsuit for damages and injunctive relief under the Kentucky emergency pricing laws to progress this far and it contains many novel issues. In May 2011, the Kentucky attorney general amended his complaint to include a request for immediate injunctive relief as well as unspecified damages and penalties related to our wholesale gasoline pricing in April and May 2011 under statewide price controls that were activated by the Kentucky governor on April 26, 2011 and which have since expired. The court denied the attorney general’s request for immediate injunctive relief, and the remainder of the 2011 claims likely will be resolved along with those dating from 2005. If the lawsuit is resolved unfavorably in its entirety, it could materially impact our consolidated results of operations, financial position or cash flows. However, management does not believe the ultimate resolution of this litigation will have a material adverse effect.
We are a defendant in a number of other lawsuits and other proceedings arising in the ordinary course of business. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the resolution of these other lawsuits and proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Guarantees –
We have provided certain guarantees, direct and indirect, of the indebtedness of other companies. Under the terms of most of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements. In addition to these financial guarantees, we also have various performance guarantees related to specific agreements.
Guarantees related to indebtedness of equity method investees
– We hold interests in an offshore oil port, LOOP, and a crude oil pipeline system, LOCAP LLC. Both LOOP and LOCAP LLC have secured various financings by assigning certain of their rights under throughput and deficiency agreements that they have entered into with us. Under the agreements, we are required to advance funds if the investees are unable to service their debt. Any such advances are considered prepayments of future transportation charges. The duration of the agreements follow the terms of the underlying debt obligations, some of which extend through
2037
. Our maximum potential undiscounted payments under these agreements for the debt principal totaled
$172 million
as of
December 31, 2014
.
We hold an interest in a refined products pipeline through our investment in Centennial, and have guaranteed the payment of Centennial’s principal, interest and prepayment costs, if applicable, under a Master Shelf Agreement, which is scheduled to expire in
2024
. The guarantee arose in order for Centennial to obtain adequate financing. Our maximum potential undiscounted payments under this agreement for debt principal totaled
$38 million
as of
December 31, 2014
.
120
Marathon Oil indemnifications –
In conjunction with the Spinoff, we have entered into arrangements with Marathon Oil providing indemnities and guarantees with recorded values of
$2 million
as of
December 31, 2014
, which consist of unrecognized tax benefits related to MPC, its consolidated subsidiaries and the RM&T Business operations prior to the Spinoff which are not already reflected in the unrecognized tax benefits described in Note
13
, and other contingent liabilities Marathon Oil may incur related to taxes. Furthermore, the separation and distribution agreement and other agreements with Marathon Oil to effect the Spinoff provide for cross-indemnities between Marathon Oil and us. In general, Marathon Oil is required to indemnify us for any liabilities relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and we are required to indemnify Marathon Oil for any liabilities relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these indemnifications are indefinite and the amounts are not capped.
Other guarantees
– We have entered into other guarantees with maximum potential undiscounted payments totaling
$81 million
as of
December 31, 2014
, which primarily consist of a commitment to contribute cash to an equity method investee for certain catastrophic events, up to
$50 million
per event, in lieu of procuring insurance coverage and leases of assets containing general lease indemnities and guaranteed residual values.
General guarantees associated with dispositions –
Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.
Contractual commitments –
At both
December 31, 2014
and
2013
, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled
$1.7 billion
. The contractual commitments at
December 31, 2014
includes
$520 million
of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets,
$703 million
for contributions to North Dakota Pipeline and
$185 million
for contributions to the SAX project. The contractual commitments at December 31, 2013 included the
$700 million
contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets and
$892 million
for contributions to North Dakota Pipeline. See Note
5
.
|
27.
|
Subsequent Event
|
On February 12, 2015, MPLX completed an initial underwritten public offering of
$500 million
aggregate principal amount of
four percent
unsecured senior notes due
February 15, 2025
(the “MPLX Senior Notes”). The MPLX Senior Notes were offered at a price to the public of
99.64 percent
of par. The net proceeds of this offering were used to repay the amounts outstanding under the MPLX Credit Agreement, as well as for general partnership purposes.
121
Selected Quarterly Financial Data (Unaudited)
|
2014
|
2013
|
||||||||||||||||||||||||||||||
|
(In millions, except per share data)
|
1st Qtr.
|
2nd Qtr.
|
3rd Qtr.
|
4th Qtr.
|
1st Qtr.
|
2nd Qtr.
|
3rd Qtr.
|
4th Qtr.
|
|||||||||||||||||||||||
|
Revenues
|
$
|
23,285
|
|
$
|
26,844
|
|
$
|
25,438
|
|
$
|
22,250
|
|
$
|
23,330
|
|
$
|
25,677
|
|
$
|
26,256
|
|
$
|
24,897
|
|
|||||||
|
Income from operations
|
361
|
|
1,369
|
|
1,062
|
|
1,259
|
|
1,156
|
|
960
|
|
301
|
|
1,008
|
|
|||||||||||||||
|
Net income
|
207
|
|
864
|
|
679
|
|
805
|
|
730
|
|
599
|
|
173
|
|
631
|
|
|||||||||||||||
|
Net income attributable to MPC
|
199
|
|
855
|
|
672
|
|
798
|
|
725
|
|
593
|
|
168
|
|
626
|
|
|||||||||||||||
|
Net income attributable to MPC per share:
|
|||||||||||||||||||||||||||||||
|
Basic
|
$
|
0.68
|
|
$
|
2.97
|
|
$
|
2.38
|
|
$
|
2.88
|
|
$
|
2.19
|
|
$
|
1.84
|
|
$
|
0.54
|
|
$
|
2.09
|
|
|||||||
|
Diluted
|
0.67
|
|
2.95
|
|
2.36
|
|
2.86
|
|
2.17
|
|
1.83
|
|
0.54
|
|
2.07
|
|
|||||||||||||||
|
Dividends paid per share
|
0.42
|
|
0.42
|
|
0.50
|
|
0.50
|
|
0.35
|
|
0.35
|
|
0.42
|
|
0.42
|
|
|||||||||||||||
122
Supplementary Statistics (Unaudited)
|
(In millions)
|
2014
|
2013
|
2012
|
||||||||
|
Income from Operations by segment
|
|||||||||||
|
Refining & Marketing
|
$
|
3,609
|
|
$
|
3,206
|
|
$
|
5,098
|
|
||
|
Speedway
|
544
|
|
375
|
|
310
|
|
|||||
|
Pipeline Transportation
(a)
|
280
|
|
210
|
|
216
|
|
|||||
|
Items not allocated to segments:
|
|||||||||||
|
Corporate and other unallocated items
(a)
|
(286
|
)
|
(271
|
)
|
(336
|
)
|
|||||
|
Minnesota Assets sale settlement gain
|
—
|
|
—
|
|
183
|
|
|||||
|
Pension settlement expenses
|
(96
|
)
|
(95
|
)
|
(124
|
)
|
|||||
|
Income from operations
|
$
|
4,051
|
|
$
|
3,425
|
|
$
|
5,347
|
|
||
|
Capital Expenditures and Investments
(b)(c)
|
|||||||||||
|
Refining & Marketing
|
$
|
1,104
|
|
$
|
2,094
|
|
$
|
705
|
|
||
|
Speedway
|
2,981
|
|
296
|
|
340
|
|
|||||
|
Pipeline Transportation
|
543
|
|
234
|
|
211
|
|
|||||
|
Corporate and Other
(d)
|
110
|
|
165
|
|
204
|
|
|||||
|
Total
|
$
|
4,738
|
|
$
|
2,789
|
|
$
|
1,460
|
|
||
|
(a)
|
Included in the Pipeline Transportation segment for
2014
,
2013
and
2012
are
$19 million
,
$20 million
and
$4 million
of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments.
|
|
(b)
|
Capital expenditures include changes in capital accruals.
|
|
(c)
|
Includes
$2.71 billion
in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and
$1.36 billion
in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note
5
to the audited consolidated financial statements.
|
|
(d)
|
Includes capitalized interest of
$27 million
,
$28 million
and
$101 million
for
2014
,
2013
and
2012
, respectively.
|
123
Supplementary Statistics (Unaudited)
|
2014
|
2013
|
2012
|
|||||||||
|
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)
(a)(b)
|
2,138
|
|
2,086
|
|
1,618
|
|
|||||
|
Refining & Marketing Operating Statistics
(b)
|
|||||||||||
|
Refining & Marketing refined product sales volume (thousands of barrels per day)
(c)
|
2,125
|
|
2,075
|
|
1,599
|
|
|||||
|
Refining & Marketing gross margin (dollars per barrel)
(d)
|
$
|
15.05
|
|
$
|
13.24
|
|
$
|
17.85
|
|
||
|
Crude oil capacity utilization percent
(e)
|
95
|
|
96
|
|
100
|
|
|||||
|
Refinery throughputs (thousands of barrels per day):
(f)
|
|||||||||||
|
Crude oil refined
|
1,622
|
|
1,589
|
|
1,195
|
|
|||||
|
Other charge and blendstocks
|
184
|
|
213
|
|
168
|
|
|||||
|
Total
|
1,806
|
|
1,802
|
|
1,363
|
|
|||||
|
Sour crude oil throughput percent
|
52
|
|
53
|
|
53
|
|
|||||
|
WTI-priced crude oil throughput percent
|
19
|
|
21
|
|
28
|
|
|||||
|
Refined product yields (thousands of barrels per day):
(f)
|
|||||||||||
|
Gasoline
|
869
|
|
921
|
|
738
|
|
|||||
|
Distillates
|
580
|
|
572
|
|
433
|
|
|||||
|
Propane
|
35
|
|
37
|
|
26
|
|
|||||
|
Feedstocks and special products
|
276
|
|
221
|
|
109
|
|
|||||
|
Heavy fuel oil
|
25
|
|
31
|
|
18
|
|
|||||
|
Asphalt
|
54
|
|
54
|
|
62
|
|
|||||
|
Total
|
1,839
|
|
1,836
|
|
1,386
|
|
|||||
|
Refinery direct operating costs (dollars per barrel):
(g)
|
|||||||||||
|
Planned turnaround and major maintenance
|
$
|
1.80
|
|
$
|
1.20
|
|
$
|
1.00
|
|
||
|
Depreciation and amortization
|
1.41
|
|
1.36
|
|
1.44
|
|
|||||
|
Other manufacturing
(h)
|
4.86
|
|
4.14
|
|
3.15
|
|
|||||
|
Total
|
$
|
8.07
|
|
$
|
6.70
|
|
$
|
5.59
|
|
||
|
Refining & Marketing Operating Statistics By Region – Gulf Coast
(b)
|
|||||||||||
|
Refinery throughputs (thousands of barrels per day):
(i)
|
|||||||||||
|
Crude oil refined
|
991
|
|
964
|
|
|||||||
|
Other charge and blendstocks
|
182
|
|
195
|
|
|||||||
|
Total
|
1,173
|
|
1,159
|
|
|||||||
|
Sour crude oil throughput percent
|
64
|
|
65
|
|
|||||||
|
WTI-priced crude oil throughput percent
|
3
|
|
7
|
|
|||||||
|
Refined product yields (thousands of barrels per day):
(i)
|
|||||||||||
|
Gasoline
|
508
|
|
551
|
|
|||||||
|
Distillates
|
368
|
|
365
|
|
|||||||
|
Propane
|
23
|
|
23
|
|
|||||||
|
Feedstocks and special products
|
274
|
|
215
|
|
|||||||
|
Heavy fuel oil
|
13
|
|
19
|
|
|||||||
|
Asphalt
|
13
|
|
13
|
|
|||||||
|
Total
|
1,199
|
|
1,186
|
|
|||||||
|
Refinery direct operating costs (dollars per barrel):
(g)
|
|||||||||||
|
Planned turnaround and major maintenance
|
$
|
1.82
|
|
$
|
1.00
|
|
|||||
|
Depreciation and amortization
|
1.15
|
|
1.09
|
|
|||||||
|
Other manufacturing
(h)
|
4.73
|
|
3.98
|
|
|||||||
|
Total
|
$
|
7.70
|
|
$
|
6.07
|
|
|||||
124
|
Supplementary Statistics (Unaudited)
|
|||||||||||
|
2014
|
2013
|
2012
|
|||||||||
|
Refining & Marketing Operating Statistics By Region – Midwest
|
|||||||||||
|
Refinery throughputs (thousands of barrels per day):
(i)
|
|||||||||||
|
Crude oil refined
|
631
|
|
625
|
|
|||||||
|
Other charge and blendstocks
|
45
|
|
54
|
|
|||||||
|
Total
|
676
|
|
679
|
|
|||||||
|
Sour crude oil throughput percent
|
33
|
|
35
|
|
|||||||
|
WTI-priced crude oil throughput percent
|
44
|
|
42
|
|
|||||||
|
Refined product yields (thousands of barrels per day):
(i)
|
|||||||||||
|
Gasoline
|
361
|
|
371
|
|
|||||||
|
Distillates
|
212
|
|
207
|
|
|||||||
|
Propane
|
13
|
|
14
|
|
|||||||
|
Feedstocks and special products
|
43
|
|
41
|
|
|||||||
|
Heavy fuel oil
|
13
|
|
12
|
|
|||||||
|
Asphalt
|
41
|
|
41
|
|
|||||||
|
Total
|
683
|
|
686
|
|
|||||||
|
Refinery direct operating costs (dollars per barrel):
(g)
|
|||||||||||
|
Planned turnaround and major maintenance
|
$
|
1.66
|
|
$
|
1.47
|
|
|||||
|
Depreciation and amortization
|
1.78
|
|
1.74
|
|
|||||||
|
Other manufacturing
(h)
|
4.76
|
|
4.21
|
|
|||||||
|
Total
|
$
|
8.20
|
|
$
|
7.42
|
|
|||||
|
Speedway Operating Statistics
(j)
|
|||||||||||
|
Convenience stores at period-end
|
2,746
|
|
1,478
|
|
1,464
|
|
|||||
|
Gasoline and distillate sales (millions of gallons)
|
3,942
|
|
3,146
|
|
3,027
|
|
|||||
|
Gasoline & distillate gross margin (dollars per gallon)
(k)
|
$
|
0.1775
|
|
$
|
0.1441
|
|
$
|
0.1318
|
|
||
|
Merchandise sales (in millions)
|
$
|
3,611
|
|
$
|
3,135
|
|
$
|
3,058
|
|
||
|
Merchandise gross margin (in millions)
|
$
|
975
|
|
$
|
825
|
|
$
|
795
|
|
||
|
Merchandise gross margin percent
|
27.0
|
%
|
26.3
|
%
|
26.0
|
%
|
|||||
|
Same store gasoline sales volume (period over period)
|
(0.7
|
)%
|
0.5
|
%
|
(0.8
|
)%
|
|||||
|
Same store merchandise sales (period over period)
(l)
|
5.0
|
%
|
4.3
|
%
|
7.0
|
%
|
|||||
|
Pipeline Transportation Operating Statistics
|
|||||||||||
|
Pipeline throughputs (thousands of barrels per day):
(m)
|
|||||||||||
|
Crude oil pipelines
|
1,241
|
|
1,293
|
|
1,191
|
|
|||||
|
Refined products pipelines
|
878
|
|
911
|
|
980
|
|
|||||
|
Total
|
2,119
|
|
2,204
|
|
2,171
|
|
|||||
|
(a)
|
Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.
|
|
(b)
|
Includes the impact of the Galveston Bay Refinery and Related Assets beginning on the February 1, 2013 acquisition date.
|
|
(c)
|
Includes intersegment sales.
|
|
(d)
|
Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. Starting in the fourth quarter of 2013, direct operating costs are no longer included in the Refining & Marketing gross margin and the gross margin is calculated based on total refinery throughput. All prior periods presented have been recalculated to reflect a consistent approach.
|
|
(e)
|
Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.
|
|
(f)
|
Excludes inter-refinery volumes of
43 thousand
barrels per day (“mbpd”),
36
mbpd and
25
mbpd for
2014
,
2013
and
2012
, respectively.
|
|
(g)
|
Per barrel of total refinery throughputs.
|
|
(h)
|
Includes utilities, labor, routine maintenance and other operating costs.
|
|
(i)
|
Includes inter-refinery transfer volumes.
|
|
(j)
|
Includes the impact of Hess’ Retail Operations and Related Assets beginning on the September 30, 2014 acquisition date.
|
|
(k)
|
The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillate sales volume.
|
|
(l)
|
Excludes cigarettes.
|
|
(m)
|
On owned common-carrier pipelines, excluding equity method investments.
|
125
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of our management, including our chief executive officer and chief financial officer. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the design and operation of these disclosure controls and procedures were effective as of
December 31, 2014
, the end of the period covered by this Annual Report on Form 10-K.
Internal Control over Financial Reporting and Changes in Internal Control over Financial Reporting
See Item 8. Financial Statements and Supplementary Data – Management’s Report on Internal Control over Financial Reporting and – Report of Independent Registered Public Accounting Firm, which reports are incorporated herein by reference.
During the quarter ended
December 31, 2014
, we acquired Hess’ Retail Operations and Related Assets. The scope of our assessment of the effectiveness of disclosure controls and procedures does not include Hess’ Retail Operations and Related Assets. There have been no other changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
On February 24, 2015, the Compensation Committee of our Board of Directors (the “Committee”) approved and authorized a retirement lump sum benefit supplement, as further described below (the “Service Benefit”), to the respective formulaic benefit to be received under the Marathon Petroleum Excess Benefit Plan (the “Plan”) by Marathon Petroleum Corporation named executive officers, Gary R. Heminger and Anthony R. Kenney, should they individually elect to continue service as our employee beyond the age of 62. The Plan was amended and restated by the Committee on October 29, 2014, and such amended and restated Plan is filed as an exhibit to this Annual Report on Form 10-K (the “Revised Plan”). While the Revised Plan permits the Committee, on a discretionary basis, to extend the Service Benefit to individual officers of Marathon Petroleum Corporation, the amendment and restatement of the Plan by itself had no material impact on the defined benefit plan compensation of our named executive officers prior to the Committee’s subsequent action on February 24, 2015.
The Plan is an unfunded, non-qualified retirement plan for the benefit of a select group of management, including our named executive officers and highly compensated employees. The Plan generally provides benefits that participants would have otherwise received under the tax-qualified Marathon Petroleum Retirement Plan (the “Retirement Plan”) were it not for Internal Revenue Code limitations. Due to the structure of the legacy final average pay benefit formula within the Retirement Plan, the age-related lump sum benefit conversion factors used to calculate lump sum benefits under the Plan result in a year-to-year decrease in the lump sum benefit for participants generally beginning on or after the age of 59. As a result, even if participants want to continue their employment with us after they reach age 59, their lump sum benefit may decline year-to-year.
The Service Benefit will not correct for any age-related erosion of benefit occurring prior to age 62 but, for those officers selected by the Committee in its sole discretion, the Service Benefit will correct for the age-related erosion of benefit from age 62 until such officer’s actual retirement date or date of death as described herein. If an officer to whom the Service Benefit has been extended by the Committee retires or dies (1) after reaching age 62 and (2) while in service as our active employee, such officer will be eligible to receive a retirement lump sum benefit supplement calculated as follows:
|
a.
|
If the lump sum interest rate upon such officer reaching the age of 62 used to calculate the retirement lump sum benefit is less than or equal to the lump sum interest rate in effect on such officer’s actual retirement date or date of death, the retirement lump sum benefit supplement shall be the difference between the legacy final average pay-based lump sum benefit he or she would have been eligible to receive using the age 62 lump sum conversion factor based on the lump sum interest rate in effect on the actual retirement date or date of death and the legacy final average pay-based lump sum benefit he or she is eligible to receive using the lump sum conversion factor for the actual age at retirement or death based on the lump sum interest rate in effect on the actual retirement date or date of death; or
|
126
|
b.
|
If the lump sum interest rate upon such officer reaching the age of 62 used to calculate the retirement lump sum benefit is greater than the lump sum interest rate in effect on such officer’s actual retirement date or date of death, the retirement lump sum benefit supplement shall be the difference between the legacy final average pay-based lump sum benefit he or she would have been eligible to receive using the lump sum conversion factor and lump sum interest rate in effect at age 62 and the legacy final average pay-based lump sum benefit he or she is eligible to receive using the lump sum conversion factor and lump sum interest rate in effect on the actual retirement date or date of death.
|
As designed by the Committee, the Service Benefit does not compensate for unfavorable fluctuations in the lump sum interest rate and is in fact structured to prevent payment of a retirement lump sum benefit supplement greater than intended within a favorable interest rate environment; the Service Benefit is designed to correct only for the benefit erosion an officer may experience for continued service should he or she elect to remain our employee beyond the age of 62.
The foregoing description of the Plan, the Revised Plan and the Service Benefit are summary in nature and subject to, and qualified in their entirety by, the full text of the Revised Plan, a copy of which is attached hereto as Exhibit 10.14 and is incorporated herein by reference.
127
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information concerning our directors required by this item is incorporated by reference to the material appearing under the sub-heading “Proposal No. 1 – Election of Class I Directors” located under the heading “Proposals of the Board” in our Proxy Statement for the
2015
Annual Meeting of Shareholders. Information concerning our executive officers is included in Part I, Item 1 of this Annual Report on Form 10-K.
Our board of directors has established the Audit Committee and determined our “Audit Committee Financial Experts.” The related information required by this item is incorporated by reference to the material appearing under the sub-heading “Audit Committee Financial Expert” located under the heading “The Board of Directors and Corporate Governance” in our Proxy Statement for the
2015
Annual Meeting of Shareholders.
We have adopted a Code of Ethics for Senior Financial Officers, which applies to our Chief Executive Officer, Chief Financial Officer, Vice President and Controller, Treasurer and other persons performing similar functions. It is available on our website at http://ir.marathonpetroleum.com by selecting “Corporate Governance” and clicking on “Code of Ethics for Senior Financial Officers.”
Section 16(a) Beneficial Ownership Reporting Compliance
Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934 is set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement for the
2015
Annual Meeting of Shareholders, which is incorporated herein by reference.
Item 11. Executive Compensation
Information required by this item is incorporated by reference to the material appearing under the heading “Executive Compensation;” under the sub-headings “Compensation Committee” and “Compensation Committee Interlocks and Insider Participation” located under the heading “The Board of Directors and Corporate Governance;” under the heading “Compensation of Directors;” and under the heading “Compensation Committee Report” in our Proxy Statement for the
2015
Annual Meeting of Shareholders.
128
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information concerning security ownership of certain beneficial owners and management required by this item is incorporated by reference to the material appearing under the headings “Security Ownership of Certain Beneficial Owners” and “Security Ownership of Directors and Executive Officers” in our Proxy Statement for the 2015 Annual Meeting of Shareholders.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of
December 31, 2014
with respect to shares of our common stock that may be issued under the MPC 2012 Plan and the MPC 2011 Plan:
|
Plan category
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
(a)
|
|
Weighted-average exercise price of outstanding options, warrants and rights
(b)
|
Number of securities remaining available for future issuance under equity compensation
plans
(c)
|
|||||
|
Equity compensation plans approved by stockholders
|
5,290,867
|
|
|
$
|
45.47
|
|
23,510,876
|
|
|
|
Equity compensation plan not approved by stockholders
|
—
|
|
—
|
|
—
|
|
|||
|
Total
|
5,290,867
|
|
N/A
|
|
23,510,876
|
|
|||
(a)
Includes the following:
|
1)
|
4,751,438
stock options granted pursuant to the MPC 2012 Plan and the MPC 2011 Plan and not forfeited, cancelled or expired as of
December 31, 2014
.
|
|
2)
|
411,093
restricted stock units granted pursuant to the MPC 2012 Plan and the MPC 2011 Plan for shares unissued and not forfeited, cancelled or expired as of
December 31, 2014
.
|
|
3)
|
128,336
shares as the maximum potential number of shares that could be issued in settlement of performance units outstanding as of
December 31, 2014
pursuant to the MPC 2012 Plan and the MPC 2011 Plan, based on the closing price of our common stock on
December 31, 2014
of
$90.26
per share. The number of shares reported for this award vehicle may overstate dilution. See Note
24
for more information on performance unit awards granted under the MPC 2012 Plan and the MPC 2011 Plan.
|
In addition to the awards reported above,
515,073
shares of restricted stock have been issued pursuant to the MPC 2012 Plan and the MPC 2011 Plan and were outstanding as of
December 31, 2014
.
|
(b)
|
Restricted stock, restricted stock units and performance units are not taken into account in the weighted-average exercise price as such awards have no exercise price.
|
|
(c)
|
Reflects the shares available for issuance pursuant to the MPC 2012 Plan. All granting authority under the MPC 2011 Plan was revoked following the approval of the MPC 2012 Plan by shareholders on April 25, 2012. No more than
9,357,450
of the shares reported in this column may be issued for awards other than stock options or stock appreciation rights. The number of shares reported in this column assumes
83,226
as the maximum potential number of shares that could be issued pursuant to the MPC 2012 Plan in settlement of performance units outstanding as of
December 31, 2014
, based on the closing price of our common stock on
December 31, 2014
, of
$90.26
per share. The number of shares assumed for this award vehicle may understate the number of shares available for issuance pursuant to the MPC 2012 Plan. See Note
24
for more information on performance unit awards granted pursuant to the MPC 2012 Plan. Shares related to grants made pursuant to the MPC 2012 Plan that are forfeited, cancelled or expire unexercised become immediately available for issuance under the MPC 2012 Plan.
|
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item is incorporated by reference to the material appearing under the heading “Certain Relationships and Related Person Transactions,” and under the sub-heading “Board and Committee Independence” under the heading “The Board of Directors and Corporate Governance” in our Proxy Statement for the
2015
Annual Meeting of Shareholders.
Item 14. Principal Accountant Fees and Services
Information required by this item is incorporated by reference to the material appearing under the heading “Independent Registered Public Accounting Firm’s Fees, Services and Independence” in our Proxy Statement for the
2015
Annual Meeting of Shareholders.
129
PART IV
Item 15. Exhibits and Financial Statement Schedules
A. Documents Filed as Part of the Report
1. Financial Statements (see Part II, Item 8. of this Annual Report on Form 10-K regarding financial statements)
2. Financial Statement Schedules
Financial statement schedules required under SEC rules but not included in this Annual Report on Form 10-K are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.
3. Exhibits:
|
Exhibit
Number
|
Exhibit Description
|
|
Incorporated by Reference
|
Filed
Herewith
|
Furnished
Herewith
|
|||||||||
|
Form
|
Exhibit
|
Filing
Date
|
SEC
File No.
|
|||||||||||
|
2
|
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
|
|||||||||||||
|
2.1 †
|
Separation and Distribution Agreement, dated as of May 25, 2011, among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation
|
10
|
2.1
|
5/26/2011
|
001-35054
|
|||||||||
|
2.2 †
|
Purchase and Sale Agreement, dated as of October 7, 2012, by and among BP Products North America Inc. and BP Pipelines (North America) Inc., as the Sellers and Marathon Petroleum Company LP, as the Buyer
|
8-K
|
2.1
|
10/9/2012
|
001-35054
|
|||||||||
|
2.3 †
|
Purchase Agreement by and between Speedway LLC and Hess Corporation, dated as of May 21, 2014
|
8-K
|
2.1
|
5/27/2014
|
001-35054
|
|||||||||
|
2.4 †
|
Amendment No. 1 effective as of September 30, 2014, to the Purchase Agreement by and between Speedway LLC and Hess Corporation, dated as of May 21, 2014
|
8-K
|
2.2
|
10/6/2014
|
001-35054
|
|||||||||
|
3
|
Articles of Incorporation and Bylaws
|
|||||||||||||
|
3.1
|
Restated Certificate of Incorporation of Marathon Petroleum Corporation
|
8-K
|
3.1
|
6/22/2011
|
001-35054
|
|||||||||
|
3.2
|
Amended and Restated Bylaws of Marathon Petroleum Corporation
|
10-Q
|
3.2
|
8/8/2012
|
001-35054
|
|||||||||
|
4
|
Instruments Defining the Rights of Security Holders, Including Indentures
|
|||||||||||||
|
4.1
|
Indenture dated as of February 1, 2011 between Marathon Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee
|
10
|
4.1
|
5/26/2011
|
001-35054
|
|||||||||
|
4.2
|
Form of the terms of the 3
1/2% Senior Notes due 2016, 5
1/8% Senior Notes due 2021 and 6
1/2% Senior Notes due 2041 of Marathon Petroleum Corporation (including form of note)
|
10
|
4.2
|
5/26/2011
|
001-35054
|
|||||||||
|
4.3
|
First Supplemental Indenture, dated as of September 5, 2014, by and between Marathon Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee
|
10-Q
|
4.1
|
11/3/2014
|
001-35054
|
|||||||||
|
10
|
Material Contracts
|
|||||||||||||
|
10.1
|
Tax Sharing Agreement dated as of May 25, 2011 by and among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC
|
10
|
10.1
|
5/26/2011
|
001-35054
|
|||||||||
|
10.2
|
Employee Matters Agreement dated as of May 25, 2011 by and between Marathon Oil Corporation and Marathon Petroleum Corporation
|
10
|
10.2
|
5/26/2011
|
001-35054
|
|||||||||
|
10.3
|
Amendment to Employee Matters Agreement, dated as of June 30, 2011 by and between Marathon Oil Corporation and Marathon Petroleum Corporation
|
8-K
|
10.1
|
7/1/2011
|
001-35054
|
|||||||||
130
|
Exhibit
Number
|
Exhibit Description
|
|
Incorporated by Reference
|
Filed
Herewith
|
Furnished
Herewith
|
|||||||||
|
Form
|
Exhibit
|
Filing
Date
|
SEC
File No.
|
|||||||||||
|
10.4
|
Receivables Purchase Agreement, dated as of December 18, 2013, by and among MPC Trade Receivables Company, LLC, Marathon Petroleum Company LP, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, as administrative agent and sole lead arranger, certain committed purchasers and conduit purchasers that are parties thereto from time to time and certain other parties thereto from time to time as managing agents and letter of credit issuers.
|
8-K
|
10.1
|
12/23/2013
|
001-35054
|
|||||||||
|
10.5
|
Second Amended and Restated Receivables Sale Agreement, dated as of December 18, 2013, by and between Marathon Petroleum Company LP and MPC Trade Receivables Company LLC
|
8-K
|
10.2
|
12/23/2013
|
001-35054
|
|||||||||
|
10.6
|
Revolving Credit Agreement, dated as of September 14, 2012, by and among MPC, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, each of J.P. Morgan Securities LLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley Senior Funding, Inc., RBS Securities Inc. and UBS Securities LLC, as joint lead arrangers and joint bookrunners, Citigroup Global Markets Inc., as syndication agent, each of Bank of America, N.A., Morgan Stanley Senior Funding, Inc., The Royal Bank of Scotland PLC and USB AG, Stamford Branch, as documentation agents, and several other commercial lending institutions that are parties thereto.
|
8-K
|
10.1
|
9/20/2012
|
001-35054
|
|||||||||
|
10.7
|
First Amendment, dated December 20, 2012, to the Revolving Credit Agreement, dated as of September 14, 2012, by and among MPC, as borrower, the commercial financial institutions that are lending parties thereto, and JPMorgan Chase Bank, N.A., as administrative agent.
|
8-K
|
10.1
|
12/20/2012
|
001-35054
|
|||||||||
|
10.8
|
Credit Agreement, dated as of November 20, 2014, among MPLX LP, as borrower, Citibank, N.A., as administrative agent, each of Citigroup Global Markets Inc., Wells Fargo Securities, LLC, Barclays Bank PLC, J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporate and RBS Securities Inc., as joint lead arrangers and joint bookrunners, Wells Fargo Bank, N.A., as syndication agent, and each of Bank of America, N.A., Barclays Bank PLC, JPMorgan Chase Bank, N.A., and The Royal Bank of Scotland PLC, as documentation agents, and the other lenders and issuing banks that are parties thereto.
|
8-K
|
10.1
|
11/26/2014
|
001-35054
|
|||||||||
|
10.9
|
Contribution, Conveyance and Assumption Agreement, dated as of October 31, 2012, among MPLX LP, MPLX GP LLC, MPLX Operations LLC, MPC Investment LLC, MPLX Logistics Holdings LLC, Marathon Pipe Line LLC, MPL Investment LLC, MPLX Pipe Line Holdings LP and Ohio River Pipe Line LLC.
|
8-K
|
10.1
|
11/6/2012
|
001-35054
|
|||||||||
|
10.10
|
Omnibus Agreement
,
dated as of October 31, 2012, among Marathon Petroleum Corporation, Marathon Petroleum Company LP, MPL Investment LLC, MPLX Operations LLC, MPLX Terminal and Storage LLC, MPLX Pipe Line Holdings LP, Marathon Pipe Line LLC, Ohio River Pipe Line LLC, MPLX LP and MPLX GP LLC.
|
8-K
|
10.2
|
11/6/2012
|
001-35054
|
|||||||||
|
10.11 *
|
Marathon Petroleum Corporation Second Amended and Restated 2011 Incentive Compensation Plan
|
S-3
|
4.3
|
12/7/2011
|
333-175286
|
|||||||||
|
10.12 *
|
Marathon Petroleum Corporation Policy for Recoupment of Annual Cash Bonus Amounts
|
10-K
|
10.1
|
2/29/2012
|
001-35054
|
|||||||||
|
10.13 *
|
Marathon Petroleum Corporation Deferred Compensation Plan for Non-Employee Directors
|
10-K
|
10.13
|
2/28/2013
|
001-35054
|
|||||||||
|
10.14 *
|
Marathon Petroleum Amended and Restated Excess Benefit Plan
|
X
|
||||||||||||
|
10.15 *
|
Marathon Petroleum Amended and Restated Deferred Compensation Plan
|
10-K
|
10.13
|
2/29/2012
|
001-35054
|
|||||||||
131
|
Exhibit
Number
|
Exhibit Description
|
|
Incorporated by Reference
|
Filed
Herewith
|
Furnished
Herewith
|
|||||||||
|
Form
|
Exhibit
|
Filing
Date
|
SEC
File No.
|
|||||||||||
|
10.16 *
|
Marathon Petroleum Corporation Executive Tax, Estate, and Financial Planning Program
|
10-K
|
10.14
|
2/29/2012
|
001-35054
|
|||||||||
|
10.17 *
|
Speedway Excess Benefit Plan
|
10-K
|
10.15
|
2/29/2012
|
001-35054
|
|||||||||
|
10.18 *
|
Speedway Deferred Compensation Plan
|
10-K
|
10.16
|
2/29/2012
|
001-35054
|
|||||||||
|
10.19 *
|
Form of Marathon Petroleum Corporation Amended and Restated 2011 Incentive Compensation Plan – Section 16 Officer Restricted Stock Award Agreement (3 year pro rata vesting)
|
8-K
|
10.4
|
7/7/2011
|
001-35054
|
|||||||||
|
10.20 *
|
Form of Marathon Petroleum Corporation Amended and Restated 2011 Incentive Compensation Plan – Section 16 Officer Restricted Stock Award Agreement (3 year cliff vesting)
|
8-K
|
10.5
|
7/7/2011
|
001-35054
|
|||||||||
|
10.21 *
|
Form of Marathon Petroleum Corporation Amended and Restated 2011 Incentive Compensation Plan Nonqualified Stock Option Award Agreement – Section 16 Officer
|
8-K
|
10.6
|
7/7/2011
|
001-35054
|
|||||||||
|
10.22 *
|
Form of Marathon Petroleum Corporation 2011 Incentive Compensation Plan Supplemental Restricted Stock Award Agreement – Section 16 Officer
|
8-K
|
10.1
|
12/7/2011
|
001-35054
|
|||||||||
|
10.23 *
|
Form of Marathon Petroleum Corporation 2011 Incentive Compensation Plan Supplemental Nonqualified Stock Option Award Agreement – Section 16 Officer
|
8-K
|
10.2
|
12/7/2011
|
001-35054
|
|||||||||
|
10.24 *
|
Form of Marathon Petroleum Corporation 2011 Incentive Compensation Plan Supplemental Restricted Stock Unit Award Agreement – Non-Employee Director
|
10-K
|
10.22
|
2/29/2012
|
001-35054
|
|||||||||
|
10.25 *
|
Form of Marathon Petroleum Corporation Amended and Restated 2011 Incentive Compensation Plan – Performance Unit Award Agreement
|
10-K
|
10.23
|
2/29/2012
|
001-35054
|
|||||||||
|
10.26 *
|
Marathon Petroleum Corporation Amended and Restated Executive Change in Control Severance Benefits Plan
|
10-K
|
10.26
|
2/28/2013
|
001-35054
|
|||||||||
|
10.27 * `
|
Form of Marathon Petroleum Corporation Performance Unit Award Agreement – 2012-2014 Performance Cycle
|
10-Q
|
10.3
|
5/9/2012
|
001-35054
|
|||||||||
|
10.28 *
|
Form of Marathon Petroleum Corporation Restricted Stock Award Agreement – Officer
|
10-Q
|
10.4
|
5/9/2012
|
001-35054
|
|||||||||
|
10.29 *
|
Form of Marathon Petroleum Corporation Nonqualified Stock Option Award Agreement – Officer
|
10-Q
|
10.5
|
5/9/2012
|
001-35054
|
|||||||||
|
10.30 *
|
Marathon Petroleum Corporation 2012 Incentive Compensation Plan
|
S-8
|
4.3
|
4/27/2012
|
333-181007
|
|||||||||
|
10.31 *
|
Amended and Restated Marathon Petroleum Annual Cash Bonus Program
|
X
|
||||||||||||
|
10.32 *
|
MPC Non-Employee Director Phantom Unit Award Policy
|
10-K
|
10.32
|
2/28/2013
|
001-35054
|
|||||||||
|
10.33 *
|
Form of Marathon Petroleum Corporation Performance Unit Award Agreement – 2013-2015 Performance Cycle
|
10-Q
|
10.1
|
5/9/2013
|
001-35054
|
|||||||||
|
10.34 *
|
Form of Marathon Petroleum Corporation Restricted Stock Award Agreement – Officer
|
10-Q
|
10.2
|
5/9/2013
|
001-35054
|
|||||||||
|
10.35 *
|
Form of Marathon Petroleum Corporation Nonqualified Stock Option Award Agreement – Officer
|
10-Q
|
10.3
|
5/9/2013
|
001-35054
|
|||||||||
|
10.36 *
|
MPLX LP – Form of MPC Officer Phantom Unit Award Agreement
|
10-Q
|
10.4
|
5/9/2013
|
001-35054
|
|||||||||
|
10.37 *
|
MPLX LP – Form of MPC Officer Performance Unit Award Agreement – 2013-2015 Performance Cycle
|
10-Q
|
10.5
|
5/9/2013
|
001-35054
|
|||||||||
|
10.38 *
|
Amendment to Certain Outstanding MPC Restricted Stock Award Agreements and Performance Unit Award Agreements of Garry L. Peiffer
|
10-K
|
10.38
|
2/28/2014
|
001-35054
|
|||||||||
132
|
Exhibit
Number
|
Exhibit Description
|
|
Incorporated by Reference
|
Filed
Herewith
|
Furnished
Herewith
|
|||||||||
|
Form
|
Exhibit
|
Filing
Date
|
SEC
File No.
|
|||||||||||
|
10.39*
|
Form of Marathon Petroleum Corporation Performance Unit Award Agreement – 2014-2016 Performance Cycle
|
10-Q
|
10.1
|
5/5/2014
|
001-35054
|
|||||||||
|
10.4
|
Term Loan Agreement, dated August 26, 2014, by and among Marathon Petroleum Corporation, as borrower, The Royal Bank of Scotland PLC, as administrative agent, each of RBS Securities Inc., The Bank of Tokyo-Mitsubishi UFJ, Ltd. Barclays Bank PLC, Citigroup Global Markets Inc., and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and joint bookrunners. The Bank of Tokyo-Mitsubishi UFJ, Ltd., as syndication agent, each of Barclays Bank PLC, Citigroup Global Markets Inc. and Morgan Stanley Senior Funding, Inc., as documentation agents, and several other commercial lending institutions that are parties thereto
|
8-K
|
10.1
|
8/29/2014
|
001-35054
|
|||||||||
|
12.1
|
Computation of Ratio of Earnings to Fixed Charges
|
X
|
||||||||||||
|
14.1
|
Code of Ethics for Senior Financial Officers
|
10-K
|
14.1
|
2/29/2012
|
001-35054
|
|||||||||
|
21.1
|
List of Subsidiaries
|
X
|
||||||||||||
|
23.1
|
Consent of Independent Registered Public Accounting Firm
|
X
|
||||||||||||
|
24.1
|
Power of Attorney of Directors and Officers of Marathon Petroleum Corporation
|
X
|
||||||||||||
|
31.1
|
Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.
|
X
|
||||||||||||
|
31.2
|
Certification of Senior Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.
|
X
|
||||||||||||
|
32.1
|
Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
|
X
|
||||||||||||
|
32.2
|
Certification of Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
|
X
|
||||||||||||
|
101.INS
|
XBRL Instance Document.
|
X
|
||||||||||||
|
101.SCH
|
XBRL Taxonomy Extension Schema.
|
X
|
||||||||||||
|
101.PRE
|
XBRL Taxonomy Extension Presentation Linkbase.
|
X
|
||||||||||||
|
101.CAL
|
XBRL Taxonomy Extension Calculation Linkbase.
|
X
|
||||||||||||
|
101.DEF
|
XBRL Taxonomy Extension Definition Linkbase.
|
X
|
||||||||||||
|
101.LAB
|
XBRL Taxonomy Extension Label Linkbase.
|
X
|
||||||||||||
|
†
|
The exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.
|
|
*
|
Indicates management contract or compensatory plan, contract or arrangement in which one or more directors or executive officers of the Registrant may be participants.
|
133
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.
|
February 27, 2015
|
MARATHON PETROLEUM CORPORATION
|
|
|
By: /s/ John J. Quaid
|
||
|
John J. Quaid
Vice President and Controller
|
||
134
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on
February 27, 2015
on behalf of the registrant and in the capacities indicated.
|
Signature
|
Title
|
|
|
/s/ Gary R. Heminger
|
President and Chief Executive Officer and Director
(Principal Executive Officer)
|
|
|
Gary R. Heminger
|
||
|
/s/ Donald C. Templin
|
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
|
|
|
Donald C. Templin
|
||
|
/s/ John J. Quaid
|
Vice President and Controller
(Principal Accounting Officer)
|
|
|
John J. Quaid
|
||
|
*
|
Director
|
|
|
Evan Bayh
|
||
|
*
|
Director
|
|
|
David A. Daberko
|
||
|
*
|
Director
|
|
|
Steven A. Davis
|
||
|
*
|
Director
|
|
|
William L. Davis
|
||
|
*
|
Director
|
|
|
Donna A. James
|
||
|
*
|
Director
|
|
|
Charles R. Lee
|
||
|
*
|
Director
|
|
|
James E. Rohr
|
||
|
*
|
Director
|
|
|
Seth E. Schofield
|
||
|
*
|
||
|
John W. Snow
|
Director
|
|
|
*
|
Director
|
|
|
John P. Surma
|
||
|
*
|
Chairman of the Board and Director
|
|
|
Thomas J. Usher
|
||
135
* The undersigned, by signing his name hereto, does sign and execute this report pursuant to the Power of Attorney executed by the above-named directors and officers of the registrant, which is being filed herewith on behalf of such directors and officers.
|
By: /s/ Gary R. Heminger
|
February 27, 2015
|
|
|
Gary R. Heminger
Attorney-in-Fact
|
||
136
TABLE OF CONTENTS
Part IprintItem 1. BusinessprintItem 1A. Risk FactorsprintItem 1B. Unresolved Staff CommentsprintItem 2. PropertiesprintItem 3. Legal ProceedingsprintItem 4. Mine Safety DisclosuresprintPart IIprintItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesprintItem 6. Selected Financial DataprintItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsprintItem 8. Financial Statements and Supplementary Data NoteprintItem 7A. Quantitative and Qualitative Disclosures About Market RiskprintItem 8. Financial Statements and Supplementary DataprintItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureprintItem 9A. Controls and ProceduresprintItem 9B. Other InformationprintPart IIIprintItem 10. Directors, Executive Officers and Corporate GovernanceprintItem 11. Executive CompensationprintItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersprintItem 13. Certain Relationships and Related Transactions, and Director IndependenceprintItem 14. Principal Accountant Fees and ServicesprintPart IVprintItem 15. Exhibits and Financial Statement Schedulesprint