10-K 1 kmp-20131231x10k.htm 10-K KMP-2013.12.31-10K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________
 
Form 10-K

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

For the fiscal year ended December 31, 2013
 
or
 
[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____
 

Commission file number: 001-11234
Kinder Morgan Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
 
Delaware
 
 
76-0380342
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)

1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices) (zip code)

Registrant’s telephone number, including area code: 713-369-9000

____________
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
Name of each exchange on which registered
Common Units
New York Stock Exchange

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



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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ  No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 þ  No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ                             Accelerated filer o 
Non-accelerated filer o (Do not check if a smaller reporting company)        Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o  No þ
 
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 28, 2013 was approximately $18,553,816,889.  As of January 31, 2014, the registrant had 312,989,671 Common Units outstanding.






KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
 
 
Page
Number
 
 
 
PART I
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
PART IV
 
 


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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
GLOSSARY
 
Company Abbreviations
Calnev
=
Calnev Pipe Line LLC
 
KMP
=
Kinder Morgan Energy Partners, L.P., and our majority-owned and controlled subsidiaries
Copano
=
Copano Energy, L.L.C.
 
KinderHawk
=
KinderHawk Field Services LLC
EP
=
El Paso Corporation and its majority-owned and controlled subsidiaries
 
KMI
=
Kinder Morgan, Inc. and its majority-owned and controlled subsidiaries
EPB
=
El Paso Pipeline Partners, L.P. and its majority-owned and controlled subsidiaries
 
KMR
=
Kinder Morgan Management, LLC
EPNG
=
El Paso Natural Gas Company, L.L.C.
 
NGPL
=
Natural Gas Pipeline Company of America LLC
KMCO2
=
Kinder Morgan CO2 Company, L.P.
 
SFPP
=
SFPP, L.P.
KMEP
=
Kinder Morgan Energy Partners, L.P.
 
TGP
=
Tennessee Gas Pipeline Company, L.L.C.
 
 
 
 
 
 
 
Unless the context otherwise requires, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P., our majority-owned and controlled subsidiaries, and our operating limited partnerships and their majority-owned and controlled subsidiaries.
 
 
 
 
 
 
 
Common Industry and Other Terms
AFUDC
=
allowance for funds used during construction
 
LLC
=
limited liability company
Bcf/d
=
billion cubic feet per day
 
LNG
=
liquefied natural gas
BBtu/d
=
billion British Thermal Units per day
 
MBbl/d
=
thousands of barrels per day
CERCLA
=
Comprehensive Environmental Response, Compensation and Liability Act
 
MDth/d
=
thousand dekatherm per day
CFTC
=
Commodities Futures Trading Commission
 
MLP
=
master limited partnership
CO2
=
carbon dioxide
 
MMBbl/d
=
millions of barrels per day
CPUC
=
California Public Utilities Commission
 
MMcf/d
=
million cubic feet per day
EBDA
=
earnings before depreciation, depletion and amortization
 
NEB
=
National Energy Board
DD&A
=
depreciation, depletion and amortization
 
NGL
=
natural gas liquids
DCF
=
distributable cash flow
 
NYMEX
=
New York Mercantile Exchange
Dth
=
dekatherm
 
NYSE
=
New York Stock Exchange
EPA
=
United States Environmental Protection Agency
 
OTC
=
over-the-counter
FERC
=
Federal Energy Regulatory Commission
 
PHMSA
=
Pipeline and Hazardous Materials Safety Administration
FASB
=
Financial Accounting Standards Board
 
PRP
=
Potentially Responsible Party
FTC
=
Federal Trade Commission
 
SEC
=
United States Securities and Exchange Commission
GAAP
=
United States Generally Accepted Accounting Principles
 
TBtu
=
trillion British Thermal Units
LIBOR
=
London Interbank Offered Rate
 
WTI
=
West Texas Intermediate
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.



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Information Regarding Forward-Looking Statements
 
This report includes forward-looking statements.  These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts.  They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” or the negative of those terms or other variations of them or comparable terminology.  In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements.  Forward-looking statements are not guarantees of performance.  They involve risks, uncertainties and assumptions.  Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements.  Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

the availability of drop-down assets and the terms and timing of sales from KMI;

the timing and extent of changes in price trends and overall demand for NGL, refined petroleum products, oil, CO2, natural gas, electricity, coal, steel and other bulk materials and chemicals and certain agricultural products in North America;

economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

changes in our tariff rates required by the FERC, the CPUC, Canada’s NEB or another regulatory agency;

our ability to acquire new businesses and assets and integrate those operations into our existing operations, and make cost-saving changes in operations, particularly if we undertake multiple acquisitions in a relatively short period of time, as well as our ability to expand our facilities;

our ability to safely operate and maintain our existing assets and to access or construct new pipeline, gas processing and NGL fractionation capacity;

our ability to attract and retain key management and operations personnel;

difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;

shut-downs or cutbacks at major refineries, petrochemical or chemical plants, natural gas processing plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us;

changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in Oklahoma, Ohio, Pennsylvania and Texas, and the U.S. Rocky Mountains and the Alberta, Canada oil sands;

changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete;

interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes;

the uncertainty inherent in estimating future oil, natural gas, and CO2 production or reserves that we may experience;

the ability to complete expansion projects and construction of our vessels on time and on budget;

the timing and success of our business development efforts, including our ability to renew long-term customer contracts;

changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;

changes in tax law, particularly as it relates to partnerships or other “pass-through” entities;


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our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts and on acceptable terms to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities;

our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at a competitive disadvantage compared to our competitors that have less debt, or have other adverse consequences;

our ability to obtain insurance coverage without significant levels of self-retention of risk;

acts of nature, sabotage, terrorism (including cyber attacks) or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits;

possible changes in our credit ratings;

capital and credit markets conditions, inflation and fluctuations in interest rates;

the political and economic stability of the oil producing nations of the world;

national, international, regional and local economic, competitive and regulatory conditions and developments;

our ability to achieve cost savings and revenue growth;

foreign exchange fluctuations;

the extent of our success in developing and producing CO2 and oil and gas reserves, including the risks inherent in development drilling, well completion and other development activities;

engineering and mechanical or technological difficulties that we may experience with operational equipment, in well completions and workovers, and in drilling new wells; and

unfavorable results of litigation and the outcome of contingencies referred to in Note 16 to our consolidated financial statements.
 
The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable.  However, there is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition.  Because of these uncertainties, you should not put undue reliance on any forward-looking statements.
 
See Item 1A “Risk Factors” for a more detailed description of these and other factors that may affect the forward-looking statements.  When considering forward-looking statements, one should keep in mind the risk factors described in Item 1A “Risk Factors.”  The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement.  We disclaim any obligation, other than as required by applicable law and described below under Items 1 and 2, “Business and Properties—Recent Developments—2014 Outlook”, to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.


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PART I
Items 1 and 2.  Business and Properties.

Kinder Morgan Energy Partners, L.P. is a leading pipeline transportation and energy storage company in North America. We own an interest in or operate approximately 52,000 miles of pipelines and 180 terminals, and conduct our business through five reportable business segments (described more fully below in “-(c) Narrative Description of Business-Business Segments”).
Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store petroleum products, ethanol and chemicals, and handle such products as coal, petroleum coke and steel. We are also the leading producer and transporter of CO2, for enhanced oil recovery projects in North America. The address of our principal executive offices is 1001 Louisiana Street, Suite 1000, Houston, Texas 77002, and our telephone number at this address is (713) 369-9000.
You should read the following in conjunction with our audited consolidated financial statements and the notes. We have prepared our accompanying consolidated financial statements under GAAP and the rules and regulations of the SEC. Our accounting records are maintained in U.S. dollars, and all references to dollars in this report are to U.S. dollars, except where stated otherwise. Canadian dollars are designated as C$. Our consolidated financial statements include our accounts and those of our operating limited partnerships and their majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation.
(a) General Development of Business
 
Organizational Structure
 
We are a Delaware limited partnership formed in August 1992, and our common units, which represent limited partner interests in us, trade on the NYSE under the symbol “KMP.” In general, our limited partner units, consisting of common units, Class B units (which are similar to our common units except that they are not eligible for trading on the NYSE) and i-units, will vote together as a single class, with each common unit, Class B unit, and i-unit having one vote. Our partnership agreement requires us to distribute all of our available cash, as defined in our partnership agreement, to our partners on a quarterly basis within 45 days after the end of each calendar quarter. We pay our quarterly distributions to our common unitholders, our sole Class B unitholder and our general partner in cash, and we pay our quarterly distributions to our sole i-unitholder in additional i-units rather than in cash. For further information about our distributions, see Note 11 “Related Party Transactions-Partnership Interests and Distributions” to our consolidated financial statements.
KMI and Kinder Morgan G.P., Inc.

KMI, a Delaware corporation, indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation; however, in July 2007, our general partner issued and sold to a third party 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057. The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us or two of our subsidiaries, SFPP and Calnev. KMI’s common stock trades on the NYSE under the symbol “KMI.”
As of December 31, 2013, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary KMR (discussed following), an approximate 11.6% interest in us. In addition to the distributions it receives from its limited and general partner interests, KMI also receives an incentive distribution from us as a result of its ownership of our general partner. Including both its general and limited partner interests in us, at the 2013 distribution level, KMI received approximately 49% of all quarterly distributions of available cash from us, with approximately 43% and 6% of all quarterly distributions from us attributable to KMI’s general partner and limited partner interests, respectively.
KMR

KMR is a Delaware LLC formed in February 2001. Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner. KMR’s shares represent LLC interests and trade on the NYSE under the symbol “KMR.”


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Under the delegation of control agreement, KMR, as the delegate of our general partner, manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their majority-owned and controlled subsidiaries. Furthermore, in accordance with its LLC agreement, KMR’s activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their majority-owned and controlled subsidiaries. As of December 31, 2013, KMR, through its sole ownership of our i-units, owned approximately 28.3% of our outstanding limited partner units.
Recent Developments

The following is a brief listing of significant developments since December 31, 2012.  We begin with developments pertaining to our reportable business segments.  Additional information regarding most of these items may be found elsewhere in this report.

Natural Gas Pipelines
 
On March 1, 2013, we acquired from KMI both the remaining 50% ownership interest we did not already own in EPNG and the remaining 50% ownership interest we did not already own in the EP midstream assets for an aggregate consideration of approximately $1.7 billion, consisting of cash paid, common units issued and debt assumed. In this report, we refer to this acquisition of assets from KMI as the March 2013 drop-down transaction; the combined group of assets acquired from KMI effective March 1, 2013 as the March 2013 drop-down asset group; and the EP midstream assets or Kinder Morgan Altamont LLC (formerly, El Paso Midstream Investment Company, L.L.C.) as the midstream assets. We acquired our initial 50% ownership interest in the midstream assets effective June 1, 2012 from an investment vehicle affiliated with KKR for consideration of $289 million in common units.
On August 1, 2012, we acquired both the full ownership interest in TGP and an initial 50% ownership interest in EPNG from KMI for an aggregate consideration of approximately $6.2 billion, consisting of cash paid, common units issued and debt assumed. In this report, we refer to the August 1, 2012 acquisition of assets from KMI as the August 2012 drop-down transaction; the combined group of assets acquired from KMI effective August 1, 2012 as the August 2012 drop-down asset group; the combined August 2012 drop-down transaction and the March 2013 drop-down transaction (described above) as the drop-down transactions; and the combined August 2012 drop-down asset group and the March 2013 drop-down asset group (described above) as the drop-down asset groups.
KMI acquired the drop-down asset groups as part of its acquisition of EP on May 25, 2012. Prior to the March 2013 drop-down transaction, we accounted for our initial 50% ownership interests in both EPNG and the midstream assets under the equity method of accounting. Accounting principles require us to account for the drop-down transactions as combinations of entities under common control and accordingly, we prepared our consolidated financial statements and the related financial information contained in this report to reflect the transfers of the drop-down asset groups from KMI to us as of May 25, 2012 for both TGP and EPNG, and June 1, 2012 for the midstream assets. For further information about the drop-down transactions, see Note 3 to our consolidated financial statements;

On May 1, 2013, we closed our previously announced acquisition of Copano. We acquired all of Copano’s outstanding units for a total purchase price of approximately $5.2 billion (including assumed debt and all other assumed liabilities). The transaction was a 100% unit for unit transaction with an exchange ratio of 0.4563 of our common units for each Copano common unit. We issued 43,371,210 of our common units valued at approximately $3.7 billion as consideration for the Copano acquisition (based on the $86.08 closing market price of a common unit on the NYSE on the May 1, 2013 issuance date). In association with our Copano acquisition, our general partner waived $75 million of its incremental incentive distributions for 2013, and intends to forgo incentive distributions of $120 million for 2014, $120 million for 2015, $110 million for 2016 and annual amounts thereafter decreasing by $5 million per year from this level.
Our acquisition of Copano added midstream natural gas assets located primarily in Texas, Oklahoma and Wyoming to our existing business portfolio, and enlarged our existing service offerings to natural gas producers, including gathering, processing, treating and fractionation. Additionally, as a result of this acquisition, we are currently pursing incremental development projects in the Eagle Ford shale formation in South Texas, and have gained entry into the Barnett shale formation in North Texas and the Mississippi Lime and Woodford shale formations in Oklahoma. For more information about this acquisition, see Note 3 to our consolidated financial statements;

In April 2013, we completed construction and began transportation service on a newly expanded segment of our DeWitt/Karnes (DK) natural gas pipeline system. Our DK pipeline system runs through DeWitt County and Karnes County, Texas, and in 2012, Copano initiated an approximately $120 million expansion project to extend the 24-inch diameter


6


pipeline approximately 65 miles southwest into McMullen County, Texas. The expansion was based on a fee-based agreement with a single customer whereby we provide midstream gathering and handling services in exchange for committed production volumes;

In April 2013, we commissioned the first of two 400 MMcf/d cryogenic unit expansions at our Houston Central processing plant located in Colorado County, Texas. We expect to complete the second expansion in mid-2014, and when completed, total processing capacity at our Houston Central plant will be approximately 1.5 Bcf/d. Our current estimate of total project construction costs including expansion of the pipeline capacity upstream of the plant is approximately $250 million;

TGP continues to move forward on its approximately $83 million Rose Lake expansion project in northeastern Pennsylvania. The project will provide long-term firm transportation service for two shippers that have fully subscribed 230 MDth/d of firm capacity. Subject to regulatory approvals, a November 1, 2014, in-service date is anticipated;

On July 2, 2013, our wholly-owned subsidiary Sierrita Gas Pipeline LLC entered into a Subscription Agreement with us, MGI Enterprises U.S. LLC (an affiliate of PEMEX), and MIT Pipeline Investment Americas, Inc. (an affiliate of Mitsui), whereby MGI and MIT acquired equity interests of 35% and 30%, respectively, in Sierrita in exchange for capital contributions. Each member of Sierrita, including us, contributed approximately $5 million, determined based on the anticipated cash requirement of Sierrita through the end of September 2013. Following the execution of a First Amended and Restated LLC Agreement, we now operate and own a 35% equity interest in Sierrita Gas Pipeline LLC, and we account for our investment under the equity method of accounting. The company will invest approximately $72 million in the proposed Sierrita Pipeline Project, which includes construction of a 60-mile pipeline that will extend from the EPNG pipeline system, near Tucson, Arizona, to the Mexican border at Sasabe, Arizona. The 36-inch Sierrita Pipeline will have approximately 200 MMcf/d of capacity and an affiliate of PEMEX previously executed a 25-year agreement for all of the capacity. Subject to regulatory approvals, the pipeline is expected to be in service in September 2014;
On September 1, 2013, TGP sold certain natural gas facilities located offshore in the Gulf of Mexico and onshore in the state of Louisiana to Kinetica Partners LLC for an aggregate consideration of $32 million in cash. TGP’s investment in the net assets sold in this transaction totaled $89 million, and as a result of the sale, TGP recognized both a $93 million increase in regulatory assets and a $36 million gain from the sale of assets in 2013;

Field survey work continues for TGP’s fully subscribed approximately $77 million Connecticut expansion project. The project will provide 72 MDth/d of additional long-term natural gas capacity to two local distribution customers. The project includes constructing approximately 13-miles of new pipeline loops along the TGP system in Connecticut, New York and Massachusetts, and acquiring an existing pipeline lateral from another operator. Pending regulatory approvals, we expect this expansion project will be operational on November 1, 2016;

The proposed Cameron LNG liquefaction facility at Hackberry, Louisiana, in which we do not own an interest, received Department of Energy conditional approval for non-Free Trade Agreement export on February 11, 2014, and TGP continues to advance plans to transport 900 MDth/d of natural gas to the future facility under long-term agreements. Following a binding open season in the summer of 2013, TGP awarded 300 MDth/d of capacity to a subsidiary of MMGS Inc. (Mitsui) for a 20-year agreement to transport natural gas earmarked for the liquefaction facility, which is slated to begin LNG exports in the second half of 2017. Earlier in 2013, TGP announced a binding, 20-year agreement with anchor shipper Mitsubishi Corporation to ship 600 MDth/d of natural gas for the proposed project. Future shipments by TGP are part of its approximately $138 million Southwest Louisiana Supply Project;

On November 1, 2013, TGP completed and placed into service its previously announced $504 million Northeast Upgrade project. The project expanded TGP’s pipeline facilities in Pennsylvania and New Jersey and provides for additional takeaway capacity from the Marcellus shale gas formation. The fully-subscribed project increased system capacity on TGP’s 300 Line system by approximately 636 MDth/d through five segment loops and system upgrades at four existing compressor stations and one meter upgrade in New Jersey;

On November 1, 2013, TGP completed and placed into service its previously announced $54 million Marcellus Pooling project. The fully subscribed project provides approximately 240 MDth/d of additional firm transportation capacity from the Marcellus shale gas formation. The expansion included approximately eight miles of 30-inch diameter pipeline looping, system modifications and upgrades to allow bi-directional flow at four existing compressor stations in Pennsylvania;



7


TGP completed a successful binding open season in December for incremental, north-to-south natural gas transportation capacity on the TGP system totaling 500 MDth/d, which was awarded to five different shippers. The awarded capacity will provide firm transportation service for Marcellus and Utica production from receipt points as far north as Mercer, Pennsylvania, for delivery to multiple delivery points on the Gulf Coast. TGP will invest approximately $156 million in this Utica Backhaul project. Capacity bids exceeded the capacity offered, and TGP is exploring further capacity expansions for its customers;

TGP signed a binding, 15-year firm transportation agreement with Seneca Resources Corporation to ship 158 MDth/d of natural gas to eastern Canadian markets on the Niagara Expansion Project. Subject to regulatory approvals, the approximately $26 million project is expected to begin service November 1, 2015. Seneca will be the foundation shipper for TGP’s Niagara Expansion Project, designed to provide transportation from the Marcellus Shale in Pennsylvania to TGP’s interconnect with TransCanada Pipeline in Niagara County, New York, to serve growing markets for U.S. gas in eastern Canada; and

We are investing approximately $126 million for additional compression and pipeline system modifications to expand the Kinder Morgan Texas and Mier-Monterrey pipelines.  The project is supported by three customers in Mexico that entered into long-term firm transportation contracts for more than 200 MMcf/d of capacity, which will be phased in from 2014 through 2016.  A fourth customer has also contracted for 150 MMcf/d of the project’s capacity on an interim basis for use prior to the effective date of the contracts with the other customers, accelerating the timing of the expansion for a projected initial in-service date of September 1, 2014.
CO2 
 
On June 1, 2013, we acquired certain oil and gas properties, rights, and related assets in the Permian Basin of West Texas from Legado Resources LLC for approximately $285 million (before working capital adjustments and excluding assumed liabilities). The acquisition of the Goldsmith Landreth San Andres oil field unit includes more than 6,000 acres located in Ector County, Texas. The acquired oil field is in the early stages of CO2 flood development and includes a residual oil zone along with a classic San Andres waterflood. The field currently produces approximately 1,230 Bbl/d of oil, and as part of the transaction, we obtained a long-term supply contract (now held by one of our wholly-owned subsidiaries) for up to 150 MMcf/d of CO2;

Construction continues on our approximately $214 million Yellow Jacket Central Facility expansion at the McElmo Dome CO2 source field in southwest Colorado. The first of four planned expansion projects is expected to be operational by November 2014. These expansions will increase CO2 production from 1.1 Bcf/d to 1.23 Bcf/d;

In September 2013, we completed the parallel (primary) compression portion of our previously announced $255 million investment to expand the CO2 capacity of our approximately 87%-owned Doe Canyon Deep unit in southwestern Colorado. Doe Canyon is now producing about 200 MMcf/d of CO2, substantially higher than the initial projection of 170 MMcf/d. Construction was completed and the booster compression was available for service in mid-December 2013. Additional well drilling and completions in the field have allowed continued production without operation of the booster compression. Booster compression operation is expected to begin in late 2015. Final work continues on pipeline insulation, painting, and final cleanup and is expected to be complete in early April. We plan to drill approximately 18 more wells during the next ten years, with four expected to be drilled in 2014; and

Work continues on the expansion of our Wink Pipeline System, which transports crude oil from the company’s West Texas oil fields to Western Refining Company’s facility in El Paso, Texas. The company is in the process of increasing Wink’s capacity from 132 MBbl/d to 145 MBbl/d to meet expected higher future throughput requirements at Western’s refinery. We anticipate that the new facilities will be online in the first quarter of 2014.
Products Pipelines
 
On September 3, 2013, we and Valero Energy Corporation completed construction and placed into service our previously announced Parkway Pipeline, a new 141-mile, 16-inch diameter pipeline that transports refined petroleum products from refineries located in Norco, Louisiana, to Plantation Pipe Line Company’s (our approximately 51%-owned equity investee) petroleum transportation hub located in Collins, Mississippi. We operate and own a 50% equity interest in the Parkway Pipeline LLC, which has an initial capacity of 110 MBbl/d, with the ability to expand to over 200 MBbl/d. The approximately $260 million pipeline system is supported by a long-term throughput agreement with a credit-worthy shipper;



8


Construction continues on our approximately $360 million petroleum condensate processing facility near our Galena Park terminal on the Houston Ship Channel. Supported by a long-term, fee-based agreement with BP North America for substantially all 100 MBbl/d of throughput capacity at the facility, the project includes building two separate units to split condensate into its various components and the construction of storage tanks for the almost 2 MMBbl of product that will be split at the facility. The first phase of the splitter is scheduled to be commissioned in June 2014 and the second phase is expected to come online in the second quarter of 2015;

We continue to make progress on pipeline modifications for our approximately $310 million Cochin Reversal project to move light condensate from Kankakee County, Illinois, to existing terminal facilities near Fort Saskatchewan, Alberta. Construction also is underway on the 1 MMBbl storage capacity Kankakee tank farm and associated pipeline facilities where Cochin will interconnect with the Explorer Pipeline and the Enterprise TEPPCO Pipeline. The project remains on schedule for a late June 2014 in-service date;

Tank and pipeline construction continues on our approximately $109 million expansion of our KMCC pipeline to ConocoPhillips’ central delivery facility in Karnes County, Texas. The project, supported by a long-term contract with ConocoPhillips, will extend the 178-mile pipeline 31 miles west from the company’s DeWitt Station (west of Cuero, Texas) to ConocoPhillips’ central delivery facility in Helena, Texas. We expect to complete the project in the third quarter of 2014;

In January 2014, we completed and placed into service our approximately $101 million, 27‑mile Sweeny Lateral pipeline, which transports Eagle Ford crude and condensate from our KMCC pipeline to Phillips 66’s Sweeny Refinery in Brazoria County, Texas. The two 120,000-barrel storage tanks and seven truck offloading racks at our DeWitt County station are also complete and in service, and the new pumps and two 120,000-barrel storage tanks at our Wharton County pump station will be completed February 2014;

We have entered into an agreement with a large Eagle Ford Shale producer to extend the KMCC pipeline farther into the Eagle Ford Shale in South Texas. We will invest approximately $74 million to build an 18-mile lateral pipeline northwest from our DeWitt Station to a new facility in Gonzales County, where we will construct 300 MBbl of storage, a pipeline pump station and truck offloading facilities. The lateral will have a capacity of 300 MBbl/d and will enable us to batch Eagle Ford Gathering LLC crude oil and condensate from the new Gonzales Station via KMCC to its delivery points on the Houston Ship Channel and the soon to be in service Sweeny Lateral pipeline serving the Phillips 66 Sweeny Refinery in Brazoria County, Texas. Construction on the pipeline will start later this month and the project is expected to be completed in the first quarter of 2015;

We and NOVA Chemicals Corporation announced in December 2013 a letter of intent to develop a new products pipeline from the Utica Shale. Under the agreement, KMP’s Cochin pipeline will construct, own and operate a 210-mile pipeline from multiple fractionation facilities in Harrison County, Ohio, to KMP’s Cochin pipeline near Riga, Michigan, where the company will then move product via Cochin east to Windsor, Ontario, Canada. The proposed approximately $300 million KMP Utica To Ontario Pipeline Access (UTOPIA) would transport previously refined or fractionated NGL, including ethane and propane. UTOPIA is expected to have an initial 50 MBbl/d of capacity, which is expandable to more than 75 MBbl/d, and anticipates a mid-year 2017 in-service date, pending NOVA’s execution of a definitive agreement during the binding open season (which is expected in 2014) and timely receipt of necessary permitting and regulatory approvals; and

We and Targa Resources Partners signed a letter of intent in December 2013 to form a joint venture to construct new NGL fractionation facilities at Mont Belvieu, Texas, to provide services for producers in the Utica and Marcellus Shale resource plays in Ohio, West Virginia and Pennsylvania. The obligations under the letter of intent are conditioned upon a successful open season and the construction of the Utica Marcellus Texas Pipeline (UMTP). UMTP is a proposed joint venture between MarkWest Utica EMG and us (also announced in the fourth quarter of 2013), of up to 150 MBbl/d expandable to 400 MBbl/d of maximum pipeline capacity over time. The new NGL fractionation facilities would be located adjacent to Targa’s existing fractionation facilities at Mont Belvieu and would provide fractionation services for customers of UMTP. To allow shippers time to assess their Gulf Coast fractionation and pipeline needs, the binding open season currently under way for the proposed Y-grade UMTP has been extended until February 28, 2014. UMTP would involve the abandonment and conversion of over 1,000 miles of our existing TGP system, currently in natural gas service, and building approximately 200 miles of new pipeline.

We entered into a long term agreement in January 2014 with BP North America for pipeline transportation of Eagle Ford condensate to the Houston Ship Channel.  The $28 million project includes construction of tankage and truck rack receipt facilities at the KMCC Helena Station in Karnes County, Texas and is scheduled to be operational in the first


9


quarter of 2015.  This new origin facility will provide additional supply for the 100 MBbl/d condensate processing facility subscribed to by BP and currently under construction by KMCC in Galena Park, Texas.

In December 2013, we and our Double Eagle joint venture signed a long term agreement with Anadarko for firm transportation service of Eagle Ford condensate to the Houston Ship Channel.  Improvements include construction of tanks and a pump station near Gardendale in LaSalle County, Texas and a new ten mile pipeline joining the Double Eagle and KMCC pipeline systems at Helena Station in Karnes County, Texas.  Our share of the total project cost is approximately $45 million and the facilities are expected to be operation in early 2015.  

Terminals

In August 2013, we completed and commissioned for service our previously announced petroleum coke terminal located at BP’s Whiting refinery in Hammond, Indiana. We expect that the terminal will handle approximately 2.2 million tons of petroleum coke per year for the next three years, and this volume is supported by a 20-year service contract with BP. We invested approximately $62 million for the construction of this facility, which includes nine conveyors, a 30,000-ton storage barn and a fleet of 190 railcars to move approximately 6,000 tons of petroleum coke per day;

As of the date of this report, construction continues on our previously announced three phase export coal expansion project at our International Marine Terminals facility, a multi-product, import-export facility located in Myrtle Grove, Louisiana and owned 66 2/3% by us. In August 2013, we completed the project’s $83 million phase one, which added approximately 800,000 tons of ground storage to the facility. The remaining two phases entail adding a new continuous barge unloader, a new coal reclaim conveyor system and an additional five million tons of coal throughput capacity. We expect the entire project to be operational in the second quarter of 2014 and currently, we estimate our share of the total expansion project at International Marine Terminals (including all phases) will cost approximately $150 million;

Construction continues on our investment of $106 million to meet customer demand in the Houston Ship Channel with a new barge dock adjacent to our Pasadena terminal and nine new storage tanks (with total capacity of 1.2 million barrels) at our Galena Park terminal. The new barge dock is expected to help relieve current dock congestion on the Houston Ship Channel and will enable us to handle up to 50 barges per month. The tanks are expected to be placed in service as they are completed, beginning in the third quarter of 2014 and ending in the first quarter of 2015. The barge dock is slated for a fourth quarter 2015 completion;

The 185-acre Battleground Oil Specialty Terminal Company LLC project located on the Houston Ship Channel is continuing to progress toward completion. Thirty-one of the 51 storage tanks built during phase one construction have been placed in service and the remaining tanks will come online during the first half of 2014. A two-berth ship dock and 12 barge berths were also placed in service in October, 2013. Phase two construction also continues and involves building an additional 0.9 MMBbl of storage capacity. BOSTCO expects phase two to begin service in the third quarter of 2014. The approximately $500 million BOSTCO terminal is fully subscribed for a total capacity of 7.1 MMBbl and is able to handle ultra-low sulfur diesel, residual fuels and other black oil terminal services. We own 55% of and operate BOSTCO;

We are preparing a 42-acre site along the Houston Ship Channel for construction of a new ship dock to handle ocean going vessels and 1.5 MMBbl of liquids storage tanks. The approximately $172 million project is supported by a long-term contract with a major ship channel refiner to construct the tanks and connect our Galena Park terminal to the refiner’s location. Construction is scheduled to begin in the second quarter of 2014 and the project is expected to be in service in the first quarter of 2016;

Construction continues at our Edmonton Terminal expansion in Alberta, Canada. By the end of February 2014, nine tanks with a capacity of 3.4 MMBbl will be in service and phase one will be complete. Construction also continues on phase two, which will add an incremental 1.2 MMBbl storage capacity and is expected to be completed in late 2014. The approximately $419 million project is supported by long-term contracts with major producers and refiners;

In December 2013, we announced a joint venture with Imperial Oil to build the Edmonton Rail Terminal, a crude oil loading facility, near its Edmonton storage terminal on land adjacent to Imperial’s Strathcona Refinery. Construction is underway on the Edmonton Rail Terminal, which will be capable of loading one to three unit trains per day totaling 100 MBbl/d at startup, with the potential to expand up to 250 MBbl/d. The new rail terminal will be connected via pipeline to the Trans Mountain terminal and will be capable of sourcing crude oil handled by us for delivery by rail to North American markets and refineries. The rail will be constructed and operated by us and will connect to both Canadian National and Canadian Pacific mainlines. The joint venture is investing approximately $175 million in the project, and


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we will invest an additional approximately $100 million in pipeline connections and new staging tanks. The facility is expected to be in service at the end of 2014; and

On January 17, 2014, we acquired American Petroleum Tankers (APT) and State Class Tankers (SCT) from affiliates of The Blackstone Group and Cerberus Capital Management for an aggregate consideration of approximately $962 million in cash. APT and SCT are engaged in the marine transportation of crude oil, condensate and refined products in the U.S. domestic trade, commonly referred to as the Jones Act trade. We expect that the transaction will be immediately accretive to cash available to our unitholders.
Kinder Morgan Canada

On March 14, 2013, we closed our previously announced sale of both our one-third equity ownership interest in the Express pipeline system and our subordinated debenture investment in Express to Spectra Energy Corp. For the divestiture of our investments, we received net cash proceeds of $402 million (after settlements of both final working capital balances and transaction related selling costs), and we recorded both a pre-tax gain amount of $224 million and an associated increase in income tax expense of $84 million; and

Trans Mountain Pipeline filed a Facilities Application with Canada's NEB in December 2013 requesting authorization to build and operate the necessary facilities for the proposed $5.4 billion pipeline system expansion. With this filing, the proposed project will undergo a comprehensive public regulatory review. For the past 18 months, Kinder Morgan Canada has engaged, and will continue to engage, extensively with landowners, Aboriginal groups, communities and stakeholders along the proposed expansion route, and marine communities. The next step is for the NEB to establish a hearing schedule that corresponds to the federal government’s legislated 15-month review and decision time frame. Thirteen companies in the Canadian producing, refining and oil export business have signed firm contracts representing a total volume commitment of to approximately 708 MBbl/d. Kinder Morgan Canada received approval of the commercial terms related to the expansion from the NEB in May of 2013. The proposed expansion will increase capacity on Trans Mountain from approximately 300 MBbl/d to 890 MBbl/d. If approvals are received as planned, the expansion is expected to be operational at the end of 2017.
 
Financings

For information about our 2013 debt offerings and retirements, see Note 8 “Debt—2013 Changes in Debt” to our consolidated financial statements. For information about our 2013 equity offerings, see Note 10 “Partners’ Capital—Equity Issuances—2013 Issuances” to our consolidated financial statements.

2014 Outlook

As previously announced, we anticipate that for the year 2014, (i) we will declare total annual cash distributions of $5.58 per unit, a 5% increase over our cash distributions of $5.33 per unit for 2013; (ii) our business segments will generate approximately $6.4 billion in earnings before DD&A, including amortization of excess cost of equity investments and our proportionate share of all DD&A of our unconsolidated joint ventures accounted for under the equity-method of accounting; (iii) we will distribute over $2.5 billion to our limited partners; (iv) we will produce excess cash flow of approximately $15 million above our cash distribution target of $5.58 per unit; and (v) we will invest approximately $3.6 billion for our capital expansion program (including small acquisitions and contributions to joint ventures, but excluding acquisitions from KMI). 
We expect that a full-year of contributions from our 2013 acquisitions and expansions, along with partial-year contributions from our anticipated 2014 expansion investments, as described above under -Recent Developments, will help drive earnings and cash flow growth in 2014 and beyond.  Generally, our base cash flows (that is, cash flows not attributable to acquisitions or expansions) are relatively stable from year to year and are largely supported by multi-year, fee-based customer arrangements.  In addition, our expectations for 2014 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance.  Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable to not put undue reliance on any forward-looking statement.  Please read our Item 1A “Risk Factors” below for more information.  Furthermore, we plan to provide updates to our 2014 expectations when we believe previously disclosed expectations no longer have a reasonable basis.
Our expectations assume an average WTI crude oil price of approximately $96.15 per barrel in 2014.  Although cash generated by our assets is predominantly fee based and is generally not sensitive to commodity prices, our CO2 business


11


segment is exposed to commodity price risk related to the price volatility of crude oil and NGL.  We hedge the majority of our crude oil production, but do have exposure to unhedged volumes, the majority of which are NGL volumes.  For 2014, we expect that every $1 change in the average WTI crude oil price per barrel will impact our CO2 segment’s cash flows by approximately $7 million (or approximately 0.125% of our combined business segments’ anticipated EBDA expenses).
(b) Financial Information about Segments
 
For financial information on our five reportable business segments, see Note 15 “Reportable Segments” to our consolidated financial statements.
(c) Narrative Description of Business

Business Strategy
 
Our business strategy is to:
 
focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of growing markets within North America;
increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;
leverage economies of scale from incremental acquisitions and expansions of assets that fit within our strategy and are accretive to cash flow; and
maximize the benefits of our financial structure to create and return value to our unitholders.
 
It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances.  However, as discussed under Item 1A “Risk Factors” below, there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.
 
We regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and are currently contemplating potential acquisitions.  Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, receipt of fairness opinions, if applicable, and approval of the parties’ respective boards of directors.  While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.

Business Segments
 
We own and manage a diversified portfolio of energy transportation and storage assets. Our operations are conducted through our five operating limited partnerships and their subsidiaries and are grouped into five reportable business segments. These segments are as follows:
Natural Gas Pipelines—which consists of approximately 40,000 miles of natural gas transmission pipelines and gathering lines, plus natural gas storage, treating and processing facilities, through which natural gas is gathered, transported, stored, treated, processed and sold;
CO2—which produces, markets and transports, through approximately 1,500 miles of pipelines, CO2 to oil fields that use CO2 to increase production of oil; owns interests in and/or operate four primary oil fields in West Texas; and owns and operates a 450-mile crude oil pipeline system in West Texas;
Products Pipelines—which consists of approximately 9,000 miles of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets; plus approximately 62 associated product terminals and petroleum pipeline transmix processing facilities serving customers across the U.S.;
Terminals—which consists of approximately 122 owned or operated liquids and bulk terminal facilities and approximately 10 rail transloading and materials handling facilities located throughout the U.S. and portions of Canada, which together transload, store and deliver a wide variety of bulk, petroleum, petrochemical and other liquids products for customers across the U.S. and Canada; and
Kinder Morgan Canada—which transports crude oil and refined petroleum products through approximately 800 miles of pipelines from Alberta, Canada to marketing terminals and refineries in British Columbia and the state of Washington; plus five associated product terminal facilities.


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Natural Gas Pipelines

Our Natural Gas Pipelines segment contains both interstate and intrastate pipelines, which are FERC regulated and non-FERC regulated natural gas assets, respectively.  Our non-FERC regulated natural gas assets are included in the KM Midstream Group. Its primary businesses consist of natural gas sales, transportation, storage, gathering, processing and treating.  Within this segment, we own approximately 40,000 miles of natural gas pipelines and associated storage and supply lines. Our transportation network provides access to the major gas supply areas in the western U.S., Louisiana, Texas, the Midwest and Northeast, as well as major consumer markets.

Natural Gas Pipelines Assets
The table below and discussion that follows provides detail of our pipeline systems as of December 31, 2013:
 
 
As of December 31, 2013
 
Average Transport/Gathering Volumes (a)
Transmission
System
 
Ownership
Interest
 
Miles of
Pipeline
 
Design
Capacity
 
Storage
Capacity
 
Remaining Weighted Average Contract Life
 
Type of Service
 
2013
 
2012
 
2011
 
 
(%)
 
 
 
(Bcf/d)
 
(Bcf)
 
(Years)
 
 
 
(BBtu/d)/(MBbl/d)
Kinder Morgan Texas Pipeline and Kinder Morgan Tejas Pipeline
 
100

 
5,763

 
6.00

 
118

 
5yr, 5 mo
 
Transportation
 
1,743

 
2,021

 
1,780

Mier-Monterrey Pipeline
 
100

 
95

 
0.43

 

 
4yr, 2mo
 
Transportation
 
379

 
366

 
180

Kinder Morgan North Texas Pipeline
 
100

 
82

 
0.33

 

 
19 yr, 7 mo
 
Transportation
 
262

 
300

 
271

KinderHawk Field Services LLC
 
100

 
479

 
2.00

 

 
Life of Lease
 
Gathering
 
668

 
957

 
965

BHP Billiton Petroleum (Eagle Ford Gathering) LLC
 
25

 
654

 
0.70

 

 
Life of Lease
 
Gathering
 
131

 
103

 
36

Red Cedar Gathering Company
 
49

 
755

 
0.75

 

 
4 yr, 4 mo
 
Gathering
 
270

 
294

 
286

Kinder Morgan Altamont LLC
 
100

 
650

 
0.08

 

 
7 yr, 4 mo
 
Gathering
 
67

 
56

 
44

Camino Real Gathering, L.L.C. - Gas
 
100

 
70

 
0.15

 

 
9 yr, 0 mo
 
Gathering
 
103

 
53

 
14

Camino Real Gathering, L.L.C. - Oil
 
100

 
68

 
110 (MBbl)

 

 
9 yr, 0 mo
 
n/a
 
28

 
14

 

Copano operations (including Eagle Ford Gathering LLC) - Gas
 
100

 
6,805

 
3.58

 

 
6yr, 5mo
 
Gathering
 
1,694

 
1,494

 
1,067

 
Transportation
 
26

 
25

 
33

Copano operations - Liquids
 
100

 
459

 
115 (MBbl/d)

 

 
8yr, 7mo
 
n/a
 
67

 
42

 
26

TGP
 
100

 
11,840

 
8.50

 
94

 
6yr, 7mo
 
Transportation
 
7,082

 
7,175

 
6,267

EPNG
 
100

 
10,141

 
5.65

 
44

 
5yr, 1mo
 
Transportation
 
3,326

 
3,167

 
3,109

Mojave Pipeline Company, LLC
 
100

 
562

 
2.0 / 0.4

 

 
2 yr, 0mo
 
Transportation
 
6

 
22

 
22

TransColorado Gas Transmission Company LLC
 
100

 
312

 
1.00

 

 
2yr, 5mo
 
Transportation
 
303

 
398

 
420

Kinder Morgan Louisiana Pipeline    
 
100

 
136

 
3.20

 

 
15yr, 8mo
 
Transportation
 
9

 
9

 
21

Midcontinent Express Pipeline LLC
 
50

 
512

 
1.80

 

 
5yr, 3mo
 
Transportation
 
1,315

 
1,405

 
1,361

Fayetteville Express Pipeline LLC
 
50

 
185

 
2.00

 

 
7yr, 2mo
 
Transportation
 
1,270

 
1,165

 
1,015

——————
(a)
Volumes for acquired pipelines are included for all periods and joint venture pipeline throughput is reported at 100%.



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KM Midstream Group

Texas Intrastate Natural Gas Pipeline Group

Our Texas intrastate natural gas pipeline group, which operates primarily along the Texas Gulf Coast, consists of the following four natural gas pipeline systems: (i) our Kinder Morgan Texas Pipeline; (ii) our Kinder Morgan Tejas Pipeline; (iii) our Mier-Monterrey Mexico Pipeline; and (iv) our Kinder Morgan North Texas Pipeline.

The two largest systems in the group are our Kinder Morgan Texas Pipeline and our Kinder Morgan Tejas Pipeline.  The combined system (i) has facilities to both treat approximately 180 MMcf/d of natural gas for CO2 and hydrogen sulfide removal, and to process approximately 85 MMcf/d of natural gas for liquids extraction and (ii) holds contractual rights to process natural gas at certain third party facilities.

Our Mier-Monterrey Pipeline consists of a natural gas pipeline that stretches from the international border between the U.S. and Mexico in Starr County, Texas, to Monterrey, Mexico and its capacity is being expanded to 640 MMcf/d. The pipeline connects to the Pemex natural gas transportation system and serves a 1,000-megawatt power plant complex.  We have entered into long-term contracts which have subscribed for substantially all of the pipeline’s capacity.

Our Kinder Morgan North Texas Pipeline consists of a pipeline that transports natural gas from an interconnect with the facilities of NGPL (a 20%-owned equity investee of KMI) in Lamar County, Texas to a 1,750-megawatt electricity generating facility located in Forney, Texas, 15 miles east of Dallas, Texas and to a 1,000-megawatt electricity generating facility located near Paris, Texas.  It is fully subscribed under a long-term contract that expires in 2032.  The system is bi-directional, permitting deliveries of additional supply from the Barnett Shale area to NGPL’s pipeline as well as power plants in the area.

Texas is one of the largest natural gas consuming states in the country.  The natural gas demand profile in our Texas intrastate natural gas pipeline group’s market area is primarily composed of industrial (including on-site cogeneration facilities), merchant and utility power, and local natural gas distribution consumption.  The industrial demand is primarily year-round load.  Merchant and utility power demand peaks in the summer months and is complemented by local natural gas distribution demand that peaks in the winter months.

Collectively, our Texas intrastate natural gas pipeline system primarily serves the Texas Gulf Coast by selling, transporting, processing and treating natural gas from multiple supply sources to serve the Houston/Beaumont/Port Arthur/Austin industrial markets, local natural gas distribution utilities, electric utilities and merchant power generation markets.  It serves as a buyer and seller of natural gas, as well as a transporter of natural gas.

The purchases and sales of natural gas are primarily priced with reference to market prices in the consuming region of the system.  The difference between the purchase and sale prices is the rough equivalent of a transportation fee and fuel costs.  Generally, we purchase natural gas directly from producers with reserves connected to our intrastate natural gas system in South Texas, East Texas, West Texas, and along the Texas Gulf Coast.  In addition, we also purchase gas at interconnects with third-party interstate and intrastate pipelines.  While our intrastate group does not produce gas, it does maintain an active well connection program in order to offset natural declines in production along its system and to secure supplies for additional demand in its market area.  Our intrastate system is interconnected with both LNG import terminals located on the Texas Gulf Coast.  Our intrastate group also has access to markets within and outside of Texas through interconnections with numerous interstate natural gas pipelines.

Kinder Morgan Treating L.P.

Our subsidiary, Kinder Morgan Treating, L.P., owns and operates (or leases to producers for operation) treating plants that remove impurities (such as CO2 and hydrogen sulfide) and hydrocarbon liquids from natural gas before it is delivered into gathering systems and transmission pipelines to ensure that it meets pipeline quality specifications.  Additionally, its subsidiary KM Treating Production LLC, designs, constructs, and sells custom and stock natural gas treating plants and condensate stabilizers. Our rental fleet of treating assets includes approximately 211 natural gas amine-treating plants, approximately 20 hydrocarbon dew point control plants, and approximately 186 mechanical refrigeration units that are used to remove impurities and hydrocarbon liquids from natural gas streams prior to entering transmission pipelines.

KinderHawk Field Services LLC

Our subsidiary, KinderHawk Field Services LLC, gathers and treats natural gas in the Haynesville and Bossier shale gas formations located in northwest Louisiana.  Its natural gas amine treating plants have a current capacity of approximately 2,600


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gallons per minute (GPM). KinderHawk owns life of lease dedications to gather and treat substantially all of BHP Billiton (BHP) operated Haynesville and Bossier shale gas production at agreed upon rates, as well as minimum volume commitments for a five-year term that expires in May 2015.  KinderHawk also holds additional third-party gas gathering and treating commitments.

BHP Billiton Petroleum (Eagle Ford Gathering) LLC

Formerly known as EagleHawk Field Services LLC and currently referred to as EagleHawk in this document, it provides natural gas and condensate gathering, treating, condensate stabilization and transportation services in the Eagle Ford shale formation in South Texas. EagleHawk, which is operated by BHP, owns two midstream gathering systems in and around BHP’s Hawkville and Black Hawk areas of the Eagle Ford shale formation.  In addition, EagleHawk has a life of lease dedication of certain of BHP’s Eagle Ford shale reserves, and to a limited extent, contracts with other producers in the Eagle Ford shale formation to provide natural gas and condensate gathering, treating, condensate stabilization and transportation services.

Red Cedar Gathering Company

Red Cedar owns and operates natural gas gathering, compression and treating facilities in the Ignacio Blanco Field in La Plata County, Colorado.  A 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe.  Red Cedar’s natural gas gathering system connects more than 900 producing wells, 133,400 horsepower of compression at 20 field compressor stations and three CO2 treating plants.

Kinder Morgan Altamont LLC and Camino Real Gathering, L.L.C.

Effective March 1, 2013, as part of the March 2013 drop-down transaction, we acquired the remaining 50% equity ownership interest in the midstream assets that we did not already own. The midstream assets include our subsidiaries Kinder Morgan Altamont LLC and Camino Real Gathering Company, L.L.C. These entities own and operate the Altamont natural gas gathering, processing and treating assets located in the Uinta Basin in Utah, and the Camino Real natural gas and oil gathering systems located in the Eagle Ford shale formation in South Texas. The Altamont system has over 516 well connections with producers, a natural gas processing plant, and a NGL fractionator with a design capacity of 5.6 MBbl/d.

Endeavor Gathering LLC

Endeavor Gathering LLC provides natural gas gathering service to GMX Resources, Inc., and others in the Cotton Valley Sands and Haynesville/Bossier Shale horizontal well developments located in East Texas.  GMX Resources, Inc. operates and owns the remaining 60% ownership interest in Endeavor Gathering LLC.  Endeavor’s gathering system consists of over 100 miles of gathering lines and 25,000 horsepower of compression. In 2013, average gathering volume was approximately 27.6 BBtu/d of natural gas. The natural gas gathering system has takeaway capacity of approximately 115 MMcf/d.

Copano operations (including Eagle Ford Gathering LLC)

Our Copano operations assets (including equity investments owned by Copano) include natural gas gathering and intrastate transportation pipeline assets, natural gas processing and fractionation facilities and NGL pipelines.  Through our Copano operations’ natural gas pipelines, we gather natural gas from wellheads or designated points near producing wells. We also treat and process natural gas as needed to remove contaminants and extract mixed NGL, and we deliver the resulting residue gas to our own and third-party pipelines, local distribution companies, power generation facilities and industrial customers. We also sell extracted NGL as a mixture or as fractionated purity products, and we deliver them through our pipeline interconnects and truck loading facilities. We process natural gas from both our own gathering systems and from third-party pipelines, and in some cases, we deliver natural gas and mixed NGL to other third parties who provide us with transportation, processing or fractionation services. We commonly divide our Copano operations into four regions: South Texas, North Texas, Oklahoma and Rocky Mountain.

Copano South Texas Region

Our Copano South Texas operations deliver a majority of the natural gas gathered on our wholly-owned gathering systems to our Houston Central complex located in Colorado County, Texas. At our Houston Central complex, we provide treating, processing and NGL fractionation and transportation services, as needed. The plant and related facilities has approximately 1.1 Bcf/d of processing capacity, consisting of 500 MMcf/d lean oil and 600 MMcf/d cryogenic processing facilities. A new 400 MMcf/d cryogenic processing train (or tower) is under construction, and when it is placed into service at the end of the second


15


quarter of 2014, it will largely replace the capacity currently served by the less-efficient “lean oil” method of extracting valuable NGL. Our Houston Central complex also includes a 1,725 GPM amine treating system, a 44 MBbl/d NGL fractionation facility and a truck rack to facilitate the transport of NGL.

Our gathering systems have access to Houston Central through both our DeWitt/Karnes (DK) pipeline system, which extends from DeWitt County and Karnes County, Texas, and our Laredo-to-Katy (LK) pipeline system, which extends along the Texas Gulf Coast from south Texas to Houston. Our Houston Central complex straddles our LK pipeline system, which allows us to move natural gas from our pipeline systems in south Texas and near the Texas Gulf Coast to our Houston Central complex for processing and treating and then on to downstream markets. We also deliver gas from our south Texas gathering systems to other third-party pipelines and processing plants. Depending on our contractual arrangements, third-party service providers collect fees, retain a portion of the NGL, or retain a portion of the proceeds from the sale of the NGL and residue gas in exchange for their services.

We provide midstream natural gas services to Eagle Ford Shale producers through our wholly-owned subsidiary Eagle Ford Gathering, LLC (Eagle Ford).  Eagle Ford provides natural gas gathering, transportation and processing services to natural gas producers in the Eagle Ford shale gas formation in South Texas.  Eagle Ford has approximately 190 miles of pipelines with capacity to gather and has contracted processing capacity at Houston Central and third party plants to process over 585 MMcf/d.

Our South Texas Copano operations include pipelines which gather natural gas from counties to the north of Houston, Texas and take deliveries from several third-party pipelines. We then deliver or sell the natural gas gathered or transported on these systems to utilities and industrial customers. We also provide gas conditioning and processing services to natural gas producers in the Woodbine and Eaglebine shale gas formations, emerging rich resource plays located in East Texas near our gathering systems.

Our South Texas Copano operations also include our (i) our 62.5% equity ownership interest in Webb/Duval Gatherers, the sole owner of the Webb/Duval gas gathering system that provides natural gas gathering services in South Texas and (ii) 50% equity ownership interest in Liberty Pipeline Group, LLC, the sole owner of the Liberty pipeline system which transports mixed NGL from our Houston Central complex to the Texas Gulf Coast. Webb/Duval Gatherers is a general partnership that we operate. Each partner has the right to use its pro rata share of pipeline capacity on this system, subject to applicable ratable take and common purchaser statutes. Energy Transfer Partners, L.P. operates and owns the remaining 50% interest in the Liberty pipeline system.

Copano North Texas Region

Our Copano North Texas region provides midstream natural gas services in north Texas, including gathering of natural gas, and related services including compression, dehydration, amine treating, processing and marketing.

Our Copano North Texas pipelines gather natural gas from the north Barnett shale combo play located in Cook, Denton, Montague and Wise Counties in Texas and deliver the natural gas to both our Saint Jo processing plant located in Montague County, Texas, and to third-party processing plants and pipelines. A large majority of the natural gas on the Copano North Texas system comes from a single producer under a long term contract which includes certain acreage dedications and volume commitments. Our Saint Jo high recovery cryogenic plant has an inlet capacity of 100 MMcf/d, and contains both a 1,500 GPM amine treating facility and condensate stabilization facilities. Our Saint Jo NGL pipeline system transports NGL from the plant to ONEOK Partners’ Hydrocarbon’s Arbuckle NGL pipeline system.

Copano Oklahoma Region

Our Copano Oklahoma region provides midstream natural gas services in central and east Oklahoma, including primarily low-pressure gathering of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. In addition to gathering natural gas to our plants, our Oklahoma segment delivers natural gas to third-party plants. Depending on our contractual arrangements, third parties collect processing fees, retain a portion of the NGL or residue gas, or retain a portion of the proceeds from the sale of the NGL and residue gas in exchange for their services.

The Oklahoma region includes seven natural gas processing plants with a combined capacity of 236 MMcf/d, and over 3,900 miles of gathering pipelines. The region includes the operations of Southern Dome, LLC, which provides gathering and processing services within the Southern Dome prospect in the southern portion of Oklahoma County. We consolidate and currently hold a 69.5% ownership interest in Southern Dome.



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Copano Rocky Mountain Region

Our Copano Rocky Mountain region provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas. The region includes our (i) 51% equity ownership interest in Bighorn Gas Gathering, L.L.C., the sole owner of the Bighorn natural gas gathering system and (ii) 37.04% equity ownership interest in Fort Union Gas Gathering, L.L.C., the sole owner of the Fort Union natural gas gathering system. The Rocky Mountain region also includes firm gathering agreements with Fort Union; firm transportation agreements with Wyoming Interstate Gas Company, a wholly-owned subsidiary of EPB (which capacity has been released to various producers); and services we provide to a number of producers in the Powder River Basin, including producers who deliver natural gas into the Bighorn or Fort Union gathering systems.

Bighorn provides low and high pressure natural gas gathering service to coal-bed methane producers in the Powder River Basin. We serve as managing member and field operator of Bighorn. Fort Union takes delivery of natural gas from Bighorn, provides gathering services to other producers and provides amine treating services at its Medicine Bow treating facility in order to meet the quality specifications of downstream pipelines. Pipeline interconnects downstream from the Fort Union system include Wyoming Interstate Gas Company, Tallgrass Interstate Gas Transportation and Colorado Interstate Gas Company (CIG), a wholly-owned subsidiary of EPB.

Fort Union has firm gathering agreements with each of its four owners, including us. Each owner has the right to use a fixed quantity of firm gathering capacity on the system (referred to as variable capacity) that must be paid for only to the extent the owner’s dedicated production exceeds that owner’s demand capacity. We serve as the managing member of Fort Union. Western Gas Wyoming, L.L.C., a subsidiary of Anadarko Petroleum Corporation, acts as field operator, and a ONEOK Partners subsidiary acts as administrative manager and provides gas control, contract management and contract invoicing services.

TGP

The multiple-line TGP system begins in the natural gas producing regions of Louisiana, the Gulf of Mexico and South Texas and extends to the northeast section of the U.S., including the metropolitan areas of New York City and Boston.

Our TGP system connects with multiple pipelines (including interconnects at the U.S.-Mexico border and the U.S.-Canada border) that provide customers with access to diverse sources of supply and various natural gas markets. The pipeline system is also connected to four major shale formations: (i) the Haynesville shale formation in northern Louisiana and Texas; (ii) the Marcellus shale formation in Pennsylvania; (iii) the Utica shale formation that spans an area from Ohio to Pennsylvania; and (iv) the previously discussed Eagle Ford shale formation, located in South Texas. The TGP system also includes underground working natural gas storage capacity through partially owned facilities or long-term contracts. Of this total storage capacity, 29.6 Bcf is contracted from Bear Creek located in Bienville Parish, Louisiana. Bear Creek is a joint venture equally owned by us and EPB, an affiliate of KMI. The facility has 59.2 Bcf of working natural gas storage capacity that is committed equally to EPB and us.

Our TGP pipeline system provides natural gas services to a variety of customers, including natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. Its existing transportation and storage contracts expire at various times and in varying amounts of throughput capacity, and our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Although we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariff, we frequently enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.

Western Interstate Natural Gas Pipeline Group

Our Western interstate natural gas pipeline systems, which operate along the South Central region and the Rocky Mountain region of the western portion of the U.S., consist of the following two natural gas pipeline systems (i) the combined EPNG and Mojave Pipelines and (ii) the TransColorado Pipeline.



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EPNG

Effective March 1, 2013, as part of the March 2013 drop-down transaction, we acquired the remaining 50% equity ownership interest in EPNG that we did not already own. EPNG, is the sole owner of (i) the EPNG pipeline system and (ii) Mojave Pipeline Company, LLC, the sole owner of the Mojave Pipeline system. Although the Mojave Pipeline system is a wholly owned entity, it shares common pipeline and compression facilities that are 25% owned by Mojave Pipeline Company, LLC and 75% owned by Kern River Gas Transmission Company.

The EPNG system extends from the San Juan, Permian and Anadarko basins to California, its single largest market, as well as markets in Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico. Its design capacity for natural gas reflects winter-sustainable west-flow capacity of 4.85 Bcf/d and approximately 800 MMcf/d of east-end delivery capacity.

The Mojave system connects with other pipeline systems including (i) the EPNG system near Cadiz, California; (ii) the EPNG and Transwestern Pipeline Company, LLC systems at Topock, Arizona; and (iii) the Kern River Gas Transmission Company system in California. The Mojave system also extends to customers in the vicinity of Bakersfield, California. The portion of the total design capacity of the Mojave system attributable the Mojave Pipeline Company, LLC, reflecting total east to west flow activity from Topock to Daggett. The east to west capacity from Topock to the Cadiz interconnect with EPNG is 456 MMcf/d.

In addition to its two pipeline systems, EPNG utilizes its Washington Ranch underground natural gas storage facility located in New Mexico to manage its transportation needs and to offer interruptible storage services.

The EPNG system provides natural gas services to a variety of customers, including natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines, and natural gas marketing and trading companies. California, Arizona, and Mexico customers account for the majority of transportation on the EPNG system, followed by Texas and New Mexico. The Mojave system is largely contracted to EPNG, which utilizes the capacity to provide service to EPNG’s customers. Furthermore, the EPNG system also delivers natural gas to Mexico along the U.S. border serving customers in the Mexican states of Chihuahua, Sonora, and Baja California.

TransColorado Gas Transmission Company LLC

Our subsidiary, TransColorado, owns an interstate natural gas pipeline that extends from approximately 20 miles southwest of Meeker, Colorado to the Blanco Hub near Bloomfield, New Mexico.  It has multiple points of interconnection with various interstate and intrastate pipelines, gathering systems, and local distribution companies.  Our TransColorado pipeline system is powered by eight compressor stations having an aggregate of approximately 39,000 horsepower.  The system is bi-directional to the north and south.

Our TransColorado pipeline system receives natural gas from a coal seam natural gas treating plant, located in the San Juan Basin of Colorado, and from pipeline, processing plant and gathering system interconnections within the Paradox and Piceance Basins of western Colorado.  It provides transportation services to third-party natural gas producers, marketers, gathering companies, local distribution companies and other shippers.  Pursuant to transportation agreements and FERC tariff provisions, TransColorado offers its customers firm and interruptible transportation and interruptible park and loan services. TransColorado also has the authority to negotiate rates with customers if it has first offered service to those customers under its reservation and commodity charge rate structure.

Central Interstate Natural Gas Pipeline Group

Our Central interstate natural gas pipeline group, which operates primarily in the Mid-Continent region of the U.S., consists of the following three natural gas pipeline systems (i) Kinder Morgan Louisiana Pipeline; (ii) our 50% ownership interest in Midcontinent Express Pipeline LLC; and (iii) our 50% ownership interest in Fayetteville Express Pipeline LLC.

Kinder Morgan Louisiana Pipeline

Our subsidiary, Kinder Morgan Louisiana Pipeline LLC owns the Kinder Morgan Louisiana natural gas pipeline system.  The pipeline system provides take-away natural gas capacity from the Cheniere Sabine Pass LNG terminal located in Cameron Parish, Louisiana, and transports natural gas to various delivery points located in Cameron, Calcasieu, Jefferson Davis, Acadia and Evangeline parishes in Louisiana.  The system capacity is fully supported by 20-year take-or-pay customer commitments with Chevron and Total that expire in 2029.  The Kinder Morgan Louisiana pipeline system consists of two segments.  The first segment extends from the Sabine Pass terminal to a point of interconnection with an existing Columbia


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Gulf Transmission line in Evangeline Parish, Louisiana (an offshoot extends to the Florida Gas Transmission Company compressor station located in Acadia Parish, Louisiana).  The second segment extends from the Sabine Pass terminal and connects to NGPL’s natural gas pipeline.

Midcontinent Express Pipeline LLC

We operate Midcontinent Express Pipeline LLC, the sole owner of the Midcontinent Express natural gas pipeline system.  A 50% ownership interest in Midcontinent Express Pipeline LLC is owned by Regency Midcontinent Express LLC, a wholly-owned subsidiary of Regency Energy Partners, L.P.  The Midcontinent Express pipeline system originates near Bennington, Oklahoma and extends eastward through Texas, Louisiana, and Mississippi, and terminates at an interconnection with the Transco Pipeline near Butler, Alabama.  It interconnects with numerous major pipeline systems and provides an important infrastructure link in the pipeline system moving natural gas supply from newly developed areas in Oklahoma and Texas into the U.S.’s eastern markets.

The Midcontinent Express system also has four compressor stations and one booster station totaling approximately 144,500 horsepower.  It has two rate zones: (i) Zone 1 beginning at Bennington and extending to an interconnect with Columbia Gulf Transmission near Delhi, in Madison Parish Louisiana and (ii) Zone 2 beginning at Delhi and terminating at an interconnection with Transco Pipeline near the town of Butler in Choctaw County, Alabama.  Capacity on the Midcontinent Express system is 99% contracted under long-term firm service agreements that expire between August 2014 and 2020.  The majority of volume is contracted to producers moving supply from the Barnett shale and Oklahoma supply basins.

Fayetteville Express Pipeline LLC

Energy Transfer Partners, L.P. owns a 50% ownership interest and also serves as operator and managing member of Fayetteville Express Pipeline LLC. The Fayetteville Express pipeline system originates in Conway County, Arkansas, continues eastward through White County, Arkansas, and terminates at an interconnect with Trunkline Gas Company’s pipeline in Panola County, Mississippi.  The system also interconnects with NGPL’s pipeline in White County, Arkansas, Texas Gas Transmission’s pipeline in Coahoma County, Mississippi, and ANR Pipeline Company’s pipeline in Quitman County, Mississippi.  Capacity is over 90% contracted under long-term firm service agreements.

Competition

The market for supply of natural gas is highly competitive, and new pipelines are currently being built to serve the growing demand for natural gas in each of the markets served by the pipelines in our Natural Gas Pipelines business segment.  These operations compete with interstate and intrastate pipelines, and their shippers, for connections to new markets and supplies and for transportation, processing and treating services.  We believe the principal elements of competition in our various markets are transportation rates, terms of service and flexibility and reliability of service.  From time to time, other pipeline projects are proposed that would compete with our pipelines, and some proposed pipelines may deliver natural gas to markets we serve from new supply sources closer to those markets.  We do not know whether or when any such projects would be built, or the extent of their impact on our operations or profitability.

Shippers on our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including electricity, coal, propane and fuel oils.  Several factors influence the demand for natural gas, including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather.

CO2 

Our CO2 segment consists of our subsidiary KMCO2 and its consolidated affiliates.  Our CO2 business segment produces, transports, and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields.  KMCO2’s CO2 pipelines and related assets allow it to market a complete package of CO2 supply, transportation and technical expertise to its customers.  KMCO2 also holds ownership interests in several oil-producing fields and owns a crude oil pipeline, all located in the Permian Basin region of West Texas.



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Oil and Gas Producing Activities

Oil Producing Interests

KMCO2 holds ownership interests in oil-producing fields located in the Permian Basin of West Texas, including: (i) an approximate 97% working interest in the SACROC unit; (ii) an approximate 50% working interest in the Yates unit; (iii) an approximate 99% working interest in the Goldsmith Landreth San Andres unit; (iv) an approximate 21% net profits interest in the H.T. Boyd unit; (v) an approximate 99% working interest in the Katz Strawn unit; and (vi) lesser interests in the Sharon Ridge unit, the Reinecke unit and the MidCross unit.

The SACROC unit is one of the largest and oldest oil fields in the U.S. using CO2 flooding technology. The field is comprised of approximately 56,000 acres located in the Permian Basin in Scurry County, Texas.  KMCO2 has expanded the development of the CO2 project initiated by the previous owners and increased production and ultimate oil recovery over the last several years.  In 2013, the average purchased CO2 injection rate at SACROC was 126 MMcf/d.  The average oil production rate for 2013 was approximately 30,700 Bbl/d of oil (22,500 net Bbl/d to KMCO2).

The Yates unit is also one of the largest oil fields ever discovered in the U.S.  The field is comprised of approximately 26,000 acres located about 90 miles south of Midland, Texas.  KMCO2’s plan over the last several years has been to maintain overall production levels and increase ultimate recovery from Yates by combining horizontal drilling with CO2 injection to ensure a relatively steady production profile over the next several years.  In 2013, the average purchased CO2 injection rate at the Yates unit was 99 MMcf/d, and during 2013, the Yates unit produced approximately 20.4 MBbl/d of oil (net 9.0 MBbl/d to KMCO2).

Effective June 1, 2013,  KMCO2 acquired from Legado Resources LLC their approximate 99% working interest in the Goldsmith Landreth San Andres oil field unit, which includes more than 6,000 acres located in Ector County, Texas. The acquired oil field is in the early stages of CO2 flood development and includes a residual oil zone along with a classic San Andres waterflood. During our period of ownership for the remainder of 2013, the average purchased CO2 injection rate at the Goldsmith unit was 59 MMcf/d, and during our period of ownership for the remainder of 2013, the Goldsmith unit produced approximately 1,300 Bbl/d of oil (1,100 net Bbl/d to KMCO2).

KMCO2 also operates and owns an approximate 99% working interest in the Katz Strawn unit, located in the Permian Basin area of West Texas.  During 2013, the Katz Strawn unit produced approximately 2,700 Bbl/d of oil (2,200 net Bbl/d to KMCO2).  In 2013, the average purchased CO2 injection rate at the Katz Strawn unit was 72 MMcf/d.

The following table sets forth productive wells, service wells and drilling wells in the oil and gas fields in which we owned interests as of December 31, 2013.  The oil and gas producing fields in which we own interests are located in the Permian Basin area of West Texas.  When used with respect to acres or wells, “gross” refers to the total acres or wells in which we have a working interest, and “net” refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by us:
 
Productive Wells (a)
 
Service Wells (b)
 
Drilling Wells (c)
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Crude Oil
2,164

 
1,356

 
1,092

 
846

 
3

 
3

Natural Gas
5

 
2

 

 

 

 

Total Wells
2,169

 
1,358

 
1,092

 
846

 
3

 
3

____________
(a)
Includes active wells and wells temporarily shut-in.  As of December 31, 2013, we did not operate any productive wells with multiple completions.
(b)
Consists of injection, water supply, disposal wells and service wells temporarily shut-in.  A disposal well is used for disposal of salt water into an underground formation; and an injection well is a well drilled in a known oil field in order to inject liquids and/or gases that enhance recovery.
(c)
Consists of development wells in the process of being drilled as of December 31, 2013. A development well is a well drilled in an already discovered oil field.



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The following table reflects our net productive and dry wells that were completed in each of the years ended December 31, 2013, 2012 and 2011:
 
Year Ended December 31,
 
2013
 
2012
 
2011
Productive
 
 
 
 
 
Development
51

 
59

 
85

Exploratory
4

 

 

Total Wells
55

 
59

 
85

____________
Note: The above table includes wells that were completed during each year regardless of the year in which drilling was initiated, and does not include any wells where drilling operations were not completed as of the end of the applicable year.  A development well is a well drilled in an already discovered oil field. There were no dry wells completed during the periods presented.
 
The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2013:
 
Gross
 
Net
Developed Acres
75,111

 
71,919

Undeveloped Acres
17,603

 
15,334

Total
92,714

 
87,253

____________
Note: As of December 31, 2013, we have no material amount of acreage expiring in the next three years.

See “Supplemental Information on Oil and Gas Activities (Unaudited)” for additional information with respect to operating statistics and supplemental information on our oil and gas producing activities.

Gas and Gasoline Plant Interests

KMCO2 operates and owns an approximate 22% working interest plus an additional 28% net profits interest in the Snyder gasoline plant.  It also operates and owns a 51% ownership interest in the Diamond M gas plant and a 100% ownership interest in the North Snyder plant, all of which are located in the Permian Basin of West Texas.  The Snyder gasoline plant processes natural gas produced from the SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units, all of which are located in the Permian Basin area of West Texas.  The Diamond M and the North Snyder plants contract with the Snyder plant to process natural gas.  Production of NGL at the Snyder gasoline plant during 2013 averaged approximately 19.5 gross MBbl/d (9.6 net MBbl/d to KMCO2 excluding the value associated to KMCO2’s 28% net profits interest).

Sales and Transportation Activities

CO2 

KMCO2 owns approximately 45% of, and operates, the McElmo Dome unit in Colorado, which contains more than 5.9 trillion cubic feet of recoverable CO2 as of January 1, 2014.  It also owns approximately 87% of, and operates, the Doe Canyon Deep unit in Colorado, which contains approximately 832 Bcf of recoverable CO2 as of January 1, 2014.  For both units combined, compression capacity exceeds 1.6 Bcf/d of CO2 and during 2013, the two units produced approximately 1.2 Bcf/d of CO2.

KMCO2 also owns (i) approximately 11% of the Bravo Dome unit in New Mexico and (ii) 100% of the St. Johns CO2 source field and related assets located in Apache County, Arizona, and Catron County, New Mexico. The Bravo Dome unit contains approximately 702 Bcf of recoverable CO2 as of January 1, 2014, and produced approximately 270 million cubic feet of CO2 per day in 2013. As of the date of this report, we are continuing to perform pre-development activity and test wells; however, we believe the St. Johns CO2 source field consists of all of the CO2 and helium located in both the St. Johns gas unit, a 158,000 acre unit located in Apache County, Arizona containing approximately 1.3 trillion cubic feet of recoverable CO2 as of January 1, 2014, and the Cottonwood Canyon CO2 unit, an approximate 90,000 acre unit located in Catron County, New Mexico containing approximately 360 Bcf of recoverable CO2 as of January 1, 2014. Our principal market for CO2 is for injection into mature oil fields in the Permian Basin, where industry demand is expected to remain strong for the next several years.



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CO2 Pipelines

As a result of our 50% ownership interest in Cortez Pipeline Company, we own a 50% equity interest in and operate the approximate 500-mile Cortez pipeline.  The pipeline carries CO2 from the McElmo Dome and Doe Canyon source fields near Cortez, Colorado to the Denver City, Texas hub.  In 2013, the Cortez pipeline system transported approximately 1.2 Bcf of CO2 per day.  The tariffs charged by the Cortez pipeline are not regulated, but are based on a consent decree.

KMCO2’s Central Basin pipeline consists of approximately 143 miles of mainline pipe and 177 miles of lateral supply lines located in the Permian Basin between Denver City, Texas and McCamey, Texas.  The pipeline has a throughput capacity of 700 MMcf/d.  At its origination point in Denver City, the Central Basin pipeline interconnects with all three major CO2 supply pipelines from Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO2) and the Bravo and Sheep Mountain pipelines (operated by Oxy Permian).  Central Basin’s mainline terminates near McCamey, where it interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline.  

KMCO2’s Centerline CO2 pipeline consists of approximately 113 miles of pipe located in the Permian Basin between Denver City, Texas and Snyder, Texas.  The pipeline has a capacity of 300 MMcf/d.  

KMCO2’s Eastern Shelf CO2 pipeline, which consists of approximately 91 miles of pipe located in the Permian Basin, begins near Snyder, Texas and ends west of Knox City, Texas.  The Eastern Shelf pipeline has a capacity of 110 MMcf/d.

KMCO2 also owns a 13% undivided interest in the 218-mile, Bravo pipeline, which delivers CO2 from the Bravo Dome source field in northeast New Mexico to the Denver City hub and has a capacity of more than 350 MMcf/d.  Tariffs on the Bravo pipeline are not regulated.  Occidental Petroleum (81%) and XTO Energy (6%) hold the remaining ownership interests in the Bravo pipeline.

In addition, KMCO2 owns approximately 98% of the Canyon Reef Carriers pipeline and approximately 69% of the Pecos pipeline.  The Canyon Reef Carriers pipeline extends 139 miles from McCamey, Texas, to the SACROC unit in the Permian Basin.  The pipeline has a capacity of approximately 270 MMcf/d and makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units.  The Pecos pipeline is a 25-mile pipeline that runs from McCamey to Iraan, Texas. It has a capacity of approximately 120 MMcf/d and makes deliveries to the Yates unit.  The tariffs charged on the Canyon Reef Carriers and Pecos pipelines are not regulated.

The principal market for transportation on our CO2 pipelines is to customers, including ourselves, using CO2 for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain strong for the next several years. The tariffs charged by the CO2 pipelines are not regulated; however, the tariff charged on the Cortez pipeline is based on a consent decree.

Crude Oil Pipeline

KMCO2 owns the Kinder Morgan Wink Pipeline, a 450-mile Texas intrastate crude oil pipeline system consisting of three mainline sections, two gathering systems and numerous truck delivery stations.  The pipeline allows KMCO2 to better manage crude oil deliveries from its oil field interests in West Texas.  KMCO2 has entered into a long-term throughput agreement with Western Refining Company, L.P. (Western Refining) to transport crude oil into Western Refining’s refinery located in El Paso, Texas. The throughput agreement expires in 2034.  The 20-inch diameter pipeline segment that runs from Wink to El Paso, Texas has a total capacity of 130 MBbl/d of crude oil with the use of drag reduction agent (DRA), but we are currently expanding to 145 MBbl/d. In 2013, the Kinder Morgan Wink Pipeline transported approximately 119 MBbl/d of oil. The tariffs charged on the pipeline system are regulated by both the FERC and the Texas Railroad Commission.

Competition

Our primary competitors for the sale of CO2 include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain CO2 resources, and Oxy USA, Inc., which controls waste CO2 extracted from natural gas production in the Val Verde Basin of West Texas.  Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other CO2 pipelines.  We also compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO2 to the Denver City, Texas market area.



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Products Pipelines

Our Products Pipelines segment consists of our refined petroleum products, crude oil and condensate, and NGL pipelines and associated terminals, Southeast terminals, and our transmix processing facilities.

West Coast Products Pipelines

Our West Coast Products Pipelines include our SFPP operations (often referred to in this report as our Pacific operations), Calnev, and our West Coast Terminals operations.  The assets include interstate common carrier pipelines rate-regulated by the FERC, intrastate pipelines in the state of California rate-regulated by the CPUC, and certain non rate-regulated operations and terminal facilities.

Our Pacific operations serve six western states with approximately 2,500 miles of refined petroleum products pipelines and related terminal facilities that provide refined products to major population centers in the U.S., including California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona corridor.  In 2013, our Pacific operations’ mainline pipeline system transported approximately 1.1 MMBbl/d of refined products, with the product mix being approximately 60% gasoline, 23% diesel fuel, and 17% jet fuel.

Calnev consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines that run from our facilities at Colton, California to Las Vegas, Nevada.  The pipeline serves the Mojave region through deliveries to a terminal at Barstow, California and two nearby major railroad yards.  It also serves Nellis Air Force Base, located in Las Vegas, and serves a military supply terminal at Barstow for various desert defense installations which is operated by Calnev. Calnev also serves Edwards Air Force Base in California through a 55 mile pipeline.  In 2013, Calnev transported approximately 104 MBbl/d of refined products, with the product mix being approximately 39% gasoline, 30% diesel fuel, and 31% jet fuel.

Our West Coast Products Pipelines operations include 15 truck-loading terminals (13 on our Pacific operations and two on Calnev) with an aggregate usable tankage capacity of approximately 15.5 MMBbl.  The truck terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.

Our West Coast Terminals are fee-based terminals located in the Seattle, Portland, San Francisco and Los Angeles areas along the west coast of the U.S. with a combined total capacity of approximately 9.2 MMBbl of storage for both petroleum products and chemicals.  Our West Coast Products Pipelines and associated West Coast Terminals together handled 17.6 MMBbl of ethanol in 2013.

Combined, our West Coast Products Pipelines operations’ pipelines transport approximately 1.2 MMBbl/d of refined petroleum products, providing pipeline service to approximately 28 customer-owned terminals, 10 commercial airports and 15 military bases.  The pipeline systems serve approximately 60 shippers in the refined petroleum products market, the largest customers being major petroleum companies, independent refiners, and the U.S. military.  The majority of refined products supplied to our West Coast Product Pipelines come from the major refining centers around Los Angeles, San Francisco, West Texas and from waterborne terminals and connecting pipelines located near these refining centers.

Plantation Pipe Line Company

We own approximately 51% of Plantation, the sole owner of the approximately 3,100-mile refined petroleum products Plantation pipeline system serving the southeastern U.S.  We operate the system pursuant to agreements with Plantation and its wholly-owned subsidiary, Plantation Services LLC.  The Plantation pipeline system originates in Louisiana and terminates in the Washington, D.C. area.  It connects to approximately 130 shipper delivery terminals throughout eight states and serves as a common carrier of refined petroleum products to various metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area.  An affiliate of ExxonMobil Corporation owns the remaining approximately 49% ownership interest, and ExxonMobil has historically been one of the largest shippers on the Plantation system both in terms of volumes and revenues.  In 2013, Plantation delivered approximately 576,600 Bbl/d of refined petroleum products, with the product mix being approximately 71% gasoline, 17% diesel fuel, and 12% jet fuel.

Products shipped on Plantation originate at various Gulf Coast refineries from which major integrated oil companies and independent refineries and wholesalers ship refined petroleum products, from other products pipeline systems, and via marine facilities located along the Mississippi River.  Plantation ships products for approximately 40 companies to terminals throughout the southeastern U.S.  Plantation’s principal customers are Gulf Coast refining and marketing companies, and fuel wholesalers.



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Central Florida Pipeline

Our Central Florida pipeline system consists of a 110-mile, 16-inch diameter pipeline that transports gasoline and ethanol, and an 85-mile, 10-inch diameter pipeline that transports diesel fuel and jet fuel from Tampa to Orlando.  Our Central Florida pipeline operations also include two separate liquids terminals located in Tampa and Taft, Florida, which we own and operate.

In addition to being connected to our Tampa terminal, the Central Florida pipeline system is connected to terminals owned and operated by TransMontaigne, Citgo, Buckeye, and Marathon Petroleum.  The 10-inch diameter pipeline is connected to our Taft terminal (located near Orlando), has an intermediate delivery point at Intercession City, Florida, and is also the sole pipeline supplying jet fuel to the Orlando International Airport in Orlando, Florida.  In 2013, the pipeline system transported approximately 95,400 Bbl/d of refined products, with the product mix being approximately 71% gasoline and ethanol, 10% diesel fuel, and 19% jet fuel.

Our Tampa terminal contains approximately 1.6 MMBbl of refined products storage capacity and is connected to two ship dock facilities in the Port of Tampa and is also connected to an ethanol unit train off-load facility.  Our Taft terminal contains approximately 0.8 MMBbl of storage capacity, for gasoline, ethanol and diesel fuel for further movement into trucks.

Cochin Pipeline System

Our Cochin pipeline system consists of an approximately 1,900-mile, 12-inch diameter multi-product pipeline operating between Fort Saskatchewan, Alberta and Windsor, Ontario, along with five terminals.  The pipeline operates on a batched basis and has an estimated system capacity of 50 MBbl/d.  It includes 31 pump stations spaced at 60 mile intervals and five U.S. propane terminals.  Underground storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario through third parties.  The pipeline traverses three provinces in Canada and seven states in the U.S. and can transport ethane, propane, butane and NGL to the midwestern U.S. and eastern Canadian petrochemical and fuel markets.  In 2013, the system transported approximately 33 MBbl/d of propane, and 16.4 MBbl/d of ethane-propane mix. In mid-2014, we expect to complete the expansion and reversal of the Cochin pipeline system to transport 95 MBbl/d of condensate from a new receipt terminal in Kankakee County, Illinois to third party storage in Fort Saskatchewan, Alberta.

Cypress Pipeline

We own 50% of Cypress Interstate Pipeline LLC, the sole owner of the Cypress pipeline system.  We operate the system pursuant to a long-term agreement.  The Cypress pipeline is an interstate common carrier NGL pipeline originating at storage facilities in Mont Belvieu, Texas and extending 104 miles east to a connection with Westlake Chemical Corporation, a major petrochemical producer in the Lake Charles, Louisiana area.  Mont Belvieu, located approximately 20 miles east of Houston, is the largest hub for NGL gathering, transportation, fractionation and storage in the U.S.  The Cypress pipeline system has a current capacity of approximately 55 MBbl/d for NGL.  In 2013, the system transported approximately 52.8 MBbl/d.

Southeast Terminals

Our Southeast terminal operations consist of 28 high-quality, liquid petroleum products terminals located along the Plantation/Colonial pipeline corridor in the Southeastern U.S.  The marketing activities of our Southeast terminal operations are focused on the Southeastern U.S. from Mississippi through Virginia, including Tennessee.  The primary function involves the receipt of petroleum products from common carrier pipelines, short-term storage in terminal tankage, and subsequent loading onto tank trucks.  Combined, our Southeast terminals have a total storage capacity of approximately 9.1 MMBbl.  In 2013, these terminals transferred approximately 418.1 MBbl/d of refined products and together handled 15.8 MMBbl of ethanol.

Transmix Operations

Our Transmix operations include the processing of petroleum pipeline transmix, a blend of dissimilar refined petroleum products that have become co-mingled in the pipeline transportation process.  During pipeline transportation, different products are transported through the pipelines abutting each other, and generate a volume of different mixed products called transmix.  We process and separate pipeline transmix into pipeline-quality gasoline and light distillate products at six separate processing facilities located in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; St. Louis, Missouri; and Greensboro, North Carolina.  Combined, our transmix facilities handled approximately 11.3 MMBbl in 2013.



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Kinder Morgan Crude & Condensate Pipeline

Our Kinder Morgan Crude and Condensate Pipeline is a Texas intrastate pipeline that transports crude oil and condensate from the Eagle Ford shale field in South Texas to the Houston ship channel refining complex. The 24-to-30-inch pipeline currently originates in Dewitt County, Texas, and extends approximately 178 miles to third party storage. It delivers product to multiple terminaling facilities that provide access to local refineries, petrochemical plants and docks along the Texas Gulf Coast. The pipeline operates on a batch basis and has a capacity of 300 MBbl/d. In 2013, the pipeline system transported approximately 8.8 MMBbl. Due to strong interest for transportation of Eagle Ford crude oil and condensate to the Houston Ship Channel, we have secured long-term commitments for more than two-thirds of the 300 MBbl/d of capacity on the pipeline.

Double Eagle Pipeline LLC

As part of our May 1, 2013 Copano acquisition, we acquired a 50% ownership interest in Double Eagle, the sole owner of the Double Eagle pipeline system. Double Eagle provides crude oil and condensate gathering and transportation services for Eagle Ford shale gas producers. The remaining 50% ownership interest in Double Eagle is owned by Magellan Midstream Partners, L.P. We operate the approximate 195-mile Double Eagle pipeline system which consists of three segments (i) a 73-mile line that extends from Three Rivers, Texas, in Live Oak County, Texas, to Magellan’s Corpus Christi terminal; (ii) a 37-mile line that extends from northern Karnes County, Texas, to Three Rivers; and (iii) an 85-mile line that extends from Gardendale, Texas, in LaSalle County to Three Rivers. The Double Eagle joint venture operations also include a truck unloading facility and a 400 MBbl storage facility located along the pipeline near Three Rivers for deliveries and storage of condensate destined for Corpus Christi. Combined, the pipeline system has a capacity of 100 MBbl/d, but can be expanded to approximately 150 MBbl/d, and is supported by long-term customer commitments from Talisman Energy USA Inc. and Statoil Marketing and Trading (US) Inc.

Competition

Our Products Pipelines’ pipeline operations compete against proprietary pipelines owned and operated by major oil companies, other independent products pipelines, trucking and marine transportation firms (for short-haul movements of products) and railcars.  Our Products Pipelines’ terminal operations compete with proprietary terminals owned and operated by major oil companies and other independent terminal operators, and our transmix operations compete with refineries owned by major oil companies and independent transmix facilities.

Terminals

Our Terminals segment includes the operations of our petroleum, chemical and other liquids terminal facilities (other than those included in our Products Pipelines segment) and all of our coal, petroleum coke, fertilizer, steel, ores and other dry-bulk material services facilities, including all transload, engineering, conveying and other in-plant services.  Combined, the segment is composed of approximately 122 owned or operated liquids and bulk terminal facilities and approximately 10 rail transloading and materials handling facilities.  Our terminals are located throughout the U.S. and in portions of Canada.  We believe the location of our facilities and our ability to provide flexibility to customers helps keep customers at our terminals and provides us opportunities for expansion. We often classify our terminal operations based on their handling of either liquids or bulk material products.

Liquids Terminals

Our liquids terminals operations primarily store petroleum products, petrochemicals, ethanol, industrial chemicals and vegetable oil products in above-ground storage tanks and transfer products to and from pipelines, vessels, tank trucks, tank barges, and tank railcars.  Combined, our approximately 40 liquids terminals facilities possess liquids storage capacity of approximately 68.1 MMBbl, and in 2013, these terminals handled approximately 618.9 MMBbl of liquids products, including petroleum products, ethanol and chemicals.

Bulk Terminals

Our bulk terminal operations primarily involve dry-bulk material handling services.  We also provide conveyor manufacturing and installation, engineering and design services, and in-plant services covering material handling, conveying, maintenance and repair, truck-railcar-marine transloading, railcar switching and miscellaneous marine services.  We own or operate approximately 82 dry-bulk terminals in the U.S. and Canada, and combined, our dry-bulk and material transloading


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facilities (described below) handled approximately 89.9 million tons of coal, petroleum coke, fertilizers, steel, ores and other dry-bulk materials in 2013.

Materials Services (rail transloading)

Our materials services operations include rail or truck transloading shipments from one medium of transportation to another conducted at approximately 10 owned and non-owned facilities.  The Burlington Northern Santa Fe, CSX, Norfolk Southern, Union Pacific, Kansas City Southern and A&W railroads provide rail service for these terminal facilities. Approximately 50% of the products handled are liquids, including an entire spectrum of liquid chemicals, and the rest are dry-bulk products.  Many of the facilities are equipped for bi-modal operation (rail-to-truck, and truck-to-rail) or connect via pipeline to storage facilities.  Several facilities provide railcar storage services.  We also design and build transloading facilities, perform inventory management services, and provide value-added services such as blending, heating and sparging.

Effective March 31, 2013, TRANSFLO, a wholly owned subsidiary of CSX, elected to terminate their contract with our materials handling wholly-owned subsidiary, Kinder Morgan Materials Services (KMMS). This contract covered 25 terminals located on the CSX Railroad throughout the southeastern section of the U.S. KMMS performed transloading services at the 25 terminals, which included rail-to-truck and truck-to-rail transloading of bulk and liquid products.
 
Competition

We are one of the largest independent operators of liquids terminals in the U.S., based on barrels of liquids terminaling capacity.  Our liquids terminals compete with other publicly or privately held independent liquids terminals, and terminals owned by oil, chemical and pipeline companies.  Our bulk terminals compete with numerous independent terminal operators, terminals owned by producers and distributors of bulk commodities, stevedoring companies and other industrial companies opting not to outsource terminal services.  In some locations, our competitors are smaller, independent operators with lower cost structures.  Our rail transloading (material services) operations compete with a variety of single- or multi-site transload, warehouse and terminal operators across the U.S.  Our ethanol rail transload operations compete with a variety of ethanol handling terminal sites across the U.S., many offering waterborne service, truck loading, and unit train capability serviced by Class 1 rail carriers.

Kinder Morgan Canada

Our Kinder Morgan Canada business segment includes our Trans Mountain pipeline system and our 25-mile Jet Fuel pipeline system.

Trans Mountain Pipeline System

Our Trans Mountain pipeline system originates at Edmonton, Alberta and transports crude oil and refined petroleum products to destinations in the interior and on the west coast of British Columbia.  The Trans Mountain pipeline is 715 miles in length.  We also own a connecting pipeline that delivers crude oil to refineries in the state of Washington.  The capacity of the line at Edmonton ranges from 300 MBbl/d when heavy crude oil represents 20% of the total throughput (which is a historically normal heavy crude oil percentage), to 400 MBbl/d with no heavy crude oil.

The crude oil and refined petroleum products transported through Trans Mountain’s pipeline system originates in Alberta and British Columbia.  The refined and partially refined petroleum products transported to Kamloops, British Columbia and Vancouver originates from oil refineries located in Edmonton, Alberta.  Petroleum products delivered through Trans Mountain’s pipeline system are used in markets in British Columbia, Washington State and elsewhere offshore. In 2013, the Trans Mountain pipeline system delivered an average of 264 MBbl/d. In February 2013, Trans Mountain completed negotiations with the Canadian Association of Petroleum Producers for a new negotiated toll settlement effective for the period beginning January 1, 2013 and ending December 31, 2015.  The NEB approved the toll settlement in April 2013. The 2013-2015 negotiated settlement contains provisions for extension of the settlement that would likely cause the 2013-2015 settlement to be extended to the completion of the expansion of Trans Mountain at the end of 2017. In 2012, Trans Mountain succeeded in contracting 80% of its total planned capacity based on a $5.4 billion expansion of the Trans Mountain pipeline from 300 MBbl to 890 MBbl, based on 15 and 20 year take or pay contracts. In May 2013, the NEB approved the commercial terms of the expansion agreement. On December 16, 2013, Trans Mountain filed its application for a Certificate of Public need, including NEB approval on all remaining aspects of the project. The regulatory process is expected to be completed in the middle of 2015.



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Trans Mountain also operates a 5.3 mile spur line from its Sumas Pump Station to the U.S. – Canada international border where it connects with our approximate 63-mile, 16-inch to 20-inch diameter Puget Sound pipeline system.  The Puget Sound pipeline system in the state of Washington has a sustainable throughput capacity of approximately 180 MBbl/d when heavy crude oil represents approximately 5% of throughput, and it connects to four refineries located in northwestern Washington State.  The volumes of crude oil shipped to the state of Washington fluctuate in response to the price levels of Canadian crude oil in relation to crude oil produced in Alaska and other offshore sources and in response to available capacity on the Trans Mountain system.

Jet Fuel Pipeline System

We also own and operate the approximate 25-mile aviation fuel pipeline that serves the Vancouver International Airport, located in Vancouver, British Columbia, Canada.  The turbine fuel pipeline is referred to in this report as our Jet Fuel pipeline system.  In addition to its receiving and storage facilities located at the Westridge Marine terminal, located in Port Metro Vancouver, the Jet Fuel pipeline system’s operations include a terminal at the Vancouver airport that consists of five jet fuel storage tanks with an overall capacity of 15 MBbl.

Competition

Trans Mountain is one of several pipeline alternatives for western Canadian crude oil and refined petroleum production, and it competes against other pipeline providers; however, it is the sole pipeline carrying crude oil and refined petroleum products from Alberta to the west coast.  Furthermore, as demonstrated by our previously announced expansion proposal, discussed above in “—(a) General Development of Business—Recent Developments—Kinder Morgan Canada,” we believe our Trans Mountain pipeline facilities provide us the opportunity to execute on capacity expansions to the west coast as the market for offshore exports continues to develop.

In December, 2013 the British Columbia Ministry of Environment granted approval for a new, airport fuel consortium owned, jet fuel terminal to be located near the Vancouver International Airport. The impact of this facility on our existing Jet Fuel pipeline system is uncertain at this time.

Major Customers

Our revenue is derived from a wide customer base. For each of the years ended December 31, 2013, 2012 and 2011, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. Our Texas intrastate natural gas pipeline group buys and sells significant volumes of natural gas within the state of Texas, and, to a far lesser extent, our CO2 business segment also sells natural gas. Combined, total revenues from the sales of natural gas from our Natural Gas Pipelines and CO2 business segments in 2013, 2012 and 2011 accounted for 28%, 28% and 42%, respectively, of our total consolidated revenues. To the extent possible, we attempt to balance the pricing and timing of our natural gas purchases to our natural gas sales, and these contracts are often settled in terms of an index price for both purchases and sales. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.
Regulation

Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation – U.S. Operations

Some of our U.S. refined petroleum products and crude oil pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA.  The ICA requires that we maintain our tariffs on file with the FERC.  Those tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipelines as well as the rules and regulations governing these services.  The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory.  The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates.  If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation.  The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively.  Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.

On October 24, 1992, Congress passed the Energy Policy Act of 1992.  The Energy Policy Act deemed petroleum products pipeline tariff rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th


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day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable or “grandfathered” under the ICA.  The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates.  Certain rates on our Pacific operations’ pipeline system were subject to protest during the 365-day period established by the Energy Policy Act.  Accordingly, certain of the Pacific pipelines’ rates have been, and continue to be, the subject of complaints with the FERC, as is more fully described in Note 16 to our consolidated financial statements.

Petroleum products pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index.  Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year.  A pipeline must, as a general rule, utilize the indexing methodology to change its rates.  Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates.

Common Carrier Pipeline Rate Regulation – Canadian Operations

The Canadian portion of our crude oil and refined petroleum products pipeline systems is under the regulatory jurisdiction of the NEB. The National Energy Board Act gives the NEB power to authorize pipeline construction and to establish tolls and conditions of service. Our subsidiary Trans Mountain Pipeline, L.P. is the sole owner of our Trans Mountain crude oil and refined petroleum products pipeline system.
The toll charged for the portion of Trans Mountain’s pipeline system located in the U.S. falls under the jurisdiction of the FERC. For further information, see “—Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation - U.S. Operations” above.
Interstate Natural Gas Transportation and Storage Regulation

Posted tariff rates set the general range of maximum and minimum rates we charge shippers on our interstate natural gas pipelines.  Within that range, each pipeline is permitted to charge discounted rates to meet competition, so long as such discounts are offered to all similarly situated shippers and granted without undue discrimination.  Apart from discounted rates offered within the range of tariff maximums and minimums, the pipeline is permitted to offer negotiated rates where the pipeline and shippers want rate certainty, irrespective of changes that may occur to the range of tariff-based maximum and minimum rate levels.  Negotiated rates provide certainty to the pipeline and the shipper of a fixed rate during the term of the transportation agreement, regardless of changes to the posted tariff rates.  There are a variety of rates that different shippers may pay, and while rates may vary by shipper and circumstance, the terms and conditions of pipeline transportation and storage services are not generally negotiable.

The FERC regulates the rates, terms and conditions of service, construction and abandonment of facilities by companies performing interstate natural gas transportation services, including storage services, under the Natural Gas Act of 1938.  To a lesser extent, the FERC regulates interstate transportation rates, terms and conditions of service under the Natural Gas Policy Act of 1978.  Beginning in the mid-1980’s, through the mid-1990’s, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace.  Among the most important of these changes were:

Order No. 436 (1985) which required open-access, nondiscriminatory transportation of natural gas;
Order No. 497 (1988) which set forth new standards and guidelines imposing certain constraints on the interaction between interstate natural gas pipelines and their marketing affiliates and imposing certain disclosure requirements regarding that interaction; and
Order No. 636 (1992) which required interstate natural gas pipelines that perform open-access transportation under blanket certificates to “unbundle” or separate their traditional merchant sales services from their transportation and storage services and to provide comparable transportation and storage services with respect to all natural gas supplies.  Natural gas pipelines must now separately state the applicable rates for each unbundled service they provide (i.e., for the natural gas commodity, transportation and storage).

The FERC standards of conduct address and clarify multiple issues, including (i) the definition of transmission function and transmission function employees; (ii) the definition of marketing function and marketing function employees; (iii) the definition of transmission function information; (iv) independent functioning; (v) transparency; and (vi) the interaction of FERC standards with the North American Energy Standards Board business practice standards. The FERC also promulgates certain standards of conduct that apply uniformly to interstate natural gas pipelines and public utilities. In light of the changing


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structure of the energy industry, these standards of conduct govern employee relationships-using a functional approach-to ensure that natural gas transmission is provided on a nondiscriminatory basis. Pursuant to the FERC’s standards of conduct, a natural gas transmission provider is prohibited from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer. Additionally, no-conduit provisions prohibit a transmission function provider from disclosing non-public information to marketing function employees by using a third party conduit. Rules also require that a transmission provider provide annual training on the standards of conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information.

In addition to regulatory changes initiated by the FERC, the U.S. Congress passed the Energy Policy Act of 2005. Among other things, the Energy Policy Act amended the Natural Gas Act to: (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder.
CPUC Rate Regulation

The intrastate common carrier operations of our Pacific operations’ pipelines in California are subject to regulation by the CPUC, under a “depreciated book plant” methodology, which is based on an original cost measure of investment.  Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of our Pacific operations’ business.  Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC.  A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates also could arise with respect to our intrastate rates.  Certain of our Pacific operations’ pipeline rates have been, and continue to be, subject to complaints with the CPUC, as is more fully described in Note 16 to our consolidated financial statements.

Texas Railroad Commission Rate Regulation

The intrastate operations of our natural gas and crude oil pipelines in Texas are subject to regulation with respect to such intrastate transportation by the Texas Railroad Commission.  The Texas Railroad Commission has the authority to regulate our transportation rates, though it generally has not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints.

Mexico - Energy Regulating Commission

The Mier-Monterrey Pipeline has a natural gas transportation permit granted by the Energy Regulating Commission (the Commission) that defines the general and directional conditions for the pipeline to carry out activity and provide natural gas transportation service. This permit expires in 2032.

This permit establishes certain restrictive conditions, including, without limitations: (i) compliance with the general conditions for the provision of natural gas transportation service; (ii) compliance with certain safety measures, contingency plans, maintenance plans and the official Mexican standards regarding safety; (iii) compliance with the technical and economic specifications of the project presented to the Commission; (iv) compliance with certain technical studies established by the Commission; and (v) compliance with a minimum contributed capital not entitled to withdrawal of at least the equivalent of 10% of the investment proposed in the project.

Safety Regulation

We are also subject to safety regulations imposed by the Department of Transportation PHMSA, including those requiring us to develop and maintain integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional measures to protect pipeline segments located in what are referred to as high consequence areas, or HCAs, where a leak or rupture could potentially do the most harm.

The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs can have a significant impact on the costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the Department of Transportation rules. The results of these tests could cause us to incur significant and


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unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

The President signed into law new pipeline safety legislation in January 2012, The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which increased penalties for violations of safety laws and rules, among other matters, and may result in the imposition of more stringent regulations in the next few years. PHMSA is also currently considering changes to its regulations. In 2012, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures.

From time to time, our pipelines may experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

We are also subject to the requirements of Occupational Safety and Health Administration (OSHA) and other comparable federal and state agencies that address employee health and safety.  In general, we believe current expenditures are addressing the OSHA requirements and protecting the health and safety of our employees.  Based on new regulatory developments, we may increase expenditures in the future to comply with higher industry and regulatory safety standards.  However, such increases in our expenditures, and the extent to which they might be offset, cannot be estimated at this time.

State and Local Regulation

Our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, and human health and safety.

Marine Operations

The operation of tankers and marine equipment create maritime obligations involving property, personnel and cargo under General Maritime Law. These obligations create a variety of risks including, among other things, the risk of collision, which may precipitate claims for personal injury, cargo, contract, pollution, third party claims and property damages to vessels and facilities.

We are subject to the Jones Act and other federal laws that restrict maritime transportation (between U.S. departure and destination points) to vessels built and registered in the U.S. and owned and manned by U.S. citizens. As a result, we monitor the foreign ownership of our common units and other partnership interests. If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels.

In addition, the U.S. Coast Guard and the American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for owners of vessels registered under foreign flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness.

The Merchant Marine Act of 1936 is a federal law that provides, upon proclamation by the U.S. President of a national emergency or a threat to the national security, the U.S. Secretary of Transportation the authority to requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our vessels were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid


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the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, we would not be entitled to compensation for any consequential damages we suffer as a result of such purchase or requisition.

Environmental Matters

Our business operations are subject to federal, state, provincial and local laws and regulations relating to environmental protection, pollution and human health and safety in the U.S. and Canada. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, or at or from our storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. Furthermore, new projects may require approvals and environmental analysis under federal and state laws, including the National Environmental Policy Act and the Endangered Species Act. The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required under federal, state and provincial environmental laws could require significant capital expenditures at our facilities.
Environmental and human health and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.
In accordance with GAAP, we accrue liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. We have accrued liabilities for estimable and probable environmental remediation obligations at various sites, including multiparty sites where the EPA, or similar state or Canadian agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could increase or mitigate our actual joint and several liability exposures.
We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $168 million as of December 31, 2013. Our reserve estimates range in value from approximately $168 million to approximately $244 million, and we recorded our liability equal to the low end of the range, as we did not identify any amounts within the range as a better estimate of the liability. For additional information related to environmental matters, see Note 16 to our consolidated financial statements.
Hazardous and Non-Hazardous Waste

We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state and Canadian statutes.  From time to time, the EPA and state and Canadian regulators consider the adoption of stricter disposal standards for non-hazardous waste.  Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations, may in the future be designated as hazardous wastes.  Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes.  Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

Superfund

The CERCLA or the Superfund law, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment.  These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site.  CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any.  Although petroleum is excluded


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from CERCLA’s definition of a hazardous substance, in the course of our ordinary operations, we have and will generate materials that may fall within the definition of hazardous substance.  By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.

Clean Air Act

Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state and Canadian statutes and regulations.  We believe that the operations of our pipelines, storage facilities and terminals are in substantial compliance with such statutes.  The EPA regulations under the Clean Air Act contain requirements for the monitoring, reporting, and control of greenhouse gas emissions from stationary sources.  For further information, see “—Climate Change” below.

Clean Water Act

Our operations can result in the discharge of pollutants.  The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the U.S.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal, state or Canadian authorities.  The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention and response to oil spills.  Spill prevention control and countermeasure requirements of the Clean Water Act and some state and Canadian laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release of oil.

Climate Change
 
Studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, may be contributing to warming of the Earth’s atmosphere.  Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases.  Various laws and regulations exist or are under development that seek to regulate the emission of such greenhouse gases, including the EPA programs to control greenhouse gas emissions and state actions to develop statewide or regional programs. The U.S. Congress is considering legislation to reduce emissions of greenhouse gases.

Beginning in December 2009, EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain greenhouse gases including CO2 and methane. Our facilities are subject to substantial compliance with these requirements. Operational and/or regulatory changes could require additional facilities to comply with greenhouse gas emissions reporting and permitting requirements. Additionally, the EPA has announced that it will propose new regulations of greenhouse gases which may impose further requirements, including emission control requirements, on Kinder Morgan facilities.

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

Because our operations, including our compressor stations and processing plants, emit various types of greenhouse gases, primarily methane and CO2, such new legislation or regulation could increase our costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we could be required to incur capital expenditures for installing new monitoring equipment of emission controls on our facilities, acquire and surrender allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated entities in the industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects.



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Some climatic models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding.  We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather.  To the extent these phenomena occur, they could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone regions.  However, the timing and location of these climate change impacts is not known with any certainty and, in any event, these impacts are expected to manifest themselves over a long time horizon.  Thus, we are not in a position to say whether the physical impacts of climate change pose a material risk to our business, financial position, results of operations or cash flows.

Because natural gas emits less greenhouse gas emissions per unit of energy than competing fossil fuels, cap-and-trade legislation or EPA regulatory initiatives could stimulate demand for natural gas by increasing the relative cost of fuels such as coal and oil.  In addition, we anticipate that greenhouse gas regulations will increase demand for carbon sequestration technologies, such as the techniques we have successfully demonstrated in our enhanced oil recovery operations within our CO2 business segment.  However, these positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels.  Although we currently cannot predict the magnitude and direction of these impacts, greenhouse gas regulations could have material adverse effects on our business, financial position, results of operations or cash flows.

Department of Homeland Security

The Department of Homeland Security, referred to in this report as the DHS, has regulatory authority over security at certain high-risk chemical facilities.  The DHS has promulgated the Chemical Facility Anti-Terrorism Standards and required all high-risk chemical and industrial facilities, including oil and gas facilities, to comply with the regulatory requirements of these standards.  This process includes completing security vulnerability assessments, developing site security plans, and implementing protective measures necessary to meet DHS-defined, risk based performance standards. The DHS has not provided final notice to all facilities that it determines to be high risk and subject to the rule; therefore, neither the extent to which our facilities may be subject to coverage by the rules nor the associated costs to comply can currently be determined, but it is possible that such costs could be substantial.

Other

Employees

KMGP Services Company, Inc., KMI, Kinder Morgan Canada Inc. and another affiliate employ all persons necessary for the operation of our business. Generally, we reimburse these entities for the services of their employees. As of December 31, 2013, KMGP Services Company, Inc., KMI, Kinder Morgan Canada Inc. and other affiliated entities had, in the aggregate, 11,075 full-time employees. Approximately 828 full-time hourly personnel at certain terminals and pipelines are represented by labor unions under collective bargaining agreements that expire between 2014 and 2018. KMGP Services Company, Inc., KMI, Kinder Morgan Canada Inc. and other affiliated entities each consider relations with their employees to be good. For more information on our related party transactions, see Note 11 to our consolidated financial statements.
Properties

We believe that we have generally satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses.  Our terminals, storage facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, offices and related facilities are located on real property owned or leased by us.  In some cases, the real property we lease is on federal, state, provincial or local government land.

We generally do not own the land on which our pipelines are constructed.  Instead, we obtain the right to construct and operate the pipelines on other people’s land for a period of time.  Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property.  In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants.  In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of a majority of the interests have been obtained.  Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense.  Permits also have been obtained from railroad companies to run along or cross over or under lands or rights-of-way, many of which are


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also revocable at the grantor’s election.  Some such permits require annual or other periodic payments.  In a few minor cases, property for pipeline purposes was purchased in fee.

(d) Financial Information about Geographic Areas

For geographic information concerning our assets and operations, see Note 15 to our consolidated financial statements.

(e) Available Information

We make available free of charge on or through our internet Website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.  The information contained on or connected to our internet Website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

Item 1A.  Risk Factors.

You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial position, results of operations or cash flows.  There are also risks associated with being an owner of common units in a partnership that are different than being an owner of common stock in a corporation.  Investors in our common units should be aware that the realization of any of those risks could result in a decline in the trading price of our common units, and they might lose all or part of their investment.

Risks Related to Our Business

New regulations, rulemaking and oversight, as well as changes in regulations, by regulatory agencies having jurisdiction over our operations could adversely impact our income and operations.

Our assets and operations are subject to regulation and oversight by federal, state and local regulatory authorities.  Regulatory actions taken by these agencies have the potential to adversely affect our profitability.  Regulation affects almost every part of our business and extends to such matters as (i) rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (ii) the types of services we may offer to our customers; (iii) the contracts for service entered into with our customers; (iv) the certification and construction of new facilities; (v) the integrity, safety and security of facilities and operations; (vi) the acquisition of other businesses; (vii) the acquisition, extension, disposition or abandonment of services or facilities; (viii) reporting and information posting requirements; (ix) the maintenance of accounts and records; and (x) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines.  Furthermore, new laws or regulations sometimes arise from unexpected sources. For example, the Department of Homeland Security Appropriation Act of 2007 required the issuance of regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to us or our assets could have a material adverse impact on our business, financial condition and results of operations.  For more information, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Regulation.”

The FERC, CPUC, or the NEB may establish pipeline tariff rates that have a negative impact on us.  In addition, the FERC, the CPUC, the NEB, or our customers could file complaints challenging the tariff rates charged by our pipelines, and a successful complaint could have an adverse impact on us.

The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers.  To the extent that our costs increase in an amount greater than what we are permitted by the FERC, the CPUC, or the NEB allows us to recover in our rates, or to the extent that there is a lag before we can file and obtain rate increases, such events can have a negative impact upon our operating results can be negatively impacted.



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Our existing rates may also be challenged by complaint.  Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations.  Some shippers on our pipelines have filed complaints with the regulators that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates.  Further, the FERC may initiate investigations to determine whether some interstate natural gas pipelines have over-collected on rates charged to shippers.  We may face challenges, similar to those described in Note 16 to our consolidated financial statements, to the rates we charge on our pipelines.  Any successful challenge could materially adversely affect our future earnings, cash flows and financial condition.

Energy commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our operations.

There are a variety of hazards and operating risks inherent to natural gas transmission and storage activities and refined petroleum products and CO2 transportation activities—such as leaks, explosions and mechanical problems—that could result in substantial financial losses.  In addition, these risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which also could result in substantial financial losses.  For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater.  Incidents that cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, may negatively impact our revenues and earnings while the affected asset is temporarily out of service.  In addition, losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations.
 
Increased regulatory requirements relating to the integrity of our pipelines may require us to incur significant capital and operating expense outlays to comply.

We are subject to extensive laws and regulations related to pipeline integrity.  There are, for example, federal guidelines for the DOT and pipeline companies in the areas of testing, education, training and communication.  The ultimate costs of compliance with the integrity management rules are difficult to predict.  The majority of compliance costs are pipeline integrity testing and the repairs. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in High Consequence Areas can have a significant impact on integrity testing and repair costs.  We plan to continue our integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the DOT rules.  The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures.  There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate.  Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

The Jones Act includes restrictions on ownership by non-U.S. citizens of our vessels, and failure to comply with the Jones Act, or changes to or repeal of the Jones Act, could limit our ability to operate our vessels in the U.S. coastwise trade or result in the forfeiture of our vessels otherwise adversely impact our income and operations.

Following our January 2014 acquisition of American Petroleum Tankers and State Class Tankers, we are subject to the Jones Act, which generally restricts U.S. point-to-point maritime shipping to vessels operating under the U.S. flag, built in the U.S., owned and operated by U.S.-organized companies that are controlled and at least 75% owned by U.S. citizens and manned by predominately U.S. crews. Our business would be adversely affected if we fail to comply with the Jones Act provisions on coastwise trade. If we do not comply with any of these requirements, we would be prohibited from operating our vessels in the U.S. coastwise trade and, under certain circumstances, we could be deemed to have undertaken an unapproved transfer to non-U.S. citizens that could result in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of vessels. Our business could be adversely affected if the Jones Act were to be modified or repealed so as to permit foreign competition that is not subject to the same U.S. government imposed burdens.



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Environmental, health and safety laws and regulations could expose us to significant costs and liabilities.

Our operations are subject to federal, state, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety.  Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals.  Liability under such laws and regulations may be incurred without regard to fault under CERCLA, the Resource Conservation and Recovery Act, the Federal Clean Water Act or analogous state laws for the remediation of contaminated areas.  Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage.  Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us.

Failure to comply with these laws and regulations also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could influence our business, financial position, results of operations and prospects. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines or our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay for government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures.  The resulting costs and liabilities could materially and negatively affect our level of earnings and cash flows.  In addition, emission controls required under the Federal Clean Air Act and other similar federal, state and provincial laws could require significant capital expenditures at our facilities.

We own and/or operate numerous properties that have been used for many years in connection with our business activities. While we have utilized operating, handling, and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal.  In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control.  These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the U.S. such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct.  Under the regulatory schemes of the various Canadian provinces, such as British Columbia’s Environmental Management Act, Canada has similar laws with respect to properties owned, operated or used by us or our predecessors.  Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators.  Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

In addition, our oil and gas development and production activities are subject to numerous federal, state and local laws and regulations relating to environmental quality and pollution control.  Due to the rise of oil and gas production in new areas of the country and increased public scrutiny of fracturing and other practices in oil and gas drilling, many states are promulgating stricter requirements not only for wells but also compressor stations and other facilities in the oil and gas industry sector. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation.  Specifically, these activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities and location, emissions into the environment, water discharges, transportation of hazardous materials, and storage and disposition of wastes.  In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities.

Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us.  There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.  Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.  For more information, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters.”

Climate change regulation at the federal, state, provincial or regional levels could result in significantly increased operating and capital costs for us.

Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases.  The EPA regulates greenhouse gas emissions and requires the reporting of


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greenhouse gas emissions in the U.S. for emissions from specified large greenhouse gas emission sources, fractionated NGL, and the production of naturally occurring CO2, like our McElmo Dome CO2 field, even when such production is not emitted to the atmosphere.

Because our operations, including our compressor stations and natural gas processing plants in our Natural Gas Pipelines segment, emit various types of greenhouse gases, primarily methane and CO2, such regulation could increase our costs related to operating and maintaining our facilities and could require us to install new emission controls on our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program, and such increased costs could be significant.  Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows.  For more information about climate change regulation, see Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters—Climate Change.”

Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas transported on our or our joint ventures’ natural gas pipelines.

The natural gas industry is increasingly relying on natural gas supplies from unconventional sources, such as shale, tight sands and coal bed methane.  The extraction of natural gas from these sources frequently requires hydraulic fracturing.  Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by oil and gas exploration and production operators in the completion of certain oil and gas wells.  There have been initiatives at the federal and state levels to regulate or otherwise restrict the use of hydraulic fracturing.  Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the volumes of natural gas transported on our or our joint ventures’ natural gas pipelines, several of which gather gas from areas in which the use of hydraulic fracturing is prevalent.

We may face competition from other pipelines and other forms of transportation into the areas we serve as well as with respect to the supply for our pipeline systems.

Any current or future pipeline system or other form of transportation that delivers crude oil, petroleum products or natural gas into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities or other factors.  To the extent that an excess of supply into these areas is created and persists, our ability to recontract for expiring transportation capacity at favorable rates or otherwise to retain existing customers could be impaired.  We also could experience competition for the supply of petroleum products or natural gas from both existing and proposed pipeline systems.  Several pipelines access many of the same areas of supply as our pipeline systems and transport to destinations not served by us.

Cost overruns and delays on our expansion and new build projects could adversely affect our business.

We regularly undertake major construction projects to expand our existing assets and to construct new assets.  A variety of factors outside of our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as performance by third-party contractors, has resulted in, and may continue to result in, increased costs or delays in construction.  Significant cost overruns or delays in completing a project could have a material adverse effect on our return on investment, results of operations and cash flows.

We must either obtain the right from landowners or exercise the power of eminent domain in order to use most of the land on which our pipelines are constructed, and we are subject to the possibility of increased costs to retain necessary land use.

We obtain the right to construct and operate pipelines on other owners’ land for a period of time.  If we were to lose these rights or be required to relocate our pipelines, our business could be negatively affected.  In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.

Whether we have the power of eminent domain for our pipelines, other than interstate natural gas pipelines, varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas, CO2, or crude oil—and the laws of the particular state.  Our interstate natural gas pipelines have federal eminent domain authority.  In either case, we must compensate


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landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. 

Our business, financial condition and operating results may be adversely affected by increased costs of capital or a reduction in the availability of credit.
Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings could cause our cost of doing business to increase by limiting our access to capital, limiting our ability to pursue acquisition opportunities and reducing our cash flows. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions.  Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect our business, financial condition and results of operations.
In addition, due to our relationship with KMI, our credit ratings, and thus our ability to access the capital markets and the terms and pricing we receive therein, may be adversely affected by any impairment to KMI’s financial condition or adverse changes in its credit ratings. Similarly, any reduction in our credit ratings could negatively impact the credit ratings of our subsidiaries, which could increase their cost of capital and negatively affect their business and operating results. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our debt instruments, as well as the market value of our common units.
Our acquisition strategy and expansion programs require access to new capital.  Limitations on our access to capital would impair our ability to grow.

Consistent with the terms of our partnership agreement, we have distributed most of the cash generated by our operations. As a result, we have relied on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund our acquisition and growth capital expenditures.  However, to the extent we are unable to continue to finance growth externally, our cash distribution policy will significantly impair our ability to grow.  We may need new capital to finance these activities.  Limitations on our access to capital, whether due to tightened capital markets, more expensive capital or otherwise, will impair our ability to execute this strategy.

Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.

As of December 31, 2013, we had $19.9 billion of consolidated debt (excluding debt fair value adjustments).  This level of debt could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; (ii) limiting our ability to use operating cash flow in other areas of our business or to pay distributions because we must dedicate a substantial portion of these funds to make payments on our debt; (iii) placing us at a competitive disadvantage compared to competitors with less debt; and (iv) increasing our vulnerability to adverse economic and industry conditions.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control.  If our operating results are not sufficient to service our indebtedness, or any future indebtedness that we incur, we will be forced to take actions, which may include reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.  For more information about our debt, see Note 8 to our consolidated financial statements.

Our large amount of variable rate debt makes us vulnerable to increases in interest rates.

As of December 31, 2013, approximately $5.7 billion (29%) of our total $19.9 billion consolidated debt (excluding debt fair value adjustments) was subject to variable interest rates, either as short-term or long-term debt of variable rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps.  Should interest rates increase, the amount of cash required to service this debt would increase and our earnings could be adversely affected.  For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”



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Our growth strategy may cause difficulties integrating and constructing new operations, and we may not be able to achieve the expected benefits from any future acquisitions or expansions.

Part of our business strategy includes acquiring additional businesses, some of which may occur in drop-down transactions from KMI, expanding existing assets and constructing new facilities.  If we do not successfully integrate acquisitions, expansions or newly constructed facilities, we may not realize anticipated operating advantages and cost savings.  The integration of acquired companies or new assets involves a number of risks, including (i) demands on management related to the increase in our size; (ii) the diversion of management’s attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; (iv) difficulties in the assimilation and retention of necessary employees; and (v) potential adverse effects on operating results.

We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately.  Successful integration of each acquisition, expansion or construction project will depend upon our ability to manage those operations and to eliminate redundant and excess costs.  Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.

Current or future distressed financial conditions of our customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide. 

Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness.  We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows.  Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities.  In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations, financial condition, and cash flows.

Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business.

The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or “cyber security” events.  These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets, our operations could be disrupted and/or customer information could be stolen. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation and or inaccurate information reported from our operations. There is no assurance that adequate sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future.  These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.

Our pipelines business is dependent on the supply of and demand for the commodities transported by our pipelines.

Our pipelines depend on production of natural gas, oil and other products in the areas served by our pipelines. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise.  Producers may shut down production at lower product prices or higher production costs, especially where the existing cost of production exceeds other extraction methodologies, such as in the Alberta oil sands.  Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our gas plants and pipelines may not be able to maintain existing volumes of throughput.  Commodity prices and tax incentives may not remain at levels that encourages producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire.

Changes in the business environment, such as a decline in crude oil or natural gas prices, an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply from oil and natural gas producing areas.  In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of crude oil and natural gas.  Each of these factors impact our customers shipping through our pipelines, which in turn could impact the prospects of new transportation contracts or renewals of existing contracts.



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Throughput on our crude oil, natural gas and refined petroleum products pipelines also may decline as a result of changes in business conditions.  Over the long term, business will depend, in part, on the level of demand for oil, natural gas and refined petroleum products in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand.

The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for natural gas, crude oil and refined petroleum products, increase our costs and have a material adverse effect on our results of operations and financial condition.  We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas, crude oil and refined petroleum products.

The future success of our oil and gas development and production operations depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable.

The rate of production from oil and natural gas properties declines as reserves are depleted.  Without successful development activities, the reserves and revenues of the oil and gas producing assets within our CO2 business segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future.  Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.

The development of oil and gas properties involves risks that may result in a total loss of investment.

The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative.  It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment.  A variety of geological, operational and market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions, may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable.  A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well.  In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

The volatility of natural gas and oil prices could have a material adverse effect on our CO2 business segment.

The revenues, profitability and future growth of our CO2 business segment and the carrying value of its oil, NGL and natural gas properties depend to a large degree on prevailing oil and gas prices.  For 2014, we estimate that every $1 change in the average WTI crude oil price per barrel would impact our CO2 segment’s cash flows by approximately $7 million.  Prices for oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control.  These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) the condition of the U.S. economy; (iii) the activities of the Organization of Petroleum Exporting Countries; (iv) governmental regulation; (v) political stability in the Middle East and elsewhere; (vi) the foreign supply of and demand for oil and natural gas; (vii) the price of foreign imports; and (viii) the availability of alternative fuel sources.

A sharp decline in the prices of oil, NGL or natural gas would result in a commensurate reduction in our revenues, income and cash flows from the production of oil, NGL, and natural gas and could have a material adverse effect on the carrying value of our proved reserves.  In the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss.  In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts.  Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis.  These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas.  The excess or short supply of crude oil or natural gas has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand.  These fluctuations impact the accuracy of assumptions used in our budgeting process.  For more information about our energy and commodity market risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Energy Commodity Market Risk.”



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Our use of hedging arrangements could result in financial losses or reduce our income.

We engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil and natural gas.  These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received.  In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for oil and natural gas.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes.  Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those statements.  In addition, it is not always possible for us to engage in hedging transactions that completely mitigate our exposure to commodity prices.  Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.  For more information about our hedging activities, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Hedging Activities” and Note 13 to our consolidated financial statements.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that market.  The CFTC has proposed new rules pursuant to the Dodd-Frank Act that would institute broad new aggregate position limits for OTC swaps and futures and options traded on regulated exchanges.  As the law favors exchange trading and clearing, the Dodd-Frank Act also may require us to move certain derivatives transactions to exchanges where no trade credit is provided and also comply with margin requirements in connection with our derivatives activities that are not exchange traded, although the application of those provisions to us is uncertain at this time.  The Dodd-Frank Act also requires many counterparties to our derivatives instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us.  The Dodd-Frank Act and any related regulations could (i) significantly increase the cost of derivative contracts (including those requirements to post collateral, which could adversely affect our available liquidity); (ii) reduce the availability of derivatives to protect against risks we encounter; and (iii) reduce the liquidity of energy related derivatives.

If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Increased volatility may make us less attractive to certain types of investors.  Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  Any of these consequences could have a material adverse effect on our financial condition and results of operations.

Our Kinder Morgan Canada segment is subject to U.S. dollar/Canadian dollar exchange rate fluctuations.

We are a U.S. dollar reporting company.  As a result of the operations of our Kinder Morgan Canada business segment, a portion of our consolidated assets, liabilities, revenues and expenses are denominated in Canadian dollars.  Fluctuations in the exchange rate between U.S. and Canadian dollars could expose us to reductions in the U.S. dollar value of our earnings and cash flows and a reduction in our partners’ capital under applicable accounting rules.

Our operating results may be adversely affected by unfavorable economic and market conditions.

Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services.  Our operating results in one or more geographic regions also may be affected by uncertain or changing economic conditions within that region, such as the challenges that are currently affecting economic conditions in the U.S. and Canada.  Volatility in commodity prices might have an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us.  In addition, decreases in the prices of crude oil and NGL will have a negative impact on the results of our CO2 business segment.  If global economic and market


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conditions (including volatility in commodity markets), or economic conditions in the U.S. or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations.

Hurricanes, earthquakes and other natural disasters could have an adverse effect on our business, financial condition and results of operations.

Some of our pipelines, terminals and other assets are located in areas that are susceptible to hurricanes, earthquakes and other natural disasters.  These natural disasters could potentially damage or destroy our pipelines, terminals and other assets and disrupt the supply of the products we transport through our pipelines.  Natural disasters can similarly affect the facilities of our customers.  In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially.

Our business requires the retention and recruitment of a skilled workforce and the loss of such workforce could result in the failure to implement our business plans.

Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible and have significant institutional knowledge that must be transferred to other employees. If we are unable to (a) retain current employees, (b) successfully complete the knowledge transfer and/or (c) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals.

Risks Related to Ownership of Our Common Units

The interests of KMI may differ from our interests and the interests of our unitholders.

KMI indirectly owns all of the common stock of our general partner and elects all of its directors.  Our general partner owns all of KMR’s voting shares and elects all of its directors.  Furthermore, some of KMR’s and our general partner’s directors and officers are also directors and officers of KMI and its other subsidiaries, including EPB, and have fiduciary duties to manage the businesses of KMI and its other subsidiaries in a manner that may not be in the best interests of our unitholders.  KMI has a number of interests that differ from the interests of our unitholders.  As a result, there is a risk that important business decisions will not be made in the best interests of our unitholders.

Our partnership agreement and the KMR LLC agreement restrict or eliminate a number of the fiduciary duties that would otherwise be owed by our general partner and/or its delegate to our unitholders.

Modifications of state law standards of fiduciary duties may significantly limit the ability of our unitholders to successfully challenge the actions of our general partner in the event of a breach of fiduciary duties.  These state law standards include the duties of care and loyalty.  The duty of loyalty, in the absence of a provision in the limited partnership agreement to the contrary, would generally prohibit our general partner from taking any action or engaging in any transaction as to which it has a conflict of interest.  Our limited partnership agreement contains provisions that prohibit limited partners from advancing claims that otherwise might raise issues as to compliance with fiduciary duties or applicable law.  For example, that agreement provides that the general partner may take into account the interests of parties other than us in resolving conflicts of interest.  It also provides that in the absence of bad faith by the general partner, the resolution of a conflict by the general partner will not be a breach of any duty.  The provisions relating to the general partner apply equally to KMR as its delegate.  It is not necessary for a limited partner to sign our limited partnership agreement in order for the limited partnership agreement to be enforceable against that person.

Common unitholders have limited voting rights and limited control.

Holders of common units have only limited voting rights on matters affecting us.  Our general partner manages partnership activities.  Under a delegation of control agreement, our general partner has delegated the management and control of our and our subsidiaries’ business and affairs to KMR.  Holders of common units have no right to elect the general partner or any of the directors of the general partner or KMR on an annual or other ongoing basis.  If the general partner withdraws, however, its successor may be elected by the holders of a majority of the outstanding units of all classes (excluding common units and Class B units owned by the departing general partner and its affiliates and excluding the number of i-units corresponding to the number of any KMR shares owned by the departing general partner and its affiliates).



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The limited partners may remove the general partner only if (i) the holders of at least 66 2/3% of the outstanding units of all classes, excluding common units and Class B units owned by the general partner and its affiliates and excluding the number of i-units corresponding to the number of any KMR shares owned by the general partner and its affiliates, vote to remove the general partner; (ii) a successor general partner is approved by the same vote; and (iii) we receive an opinion of counsel opining that the removal would not result in the loss of the limited liability of any limited partner or of the limited partner of an operating partnership, or cause us or an operating partnership to be taxed as a corporation or otherwise to be taxed as an entity for federal income tax purposes.

A person or group owning 20% or more of the common units and KMR shares on a combined basis cannot vote.

Any common units or KMR shares held by a person or group that owns 20% or more of the aggregate number of common units and KMR shares on a combined basis cannot be voted.  This limitation does not apply to the general partner and its affiliates.  This provision may (i) discourage a person or group from attempting to remove the general partner or otherwise change management and (ii) reduce the price at which the common units will trade under certain circumstances.  For example, a third party will probably not attempt to take over our management by making a tender offer for the common units at a price above their trading market price without removing the general partner and substituting an affiliate of its own.

The general partner’s liability to us and our unitholders may be limited.

Our partnership agreement contains language limiting the liability of the general partner to us or the holders of common units.  For example, our partnership agreement provides that (i) the general partner does not breach any duty to us or the holders of common units by borrowing funds or approving any borrowing (the general partner is protected even if the purpose or effect of the borrowing is to increase incentive distributions to the general partner); (ii) the general partner does not breach any duty to us or the holders of common units by taking any actions consistent with the standards of reasonable discretion outlined in the definitions of available cash and cash from operations contained in our partnership agreement; and (iii) the general partner does not breach any standard of care or duty by resolving conflicts of interest unless the general partner acts in bad faith.

Unitholders may have liability to repay distributions.

Unitholders will not be liable for assessments in addition to their initial capital investment in the common units.  Under certain circumstances, however, holders of common units may have to repay us amounts wrongfully returned or distributed to them.  Under Delaware law, we may not make a distribution to unitholders if the distribution causes our liabilities to exceed the fair value of our assets.  Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted.  Delaware law provides that for a period of three years from the date of such a distribution, a limited partner who receives the distribution and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount.  Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership.  However, such an assignee is not obligated for liabilities unknown to the assignee at the time the assignee became a limited partner if the liabilities could not be determined from the partnership agreement.

Unitholders may be liable if we have not complied with state partnership law.

We conduct our business in a number of states.  In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established.  The unitholders might be held liable for the partnership’s obligations as if they were a general partner if (i) a court or government agency determined that we were conducting business in the state but had not complied with the state’s partnership statute; or (ii) unitholders’ rights to act together to remove or replace the general partner or take other actions under our partnership agreement constitute “control” of our business.

The general partner may buy out minority unitholders if it owns 80% of the aggregate number of common units and KMR shares.

If at any time the general partner and its affiliates own 80% or more of the aggregate number of issued and outstanding common units and KMR shares, the general partner will have the right to purchase all, and only all, of the remaining common units, but only if KMI elects to purchase all, and only all, of the outstanding KMR shares that are not held by KMI and its affiliates pursuant to the purchase provisions that are a part of the LLC agreement of KMR.  Because of this right, a unitholder could have to sell its common units at a time or price that may be undesirable.  The purchase price for such a purchase will be the greatest of (i) the 20-day average closing price for the common units or the KMR shares as of the date five days prior to the


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date the notice of purchase is mailed; or (ii) the highest purchase price paid by the general partner or its affiliates to acquire common units or KMR shares during the prior 90 days.  The general partner can assign this right to its affiliates or to us.

We may sell additional limited partner interests, diluting existing interests of unitholders.

Our partnership agreement allows the general partner to cause us to issue additional common units and other equity securities. When we issue additional equity securities, including additional i-units to KMR when it issues additional shares, unitholders’ proportionate partnership interest in us will decrease.  Such an issuance could negatively affect the amount of cash distributed to unitholders and the market price of common units.  Issuance of additional common units will also diminish the relative voting strength of the previously outstanding common units.  Our partnership agreement does not limit the total number of common units or other equity securities we may issue.

The general partner can protect itself against dilution.

Whenever we issue equity securities to any person other than the general partner and its affiliates, the general partner has the right to purchase additional limited partnership interests on the same terms.  This allows the general partner to maintain its proportionate partnership interest in us.  No other unitholder has a similar right.  Therefore, only the general partner may protect itself against dilution caused by issuance of additional equity securities.

Our partnership agreement contains provisions that may limit the rights with respect to the ownership of our common units by individuals and entities that are not U.S. citizens within the meaning of the Jones Act. This may affect the liquidity of our common units and may result in non-U.S. citizens having their distribution and voting rights suspended or their common units redeemed by us.

We are subject to the Jones Act and, as a result, at least 75% of our outstanding units must be owned and controlled by U.S. citizens within the meaning of the Jones Act. Our partnership agreement includes provisions that may limit the rights of non-U.S. citizens with respect to ownership of our common units. These provisions are intended to facilitate compliance with laws and regulations, including the Jones Act and others to which we may become subject, that provide for the forfeiture of any property in which we have an interest based on the nationality or citizenship of our unitholders, and they may have an adverse effect on holders of our common units.

Our partnership agreement permits us to require that any unitholder provide us from time to time with certain documentation concerning such person’s citizenship. In the event that a unitholder does not submit such requested or required documentation to us, our partnership agreement provides us with certain remedies, including the suspension of the distribution and voting rights of such unitholder and the redemption by us of such unitholder’s common units.

In addition to the risks described above, the foregoing restrictions on ownership of our units by non-U.S. citizens could delay, defer or prevent a transaction or change in control that might involve a premium price for our common units or otherwise be in the best interest of our unitholders.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.  We have not requested, and do not plan to request, a ruling from the IRS with respect to our classification as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes.  Although we do not believe, based on our current operations, that we are or will be so treated, the IRS could disagree with the positions we take or a change in our business (or a change in current law) could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and we would likely pay additional state


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income taxes at varying rates.  Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to our unitholders.  Because tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced.  Therefore, treatment of us as a corporation for U.S. federal income tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing U.S. federal income tax laws that could affect the tax treatment of certain publicly traded partnerships.  We are unable to predict whether any of these changes or other proposals will ultimately be enacted.  

In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation.  For example, the Texas franchise tax is imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas.  If any additional state income taxes were imposed upon us as an entity, our cash available for distribution would be reduced. Any modification to the U.S. federal income or state tax laws, or interpretations thereof, may be applied retroactively and could negatively impact the value of an investment in our common units.

If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely affected and the cost of such contest will reduce our cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained.  It may be necessary to resort to administrative or court proceedings to sustain some or all of our the positions we take.  A court may not agree with some or all of the positions we take.  Any contest with the IRS, and the outcome of any IRS contest, may materially and adversely impact the market for our common units and the price at which they trade.  In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
Our common unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders are treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, they are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us.  Common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If a common unitholder sells common units, the common unitholder will recognize a gain or loss equal to the difference between the amount realized in the sale and that common unitholder’s adjusted tax basis in those common units.  Because distributions in excess of a common unitholder’s allocable share of our net taxable income decrease that unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income to that unitholder if the unitholder sells such common units at a price greater than that unitholder’s tax basis in those common units, even if the price received is less than the unitholder’s original cost.  Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture.  In addition, because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (IRAs), and non-U.S. persons raises issues unique to them.  For example, virtually all of our income allocated to unitholders who are organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.  Distributions to non-U.S. persons will be reduced by


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withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.  Tax-exempt entities and non-U.S. persons should consult their tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.  The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we treat each purchaser of our common units as having the same tax benefits with regard to the actual common units purchased and we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations.  A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.  The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

Our valuation methodologies may result in a shift of income, gain, loss and deduction between our general partner and the common unitholders.  The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our common unitholders and our general partner.  Our methodology may be viewed as understating the value of our assets.  In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders.  Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our common unitholders and our general partner.  It also could affect the amount of gain from our common unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our common unitholders’ or our general partner’s tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in a termination of our partnership for U.S. federal income tax purposes.

We will be considered to have technically terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period.  Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if certain relief were unavailable) for one fiscal year. The termination could result in a deferral of depreciation deductions allowable in computing our taxable income.  In the case of a common unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income being includable in the common unitholder’s taxable income for the year of termination.  Under current law, a technical termination would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, after our termination we would be treated as a new partnership for U.S. federal


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income tax purposes.  If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

The IRS has announced a publicly traded partnership technical relieve procedure, whereby, if a publicly traded partnership that has a technical termination requests and the IRS grants special relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year, notwithstanding two partnership tax years resulting from the technical terminations.

A common unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units.  If so, the common unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a common unitholder whose common units are loaned to a “short seller” to effect a short sale may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.  Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income.  Common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax adviser to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

The issuance of additional i-units may cause more taxable income and gain to be allocated to the common units.

The i-units we issue to KMR generally are not allocated income, gain, loss or deduction for U.S. federal income tax purposes until such time as we are liquidated.  Therefore, the issuance of additional i-units may cause more taxable income and gain to be allocated to the common unitholders.

As a result of investing in our common units, a common unitholder will likely be subject to state, local and non-U.S. taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, our common unitholders will likely be subject to other taxes, including state and local taxes, non-U.S. taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions.  Our common unitholders will likely be required to file state, local and non-U.S. income tax returns and pay state, local and non-U.S. income taxes in some or all of these various jurisdictions.  Further, our common unitholders may be subject to penalties for failure to comply with those requirements.  We currently own assets and conduct business in numerous states in the U.S. and in Canada.  It is the responsibility of each common unitholder to file all required U.S. federal, state, local and non-U.S. tax returns.

There is the potential for a change of control of our general partner if KMI defaults on debt.

KMI indirectly owns all the common stock of Kinder Morgan G.P., Inc., our general partner.  If KMI defaults on its debt, then the lenders under such debt, in exercising their rights as lenders, could acquire control of our general partner or otherwise influence our general partner through control of KMI.

Item 1B.  Unresolved Staff Comments.

None.

Item 3.  Legal Proceedings.

See Note 16 to our consolidated financial statements.



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Item 4.  Mine Safety Disclosures

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is in exhibit 95.1 to this annual report.


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PART II
 
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
 
The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported on the NYSE, the principal market in which our common units are traded, the amount of cash distributions declared per common and Class B unit, and the fractional i-unit distribution declared per i-unit.
 
Price Range
 
 
 
 
 
High
 
Low
 
Declared cash
distributions
for the quarter
 
Declared i-unit
distributions
for the quarter
2013
 
 
 
 
 
 
 
First Quarter
$
89.89

 
$
80.83

 
$
1.30

 
0.014770

Second Quarter
92.99

 
77.71

 
1.32

 
0.015704

Third Quarter
88.08

 
77.91

 
1.35

 
0.017610

Fourth Quarter
84.50

 
77.13

 
1.36

 
0.017841

2012
 
 
 
 
 
 
 
First Quarter
$
90.60

 
$
80.40

 
$
1.20

 
0.016044

Second Quarter
85.50

 
74.15

 
1.23

 
0.015541

Third Quarter
86.47

 
78.60

 
1.26

 
0.016263

Fourth Quarter
86.32

 
74.76

 
1.29

 
0.015676


Distribution information is for distributions declared for the respective quarter.  The declared distributions were paid within 45 days after the end of the quarter.

Our common units are traded on the NYSE under the symbol “KMP.” As of January 31, 2014, we had 1,485 unitholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank. Additionally, as of January 31, 2014, there was one holder of our Class B units and one holder of our i-units.

For information on our equity compensation plans, see Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Equity Compensation Plan Information” and Note 12 “Commitments and Contingent Liabilities—KMEP Common Unit Compensation Plan for Non-Employee Directors” to our consolidated financial statements.

We did not repurchase any units during the fourth quarter of 2013 or sell any unregistered units in the fourth quarter of 2013.

Item 6.  Selected Financial Data
 
The following tables set forth, for the periods and at the dates indicated, our summary historical financial and operating data.  The table is derived from our consolidated financial statements and notes thereto, and should be read in conjunction with those audited financial statements.  See also Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report for more information.


49


 
As of or for the year ended December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
 
(In millions, except per unit)
Income and Cash Flow Data:
 
 
 
 
 
 
 
 
 
Revenues  
$
12,530

 
$
9,035

 
$
7,889

 
$
7,739

 
$
6,697

Operating income  
3,229

 
2,484

 
1,557

 
1,460

 
1,367

Earnings from equity investments  
297

 
295

 
224

 
136

 
91

Income from continuing operations
3,321

 
2,070

 
1,067

 
1,092

 
1,036

(Loss) income from discontinued operations
(4
)
 
(669
)
 
201

 
235

 
248

Net income
3,317

 
1,401

 
1,268

 
1,327

 
1,284

Limited Partners’ interest in net income
1,565

 
(78
)
 
83

 
431

 
332

 
 
 
 
 
 
 
 
 
 
Limited Partners’ net income (loss) per unit:
 

 
 

 
 

 
 

 
 

Income (loss) per unit from continuing operations
$
3.77

 
$
1.64

 
$
(0.35
)
 
$
0.65

 
$
0.32

(Loss) income from discontinued operations
(0.01
)
 
(1.86
)
 
0.60

 
0.75

 
0.86

Net income (loss) per unit
$
3.76

 
$
(0.22
)
 
$
0.25

 
$
1.40

 
$
1.18

 
 
 
 
 
 
 
 
 
 
Per unit cash distribution declared for the period(a)
$
5.33

 
$
4.98

 
$
4.61

 
$
4.40

 
$
4.20

Per unit cash distribution paid in the period(a)
5.26

 
4.85

 
4.58

 
4.32

 
4.20

 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at end of period):
 

 
 

 
 

 
 

 
 

Net property, plant and  equipment  
$
27,405

 
$
22,330

 
$
15,596

 
$
14,604

 
$
14,154

Total assets  
42,764

 
34,976

 
24,103

 
21,861

 
20,262

Long-term debt(b)
18,410

 
15,907

 
11,183

 
10,301

 
10,022

____________
(a)
Distributions for the fourth quarter of each year are declared and paid during the first quarter of the following year.
(b)
Excludes debt fair value adjustments.  Increases to long-term debt for debt fair value adjustments totaled $1,214 million as of December 31, 2013, $1,698 million as of December 31, 2012, $1,055 million as of December 31, 2011, $582 million as of December 31, 2010 and $308 million as of December 31, 2009.

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto.  Additional sections in this report, which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2013, found in Items 1 and 2 “Business and Properties—(a) General Development of Business—Recent Developments;” and (iii) a description of risk factors affecting us and our business, found in Item 1A “Risk Factors.”

We prepared our consolidated financial statements in accordance with GAAP. Accordingly, as discussed in Notes 1, 2, and 3 to our consolidated financial statements, our financial statements reflect:

our August 1, 2012 and March 1, 2013 acquisitions from KMI as if such acquisitions had taken place on the effective dates of common control. We refer to these two separate transfers of net assets from KMI to us as the drop-down transactions, and we refer to the transferred assets as our drop-down asset groups. We accounted for the drop-down transactions as a combination of entities under common control, and accordingly, the financial information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations include the financial results of the drop-down asset groups for all periods subsequent to the effective dates of common control; and

the reclassifications necessary to reflect the results of our FTC Natural Gas Pipelines disposal group as discontinued operations. We sold our FTC Natural Gas Pipelines disposal group to Tallgrass effective November 1, 2012 for approximately $1.8 billion in cash (before selling costs), or $3.3 billion including our share of joint venture debt. In 2013, we and Tallgrass trued up the final consideration for the sale of our FTC Natural Gas Pipelines disposal group and based both on this true up and certain incremental selling expenses we paid in 2013, we recognized an additional $4 million loss related to our sale of the disposal group. Except for this loss amount, we recorded no other financial results from the operations of the disposal group during 2013. Furthermore, we have excluded the disposal group’s financial


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results from our Natural Gas Pipelines business segment disclosures for each of the years ended December 31, 2012 and 2011.

Inasmuch as the discussion below and the other sections to which we have referred you pertain to management’s comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements.  These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management’s judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties.  Our actual results could differ materially from those discussed in the forward-looking statements.  Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A “Risk Factors” and at the beginning of this report in “Information Regarding Forward-Looking Statements.”

General
 
Our business model, through our ownership and operation of energy related assets, is built to support two principal components:

helping customers by providing energy, bulk commodity and liquids products transportation, storage and distribution; and
creating long-term value for our unitholders.
 
To achieve these objectives, we focus on providing fee-based services to customers from a business portfolio consisting of energy-related pipelines, natural gas storage, processing and treating facilities, and bulk and liquids terminal facilities. We also produce and sell crude oil. Our reportable business segments are based on the way our management organizes our enterprise, and each of our business segments represents a component of our enterprise that engages in a separate business activity and for which discrete financial information is available.
 
Our reportable business segments are:
 
Natural Gas Pipelines—(i) the ownership and operation of major interstate and intrastate natural gas pipeline and storage systems; (ii) the ownership and/or operation of associated natural gas gathering systems and natural gas processing and treating facilities; and (iii) the ownership and/or operation of NGL fractionation facilities and transportation systems;
CO2(i) the production, transportation and marketing of CO2, to oil fields that use CO2 to increase production of oil; (ii) ownership interests in and/or operation of oil fields and gas processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas;
Products Pipelines—the ownership and operation of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;
Terminals—the ownership and/or operation of liquids and bulk terminal facilities and rail transloading and materials handling facilities located throughout the U.S. and portions of Canada; and
Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport.
 
As an energy infrastructure owner and operator in multiple facets of the U.S.’ and Canada’s various energy businesses and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future.
 
With respect to our interstate natural gas pipelines and related storage facilities, the revenues from these assets are primarily received under contracts with terms that are fixed for various and extended periods of time.  To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity.  These long-term contracts are typically structured with a fixed-fee reserving the right to transport natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity.  Similarly, in our Texas Intrastate Natural Gas Group, we currently derive approximately 75% of our sales and transport margins from long-term transport and sales contracts that include requirements with minimum volume payment obligations.  As contracts expire, we have additional exposure to the longer term trends in supply and demand for


51


natural gas.  As of December 31, 2013, the remaining average contract life of our natural gas transportation contracts (including our intrastate pipelines’ purchase and sales contracts) was approximately five and a half years.

During 2012 and 2013, we further expanded our midstream services through our (i) EP midstream asset operations, which we acquired 50% from KKR effective June 1, 2012, and 50% from KMI effective March 1, 2013 and (ii) our Copano operations, which included the remaining 50% ownership interest in Eagle Ford Gathering LLC that we did not already own and which was acquired effective May 1, 2013. These fee-based gathering, processing and fractionation assets, along with our financial strength and extensive pipeline transportation and storage assets, should provide an excellent platform to further grow our midstream services footprint.  The revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into their base components, are also affected by the volumes of natural gas made available to our systems, which are primarily driven by levels of natural gas drilling activity. Our midstream services are provided pursuant to a variety of arrangements, generally categorized (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, percent-of-index and keep-whole. Contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices.

Our CO2 sales and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2013, had a remaining average contract life of approximately ten years.  CO2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed.  Our recent contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price.  On a volume-weighted basis, for third-party contracts making deliveries in 2014, and utilizing the average oil price per barrel contained in our 2014 budget, approximately 69% of our contractual volumes are based on a fixed fee or floor price, and 31% fluctuate with the price of oil.  In the long-term, our success in this portion of the CO2 business segment is driven by the demand for CO2.  However, short-term changes in the demand for CO2 typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts.  In our CO2 segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add.  In that regard, our production during any period is an important measure.  In addition, the revenues we receive from our crude oil, NGL and CO2 sales are affected by the prices we realize from the sale of these products.  Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products.  In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil.  Our realized weighted average crude oil price per barrel, with all hedges allocated to oil, was $92.70 per barrel in 2013, $87.72 per barrel in 2012 and $69.73 per barrel in 2011.  Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $94.94 per barrel in 2013, $89.91 per barrel in 2012 and $92.61 per barrel in 2011.

The profitability of our refined petroleum products pipeline transportation business is generally driven by the volume of refined petroleum products that we transport and the prices we receive for our services.  Transportation volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored.  Demand for refined petroleum products tends to track in large measure demographic and economic growth, and with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable.  Because of that, we seek to own refined petroleum products pipelines located in, or that transport to, stable or growing markets and population centers.  The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index.

The factors impacting our Terminals business segment generally differ depending on whether the terminal is a liquids or bulk terminal, and in the case of a bulk terminal, the type of product being handled or stored.  As with our refined petroleum products pipeline transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored.  While we handle and store a large variety of products in our bulk terminals, the primary products are coal, petroleum coke, and steel.  For the most part, we have contracts for this business that have minimum volume guarantees and are volume based above the minimums.  Because these contracts are volume based above the minimums, our profitability from the bulk business can be sensitive to economic conditions.  Our liquids terminals business generally has longer-term contracts that require the customer to pay regardless of whether they use the capacity.  Thus, similar to our natural gas pipeline business, our liquids terminals business is less sensitive to short-term changes in supply and demand.  Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the length of the underlying service contracts (which on average is approximately four years), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time.  To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity.  In addition, weather-related factors such as hurricanes,


52


floods and droughts may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.

In our discussions of the operating results of individual businesses that follow (see “—Results of Operations” below), we generally identify the important fluctuations between periods that are attributable to acquisitions and dispositions separately from those that are attributable to businesses owned in both periods.  Continuing our history of making accretive acquisitions and economically advantageous expansions of existing businesses, in 2013, we invested approximately $3.5 billion for both strategic business acquisitions and expansions of existing assets (not including our March 1, 2013 drop-down transaction with KMI and our May 1, 2013 Copano acquisition).  Our capital investments have helped us to achieve compound annual growth rates in cash distributions to our limited partners of 7.0%, 6.6% and 5.8%, respectively, for the one-year, three-year and five-year periods ended December 31, 2013.

Thus, the amount that we are able to increase distributions to our unitholders will, to some extent, be a function of our ability to complete successful acquisitions and expansions.  We believe we will continue to have opportunities for expansion of our facilities in many markets, and we have budgeted approximately $3.6 billion for our 2014 capital expansion program (including small acquisitions and investment contributions, but excluding asset acquisitions from KMI).  We regularly consider and enter into discussions regarding potential acquisitions, including those from KMI or its affiliates, and we are currently contemplating potential acquisitions.

Based on our historical record and because there is continued demand for energy infrastructure in the areas we serve, we expect to continue to have such opportunities in the future, although the level of such opportunities is difficult to predict. While there are currently no other unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations. Furthermore, our ability to make accretive acquisitions is a function of the availability of suitable acquisition candidates at the right cost, and includes factors over which we have limited or no control.  Thus, we have no way to determine the number or size of accretive acquisition candidates in the future, or whether we will complete the acquisition of any such candidates.  Our ability to make accretive acquisitions or expand our assets is impacted by our ability to maintain adequate liquidity and to raise the necessary capital needed to fund such acquisitions.

In addition, a portion of our business portfolio (including our Kinder Morgan Canada business segment, the Canadian portion of our Cochin Pipeline, and our bulk and liquids terminal facilities located in Canada) uses the local Canadian dollar as the functional currency for its Canadian operations and enters into foreign currency-based transactions, both of which affect segment results due to the inherent variability in U.S. - Canadian dollar exchange rates.  To help understand our reported operating results, all of the following references to “foreign currency effects” or similar terms in this section represent our estimates of the changes in financial results, in U.S. dollars, resulting from fluctuations in the relative value of the Canadian dollar to the U.S. dollar.  The references are made to facilitate period-to-period comparisons of business performance and may not be comparable to similarly titled measures used by other registrants.

Critical Accounting Policies and Estimates
 
Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment.  Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared.  These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements.  We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances.  Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
 
In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining: (i) the economic useful lives of our assets and related depletion rates; (ii) the fair values used to assign purchase price from business combinations, determine possible asset impairment charges, and calculate the annual goodwill impairment test; (iii) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (iv) provisions for uncollectible accounts receivables; (v) exposures under contractual indemnifications; and (vi) unbilled revenues.
 


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For a summary of our significant accounting policies, see Note 2 to our consolidated financial statements.  We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows.
 
Environmental Matters
 
With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts.  We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs.  Generally, we do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination.
 
Our recording of our environmental accruals often coincides with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations.  These adjustments may result in increases in environmental expenses and are primarily related to quarterly reviews of potential environmental issues and resulting environmental liability estimates. In making these liability estimations, we consider the effect of environmental compliance, pending legal actions against us, and potential third party liability claims.  For more information on environmental matters, see Item 1(c).  For more information on our environmental disclosures, see Note 16 to our consolidated financial statements.
 
Legal Matters
 
Many of our operations are regulated by various U.S. and Canadian regulatory bodies and we are subject to legal and regulatory matters as a result of our business operations and transactions.  We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements.  In general, we expense legal costs as incurred.  When we identify contingent liabilities, we identify a range of possible costs expected to be required to resolve the matter.  Generally, if no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range.  Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.
 
As of December 31, 2013, our most significant ongoing legal matters involved our West Coast Products Pipelines and our Western Interstate Natural Gas Pipelines.  Transportation rates charged by certain of these pipeline systems are subject to proceedings at the FERC and the CPUC involving shipper challenges to the pipelines’ interstate and intrastate (California) rates, respectively.  For more information on our regulatory proceedings, see Note 16.
 
Intangible Assets
 
Intangible assets are those assets which provide future economic benefit but have no physical substance.  Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, and such assets are not to be amortized until their lives are determined to be finite.  Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value.  We evaluate our goodwill for impairment on May 31 of each year.  There were no impairment charges resulting from our May 31, 2013 impairment testing, and no event indicating an impairment has occurred subsequent to that date.  Furthermore, our analysis as of that date did not reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units is less than the carrying value of its net assets.  For more information on our goodwill, see Notes 2 and 7 to our consolidated financial statements.
 
Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets.  These intangible assets have definite lives, are being amortized in a systematic and rational manner over their estimated useful lives, and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets.  For more information on our amortizable intangibles, see Note 7 to our consolidated financial statements.
 


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Estimated Net Recoverable Quantities of Oil and Gas
 
We use the successful efforts method of accounting for our oil and gas producing activities.  The successful efforts method inherently relies on the estimation of proved reserves, both developed and undeveloped.  The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted or amortized into income, and the presentation of supplemental information on oil and gas producing activities.  The expected future cash flows to be generated by oil and gas producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of oil and gas.

Proved reserves are the estimated quantities of oil and gas that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change.  For more information on our ownership interests in the net quantities of proved oil and gas reserves and our measures of discounted future net cash flows from oil and gas reserves, please see “Supplemental Information on Oil and Gas Activities (Unaudited)”.

Hedging Activities
 
We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices and to balance our exposure to fixed and variable interest rates, and we believe that these hedges are generally effective in realizing these objectives.  According to the provisions of GAAP, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged, and any ineffective portion of the hedge gain or loss and any component excluded from the computation of the effectiveness of the derivative contract must be reported in earnings immediately. We may or may not apply hedge accounting to our derivative contracts depending on the circumstances. All of our derivative contracts are recorded at estimated fair value.

Since it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to unfavorable changes in commodity prices—a perfectly effective hedge—we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all.  But because the part of such hedging transactions that is not effective in offsetting undesired changes in commodity prices (the ineffective portion) is required to be recognized currently in earnings, our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.  For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations; accordingly, our financial statements may reflect some volatility due to these hedges.  For more information on our hedging activities, see Note 13 to our consolidated financial statements.

Results of Operations
 
Non-GAAP Measures

The non-GAAP financial measures of (i) distributable cash flow before certain items, both in the aggregate and per unit, and (ii) segment earnings before depreciation, depletion, and amortization (DD&A); amortization of excess cost of equity investments; and certain items, are presented below under “—Distributable Cash Flow” and “—Consolidated Earnings Results,” respectively. Certain items are items that are required by GAAP to be reflected in net income, but typically either do not have a cash impact, or by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically.

Our non-GAAP measures described below should not be considered as an alternative to GAAP net income or any other GAAP measure. Distributable cash flow before certain items, and segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider any of these non-GAAP measures in isolation or as a substitute for an analysis of our results as reported under GAAP. Because distributable cash flow before certain items excludes some but not all items that affect net income, and because distributable cash flow measures are defined differently by different companies in our industry, our distributable cash flow before certain items may not be comparable to distributable cash flow measures of other companies. Segment earnings before DD&A, amortization of excess cost of equity investments, and certain items, has similar limitations. Our management compensates for the limitations of these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.


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Distributable Cash Flow

Our partnership agreement requires us to distribute 100% of our available cash to our partners on a quarterly basis (available cash as defined in our partnership agreement generally consists of all our cash receipts, less cash disbursements and changes in reserves). For more information, see Note 11 to our consolidated financial statements. Distributable cash flow, sometimes referred to in this report as DCF, is an overall performance metric we use to estimate the ability of our assets to generate cash flows on an ongoing basis and as a measure of available cash. The following table discloses the calculation of our DCF for each of the years ended December 31, 2013, 2012 and 2011 (calculated before the combined effect from all of the 2013, 2012 and 2011 certain items disclosed in the footnotes to the tables below):
Distributable Cash Flow
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(In millions)
Net Income
$
3,317

 
$
1,401

 
$
1,268

(Less)/Add: Certain items and noncontrolling interests - combined (income)/expense(a)
(606
)
 
821

 
474

Net Income before certain items attributable to KMEP
2,711

 
2,222

 
1,742

Less: General Partner’s interest in Net Income before certain items(b)
(1,703
)
 
(1,412
)
 
(1,180
)
Limited Partners’ interest in Net Income before certain items
1,008

 
810

 
562

Depreciation, depletion and amortization(c)(e)
1,524

 
1,252

 
1,133

Book (cash) taxes paid, net
44

 
(2
)
 
27

Incremental contributions from equity investments in the Express Pipeline and Endeavor Gathering LLC
(5
)
 
3

 
15

Sustaining capital expenditures(d)(e)
(327
)
 
(285
)
 
(212
)
Distributable cash flow (DCF) before certain items
$
2,244

 
$
1,778

 
$
1,525

________
(a)
Equal to the combined effect from (i) all of the 2013, 2012 and 2011 certain items disclosed in the footnotes to the “—Results of Operations” table below, excluding footnote (g) (and described in more detail below in both our management discussion and analysis of segment results and “—Other”) and (ii) net income attributable to noncontrolling interests.
(b)
2013 amount includes a $75 million general partner incentive distribution waiver related to common units issued to finance our May 2013 Copano acquisition. 2013, 2012 and 2011 amounts also include reductions of $4 million, $26 million and $29 million, respectively, for waived general partner incentive distribution amounts related to common units issued to finance a portion of our July 2011 KinderHawk acquisition. In addition, our general partner has also agreed to waive incentive distribution amounts equal to (i) $120 million for 2014, $120 million for 2015, $110 million for 2016, and annual amounts thereafter decreasing by $5 million per year from the 2016 level to support the Copano acquisition and (ii) $13 million for 2014, $19 million for 2015 and $6 million for 2016 to support our APT and SCT acquisitions.
(c)
2013, 2012 and 2011 amounts include expense amounts of $87 million, $176 million and $171 million, respectively, for our proportionate share of the DD&A expenses of our unconsolidated joint ventures. 2012 and 2011 amounts also include expense amounts of $7 million and $27 million, respectively, from our FTC Natural Gas Pipelines disposal group. 2013 and 2012 amounts also exclude expense amounts of $19 million and $97 million, respectively, attributable to our drop-down asset groups for periods prior to our acquisition.
(d)
2013, 2012 and 2011 amounts include expenditures of $3 million, $19 million and $10 million, respectively, for our proportionate share of the sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput) of certain unconsolidated joint ventures.
(e)
In order to more closely track the cash distributions we receive from our unconsolidated joint ventures, our calculation of DCF (i) adds back our proportionate share of the DD&A expenses of certain joint ventures and (ii) subtracts our proportionate share of the sustaining expenditures (those capital expenditures which do not increase the capacity or throughput) of certain joint ventures.

Consolidated Earnings Results

With regard to our reportable business segments, we consider segment earnings before all depreciation, depletion and amortization expenses, and amortization of excess cost of equity investments, to be an important measure of our success in maximizing returns to our partners. This measure, sometimes referred to in this report as segment EBDA, is more fully defined in footnote (a) to the —Results of Operations” table below. We also use segment EBDA internally as a measure of profit and loss used for evaluating segment performance and for deciding how to allocate resources to our five reportable business segments. EBDA may not be comparable to measures used by other companies. Additionally, EBDA should be considered in conjunction with net income and other performance measures such as operating income, income from continuing operations or operating cash flows.


56



Results of Operations
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(In millions)
Segment EBDA(a)
 
 
 
 
 
Natural Gas Pipelines
$
2,977

 
$
1,562

 
$
546

CO2
1,435

 
1,322

 
1,099

Products Pipelines
602

 
670

 
463

Terminals
853

 
709

 
704

Kinder Morgan Canada
340

 
229

 
202

Segment EBDA(b)
6,207

 
4,492

 
3,014

 
 
 
 
 
 
DD&A expense(c)
(1,446
)
 
(1,159
)
 
(928
)
Amortization of excess cost of equity investments
(10
)
 
(7
)
 
(7
)
General and administrative expenses(d)
(560
)
 
(547
)
 
(473
)
Interest expense, net of unallocable interest income(e)
(860
)
 
(700
)
 
(531
)
Unallocable income tax expense
(10
)
 
(9
)
 
(8
)
Income from continuing operations
3,321

 
2,070

 
1,067

(Loss) income from discontinued operations(f)
(4
)
 
(669
)
 
201

Net income
3,317

 
1,401

 
1,268

Net income attributable to noncontrolling interests(g)
(36
)
 
(18
)
 
(10
)
Net income attributable to KMEP
$
3,281

 
$
1,383

 
$
1,258

____________
(a)
Includes revenues, earnings from equity investments, allocable interest income and other, net, less operating expenses, allocable income taxes, and other expense (income).  Operating expenses include natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)
2013, 2012 and 2011 amounts include an increase in earnings of $657 million, an increase in earnings of $275 million and a decrease in earnings of $387 million, respectively, related to the combined effect from all of the 2013, 2012 and 2011 certain items impacting continuing operations and disclosed below in our management discussion and analysis of segment results.
(c)
2013 and 2012 amounts include increases in expense of $19 million and $97 million, respectively, attributable to our drop-down asset groups for periods prior to our acquisition dates.
(d)
2013, 2012 and 2011 amounts include increases in expense of $49 million, $124 million and $94 million, respectively, related to the combined effect from all of the 2013, 2012 and 2011 certain items related to general and administrative expenses disclosed below in “—Other.”
(e)
2013 and 2012 amounts include increases in expense of $10 million and $68 million, respectively, related to the combined effect from all of the 2013 and 2012 certain items related to interest expense disclosed below in “—Other.”
(f)
Represents amounts attributable to our FTC Natural Gas Pipelines disposal group. 2013 amount represents an incremental loss related to the sale of our disposal group effective November 1, 2012. 2012 amount includes a combined $829 million loss from the remeasurement of net assets to fair value and the sale of our disposal group. 2011 amount includes a $10 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011. 2012 and 2011 amounts also include depreciation and amortization expenses of $7 million and $27 million, respectively.
(g)
2013, 2012 and 2011 amounts include an increase of $5 million, a decrease of $4 million and a decreases of $7 million, respectively, in net income attributable to our noncontrolling interests, related to the combined effect from all of the 2013, 2012 and 2011 certain items disclosed below in both our management discussion and analysis of segment results and “—Other.”

For the comparable years of 2013 and 2012, total segment EBDA increased $1,715 million (38%) in 2013; however, this overall increase:
included a $382 million increase in EBDA from the effect of the certain items described in footnote (b) to the “—Results of Operations” table above; and
excluded a $167 million decrease in EBDA from discontinued operations (as described in footnote (f) to the “—Results of Operations” table above).

After adjusting for these two items, the remaining $1,166 million (27%) increase in segment EBDA in 2013 versus 2012 resulted from higher earnings from our Natural Gas Pipelines, CO2, Products Pipelines and Terminals business segments. The


57


yearly increase in total segment EBDA was partially offset by a decrease in EBDA from our Kinder Morgan Canada business segment.
For the comparable years of 2012 and 2011, total segment EBDA increased $1,478 million (49%) in 2012; however, this overall increase:
included a $662 million increase in EBDA from the effect of the certain items described in footnote (b) to the “—Results of Operations” table above; and
excluded a $71 million decrease in EBDA from discontinued operations (as described in footnote (f) to the “—Results of Operations” table above).

After adjusting for these two items, the remaining $745 million (20%) increase in segment EBDA in 2012 versus 2011 resulted from higher earnings from all five of our reportable business segments, driven mainly by increases attributable to our Natural Gas Pipelines and CO2 business segments.
Natural Gas Pipelines
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(In millions, except operating statistics)
Revenues(a)
$
7,110

 
$
4,319

 
$
3,943

Operating expenses
(4,925
)
 
(2,946
)
 
(3,370
)
Other income (expense)
44

 
(1
)
 

Earnings from equity investments
181

 
186

 
140

Interest income and Other, net
576

 
8

 
(164
)
Income tax expense
(9
)
 
(4
)
 
(3
)
EBDA from continuing operations(b)
2,977

 
1,562

 
546

Discontinued operations(c)
(4
)
 
(662
)
 
228

EBDA including discontinued operations
$
2,973

 
$
900

 
$
774

 
 
 
 
 
 
Natural gas transport volumes (TBtu)(d)
5,738.3

 
5,875.0

 
5,285.2

Natural gas sales volumes (TBtu)(e)
897.3

 
879.1

 
804.7

Natural gas gathering volumes (BBtu/d)(f)
2,959.3

 
2,996.2

 
2,475.9

__________
(a)
2013 and 2012 amounts include increases of $111 million and $574 million, respectively, attributable to our drop-down asset groups for periods prior to our acquisition dates. 2013 amount also includes a $16 million decrease related to derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales.
(b)
2013, 2012 and 2011 amounts include a $641 million increase in earnings, a $355 million increase in earnings and a $167 million decrease in earnings, respectively, related to the combined effect from certain items. 2013 amount consists of (i) a $558 million gain from the remeasurement of our previously held 50% equity interest in Eagle Ford to fair value; (ii) a $62 million increase in earnings attributable to our drop-down asset groups for periods prior to our acquisition dates; (iii) a $36 million gain from the sale of certain Gulf Coast offshore and onshore TGP supply facilities; (iv) a $16 million decrease in earnings related to derivative contracts, as described in footnote (a); and (v) a combined $1 million increase from other certain items. 2012 amount consists of a $344 million increase in earnings attributable to our drop-down asset groups for periods prior to our acquisition dates, and a combined $11 million increase from other certain items. 2011 amount consists of a $167 million loss from the remeasurement of our previously held 50% equity interest in KinderHawk to fair value.
(c)
Represents EBDA attributable to our FTC Natural Gas Pipelines disposal group.  2013 amount represents a loss from the sale of net assets. 2012 amount includes a combined loss of $829 million from the remeasurement of net assets to fair value and the sale of net assets. 2011 amount includes a $10 million increase in expense from the write-off of a receivable for fuel under-collected prior to 2011.  2012 and 2011 amounts also include revenues of $227 million and $322 million, respectively.
(d)
Includes pipeline volumes for TransColorado Gas Transmission Company LLC, Midcontinent Express Pipeline LLC, Kinder Morgan Louisiana Pipeline LLC, Fayetteville Express Pipeline LLC, TGP, EPNG, Copano South Texas and the Texas intrastate natural gas pipeline group. Volumes for acquired pipelines are included for all periods.
(e)
Represents volumes for the Texas intrastate natural gas pipeline group.
(f)
Includes Copano operations, EP midstream assets operations, KinderHawk, Endeavor, Bighorn Gas Gathering, L.L.C., Webb Duval Gatherers, Fort Union Gas Gathering L.L.C., EagleHawk, and Red Cedar Gathering Company throughput volumes. Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included for all periods.



58


The certain items described in the footnotes to the table above accounted for a $1,111 million increase in our Natural Gas Pipelines business segment’s EBDA (including discontinued operations) in 2013, and a $297 million decrease in segment EBDA in 2012, when compared to the respective prior year. The certain items also accounted for a $479 million decrease in segment revenues (including discontinued operations) in 2013, and a $574 million increase in segment revenues in 2012, when compared to the respective prior year. Following is information, including discontinued operations, related to the segment’s remaining (i) $962 million (70%) and $423 million (44%) increases in EBDA and (ii) $3,043 million (77%) increase and $293 million (7%) decrease in revenues in 2013 and 2012, when compared with the respective prior year:

Year Ended December 31, 2013 versus Year Ended December 31, 2012
 
EBDA
increase/(decrease)
 
Revenues
increase/(decrease)
 
(In millions, except percentages)
TGP
$
494

 
n/a

 
$
621

 
n/a

EPNG
284

 
n/a

 
434

 
n/a

Copano operations (excluding Eagle Ford)
233

 
n/a

 
1,119

 
n/a

EP midstream asset operations
63

 
n/a

 
147

 
n/a

Eagle Ford(a)
56

 
166
 %
 
419

 
n/a

Texas Intrastate Natural Gas Pipeline Group
16

 
5
 %
 
874

 
31
 %
KinderHawk Field Services
13

 
8
 %
 
9

 
5
 %
Kinder Morgan Treating operations
(26
)
 
(32
)%
 
(47
)
 
(30
)%
All others (including eliminations)
(4
)
 
(2
)%
 
(306
)
 
(263
)%
Total Natural Gas Pipelines-continuing operations
1,129

 
93
 %
 
3,270

 
87
 %
Discontinued operations(b)
(167
)
 
(100
)%
 
(227
)
 
(100
)%
Total Natural Gas Pipelines-including discontinued operations
$
962

 
70
 %
 
$
3,043

 
77
 %
__________
n/a - not applicable
(a)
Equity investment until May 1, 2013.  On that date, as part of our Copano acquisition, we acquired the remaining 50% ownership interest that we did not already own. Prior to that date, we recorded earnings under the equity method of accounting, but we received distributions in amounts essentially equal to equity earnings plus our share of depreciation and amortization expenses less our share of sustaining capital expenditures (those capital expenditures which do not increase the capacity or throughput).
(b)
Represents amounts attributable to our FTC Natural Gas Pipelines disposal group.

The significant increases and decreases in our Natural Gas Pipelines business segment’s EBDA in the comparable years of 2013 and 2012 included the following:
incremental earnings of $494 million from TGP, which we acquired from KMI effective August 1, 2012;
incremental earnings of $284 million from EPNG, which we acquired 50% from KMI effective August 1, 2012, and 50% from KMI effective March 1, 2013;
incremental earnings of $233 million from our Copano operations, which we acquired effective May 1, 2013 (but excluding Copano’s 50% ownership interest in Eagle Ford, which is included below with the 50% ownership interest we previously owned);
incremental earnings of $63 million from our EP midstream assets, which we acquired 50% from KKR effective June 1, 2012, and 50% from KMI effective March 1, 2013;
incremental earnings of $56 million (166%) from our now wholly-owned Eagle Ford natural gas gathering operations, due primarily to the incremental 50% ownership interest we acquired as part of our acquisition of Copano effective May 1, 2013, and partly to higher natural gas gathering volumes from the Eagle Ford shale formation;
a $16 million (5%) increase from our Texas intrastate natural gas pipeline group, due largely to higher transport margins (primarily related to higher transportation volumes from the Eagle Ford shale formation in south Texas) and lower pipeline maintenance expenses (due to both higher pipeline integrity maintenance and unexpected well repair expenses incurred in the last half of 2012), but partially offset by both lower storage margins (due mainly to timing differences on storage settlements) and lower natural gas processing margins (due mainly to lower NGL prices). The growth in revenues across both comparable years reflect higher natural gas sales revenues, driven by higher natural gas sales volumes in 2013 versus 2012. However, because our intrastate group both purchases and sells significant volumes of natural gas, and because the group generally sells natural gas in the same price environment in which it is purchased, the increases in its natural gas sales revenues were largely offset by corresponding increases in its natural gas purchase costs;


59


incremental earnings of $13 million (8%) increase from KinderHawk Field Services, driven by increased CO2 treating fees, increased gathering rates and increased minimum volume commitments, partly offset by lower throughput volumes; and
a $26 million (32%) decrease from our natural gas treating operations, primarily due to lower sales volumes and margins from treating equipment manufacturing.