10-K 1 kmi-2014x10k.htm 10-K KMI-2014-10K
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, 2014
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: 001-35081
Kinder Morgan, Inc.
(Exact name of registrant as specified in its charter) 
Delaware
 
80-0682103
(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
Class P Common Stock
New York Stock Exchange
Warrants to Purchase Class P Common Stock
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 of 1933.  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 Securities Exchange Act of 1934.  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.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Large accelerated filer þ  Accelerated filer o  Non-accelerated filer o  Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). 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 30, 2014 was approximately $24,279,037,627.  As of February 2, 2015, the registrant had 2,130,052,022 Class P shares outstanding.



KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS

 
 
Page
Number
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CO2
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 

2


KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS (continued)

 
 
 
 
 
  
 
  
 
 
  
 
 

3


KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY

Company Abbreviations

BOSTCO
=
Battleground Oil Specialty Terminal Company LLC
KMCO2
=
Kinder Morgan CO2 Company, L.P.
Calnev
=
Calnev Pipe Line LLC
KMEP
=
Kinder Morgan Energy Partners, L.P.
CIG
=
Colorado Interstate Gas Company, L.L.C.
KMGP
=
Kinder Morgan G.P., Inc.
Copano
=
Copano Energy, L.L.C.
KMI
=
Kinder Morgan Inc. and its majority-owned and/or
CPG
=
Cheyenne Plains Gas Pipeline Company, L.L.C.
 
 
controlled subsidiaries
El Paso
=
El Paso Holdco LLC
KMP
=
Kinder Morgan Energy Partners, L.P. and its
Elba Express
=
Elba Express Company, L.L.C.
 
 
majority-owned and controlled subsidiaries
ELC
=
Elba Liquefaction Company, L.L.C.
KMR
=
Kinder Morgan Management, LLC
EP
=
El Paso Corporation and its its majority-owned and
MEP
=
Midcontinent Express Pipeline LLC
 
 
controlled subsidiaries
NGPL
=
Natural Gas Pipeline Company of America LLC
EPB
=
El Paso Pipeline Partners, L.P. and its majority-
SFPP
=
SFPP, L.P.
 
 
owned and controlled subsidiaries
SLC
=
Southern Liquefaction Company, L.L.C.
EPNG
=
El Paso Natural Gas Company, L.L.C.
SLNG
=
Southern LNG Company, L.L.C.
EPPOC
=
El Paso Pipeline Partners Operating Company,
SNG
=
Southern Natural Gas Company, L.L.C.
 
 
L.L.C.
TGP
=
Tennessee Gas Pipeline Company, L.L.C.
FEP
=
Fayetteville Express Pipeline LLC
WIC
=
Wyoming Interstate Company, L.L.C.
KinderHawk
=
KinderHawk Field Services LLC
WYCO
=
WYCO Development L.L.C.
 
 
 
 
 
 
Unless the context otherwise requires, references to “we,” “us,” or “our,” are intended to mean Kinder Morgan, Inc. and its its majority-owned and/or controlled subsidiaries.
 
 
 
 
 
 
Common Industry and Other Terms
AFUDC
=
allowance for funds used during construction
LIBOR
=
London Interbank Offered Rate
BBtu/d
=
billion British Thermal Units per day
LLC
=
limited liability company
Bcf/d
=
billion cubic feet per day
LNG
=
liquefied natural gas
CERCLA
=
Comprehensive Environmental Response,
MBbl/d
=
thousands of barrels per day
 
 
Compensation and Liability Act
MDth/d
=
thousand of dekatherm per day
CO2
=
carbon dioxide or our CO2 business segment
MLP
=
master limited partnership
CPUC
=
California Public Utilities Commission
MMBbl/d
=
millions barrels per day
DCF
=
distributable cash flow
MMcf/d
=
million cubic feet per day
DD&A
=
depreciation, depletion and amortization
NEB
=
National Energy Board
DGCL
=
General Corporation Law of the state of Delaware
NGL
=
natural gas liquids
Dth
=
dekatherm
NYMEX
=
New York Mercantile Exchange
EBDA
=
earnings before depreciation, depletion and
NYSE
=
New York Stock Exchange
 
 
amortization expenses, including amortization of
OTC
=
over-the-counter
 
 
excess cost of equity investments
PHMSA
=
United States Department of Transportation
EPA
=
United States Environmental Protection Agency
 
 
Pipeline and Hazardous Materials Safety
FASB
=
Financial Accounting Standards Board
 
 
Administration
FERC
=
Federal Energy Regulatory Commission
SEC
=
United States Securities and Exchange
FTC
=
Federal Trade Commission
 
 
Commission
GAAP
=
United States Generally Accepted Accounting
TBtu
=
trillion British Thermal Units
 
 
Principles
WTI
=
West Texas Intermediate
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.


4


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 service debt or to pay dividends 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 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;


5


our ability to offer and sell 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 and our subsidiaries 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 “Litigation, Environmental and Other” 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—(a) General Development of Business—Recent Developments—2015 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.

PART I
Items 1 and 2. Business and Properties.
We are the largest energy infrastructure and the third largest energy company in North America with an enterprise value of more than $125 billion. We own an interest in or operate approximately 80,000 miles of pipelines and 180 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals transload and 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, which is utilized for enhanced oil recovery projects in North America. Our common stock trades on the NYSE under the symbol “KMI.”


6


(a) General Development of Business
 
Organizational Structure
   
On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of Kinder Morgan Energy Partners, L.P. (NYSE: KMP) and El Paso Pipeline Partners, L.P. (NYSE: EPB) and all of the outstanding shares of Kinder Morgan Management, LLC (NYSE: KMR) that we did not already own. The transactions, valued at approximately $77 billion, are referred to collectively as the “Merger Transactions.”

Upon completion of the Merger Transactions: (i) each publicly held KMR share received 2.4849 shares of KMI common stock; (ii) through the election and proration mechanisms in the KMP merger agreement, on average, each common unit held by a public KMP unitholder received 2.1931 shares of KMI common stock and $10.77 in cash; and (iii) through the election and proration mechanisms in the EPB merger agreement, on average, each common unit held by a public EPB unitholder received 0.9451 shares of KMI common stock and $4.65 in cash. The cash payments to the public unitholders of KMP and EPB totaled approximately $3.9 billion.

As we controlled each of KMP, KMR and EPB and continued to control each of them after the Merger Transactions, the changes in our ownership interest in each of KMP, KMR and EPB were accounted for as an equity transaction and no gain or loss was recognized in our consolidated statements of income resulting from the Merger Transactions. After closing the KMR Merger Transaction, KMR was merged with and into KMI.

Additionally, on January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP and were dissolved. As a result of such merger, all of the subsidiaries of EPB and EPPOC are wholly owned subsidiaries of KMP.

Prior to November 26, 2014, we owned an approximate 10% limited partner interest (including our interest in KMR) and the 2% general partner interest including incentive distribution rights in KMP, and an approximate 39% limited partner interest and the 2% general partner interest and incentive distribution rights in EPB. Effective with the Merger Transactions, the incentive distribution rights held by the general partner of KMP was eliminated.

Historically, most of our operating assets were owned and most of our investments were conducted by KMP and EPB.

The equity interests in KMP, EPB and KMR (which are all consolidated in our financial statements) owned by the public prior to November 26, 2014 are reflected within “Noncontrolling interests” in our accompanying December 31, 2013 consolidated balance sheet. The earnings recorded by KMP, EPB and KMR that are attributed to their units and shares, respectively, held by the public prior to November 26, 2014 are reported as “Net income attributable to noncontrolling interests” in our accompanying consolidated statements of income.

You should read the following in conjunction with our audited consolidated financial statements and the notes thereto. 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. Our consolidated financial statements include our accounts and those of our majority-owned and/or controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. 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.

Recent Developments

The following is a brief listing of significant developments and updates related to our major projects since December 31, 2013. Additional information regarding most of these items may be found elsewhere in this report. “Capital Scope” is estimated for our share of the entire project which may include portions not yet completed.

7


Asset or project
 
Description
 
Activity
 
Capital Scope
Natural Gas Pipelines - Placed in service or acquisitions
Hiland Partners
 
Assets consist of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily serving production from the Bakken Formation in North Dakota and Montana. 
 
Acquired February 2015.
 
$3.0
billion
DK Expansion
 
Construction of the second of two 400,000 Mcf/d cryogenic unit expansions and compression to support volume growth in the Eagle Ford shale.
 
Plant placed in service third quarter 2014. Compression placed in service fourth quarter 2014.
 
$236 million
TGP Utica Backhaul
 
Expansion project that provides 500,000 Dth/d incremental natural gas transportation capacity, from Utica south to the Tennessee Zone 1 area.
 
Placed in service April 2014.
 
$175 million
KM Texas and Mier-Monterrey pipelines expansion
 
Expansion project provides 150,000 Dth/d of service to PEMEX Gas y Petroquímica Básica on an interim basis and is part of a larger project that is supported by three customers in Mexico that entered into long-term firm transportation contracts.
 
First portion placed in service September and December 2014, expected second phase in service 2016.
 
$105 million
Keystone Storage
 
Multi-cycle gas storage facility in West Texas near the WAHA Hub that connects to EPNG and two other interstate pipelines and has 8.5 Bcf of total storage capacity.
 
Acquired July 2014.
 
$92
million
TGP Rose Lake
 
Located in northeastern Pennsylvania, fully subscribed for 10-year terms by South Jersey Resources and Statoil and provides an additional 230,000 Dth/d per day of capacity.
 
Placed in service November 2014.
 
$74
million
Sierrita Gas Pipeline
 
The 60-mile pipeline provides 200 MMcf/d of capacity and extends from near Tucson to the U.S.-Mexico border near Sasabe, Arizona.
 
Placed in service October 2014.
 
$66
million
Natural Gas Pipelines - Other announcements
TGP Northeast Energy Direct
 
Development of a 171-mile supply path that will extend from the Marcellus supply area in Pennsylvania to a point near Wright, New York, the market path will consist of 188 miles of mainline from Wright to Dracut, Massachusetts.
 
Expected in service November 2018.
 
$4.5 to
$5.5
billion
Elba Liquefaction
 
Building of new natural gas liquefaction and export facilities at our SLNG natural gas terminal on Elba Island, near Savannah, Ga., with a total capacity of 2.5 million tonnes per year of LNG, equivalent to 350 MMcf/d of natural gas.
 
Planning and engineering activities continue, expected full in service 2018.
 
$1.3
billion
TGP Broad Run Flexibility and Broad Run Expansion
 
Modification to existing pipelines to create 790,000 Dth/d of north-to-south gas transportation capacity from a receipt point in West Virginia to delivery points in Mississippi and Louisiana.
 
Final facility design, expected in service November 2015 and November 2017.
 
$751 million
EPNG upstream Sierrita
 
Expansion projects to provide 550,000 Dth/d firm natural gas transport capacity, which involves a first phase of system improvements to deliver volumes to the Sierrita Pipeline, and the second phase that will result in incremental deliveries of natural gas to Arizona and California.
 
Phase one placed in service October 2014, phase two expected fully in service October 2020.
 
$529 million
Elba Express Company and SNG expansion
 
Expansion project that provides 854,000 Dth/d incremental natural gas transportation service supporting the needs of customers in Georgia, South Carolina and northern Florida, and also serving Elba Liquefaction.
 
Expected in service 2016 (first phase) and 2017.
 
$282 million
TGP South System Flexibility
 
Expansion project that provides more than 900 miles of north-to-south transportation capacity of 500,000 Dth/d on our TGP system from Tennessee to South Texas and expands our transportation service to Mexico.
 
Initial volume placed into service January 2015, with the remainder expected December 2016.
 
$187 million
Texas Intrastate SK Freeport LNG
 
Entered into a 20-year firm transportation services agreement with SK E&S LNG, LLC in December 2014. We will provide more than 320,000 Dth/d of firm natural gas transportation services.
 
Completion expected third quarter 2019.
 
$153 million
KMLP Magnolia LNG Liquefaction Transport
 
Upgrades to this existing pipeline system to provide 700,000 Dth/d capacity to serve Magnolia LNG in the Lake Charles, La., area.
 
Precedent agreement executed. Expected in service third quarter 2018.
 
$143 million


8


Asset or project
 
Description
 
Activity
 
Capital Scope
Natural Gas Pipelines - Other announcements continued
TGP Susquehanna West
 
Expansion project that provides 145,000 Dth/d incremental natural gas transportation capacity, serving the northeast Marcellus to points of liquidity.
 
Capacity awarded. Precedent agreement executed. Expected in service November 2017.
 
$143 million
TGP Cameron LNG
 
Compressor station modifications and new pipeline laterals for enhanced supply access to the Perryville Hub, for a capacity of 900,000 Dth/d.
 
Precedent agreements executed. Expected in service fourth quarter 2018.
 
$138 million
TGP Marcellus to Milford
 
An expansion project to provide additional firm capacity from the Marcellus supply basin to TGP’s interconnection with Columbia Gas Transmission in Pike County, Pennsylvania. The capacity of this expansion will be at least 135,000 Dth/d.
 
Precedent agreements executed. Expected in service June 2018.
 
$129 million
TGP Lone Star
 
Two greenfield compressor stations to provide supply to the Corpus Christi LNG liquefaction project, for a capacity of 300,000 Dth/d.
 
Capacity awarded. Precedent agreement executed. Expected in service July 2019.
 
$123 million
TGP Connecticut Expansion
 
Expansion project that provides 72,100 Dth/d incremental natural gas transportation capacity, serving the New England market.
 
Precedent agreements executed. Expected in service November 2016.
 
$82
million
Texas Intrastate Cheniere Corpus Christi
LNG
 
Project provides 250,000 Dth/d of firm natural gas transportation service, as well as 3 Bcf of natural gas storage capacity, to serve the LNG export facility.
Entered into 15-year firm transportation and multi-year storage agreements with Cheniere Energy, through its subsidiary, Corpus Christi Liquefaction.
 
Agreements signed December 2014. Startup expected fourth quarter 2018.
 
$77
million
CO2 - Placed in service
Yellow Jacket Central Facility expansion
 
A booster compression project at the McElmo Dome source field in southwestern Colorado that will increase CO2 production by up to 90 MMcf/d.
 
Placed in service September 2014.
 
$214 million
CO2 - Other announcements
St. Johns Development
 
Developing an additional 300 MMcf/d and building a new pipeline (Lobos) to transport CO2 from our St. Johns source field in Apache County, Arizona.
 
Expected in service 2018.
 
$982 million
Cow Canyon development
 
An expansion project that will increase CO2 production in the Cow Canyon area of the McElmo Dome source field by 200 MMcf/d.
 
Expected full in service fourth quarter 2015.
 
$344 million
Cortez Pipeline expansion - phase 1
 
Project will increase capacity from 1.35 Bcf/d to 1.7 Bcf/d on this existing pipeline. This pipeline will transport CO2 from southwestern Colorado to eastern New Mexico and west Texas for use in enhanced oil recovery projects.
 
Expected full in service fourth quarter 2015.
 
$233 million
Terminals - Placed in service or acquisitions
American Petroleum Tankers and State Class Tankers
 
Purchase of five on-the-water Jones Act tankers, each operating pursuant to long-term time charters with high quality counterparties, and assumption of a contract to receive four more tankers currently under construction, which will be operated pursuant to long-term time charters with a major integrated oil company.
 
Acquired January 2014.
 
$961 million
Edmonton Terminal expansion—Phases 1 and 2
 
A two-phase expansion project that adds 4.6 million barrels of storage capacity to our Edmonton terminal for crude oil and refined petroleum products, supported by long-term contracts with major producers and refiners.
 
Placed in service first quarter 2014 (phase 1) and fourth quarter 2014 (phase 2).
 
$402 million
BOSTCO expansion—Phases 1 and 2
 
A two-phase greenfield joint venture terminal development that adds 7.1 million barrels of distillate, residual fuel and other black oil product storage at the Houston Ship Channel site, fully subscribed and supported by long-term contracts with major oil companies.
 
Placed in service second quarter 2014 (phase 1) and third quarter 2014 (phase 2).
 
$305 million
Pennsylvania and Florida Jones Act Tankers
 
Purchase from Crowley Maritime of two Jones Act tankers, engaging in the marine transportation of crude oil, condensate, and refined products in the U.S, both supported by long-term time charters with major shippers.
 
Acquired November 2014.
 
$270 million



9


Asset or project
 
Description
 
Activity
 
Capital Scope
Terminals - Placed in service or acquisitions continued
Deepwater Coal Handling (Deer Park, TX)
 
Expansion project at our multi-purpose Deepwater Terminal along the Houston Ship Channel adds 10 million tons per year of coal export capacity secured by long-term take-or-pay volume commitments.
 
Construction completed third quarter of 2014.
 
$184 million
Lousiana Chemical Tankage Expansion
 
In two separate projects added additional chemical storage to our Harvey, LA terminal and storage and various marine, truck, and rail infrastructure improvements in support of Methanex Corporation's relocated production plant.
 
Construction completed second half of 2014.
 
$85
million
International Marine Terminal Phase 3
 
Phase 3 expansion at the joint venture International Marine Terminal in Louisiana adds additional export coal capacity supported by long-term take-or-pay volume commitments.
 
Construction completed first quarter of 2014.
 
$64
million
Terminals - Other announcements
Edmonton Rail Terminal
 
Announced expansion increases capacity to over 210,000 bpd at the joint venture crude rail terminal in Edmonton. The facility, supported by long-term customer contracts, will be connected via pipeline to the Trans Mountain pipeline and be capable of sourcing all crude streams handled by Kinder Morgan for delivery by rail to North American markets and refineries.
 
Expected in service first quarter 2015.
 
$249 million
Pasadena and Galena Park Infrastructure Improvements and Greensport Ship Dock 2
 
Construction of 2.1 million barrels of storage between the Pasadena and Galena Park terminals, a new ship dock, and various other infrastructure improvements providing enhanced product export capabilities, supported by long-term customer contracts.
 
Phase into service in 2016 and 2017.
 
$238 million
Houston Export Terminal
 
Brownfield expansion along Houston Ship Channel will add 1.5 million barrels of liquids storage capacity and a new ship dock that will handle ocean going vessels, supported by a long-term contract with a major ship channel refiner.
 
Expected in service first quarter 2017.
 
$172 million
Royal Vopak U.S. Terminal acquisition
 
Announced purchase of three U.S. Terminals and one undeveloped site.
 
Expected acquisition close first quarter 2015.
 
$158 million
Galena Park Tank Project and Pasadena Barge Dock
 
Construction of nine storage tanks with total shell capacity of 1.2 million barrels and a new barge dock at Pasadena, supported by long-term customer contracts.
 
Final three tanks expected in service first quarter 2015; barge dock expected in service fourth quarter 2015.
 
$124 million
Products Pipelines - Placed in service
Cochin Reversal project
 
Conversion of the line to northbound condensate service to serve oilsands producers’ needs in western Canada, supported by long-term customer contracts.
 
In service July 2014.
 
$301 million
KM Crude & Condensate Helena Extension
 
Constructed 30 miles of new pipeline from Helena to Dewitt, the Helena pump station, two new tanks and a four lane truck offload system, supported by long-term customer contracts.
 
In service September 2014.
 
$99
million
Products Pipelines - Other announcements
Palmetto Pipeline
 
Construction of new pipeline, underpinned by long-term customer contracts, to move gasoline, diesel and ethanol from Louisiana, Mississippi and South Carolina to points in South Carolina, Georgia and Florida.
 
Close of successful binding open season November 2014, expected in service July 2017.
 
$778
million
Cochin Utopia East
 
Building of new 240 mile pipeline, supported by long-term customer contracts, to transport ethane and ethane-propane mixtures from the prolific Utica Shale, with an initial design capacity of 50,000 bpd, expandable to more than 75,000 bpd.
 
Work continues, expected in service January 2018.
 
$507 million
KM Condensate Processing Facility
 
Project includes building two separate units to split condensate into various components and construct storage tanks totaling almost 2 million barrels to support the processing operation, supported by long-term customer contracts.
 
Construction continues, expected in service March 2015 (phase 1) and July 2015 (phase 2).
 
$383 million
KM Crude and Condensate Pipeline/ Double Eagle Pipeline
 
Project will provide transportation of Eagle Ford crude and condensate to the Houston Ship Channel.
 
Continues to see strong interest, expected in service second quarter 2015.
 
$235 million

10


Asset or project
 
Description
 
Activity
 
Capital Scope
Products Pipelines - Other announcements continued
Utica Marcellus Texas Pipeline
 
Project involves the abandonment and conversion of over 1,000 miles of natural gas service on TGP, the construction of approximately 200 miles of new pipeline from Louisiana to Texas and 155 miles of new laterals in Pennsylvania, Ohio and West Virginia.
 
Pending customer commitments, expected in service 2018.
 
still developing
Kinder Morgan Canada
Trans Mountain Expansion Project
 
An increase of capacity on our Trans Mountain pipeline system from approximately 300,000 to 890,000 barrels per day, underpinned by long-term take-or-pay contracts.
 
Currently engaged in final approval process with the NEB, expected in service third quarter 2018.
 
$5.4
billion
_______

Financings

For information about our 2014 debt offerings and retirements, see Note 8 “Debt” to our consolidated financial statements. For information about our 2014 equity offerings, see Note 10 “Stockholders’ Equity­­—Non-Controlling Interests—Contributions” to our consolidated financial statements.

2015 Outlook

We expect to declare dividends of $2.00 per share for 2015, a 15% increase over our 2014 declared dividend of $1.74 per share. Growth in 2015 cash dividends is expected to be driven by continued high demand for North American energy infrastructure, including the transportation and storage of natural gas, NGL, crude oil and refined products. Additionally, growth is expected to be driven by contributions from our expansion projects across our business units.
We expect that a full-year of contributions from our 2014 acquisitions and expansions, including cash tax benefits from the Merger Transactions, along with partial-year contributions from our anticipated 2015 expansion investments, as described above under —Recent Developments, will help drive earnings and cash flow growth in 2015 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. 
The overwhelming majority of cash generated by our assets is fee-based and is not sensitive to commodity prices.  We do have some commodity price sensitivity, primarily in our CO2 segment, and hedge the majority of our next twelve months of oil production to minimize this sensitivity.  For 2015, we estimate that every $1 per barrel change in average WTI crude oil price impacts distributable cash flow by approximately $10 million (budget assumes average WTI price of $70 per barrel), and each $0.10 per MMBtu change in the average price of natural gas impacts distributable cash flow by approximately $3 million (budget assumes average natural gas price of $3.80 per MMBtu).  This assumes we do not add additional hedges during the year which could reduce these sensitivities.  These sensitivities compare to total anticipated segment earnings before DD&A in 2015 of approximately $8 billion (adding back our share of joint venture DD&A).
In addition, our expectations for 2015 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 2015 expectations when we believe previously disclosed expectations no longer have a reasonable basis.
(b) Financial Information about Segments
For financial information on our six reportable business segments, see Note 15 “Reportable Segments” to our consolidated financial statements.


11


(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
maintain a strong balance sheet and return value to our stockholders.

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 and are currently contemplating potential acquisitions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, receipt of fairness opinions, and approval of our board of directors, if applicable. 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 operate the following reportable business segments. These segments and their principal sources of revenues are as follows:
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 and crude oil 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 as a flooding medium for recovering crude oil from mature oil fields to increase production; (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;
Terminals—(i) 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 that transload and store refined petroleum products, crude oil, condensate, and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals and (ii) the ownership and operation of our Jones Act tankers;
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;
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; and
Other—primarily includes other miscellaneous assets and liabilities purchased in our 2012 EP acquisition including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with EP’s legacy trading activities; and (iii) other miscellaneous EP assets and liabilities.

Natural Gas Pipelines
Our Natural Gas Pipelines segment includes interstate and intrastate pipelines and our LNG terminals, and includes both FERC regulated and non-FERC regulated assets.

12


Our primary businesses in this segment consist of natural gas sales, transportation, storage, gathering, processing and treating, and the terminaling of LNG.  Within this segment, are: (i) approximately 48,000 miles of natural gas pipelines and (ii) our equity interests in entities that have approximately 19,000 miles of natural gas pipelines, along with associated storage and supply lines for these transportation networks, which are strategically located throughout the North American natural gas pipeline grid.  Our transportation network provides access to the major natural gas supply areas and consumers in the western U.S., Louisiana, Texas, the Midwest, Northeast, Rocky Mountain, Midwest and Southeastern regions. Our LNG storage and regasification terminals also serve natural gas supply areas in the southeast. The following tables summarize our significant Natural Gas Pipelines segment assets, as of December 31, 2014. The Design Capacity represents either transmission or gathering capacity depending on the nature of the asset.
 
 Ownership
Interest %
 
 Miles
of
Pipeline
 
Design (Bcf/d) [Storage (Bcf)] Capacity
 
Supply and Market Region
Natural Gas Pipelines
TGP
100
 
11,900

 
9.00
[97]
 
South Texas and Gulf of Mexico to northeast and southeast U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale formations
EPNG/Mojave pipeline system
100
 
10,700

 
5.65
[44]
 
Northern New Mexico, Texas, Oklahoma, to California, connects to San Juan, Permian, and Anadarko basins
NGPL
20
 
9,200

 
6.20
[288]
 
Chicago and other Midwest markets and all central U.S. supply basins
SNG
100
 
6,900

 
3.90
[68]
 
Texas, Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee; basins in Texas, Louisiana, Mississippi and Alabama
Florida Gas Transmission (Citrus)
50
 
5,300

 
3.60
 
Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico
CIG
100
 
4,300

 
5.20
[43]
 
Colorado and Wyoming; Rocky Mountains and the Anadarko Basin
WIC
100
 
850

 
3.90
 
Wyoming, Colorado, and Utah; Overthrust, Piceance, Uinta, Powder River and Green River Basins
Ruby pipeline
50
 
680

 
1.50
 
Wyoming to Oregon; Rocky Mountain basins
MEP
50
 
510

 
1.80
 
Oklahoma and north Texas supply basins to interconnects with deliveries to interconnects with Transco, Columbia Gulf and various other pipelines
CPG
100
 
410

 
1.20
 
Colorado and Kansas, natural gas basins in the Central Rocky Mountain area
TransColorado
Gas
100
 
310

 
1.00
 
Colorado and New Mexico; connects to San Juan, Paradox and Piceance basins
WYCO
50
 
224

 
1.20
[7]
 
Northeast Colorado; connects with High Plains
Elba Express
100
 
200

 
0.95
 
Georgia; connects to SNG (Georgia), Transco (Georgia/South Carolina) and CGT (Georgia).
FEP
50
 
185

 
2.00
 
Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission, and ANR Pipeline Company
KM Louisiana
100
 
135

 
3.20
 
sources gas from Cheniere Sabine Pass LNG terminal to interconnects with Columbia Gulf, ANR and various other pipelines
Sierrita pipeline
35
 
60

 
0.20
 
near Tucson, Arizona, to the U.S.-Mexico border near Sasabe, Arizona; connects to EPNG and via a new international border crossing with a new natural gas pipeline in Mexico
Young Gas Storage
48
 
17

 
[6]
 
Morgan County, Colorado, capacity is committed to CIG and Colorado Springs Utilities.
Keystone Gas Storage
100
 
12

 
[9]
 
located in the Permian Basin and near the WAHA natural gas trading hub in West Texas.
Gulf LNG Holdings
50
 
5

 
[7]
 
near Pascagoula, Mississippi; connects to four interstate pipelines and natural gas processing plant
Bear Creek Storage
100
 

 
[59]
 
50% SNG and 50% TGP

13


 
 Ownership
Interest %
 
 Miles
of
Pipeline
 
Design (Bcf/d) [Storage (Bcf)] Capacity
 
Supply and Market Region
SLNG
100
 

 
[12]
 
Georgia; connects to Elba Express, SNG and CGT
ELC
51
 

 
 
 
not in service until 2017 - 2018
 
 
 
 
 
 
 
 
Midstream group
 
 
 
 
 
 
KM Texas and
Tejas pipelines(a)
100
 
5,800

 
6.20
[120]
 
Texas Gulf Coast.
Mier-Monterrey
pipeline
100
 
95

 
0.65
 
Starr County, Texas to Monterrey, Mexico; connects to Pemex NG Transportation system and a 1,000-megawatt power plant
KM North Texas
pipeline
100
 
80

 
0.33
 
interconnect from NGPL; connects to 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant
Copano Oklahoma
 
 
 
 
 
 
Southern Dome
70
 

 
0.03
 
propane refrigeration plant in the southern portion of Oklahoma county
Copano Oklahoma System
100
 
3,500

 
0.38
 
Hunton Dewatering, Woodford Shale, and Mississippi Lime
Copano South Texas
 
 
 
 
 
 
Webb/Duval gas gathering system
63
 
145

 
0.15
 
South Texas
Copano South Texas System
100
 
1,255

 
1.88
 
Eagle Ford shale formation, Woodbine and Eaglebine (Texas)
EagleHawk
25
 
860

 
1.00
 
South Texas, Eagle Ford shale formation
KM Altamont
100
 
790

 
0.08
 
Utah, Uinta Basin
Red Cedar
49
 
750

 
0.70
 
La Plata County, Colorado, Ignacio Blanco Field
Copano Rocky Mountain
 
 
 
 
 
 
Fort Union
37
 
310

 
1.25
 
Powder River Basin (Wyoming)
Bighorn
51
 
290

 
0.60
 
Powder River Basin (Wyoming)
KinderHawk
100
 
500

 
2.00
 
Northwest Louisiana, Haynesville and Bossier shale formations
Copano North Texas
100
 
400

 
0.14
 
North Barnett Shale Combo
Endeavor
40
 
100

 
0.12
 
East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale horizontal well developments
Camino Real - Gas
100
 
70

 
0.15
 
South Texas, Eagle Ford shale formation
KM Treating
100
 

 
 
Odessa, Texas, other locations in Tyler and Victoria, Texas
 
 
 
 
 
 
 
 
 
 
 
 
 
(MBbl/d)
 
 
Copano Liquids
 
 
 
 
 
 
 
Liberty Pipeline
50
 
87

 
170
 
Houston Central complex to the Texas Gulf Coast
Copano Liquids Assets
100
 
313

 
115
 
Houston Central complex to the Texas Gulf Coast
Camino Real - Oil
100
 
70

 
110
 
South Texas, Eagle Ford shale formation
_______

Competition

The market for supply of natural gas is highly competitive, and new pipelines, storage facilities, treating facilities, and facilities for related services 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

14


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 location, rates, terms of service and flexibility and reliability of service.  From time to time, other projects are proposed that would compete with us. 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 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.  Our CO2 pipelines and related assets allow us to market a complete package of CO2 supply, transportation and technical expertise to our customers. We also hold ownership interests in several oil-producing fields and own a crude oil pipeline, all located in the Permian Basin region of West Texas.

Oil and Gas Producing Activities

Oil Producing Interests

Our ownership interests in oil-producing fields located in the Permian Basin of West Texas, include the following:
 
 
 
KM Gross
 
Working
 
Developed
 
Interest %
 
Acres
SACROC
97

 
49,156

Yates
50

 
9,576

Goldsmith Landreth San Andres(a)
99

 
6,166

Katz Strawn
99

 
7,194

Sharon Ridge
14

 
2,619

H.T. Boyd(b)
21

 
n/a

MidCross
13

 
320

Reinecke(c)

 
80

_______
(a)
Acquired June 1, 2013
(b)
Net profits interest
(c)
Working interest less than 1 percent.

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, 2014.  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

 
1,381

 
1,152

 
903

 
2

 
2

Natural Gas
5

 
2

 

 

 

 

Total Wells
2,169

 
1,383

 
1,152

 
903

 
2

 
2

_______
(a)
Includes active wells and wells temporarily shut-in.  As of December 31, 2014, 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, 2014. A development well is a well drilled in an already discovered oil field.

15



The following table reflects our net productive wells that were completed in each of the years ended December 31, 2014, 2013 and 2012:
 
Year Ended December 31,
 
2014
 
2013
 
2012
Productive
 
 
 
 
 
Development                                  
83

 
51

 
59

Exploratory                                  
26

 
4

 

Total Productive
109

 
55

 
59

Dry Exploratory
1

 

 

Total Wells
110

 
55

 
59

_______
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.
 
The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2014:
 
Gross
 
Net
Developed Acres
75,111

 
71,919

Undeveloped Acres
17,603

 
15,369

Total
92,714

 
87,288

_______
Note: As of December 31, 2014, 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

Operated gas plants in the Permian Basin of West Texas:
 
Ownership
 
 
 
Interest %
 
Source
Snyder gasoline plant(a)
22

 
The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units
Diamond M gas plant
51

 
Snyder gasoline plant
North Snyder plant
100

 
Snyder gasoline plant
_______
(a)
This is a working interest, in addition, we have a 28% net profits interest. The average net to us does not include the value associated with the net profits interest.


16


Sales and Transportation Activities

CO2 Segment Storage and Sales

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. Our ownership of CO2 reserves as of December 31, 2014 includes:
 
Ownership
Interest %
 
Recoverable
CO2 (Bcf)
 
Compression
Capacity (Bcf/d)
 
Location
Recoverable CO2
 
 
 
 
 
 
 
McElmo Dome unit(a)
45

 
5,900

 
1.4

 
Colorado
St. Johns CO2 source field and related assets(b)
100

 
1,660

 
0.3

 
Apache County, Arizona, and Catron County, New Mexico
Doe Canyon Deep unit(a)
87

 
832

 
0.2

 
Colorado
Bravo Dome unit
11

 
702

 
0.3

 
New Mexico
_______
(a)
We also operate.
(b)
Compression installation planned for the fourth quarter of 2018.

CO2 Segment Pipelines

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 stable for the next several years. The tariffs charged by our CO2 pipelines are not regulated; however, the tariff charged on the Cortez pipeline is based on a consent decree. The tariffs charged on the Wink pipeline system are regulated by both the FERC and the Texas Railroad Commission. Our ownership of CO2 and crude oil pipelines as of December 31, 2014 includes:
 
Ownership Interest %
 
Miles of Pipeline
 
Transport Capacity(Bcf/d)
 
Supply and Market Region
CO2 pipelines
 
 
 
 
 
 
 
Cortez pipeline
50

 
565

 
1.2

 
McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub
Central Basin pipeline
100

 
323

 
0.7

 
Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers, and Pecos pipelines
Bravo pipeline(a)
13

 
218

 
0.4

 
Bravo Dome to the Denver City, Texas hub
Canyon Reef Carriers pipeline
98

 
162

 
0.3

 
McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units
Centerline CO2 pipeline
100

 
112

 
0.3

 
between Denver City, Texas and Snyder, Texas
Eastern Shelf CO2 pipeline
100

 
91

 
0.1

 
between Snyder, Texas and Knox City, Texas
Pecos pipeline
69

 
25

 
0.1

 
McCamey, Texas, to Iraan, Texas, delivers to the Yates unit
Goldsmith Landreth
99

 
3

 
0.2

 
Goldsmith Landreth San Andres field in the Permian Basin of West Texas
 
 
 
 
 
(MBbl/d)
 
 
Crude oil pipeline
 
 
 
 
 
 
 
Wink pipeline
100

 
453

 
145

 
West Texas to Western Refining’s refinery in El Paso, Texas
_______
(a)
We do not operate Bravo pipeline.

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 U.S.A., 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

17


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.

Terminals

Our Terminals segment includes the operations of our petroleum, chemical, ethanol and other liquids terminal facilities (other than those included in the 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.  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 help attract new and retain existing customers at our terminals and provide us opportunities for expansion. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, we have Jones Act qualified product tankers that provide marine transportation of crude oil, condensate and refined products in the U.S. The following summarizes our Terminals segment assets, as of December 31, 2014:
 
Number
 
Capacity
(MMBbl)
Liquids terminals
39

 
78.0

Bulk terminals
78

 
n/a

Materials Services locations
8

 
n/a

Jones Act qualified tankers
7

 
2.3


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, 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 Jones Act qualified product tankers compete with other Jones Act qualified vessel fleets.


18


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. The following summarizes our significant Products Pipelines segment assets we own and operate as of December 31, 2014:
 
Ownership Interest %
 
Miles of Pipeline
 
Number of Terminals (a) or locations
 
Terminal Capacity(MMBbl)
 
Supply and Market Region
Plantation pipeline
51

 
3,182

 
 
 
 
 
Louisiana to Washington D.C.
West Coast Products Pipelines(b)
 
 
 
 
 
 
 
 
Pacific (SFPP)
100

 
2,823

 
13

 
15.3

 
six western states
Calnev
100

 
570

 
2

 
2.1

 
Colton, CA to Las Vegas, NV; Mojave region
West Coast Terminals
100

 
43

 
6

 
9.2

 
Seattle, Portland, San Francisco and Los Angeles areas
Cochin pipeline
100

 
1,877

 
5

 
1.1

 
three provinces in Canada and seven states in the U.S.
KM Crude & Condensate pipeline
100

 
252

 
2

 
1.2

 
Eagle Ford shale field in South Texas (Dewitt County) to the Houston ship channel refining complex
Central Florida pipeline
100

 
206

 
2

 
2.5

 
Tampa to Orlando
Double Eagle pipeline
50

 
194

 
 
 
0.4

 
Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County
Parkway
50

 
140

 
 
 
 
 
interconnect at Collins with Plantation and Plantation markets
Cypress pipeline
50

 
104

 
 
 
 
 
Mont Belvieu, Texas to Lake Charles, Louisiana
Southeast Terminals
100

 
 
 
28

 
9.1

 
from Mississippi through Virginia, including Tennessee
Kinder Morgan Assessment Protocol (KMAP)
100

 
 
 
 
 
 
 
pipeline integrity analysis protocol for KM and outside customers
Transmix Operations
100

 
 
 
6

 
1.5

 
Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; St. Louis, Missouri; and Greensboro, North Carolina
_______
(a)
The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.
(b)
Our West Coast Products Pipelines 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.

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.

Kinder Morgan Canada

Our Kinder Morgan Canada business segment includes our 100% owned and operated Trans Mountain pipeline system and a 25-mile Jet Fuel pipeline system.

Trans Mountain Pipeline System

The 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 713 miles in length. We also own and operate a connecting pipeline that delivers crude oil to refineries in the state of Washington. The

19


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.

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 the 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 that the 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.

Other

During 2014, our other segment activity primarily includes other miscellaneous assets and liabilities purchased in our 2012 EP acquisition including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with EP’s legacy trading activities; and (iii) other miscellaneous EP assets and liabilities.

Major Customers

Our revenue is derived from a wide customer base. For each of the years ended December 31, 2014, 2013 and 2012, 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, the CO2 business segment also sells natural gas. Combined, total revenues from the sales of natural gas from the Natural Gas Pipelines and CO2 business segments in 2014, 2013 and 2012 accounted for 25%, 28% and 28%, 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.

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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 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 “Litigation, Environmental and Other” 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

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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 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 the 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 its intrastate rates. The  intrastate rates for movements in California on our SFPP and Calnev systems have been, and may in the future be, subject to complaints before the CPUC, as is more fully described in Note 16 “Litigation, Environmental and Other” to our consolidated financial statements. 
Texas Railroad Commission Rate Regulation
The intrastate operations of our crude oil pipelines and natural gas pipelines and storage facilities 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 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 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 natural gas transportation system authorized by 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 PHMSA, including those requiring us to develop and maintain pipeline Integrity Management programs to comprehensively evaluate 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 pipeline Integrity Management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional integrity threats and changes to the amount of pipe determined

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to be located in HCAs can have a significant impact on 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 PHMSA regulations. These tests could result in significant and 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 and may result in the imposition of more stringent regulations in the next few years. 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 maximum 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 to 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 Management regulation, and actual 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, addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Repair, remediation, and 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 the Occupational Safety and Health Administration (OSHA) and other 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 stock. 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. Furthermore, from time to time, legislation has been introduced unsuccessfully in Congress to amend the Jones Act to ease or remove the requirement that vessels operating between U.S. ports be built and registered in the U.S. and owned and manned by U.S. citizens.  If the Jones Act were amended in such fashion, we could face competition from foreign flagged 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.

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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 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 suffered 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 multi-party 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 multi-party 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 $340 million as of December 31, 2014. Our reserve estimates range in value from approximately $340 million to approximately $514 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 “Litigation, Environmental and Other” 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.

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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 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 and in 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 addressing emission of greenhouse gases with a renewed focus on emissions of methane 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 the 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 the compressor stations and processing plants, emit various types of greenhouse gases, primarily methane and CO2, such new legislation or regulation could increase the costs related to operating and maintaining the facilities. Depending on the particular law, regulation or program, we or our subsidiaries could be required to incur capital

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expenditures for installing new monitoring equipment of emission controls on the facilities, acquire and surrender allowances for the greenhouse gas emissions, pay taxes related to the 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 or our subsidiaries pipelines, such recovery of costs in all cases is uncertain and may depend on events beyond their 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.

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

We employed 11,535 full-time people at December 31, 2014, including approximately 828 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2015 and 2018. We consider relations with our employees to be good.

Most of our employees are employed by a limited number of our subsidiaries and provide services to one or more of our business units. The direct costs of compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated to our subsidiaries. Our human resources department provides the administrative support necessary to implement these payroll and benefits services, and the related administrative costs are allocated to our subsidiaries pursuant to our board-approved expense allocation policy. The effect of these arrangements is that each business unit bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs.

Properties

We believe that we generally have 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

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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 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 “Reportable Segments” 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 condition, cash flows and results of operations.

Risks Related to Our Business

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 encourage 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 the recent sharp decline in crude oil 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 impacts our customers shipping through our pipelines, which in turn could impact the prospects of new transportation contracts or renewals of existing contracts.

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.


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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.

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.

Our growth strategy may cause difficulties integrating acquisitions and constructing new facilities, 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, 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 and expansions, which would harm our financial condition and results of operations.

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

As of December 31, 2014, we had approximately $41 billion of consolidated debt (excluding debt fair value adjustments). Additionally, in connection with the Merger Transactions, we and substantially all of our wholly owned subsidiaries entered into a cross guarantee agreement whereby each party to the agreement unconditionally guarantees the indebtedness of each other party to the agreement, thereby causing us to become liable for the debt of each of such subsidiaries. This level of debt and the cross guarantee agreement 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) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) 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, including the cross-guaranteed debt, and any future indebtedness that we incur, we will be forced to take actions, which may include reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 8 “Debt” to our consolidated financial statements.


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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, provincial 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. 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, the 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 to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact upon our operating results.

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 continue to initiate investigations to determine whether 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 to our rates 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 relate to pipeline integrity testing and repairs. Technological advances in 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

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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.

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 or provincial 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.

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.”


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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 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, as well as reductions in production from existing wells, which could adversely impact the volumes of natural gas transported on our or our joint ventures’ natural gas pipelines and our own oil and gas development and production activities.

Oil and gas development and production activities are subject to numerous federal, state, provincial and local laws and regulations relating to environmental quality and pollution control.  The oil and gas industry is increasingly relying on supplies of hydrocarbons from unconventional sources, such as shale, tight sands and coal bed methane.  The extraction of hydrocarbons 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.

In addition, 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. These laws and regulations may adversely affect our oil and gas development and production activities.

Our acquisition strategy and expansion programs require access to new capital.  Limitations on our access to capital would impair our ability to grow.

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

As of December 31, 2014, approximately $11 billion of our approximately $41 billion of 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.

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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.”

Our debt instruments may limit our financial flexibility and increase our financing costs.

The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that we deem beneficial and that may be beneficial to us. Some of the agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more restrictive restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.

Our business, financial condition and operating results may be affected adversely 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 business, financial condition and results of operations.

In addition, 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 and our subsidiaries’ debt securities.

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 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.

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

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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.

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 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.

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 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.

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.

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

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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 oil and natural gas prices could have a material adverse effect on our CO2 and natural gas pipeline business segments.

The revenues, profitability and future growth of our CO2 and natural gas pipeline business segments and the carrying value of its oil, NGL and natural gas properties depend to a large degree on prevailing oil and gas prices.  For 2015, we estimate that every $1 change in the average WTI crude oil price per barrel would impact our distributable cash flow by approximately $10 million and each $0.10 per MMBtu change in the average price of natural gas impacts distributable cash flow by approximately $3 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.”

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 “Risk Management” 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

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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.

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 2014 acquisitions of American Petroleum Tankers, State Class Tankers, and the Pennsylvania and Florida Jones Act tankers from Crowley Maritime Corporation 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.

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 (i) retain current employees; (ii) successfully complete the knowledge transfer; and/or (iii) 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.

If we are unable to retain our chairman or executive officers, our growth may be hindered.

Our success depends in part on the performance of and our ability to retain our chairman and our executive officers, particularly our Chairman and current Chief Executive Officer, Richard D. Kinder, who is also one of our founders, and our current President and Chief Operating Officer, Steve Kean, who will assume the Chief Executive Officer position in June of 2015.  Along with the other members of our senior management, Mr. Kinder and Mr. Kean have been responsible for developing and executing our growth strategy.  If we are not successful in retaining Mr. Kinder, Mr. Kean or our other executive officers or replacing them, our business, financial condition or results of operations could be adversely affected.  We do not maintain key personnel insurance.

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 stockholders’ equity under applicable accounting rules.


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Risks Related to the Ownership of Our Common Stock

The price of our common stock may be volatile, and holders of our common stock could lose a significant portion of their investments.

The market price of our common stock could be volatile, and our stockholders may not be able to resell their common stock at or above the price at which they purchased it due to fluctuations in its market price, including changes in price caused by factors unrelated to our operating performance or prospects.

Specific factors that may have a significant effect on the market price for our common stock include: (i) changes in stock market analyst recommendations or earnings estimates regarding our common stock, other companies comparable to us or companies in the industries we serve; (ii) actual or anticipated fluctuations in our operating results or future prospects; (iii) reaction to our public announcements; (iv) strategic actions taken by us or our competitors, such as acquisitions or restructurings; (v) the recruitment or departure of key personnel; (vi) new laws or regulations or new interpretations of existing laws or regulations applicable to our business and operations; (vii) changes in tax or accounting standards, policies, guidance, interpretations or principles; (viii) adverse conditions in the financial markets or general U.S. or international economic conditions, including those resulting from war, incidents of terrorism and responses to such events; and (ix) sales of common stock by us, members of our management team or significant stockholders.

Non-U.S. holders of our common stock may be subject to U.S. federal income tax with respect to gain on the disposition of our common stock.

If we are or have been a “U.S. real property holding corporation’’ within the meaning of the Code at any time within the shorter of (i) the five-year period preceding a disposition of our common stock by a non-U.S. holder or (ii) such holder’s holding period for such common stock, and assuming our common stock is “regularly traded,’’ as defined by applicable U.S. Treasury regulations, on an established securities market, the non-U.S. holder may be subject to U.S. federal income tax with respect to gain on such disposition if it held more than 5% of our common stock during the shorter of periods (i) and (ii) above. We believe we are, or may become, a U.S. real property holding corporation.

The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.

We disclose in this report and elsewhere our expected cash dividends. This reflects our current judgment, but as with any estimate, it may be affected by inaccurate assumptions and known and unknown risks and uncertainties, many of which are beyond our control. See “Information Regarding Forward-Looking Statements.” If the payment of dividends at the anticipated level would leave us with insufficient cash to take timely advantage of growth opportunities (including through acquisitions), to meet any large unanticipated liquidity requirements, to fund our operations, or otherwise to address properly our business prospects, our business would be harmed. Conversely, a decision to address such needs might lead to the payment of dividends below the anticipated level. As events present themselves or become reasonably foreseeable, our board of directors, which determines our business strategy and our dividends, might have to choose between addressing those matters or reducing our anticipated dividends. Alternatively, because there is nothing in our governing documents or credit agreements that prohibits us from borrowing to pay dividends, our board of directors may choose to cause us to incur debt to enable us to pay our anticipated dividends. This would add to our substantial debt discussed above under “-Risks Related to Our Business-Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic consequences.”

Item 1B.  Unresolved Staff Comments.
 
None.
 
Item 3.  Legal Proceedings.
 
See Note 16 “Litigation, Environmental and Other” to our consolidated financial statements.

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.
 
On December 26, 2012, the remaining outstanding shares of our Class A, Class B, and Class C common stock were converted into Class P shares and as of December 31, 2012 only our Class P common stock was outstanding. Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.” During the period that our Class A, Class B, and Class C common stock was outstanding, none were traded on a public trading market.  The high and low sale prices per Class P share as reported on the NYSE and the dividends declared per share by period for 2014, 2013 and 2012, are provided below. 

 
Price Range
 
Declared Cash
Dividends(a)
 
Low
 
High
 
2014
 
 
 
 
 
First Quarter
$
30.81

 
$
36.45

 
$
0.42

Second Quarter
32.10

 
36.50

 
0.43

Third Quarter
35.20

 
42.49

 
0.44

Fourth Quarter
33.25

 
43.18

 
0.45

2013
 
 
 
 
 
First Quarter
$
35.74

 
$
38.80

 
$
0.38

Second Quarter
35.52

 
41.49

 
0.40

Third Quarter
34.54

 
40.45

 
0.41

Fourth Quarter
32.30

 
36.68

 
0.41

2012
 
 
 
 
 
First Quarter
$
31.76

 
$
39.25

 
$
0.32

Second Quarter
30.51

 
40.25

 
0.35

Third Quarter
32.03

 
36.63

 
0.36

Fourth Quarter
31.93

 
36.50

 
0.37

_______
(a)
Dividend information is for dividends declared with respect to that quarter.  Generally, our declared dividends are paid on or about the 16th day of each February, May, August and November. 

As of February 2, 2015, we had 12,483 holders of our Class P common stock, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.

For information on our equity compensation plans, see Note 9 “Share-based Compensation and Employee Benefits—Share-based Compensation—Kinder Morgan, Inc.” to our consolidated financial statements. 

Our Purchases of Our Class P Shares and Warrants
Period
 
Total number of securities purchased
 
Average price paid per security
 
Total number of securities purchased as part of publicly announced plans
 
Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs(a)
October 1 to October 31, 2014
 

 
$

 

 
$
2,452,606

November 1 to November 30, 2014
 

 
$

 

 
$
2,452,606

December 1 to December 31, 2014
 

 
$

 

 
$
2,452,606

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
2,452,606

_______
(a)
Remaining amount available under a $100 million share and warrant repurchase program approved by our board of directors on March 4, 2014.


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Item 6.  Selected Financial Data.
 
The following table sets forth, for the periods and at the dates indicated, our summary historical financial 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.
Five-Year Review
Kinder Morgan, Inc. and Subsidiaries
 
As of or for the Year Ended December 31,
 
2014
 
2013
 
2012
 
2011
 
2010
 
(In millions, except per share and ratio data)
Income and Cash Flow Data:
 
 
 
 
 
 
 
 
 
Revenues
$
16,226

 
$
14,070

 
$
9,973

 
$
7,943

 
$
7,852

Operating income
4,448

 
3,990

 
2,593

 
1,423

 
1,133

Earnings (loss) from equity investments
406

 
327

 
153

 
226

 
(274
)
Income from continuing operations
2,443

 
2,696

 
1,204

 
449

 
64

(Loss) income from discontinued operations, net of tax

 
(4
)
 
(777
)
 
211

 
236

Net income
2,443

 
2,692

 
427

 
660

 
300

Net income (loss) attributable to Kinder Morgan, Inc.
1,026

 
1,193

 
315

 
594

 
(41
)
Class P Shares
 
 
 
 
 
 
 

 
 

Basic and Diluted Earnings Per Common Share From Continuing Operations
$
0.89

 
$
1.15

 
$
0.56

 
$
0.70

 
 
Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations

 

 
(0.21
)
 
0.04

 
 
Total Basic and Diluted Earnings Per Common Share
$
0.89

 
$
1.15

 
$
0.35

 
$
0.74

 
 
Class A Shares
 
 
 
 
 
 
 

 
 
Basic and Diluted Earnings Per Common Share From Continuing Operations
 
 
 
 
$
0.47

 
$
0.64

 
 
Basic and Diluted (Loss) Earnings Per Common Share From Discontinued Operations
 
 
 
 
(0.21
)
 
0.04

 
 
Total Basic and Diluted Earnings Per Common Share
 
 
 
 
$
0.26

 
$
0.68

 
 
Basic Weighted Average Number of Shares Outstanding:
 
 
 
 
 

 
 

 
 

Class P shares
1,137

 
1,036

 
461

 
118

 
 
Class A shares
 
 
 
 
446

 
589

 
 
Diluted Weighted Average Number of Shares Outstanding:
 
 
 
 
 
 
 

 
 
Class P shares
1,137

 
1,036

 
908

 
708

 
 
Class A shares
 
 
 
 
446

 
589

 
 
 
 
 
 
 
 
 
 
 
 
Dividends per common share declared for the period(a)(b)
$
1.74

 
$
1.60

 
$
1.40

 
$
1.05

 
 
Dividends per common share paid in the period(a)
1.70

 
1.56

 
1.34

 
0.74

 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
Net property, plant and equipment
$
38,564

 
$
35,847

 
$
30,996

 
$
17,926

 
$
17,071

Total assets
83,198

 
75,185

 
68,245

 
30,717

 
28,908

Long-term debt(c)
38,312

 
31,910

 
29,409

 
13,261

 
13,219

_______
(a)
Dividends for the fourth quarter of each year are declared and paid during the first quarter of the following year.
(b)
2011 declared dividend per share was prorated for the portion of the first quarter we were a public company ($0.14 per share).  If we had been a public company for the entire year, the 2011 declared dividend would have been $1.20 per share.  
(c)
Excludes debt fair value adjustments.  Increases to long-term debt for debt fair value adjustments totaled $1,934 million, $1,977 million, $2,591 million, $1,095 million and $594 million as of December 31, 2014, 2013, 2012, 2011, and 2010, respectively.  

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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.  We prepared our consolidated financial statements in accordance with GAAP. 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 2014, 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.”

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 objectives:

helping customers by providing safe and reliable energy, bulk commodity and liquids products transportation, storage and distribution; and

creating long-term value for our shareholders.
 
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 and crude oil 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 as a flooding medium for recovering crude oil from mature oil fields to increase production; (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;

Terminals—(i) 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 that transload and store refined petroleum products, crude oil, condensate, and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals and (ii) the ownership and operation of our Jones Act tankers;

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;


39


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; and

Other—primarily includes other miscellaneous assets and liabilities purchased in our 2012 EP acquisition including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with EP’s legacy trading activities; and (iii) other miscellaneous EP assets and liabilities.
 
As an energy infrastructure owner and operator in multiple facets of the various U.S. and Canadian energy industries 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, the Texas Intrastate Natural Gas Group, currently derives approximately 75% of its 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 natural gas.  As of December 31, 2014, the remaining average contract life of our natural gas transportation contracts (including intrastate pipelines’ purchase and sales contracts) was approximately six years.

Our midstream group, which is within our Natural Gas Pipelines Segment, provides gathering and processing services primarily through our (i) EP midstream asset operations, which we acquired 50% from KKR effective June 1, 2012, and 50% from the May 25, 2012 EP acquisition, (ii) our Copano operations, which included the remaining 50% ownership interest in Eagle Ford Gathering LLC (Eagle Ford) that we did not already own and which was acquired effective May 1, 2013 and (iii) our KinderHawk operation, which gathers and treats natural gas in the Haynesville and Bossier shale gas formations located in northwest Louisiana. These substantially fee-based gathering, processing and fractionation assets, along with our financial strength and extensive pipeline transportation and storage assets, provide an excellent platform to further grow our midstream group 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 group 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. 
In February 2015, we acquired Hiland Partners (Hiland) for a total purchase price of approximately $3 billion (including assumption of debt). Hiland’s assets consist of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily serving production from the Bakken Formation in North Dakota and Montana. Most of Hiland’s operations will be included in our midstream group within our Natural Gas Pipelines segment.
The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2014, 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 2015, and utilizing the average oil price per barrel contained in our 2015 budget, approximately 86% of our revenue is based on a fixed fee or floor price, and 14% fluctuates 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 the CO2 business 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

40


quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil.  The realized weighted average crude oil price per barrel, with all hedges allocated to oil, was $88.41 per barrel in 2014, $92.70 per barrel in 2013 and $87.72 per barrel in 2012.  Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $86.48 per barrel in 2014, $94.94 per barrel in 2013 and $89.91 per barrel in 2012.

 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, 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. Our seven Jones Act qualified tankers operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are currently operating pursuant to multi-year charters with major integrated oil companies, major refiners and the U.S. Military Sealift Command.

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.

Our 2015 budget, and related announced expectation to declare dividends of $2.00 per share for 2015, assumes an average WTI crude oil price of approximately $70 per barrel and an average natural gas price of $3.80 per MMBtu in 2015. For 2015, we estimate that every $1 change in the average WTI crude oil price per barrel will impact our distributable cash flow by approximately $10 million (approximately $7 million of which is attributable to our CO2 business segment), and each $0.10 per MMBtu change in the average price of natural gas will impact distributable cash flow by approximately $3 million. This assumes we do not add additional hedges during the year which could reduce these sensitivities.  These sensitivities compare to total anticipated segment earnings before DD&A in 2015 of approximately $8 billion (adding back our share of joint venture DD&A). Even adjusting for current commodity prices we expect to have significant excess coverage in 2015.

The amount that we are able to increase dividends to our shareholders 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 $4.4 billion for our 2015 capital expansion program (including small acquisitions and investment contributions, but excluding our recent acquisition of Hiland Partners, LP).  We consider and enter into discussions regarding potential acquisitions and 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 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.

41



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. Our dividend policy is to distribute most of our available cash, and we intend to continue accessing capital markets to fund acquisitions and asset expansions. Historically, we have succeeded in raising necessary capital in order to fund our acquisitions and expansions, and although we cannot predict future changes in the overall equity and debt capital markets (in terms of tightening or loosening of credit), we believe that our stable cash flows, credit ratings, and historical records of successfully accessing both equity and debt funding sources should allow us to continue to execute our current investment, dividend and acquisition strategies, as well as refinance maturing debt when required. For a further discussion of our liquidity, including our and our subsidiaries’ public debt and equity offerings in 2014, please see “—Liquidity and Capital Resources” below.
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.
In addition, a portion of our business portfolio (including the Kinder Morgan Canada business segment, the Canadian portion of the Cochin Pipeline, and the bulk and liquids terminal facilities located in Canada) use the local Canadian dollar as the functional currency for its Canadian operations and we enter 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.
 
For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” 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.

Acquisition Method of Accounting

For acquired businesses, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition. Determining the fair value of these items requires management’s judgment, the utilization of independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements.

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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 Items 1 and 2 “Business and Properties—(c) Narrative Description of Business—Environmental Matters”. For more information on our environmental disclosures, see Note 16 “Litigation, Environmental and Other Contingencies” 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. For more information on legal proceedings, see Note 16 “Litigation, Environmental and Other Contingencies” to our consolidated financial statements.
 
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, 2014 impairment testing, and no event indicating an impairment has occurred subsequent to that date, other than $2 million associated with a pending asset divestiture.  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 “Summary of Significant Accounting Policies” and 7 “Goodwill and Other Intangibles” 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 “Goodwill and Other Intangibles” to our consolidated financial statements.

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

43


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 Producing Activities (Unaudited)”.

The quantities of our proved oil and gas reserves and the measures of discounted future net cash flows from those oil and gas reserves as of December 31, 2014 are based on the 12 month unweighted average of the first day of the month price realized in 2014.  Commodity prices fell substantially toward the end of 2014 and therefore, unless commodity prices recover in the next 12 months, the amount of our proved oil and gas reserves and the measures of discounted future net cash flows from those oil and gas reserves could be negatively impacted in 2015. Any resulting reductions in our proved oil and gas reserves due to lower commodity pricing may increase our DD&A expense. Sustained lower commodity prices may also negatively impact forward curve pricing that is used in testing for impairment, estimated total proved and risk-adjusted probable and possible oil and gas reserves, and related expected future cash flows, which may result in impairment of our oil producing interests.
 
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 “Risk Management” to our consolidated financial statements.

Employee Benefit Plans
 
We reflect an asset or liability for our pension and other postretirement benefit plans based on their overfunded or underfunded status. As of December 31, 2014, our pension plans were underfunded by $427 million and our other postretirement benefits plans were underfunded by $235 million. Our pension and other postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We select our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. The selection of these assumptions is further discussed in Note 9 “Share-based Compensation and Employee Benefits” to our consolidated financial statements.
Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of

44


expected future service of active participants, or over the expected future lives of inactive plan participants. We record these deferred amounts as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations. As of December 31, 2014, we had deferred net losses of approximately $323 million in pretax accumulated other comprehensive loss and noncontrolling interests related to our pension and other postretirement benefits.
The following table shows the impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2014:
 
 
Pension Benefits
 
Other Postretirement Benefits
 
 
Net benefit cost (income)
 
Change in funded status and pretax accumulated other comprehensive income (loss)
 
Net benefit cost (income)
 
Change in funded status and pretax accumulated other comprehensive income (loss)
 
 
(In millions)
One percent increase in:
 
 
 
 
 
 
 
 
Discount rates
 
$
10

 
$
260

 
$
2

 
$
55

Expected return on plan assets
 
(23
)
 

 
(4
)
 

Rate of compensation increase
 
2

 
(13
)
 

 

Health care cost trends
 

 

 
4

 
(47
)
 
 
 
 
 
 
 
 
 
One percent decrease in:
 
 
 
 
 
 
 
 
Discount rates
 
(11
)
 
(312
)
 

 
(65
)
Expected return on plan assets
 
23

 

 
4

 

Rate of compensation increase
 
(1
)
 
12

 

 

Health care cost trends
 

 

 
(2
)
 
40

_______
Income Taxes
 
We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized.  While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached.  In addition, we do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed.  Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate.  Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.
 
In determining the deferred income tax asset and liability balances attributable to our investments, we have applied an accounting policy that looks through our investments.  The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments.

Results of Operations

Non-GAAP Measures

The non-GAAP financial measures, DCF before certain items and segment EBDA before 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. DCF before certain items and segment EBDA before certain items are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider either of these non-GAAP measures in

45


isolation or as substitutes for an analysis of our results as reported under GAAP. Because DCF before certain items excludes some but not all items that affect net income and because DCF measures are defined differently by different companies in our industry, our DCF before certain items may not be comparable to DCF measures of other companies. Our computation of segment EBDA before certain items has similar limitations. 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.

Distributable Cash Flow
 
DCF before certain items 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 cash available to pay dividends. We believe the primary measure of company performance used by us, investors and industry analysts is cash generation performance. Therefore, we believe DCF before certain items is an important measure to evaluate our operating and financial performance and to compare it with the performance of other publicly traded companies within the industry. For a discussion of our anticipated dividends for 2015, see “—Financial Condition—Cash Flows—KMI Dividends.”
  

The table below details the reconciliation of Net Income to DCF before certain items:
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(In millions)
Net Income
$
2,443

 
$
2,692

 
$
427

Add/(Subtract):
 
 
 
 
 
Certain items before book tax(a)
14

 
(609
)
 
1,692

Book tax certain items
(117
)
 
(39
)
 
(412
)
Certain items after book tax
(103
)
 
(648
)
 
1,280

Net income before certain items
2,340

 
2,044

 
1,707

Add/(Subtract):
 
 
 
 
 
Net income attributable to third-party noncontrolling interests(b)
(12
)
 
(5
)
 
(1
)
Depreciation, depletion and amortization(c)
2,390

 
2,142

 
1,678

Book taxes(d)
840

 
847

 
584

Cash taxes(d)
(448
)
 
(552
)
 
(460
)
Declared distributions to noncontrolling interests(e)
(2,000
)
 
(2,355
)
 
(1,797
)
Sustaining capital expenditures(f)
(509
)
 
(414
)
 
(393
)
Other, net(g)
17

 
6

 
93

Subtotal
278

 
(331
)
 
(296
)
DCF before certain items
$
2,618

 
$
1,713

 
$
1,411

 
 
 
 
 
 
Weighted Average Shares Outstanding for Dividends(h)
1,312

 
1,040

 
908

DCF per share before certain items