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, 2016
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
(State or other jurisdiction of
incorporation or organization)
80-0682103
(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
Class P Common Stock
Warrants to Purchase Class P Common Stock
Depositary Shares, each representing a 1/20th interest in a
share of 9.75% Series A Mandatory Convertible Preferred Stock
1.500% Senior Notes due 2022
2.250% Senior Notes due 2027
Name of each exchange on which registered
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
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
No
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
No
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
No
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
No
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.
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
Accelerated filer
Non-accelerated filer
Smaller reporting company
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
No
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, 2016 was approximately $36,035,868,866. As of February 9, 2017, the registrant had
2,232,438,943 Class P shares outstanding.
KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
Page
Number
Glossary
Information Regarding Forward-Looking Statements
PART I
Items 1. and 2. Business and Properties
General Development of Business
Organizational Structure
Recent Developments
Financial Information about Segments
Narrative Description of Business
Business Strategy
Business Segments
Natural Gas Pipelines
CO2
Terminals
Products Pipelines
Kinder Morgan Canada
Major Customers
Regulation
Environmental Matters
Other
Financial Information about Geographic Areas
Available Information
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
PART II
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
Critical Accounting Policies and Estimates
Results of Operations
Income Taxes
Liquidity and Capital Resources
Recent Accounting Pronouncements
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
1
2
4
4
4
4
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8
8
8
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11
14
15
15
16
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24
24
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64
KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS (continued)
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Energy Commodity Market Risk
Interest Rate Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
PART III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
Exhibits, Financial Statement Schedules
Index to Financial Statements
Form 10-K Summary
Item 16.
Signatures
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68
73
147
148
KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY
Company Abbreviations
Calnev
CIG
Copano
CPG
EagleHawk
= Calnev Pipe Line LLC
= Colorado Interstate Gas Company, L.L.C.
= Copano Energy, L.L.C.
= Cheyenne Plains Gas Pipeline Company, L.L.C.
= EagleHawk Field Services LLC
Elba Express = Elba Express Company, L.L.C.
ELC
EP
EPB
EPNG
EPPOC
FEP
Hiland
= Elba Liquefaction Company, L.L.C.
= El Paso Corporation and its majority-owned and
controlled subsidiaries
= El Paso Pipeline Partners, L.P. and its majority-
owned and controlled subsidiaries
= El Paso Natural Gas Company, L.L.C.
= El Paso Pipeline Partners Operating Company,
L.L.C.
= Fayetteville Express Pipeline LLC
= Hiland Partners, LP
KMEP
KMGP
KMI
KMLP
KMP
KMR
MEP
NGPL
Ruby
SFPP
SLNG
SNG
TGP
WIC
= Kinder Morgan Energy Partners, L.P.
= Kinder Morgan G.P., Inc.
= Kinder Morgan Inc. and its majority-owned and/or
controlled subsidiaries
= Kinder Morgan Louisiana Pipeline LLC
= Kinder Morgan Energy Partners, L.P. and its
majority-owned and controlled subsidiaries
= Kinder Morgan Management, LLC
= Midcontinent Express Pipeline LLC
= Natural Gas Pipeline Company of America LLC
= Ruby Pipeline Holding Company, L.L.C.
= SFPP, L.P.
= Southern LNG Company, L.L.C.
= Southern Natural Gas Company, L.L.C.
= Tennessee Gas Pipeline Company, L.L.C.
= Wyoming Interstate Company, L.L.C.
KinderHawk = KinderHawk Field Services LLC
WYCO
= WYCO Development L.L.C.
= Kinder Morgan CO2 Company, L.P.
KMCO2
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its
majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
/d
= per day
LIBOR
= London Interbank Offered Rate
AFUDC
= allowance for funds used during construction
BBtu
Bcf
= billion British Thermal Units
= billion cubic feet
CERCLA
= Comprehensive Environmental Response,
Compensation and Liability Act
LLC
LNG
MBbl
MDth
MLP
= limited liability company
= liquefied natural gas
= thousand barrels
= thousand dekatherms
= master limited partnership
CO2
CPUC
DCF
DD&A
DGCL
Dth
EBDA
EPA
FASB
FERC
FTC
GAAP
= carbon dioxide or our CO2 business segment
= California Public Utilities Commission
MMBbl
= million barrels
MMcf
= million cubic feet
= distributable cash flow
= depreciation, depletion and amortization
NEB
NGL
= National Energy Board
= natural gas liquids
= General Corporation Law of the state of Delaware
NYMEX
= New York Mercantile Exchange
= dekatherms
= earnings before depreciation, depletion and
NYSE
OTC
= New York Stock Exchange
= over-the-counter
amortization expenses, including amortization of
PHMSA
= United States Department of Transportation
excess cost of equity investments
Pipeline and Hazardous Materials Safety
= United States Environmental Protection Agency
Administration
= Financial Accounting Standards Board
= Federal Energy Regulatory Commission
= Federal Trade Commission
= United States Generally Accepted Accounting
Principles
U.S.
SEC
TBtu
WTI
= United States of America
= United States Securities and Exchange
Commission
= trillion British Thermal Units
= West Texas Intermediate
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
1
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,” “outlook,” “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, service debt or 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 may differ materially from those
expressed in our forward-looking statements. Many of the factors that will determine these results are beyond our ability to
control or accurately predict. Specific factors that could cause actual results to differ from those in our forward-looking
statements include:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the extent of volatility in prices for and resulting changes in supply of and 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,
gas storage 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 North Dakota,
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 increase our compliance costs, restrict our ability to provide or reduce demand for our
services, or otherwise adversely affect our business;
interruptions of operations at our facilities due to natural disasters, damage by third-parties, 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;
regulatory, environmental, political, legal, operational and geological uncertainties that could affect our ability to
complete our expansion projects on time and on budget;
the timing and success of our business development efforts, including our ability to renew long-term customer
contracts at economically attractive rates;
the ability of our customers and other counterparties to perform under their contracts with us;
competition from other pipelines or other forms of transportation;
2
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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 laws;
our ability to access external sources of financing in sufficient amounts and on acceptable terms to the extent needed
to fund 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;
conditions in the capital and credit markets, inflation and fluctuations in interest rates;
political and economic instability of the oil producing nations of the world;
national, international, regional and local economic, competitive and regulatory conditions and developments,
including the effects of any enactment of import or export duties, tariffs or similar measures;
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 work-overs, and in drilling new wells; and
unfavorable results of litigation and the outcome of contingencies referred to in Note 17 “Litigation, Environmental
and Other Contingencies” 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 expressed in forward-looking statements
will occur, or if any of them do, of their timing or 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.
Additional discussion of factors that may affect our forward-looking statements appears elsewhere in this report, including
in Item 1A, “Risk Factors,” Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of
Operations,” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk-Energy Commodity Market Risk.” In
addition, there is a general level of uncertainty regarding the extent to which potential positive or negative changes to fiscal, tax
and trade policies may impact us and those with whom we do business. It is not possible at this time to predict the extent of
any such impact. When considering forward-looking statements, you should keep in mind the factors described in this section
and the other sections referenced above. These 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—2017
Outlook,” to update the above list or to announce publicly the result of any revisions to any of our forward-looking statements
to reflect future events or developments.
3
Items 1 and 2. Business and Properties.
PART I
We are one of the largest energy infrastructure companies in North America. We own an interest in or operate
approximately 84,000 miles of pipelines and 155 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 steel, coal and petroleum coke. We are also a leading producer of CO2, which we and
others utilize for enhanced oil recovery projects primarily in the Permian basin. Our common stock trades on the NYSE under
the symbol “KMI.”
(a) General Development of Business
Organizational Structure
We are a Delaware corporation and our common stock has been publicly traded since February 2011. Prior to November
2014, we conducted most of our business through two master limited partnerships: KMP (whose business and affairs were
managed by KMR, a publicly traded limited liability company), and EPB.
On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the
outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we did not already own. The
transactions are referred to collectively as the “Merger Transactions.”
As we controlled each of KMP, KMR and EPB before 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 related to the Merger Transactions.
After closing the Merger Transactions, KMR was merged with and into KMI.
Prior to the Merger Transactions, 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 were eliminated.
The equity interests in KMP, EPB and KMR (which are all consolidated in our financial statements) owned by the public
prior to the Merger Transactions are reflected within “Noncontrolling interests” in our accompanying consolidated statements
of stockholders’ equity. The earnings recorded by KMP, EPB and KMR that were attributed to the units and shares,
respectively, held by the public prior to the Merger Transactions are reported as “Net income attributable to noncontrolling
interests” in our accompanying consolidated statement of income for the year ended December 31, 2014.
Additionally, on January 1, 2015, EPB and its subsidiary, EPPOC, merged with and into KMP. As a result of such merger,
all of the subsidiaries of EPB and EPPOC became wholly owned subsidiaries of KMP. References to EPB refer to EPB for
periods prior to its merger into KMP.
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 and other
transactions. Additional information regarding most of these items may be found elsewhere in this report. “Capital Scope” is
estimated for our share of the described project which may include portions not yet completed.
4
Asset or project
Description
Activity
Placed in service, acquisitions or divestitures
SNG natural gas pipeline
system
Sold 50% interest in SNG natural gas pipeline system to
The Southern Company and formed a joint venture, which
includes our remaining 50% interest in SNG.
Completed in September
2016
KM and BP Joint Venture Acquired 15 refined products terminals and associated
infrastructure. KM and BP formed a joint venture, with an
equity ownership interest of 75% and 25%, respectively,
which owns 14 of the acquired assets. One terminal is
owned solely by KM.
Acquired February 2016.
Elba Express and SNG
expansion
Cow Canyon
development
TGP South System
Flexibility
Expansion project that provides 854,000 Dth/d incremental
contracted, firm natural gas transportation service
supporting the needs of customers in Georgia, South
Carolina and northern Florida, and also serving ELC.
Supported by long-term contracts.
Initial service began in
December 2016.
An expansion project that increases CO2 production in the
Cow Canyon area of the McElmo Dome source field by
200 MMcf/d.
Majority placed in service in
2015 and completed during
the 1st quarter of 2016.
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. Subscribed
under long-term firm transportation contracts.
350,000 Dth/d placed into
service during 2015. The
final 150,000 Dth/d capacity
increment was placed in
service in October 2016.
Approx.
Capital
Scope
n/a
$349
million
$285
million
$229
million
$230
million
Cortez Pipeline expansion
Project will increase capacity from 1.35 Bcf/d to 1.5 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.
Placed in service November
2016.
$227
million
Other Announcements
Natural Gas Pipelines
ELC and SLNG
expansion
TGP Broad Run
Expansion
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. Supported by a 20-year contract with Shell.
Second of two separate projects modifying existing
pipeline facilities 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.
Subscribed under long-term firm transportation contracts.
First of 10 liquefaction units
expected in service in
mid-2018 with the
remainder by early 2019.
Broad Run Flexibility
facilities (590,000 Dth/d)
were placed in service
November 2015. Broad
Run Expansion (200,000
Dth/d) expected to be in
service in June 2018.
EPNG South Mainline
Expansion (formerly
upstream Sierrita)
Expansion projects to provide 471,000 Dth/d contracted,
firm natural gas transport capacity with a first phase of
system improvements to deliver volumes to the Sierrita
pipeline and the second phase for incremental deliveries of
natural gas to Arizona and California.
Phase one placed in service
October 2014 ($2 million),
phase two expected in
service July 2020 ($133
million).
Texas Intrastate Crossover
Expansion
Expansion project to provide transportation capacity from
the Katy Hub, the company’s Houston Central processing
plant, and other third party receipt points to serve
customers in Texas and Mexico. Phase I is supported by
commitments of over 800,000 Dth/d, including contracts
with Cheniere Energy, Inc. at its Corpus Christi LNG
facility and Comisión Federal de Electricidad. Phase 2,
which is supported by a long-term commitment from SK
E&S LNG, LLC, will provide service to the Freeport LNG
export facility and bring the total project capacity to over
1,000,000 Dth/d.
Phase 1 was placed in
service in September 2016.
Phase 2 is expected to be in
service by third quarter
2019.
$1.9
billion
$452
million
$135
million
$307
million
TGP Southwest Louisiana
Supply (formerly
Cameron LNG)
Project provides 900,000 Dth/d of long-term capacity to
the future Cameron LNG export complex at Hackberry,
Louisiana. Subscribed under long-term firm transportation
contracts.
Expected in service
February 2018.
$179
million
5
Asset or project
TGP Susquehanna West
KMLP Magnolia LNG
Liquefaction Transport
KMLP Sabine Pass
Expansion
TGP Orion
TGP Lone Star
NGPL Gulf Coast
Southbound Expansion
TGP Connecticut
Expansion
TGP Triad Expansion
Terminals
Jones Act Tankers
KM Export Terminal
KM Base Line Terminal
development
Pit 11 Expansion Project
Products Pipelines
Utopia Pipeline
Description
Expansion project that provides 145,000 Dth/d incremental
natural gas transportation capacity, serving the northeast
Marcellus to points of liquidity. Subscribed under long-
term firm transportation contracts.
Upgrades to existing pipeline system to provide 700,000
Dth/d capacity to serve Magnolia LNG in the Lake
Charles, La., area. Subscribed under long-term firm
agreements, subject to shipper’s final investment decision.
Reconfiguration to flow northeast to southeast to deliver
600,000 Dth/d to the Cheniere Sabine Pass Liquefaction
Terminal in Cameron Parish, LA. Subscribed under long-
term firm transportation contracts.
An expansion project to provide an additional 135,000
Dth/d of firm capacity from the Marcellus supply basin to
TGP’s interconnection with Columbia Gas Transmission in
Pike County, Pennsylvania. Subscribed under long-term
firm transportation contracts.
Two Greenfield compressor stations to provide supply to
the Corpus Christi LNG liquefaction project, for a capacity
of 300,000 Dth/d. Subscribed under long-term firm
transportation contracts.
Expansion project, which is fully subscribed under long-
term contracts, is designed to transport 460,000 Dth/d of
incremental firm transportation service from NGPL’s
interstate pipeline interconnects in Illinois, Arkansas and
Texas to points south on NGPL’s pipeline system to serve
growing demand in the Gulf Coast area.
Project will upgrade portions of TGP’s existing system in
New York, Massachusetts and Connecticut, and provide
72,100 Dth/d of additional firm transportation capacity for
three local distribution company customers.
Expansion project that provides 180,000 Dth/d of long-
term capacity for Invenergy’s Lackawanna Energy Center
in Lackawanna County, PA. Subscribed under long-term
firm transportation contracts.
Purchase of five medium-range Jones Act tankers
constructed by General Dynamics’ NASSCO Shipyard in
San Diego. All of the tankers will be 50,000-deadweight-
ton, LNG conversion-ready product carriers, with a
capacity of 330,000 barrels and contracted for an average
of 5 years. Also purchase of four new 50,000-deadweight-
ton Tier II tankers constructed by Philly Shipyard. Each
LNG conversion-ready will have a capacity of 337,000
barrels.
Brownfield expansion along Houston Ship Channel will
add 12 storage tanks with 1.5 million barrels of liquids
storage capacity, one ship dock, one barge dock and cross-
channel pipelines to connect with the KM Galena Park
terminal. Supported by a long-term contract with a major
ship channel refiner.
Announced a 50-50 joint venture with Keyera Corp. to
build a new 4.8 million barrels of merchant crude oil
storage facility in Edmonton, Alberta. Subscribed under
long-term contracts with an average initial term of 7.5
years.
Adds 2 million barrels of refined products storage at
Pasadena terminal, along the Houston Ship Channel.
Supported by long-term commitments from existing
customers.
Building of new 215 mile pipeline, supported by a long-
term customer contract, to transport ethane and ethane-
propane mixtures from the prolific Utica Shale, with an
initial design capacity of 50,000 barrels per day,
expandable to more than 75,000 barrels per day.
6
Approx.
Capital
Scope
$156
million
$127
million
$151
million
$141
million
$134
million
$106
million
$93
million
$69
million
$1.4
billion
$246
million
CAD$372
million
$185
million
Activity
Expected in service
November 2017.
Expected in-service fourth
quarter 2020
Expected in-service fourth
quarter 2019
Expected in service June
2018.
Expected in-service July
2019.
Pending regulatory
approvals, the project is
expected in service by the
fourth quarter of 2018.
Expected in-service
November 2017.
Expected in service between
November 2017 and June
2018.
First tanker delivery took
place in December 2015.
Four additional tankers were
delivered during 2016. The
remaining four tankers are
scheduled to be delivered
through the end of 2017.
Storage tanks placed in
service in January 2017 with
the terminal’s full marine
capabilities to follow by the
end of the first quarter 2017.
Construction continues.
Commissioning expected to
begin in the first quarter of
2018 with tanks phased-into
service throughout 2018.
Commissioning is expected
to begin in the third quarter
of 2017, with the tanks
phased into service through
the first quarter of 2018.
Expected in service January
2018.
$540
million
Description
Activity
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.
Received federal
government approval in
December 2016.
Construction is planned to
begin in September 2017.
Expected in service in
December 2019.
Approx.
Capital
Scope
$5.4
billion
Asset or project
Kinder Morgan Canada
Trans Mountain
Expansion Project
_______
n/a - not applicable
Financings
On August 16, 2016, our wholly owned subsidiary, CIG, completed a private offering of $375 million in aggregate
principal amount of 4.15% senior notes due August 15, 2026. On September 30, 2016 and October 1, 2016, a portion of the
proceeds from the sale of a 50% interest in SNG was used to repay all of the $332 million principal amount outstanding of
Copano’s 7.125% senior notes due 2021, plus accrued interest and all of the $749 million principal amount outstanding of
Hiland’s 7.25% senior notes due 2020, plus accrued interest, respectively.
Current Commodity Price Environment
Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” as well as Note 4
“Impairments and Losses on Divestitures” and Note 8 “Goodwill” to our consolidated financial statements, discuss the impacts
of the current commodity price environment on the energy industry, including our customers and us. Refer to the developments
addressed in these sections, including the resulting non-cash impairment charges related to goodwill, certain long-lived assets
and equity method investments. For a more general discussion of these related risk factors, refer to Item 1A. “Risk Factors.”
2017 Outlook
We expect to declare dividends of $0.50 per share for 2017 and generate approximately $4.46 billion of distributable cash
flow. We also expect to invest $3.2 billion on expansion projects during 2017 to be funded with internally generated cash flow
without the need to access equity markets. Our 2017 budget assumes a joint venture partner on our Trans Mountain expansion
project and contributions from that partner to fund its share of expansion capital, but does not include any potential proceeds in
excess of the partner’s share of expansion capital to recognize the value created in developing the project to this stage. We are
unable to provide budgeted net income attributable to common stockholders (the GAAP financial measure most directly
comparable to distributable cash flow) due to the inherent difficulty and impracticality of predicting certain amounts required
by GAAP, such as ineffectiveness on commodity, interest rate and foreign currency hedges, unrealized gains and losses on
derivatives marked to market, and potential changes in estimates for certain contingent liabilities.
These expectations assume an average 2017 WTI crude oil price of $53 per barrel and an average 2017 Henry Hub natural
gas price of $3 per MMBtu, which were consistent with the current forward curve at the time that our 2017 budget was
prepared.
The overwhelming majority of cash we generate is supported by multi-year fee-based customer arrangements and therefore
is not directly exposed to commodity prices. The primary area where we have direct commodity price sensitivity is in our CO2
segment, where we hedge the majority of the next 12 months of oil production to minimize this sensitivity. For 2017, we
estimate that every $1 change in the average WTI crude oil price per barrel would impact our distributable cash flow by
approximately $6 million and each $0.10 per MMBtu change in the average price of natural gas would impact distributable
cash flow by approximately $1 million.
In addition, our expectations for 2017 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 2017
expectations when we believe previously disclosed expectations no longer have a reasonable basis.
7
(b) Financial Information about Segments
For financial information on our five reportable business segments, see Note 16 “Reportable Segments” to our
consolidated financial statements.
(c) Narrative Description of Business
Business Strategy
Our business strategy is to:
•
•
•
focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of
growing markets within North America;
increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally
sound operating practices;
leverage economies of scale from incremental acquisitions and expansions of assets that fit within our strategy and are
accretive to cash flow; and
• 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 full and partial divestitures, and we
are currently contemplating potential transactions. 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 or sale agreements for the acquisition or sale 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—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and
storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii)
NGL fractionation facilities and transportation systems; and (iv) LNG facilities;
• 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—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and
portions of Canada that transload and store refined petroleum products, crude oil, chemicals, and ethanol and bulk
products, including coal, petroleum coke, fertilizer, steel and ores and (ii) Jones Act tankers;
Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate
pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, crude oil and condensate
to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline
transmix facilities; and
•
• Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil
and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British
Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the
Vancouver (Canada) International Airport.
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.
8
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 46,000 miles of natural gas pipelines and (ii)
our equity interests in entities that have approximately 26,000 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, 2016. The Design Capacity represents either transmission, gathering
or liquefaction capacity depending on the nature of the asset.
Asset (KMI
ownership shown if
not 100%)
Natural Gas Pipelines
Miles
of
Pipeline
Design
(Bcf/d)
Capacity
TGP
11,800
10.23
EPNG/Mojave
pipeline system
NGPL (50%)
10,600
5.65
9,100
6.90
SNG (50%)
6,900
4.07
Florida Gas
Transmission
(Citrus) (50%)
CIG
WIC
Ruby pipeline
(50%)
MEP (50%)
CPG
TransColorado Gas
WYCO (50%)
Elba Express
FEP (50%)
KMLP
Sierrita Gas Pipeline
LLC (35%)
Young Gas Storage
(48%)
Keystone Gas
Storage
Gulf LNG Holdings
(50%)
Bear Creek Storage
(75%)
5,300
3.60
4,350
850
680
510
410
310
224
200
185
135
5.15
3.88
1.53
1.80
1.20
0.98
1.20
0.95
2.00
2.20
61
0.20
16
12
5
—
—
—
—
—
Storage
(Bcf)
[Processing
(Bcf/d)]
Capacity
Supply and Market Region
North to south to Gulf Coast and U.S.-Mexico border, southeast
U.S.; Haynesville, Marcellus, Utica, and Eagle Ford shale
formations
Northern New Mexico, Texas, Oklahoma, to California, connects
to San Juan, Permian and Anadarko basins
Chicago and other Midwest markets and all central U.S. supply
basins; north to south for LNG and to U.S.-Mexico border
Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina
and Tennessee; basins in Texas, Louisiana, Mississippi and
Alabama
Texas to Florida; basins along Louisiana and Texas Gulf Coast,
Mobile Bay and offshore Gulf of Mexico
Colorado and Wyoming; Rocky Mountains and the Anadarko Basin
Wyoming, Colorado and Utah; Overthrust, Piceance, Uinta,
Powder River and Green River Basins
Wyoming to Oregon; Rocky Mountain basins
Oklahoma and north Texas supply basins to interconnects with
deliveries to interconnects with Transco, Columbia Gulf and
various other pipelines
Colorado and Kansas, natural gas basins in the Central Rocky
Mountain area
Colorado and New Mexico; connects to San Juan, Paradox and
Piceance basins
Northeast Colorado; interconnects with CIG, WIC, Rockies
Express Pipeline, Young Gas Storage and PSCo’s pipeline system
Georgia; connects to SNG (Georgia), Transco (Georgia/South
Carolina), SLNG (Georgia) and CGT (Georgia).
Arkansas to Mississippi; connects to NGPL, Trunkline Gas
Company, Texas Gas Transmission and ANR Pipeline Company
sources gas from Cheniere Sabine Pass LNG terminal to
interconnects with Columbia Gulf, ANR and various other
pipelines
near Tucson, Arizona, to the U.S.-Mexico border near Sasabe,
Arizona; connects to EPNG and via an international border
crossing with a third-party natural gas pipeline in Mexico
Morgan County, Colorado, capacity is committed to CIG and
Colorado Springs Utilities
located in the Permian Basin and near the WAHA natural gas
trading hub in West Texas
near Pascagoula, Mississippi; connects to four interstate pipelines
and a natural gas processing plant
located in Louisiana; provides storage capacity to SNG and TGP
104
44
288
68
—
37
—
—
—
—
—
7
—
—
—
—
6
6
6.6
59
9
Asset (KMI
ownership shown if
not 100%)
SLNG
ELC
Miles
of
Pipeline
—
—
Design
(Bcf/d)
Capacity
—
0.35
Midstream Natural Gas Assets
KM Texas and Tejas
5,650
6.40
90
80
0.65
0.33
Storage
(Bcf)
[Processing
(Bcf/d)]
Capacity
11.5
—
136
[0.51]
—
—
Supply and Market Region
Georgia; connects to Elba Express, SNG and CGT
Georgia; expect phased in service from mid-2018 to early 2019
Texas Gulf Coast
Starr County, Texas to Monterrey, Mexico; connect to CENEGAS
national system and multiple power plants in Monterrey
interconnect from NGPL; connects to 1,750-megawatt Forney,
Texas, power plant and a 1,000-megawatt Paris, Texas, power plant
pipelines
Mier-Monterrey
pipeline
KM North Texas
pipeline
Oklahoma
Oklahoma
System
Hiland -
Midcontinent
Southern Dome
(73%)
Cedar Cove
(70%)
South Texas
South Texas
System
Webb/Duval gas
gathering
system (63%)
EagleHawk (25%)
KM Altamont
Red Cedar (49%)
Rocky Mountain
Fort Union
(37%)
Bighorn (51%)
KinderHawk
North Texas
Endeavor (40%)
Camino Real
KM Treating
3,500
0.35
[0.15]
Hunton Dewatering, Woodford Shale and Mississippi Lime
622
0.20
—
Woodford Shale, Anadarko Basin and Arkoma Basin
—
89
—
0.03
[0.02]
currently idle
[0.01]
Oklahoma STACK, capacity excludes third-party offloads
1,300
1.74
[1.06]
Eagle Ford shale, Woodbine and Eaglebine formations
145
0.15
590
1,350
750
310
290
500
550
101
70
—
1.20
0.08
0.70
1.25
0.60
2.00
0.14
0.15
0.15
—
0.31
—
—
South Texas
South Texas, Eagle Ford shale formation
[0.08]
Utah, Uinta Basin
—
—
—
—
La Plata County, Colorado, Ignacio Blanco Field
Powder River Basin (Wyoming)
Powder River Basin (Wyoming)
Northwest Louisiana, Haynesville and Bossier shale formations
[0.10]
North Barnett Shale Combo
—
—
—
East Texas, Cotton Valley Sands and Haynesville/ Bossier Shale
South Texas, Eagle Ford shale formation
Odessa, Texas, other locations in Tyler and Victoria, Texas
[0.20]
Bakken/Three Forks shale formations (North Dakota/Montana)
Hiland - Williston
2,000
Midstream Liquids/Oil/Condensate Pipelines
Liberty Pipeline
(50%)
South Texas NGL
Pipelines
Camino Real -
Condensate
87
340
68
Hiland - Williston -
1,480
Oil
EagleHawk -
Condensate
(25%)
410
(MBbl/d)
170
(MBbl)
—
115
110
240
220
—
20
—
60
10
Y-grade pipeline from Houston Central complex to the Texas Gulf
Coast
Ethane and propane pipelines from Houston Central complex to the
Texas Gulf Coast
South Texas, Eagle Ford shale formation
Bakken/Three Forks shale formations (North Dakota/Montana)
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. Our operations compete with interstate and intrastate pipelines,
and their shippers, for connections to new markets and supplies and for transportation, processing and treating services. We
believe the principal elements of competition in our various markets are 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, fuel oils and renewables such as wind and solar. 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.
Sales and Transportation Activities
Our principal market for CO2 is for injection into mature oil fields in the Permian Basin, where industry demand is
expected to remain stable for the next several years. Our ownership of CO2 resources as of December 31, 2016 includes:
Ownership
Interest %
Recoverable
CO2 (Bcf)
Compression
Capacity (Bcf/d)
Location
Recoverable CO2
McElmo Dome unit(a)
Doe Canyon Deep unit(a)
Bravo Dome unit
_______
(a) We also operate this unit.
CO2 Segment Pipelines
45
87
11
4,570
420
367
1.5 Colorado
0.2 Colorado
0.3 New Mexico
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 on the Wink pipeline system are regulated by both the FERC and the Texas Railroad Commission
and the Pecos Carbon Dioxide Pipeline’s tariffs are regulated by the Texas Railroad Commission. The tariff charged on the Cortez
pipeline is based on a consent decree and the tariffs charged by our other CO2 pipelines are not regulated.
11
Our ownership of CO2 and crude oil pipelines as of December 31, 2016 includes:
Asset (KMI ownership shown if not
100%)
Miles of
Pipeline
Transport
Capacity
(Bcf/d)
Supply and Market Region
CO2 pipelines
Cortez pipeline (50%)
Central Basin pipeline
Bravo pipeline (13%)(a)
Canyon Reef Carriers pipeline (98%)
Centerline CO2 pipeline
Eastern Shelf CO2 pipeline
Pecos pipeline (95%)
Goldsmith Landreth (99%)
Crude oil pipeline
Wink pipeline
_______
(a) We do not operate Bravo pipeline.
Oil and Gas Producing Activities
Oil Producing Interests
569
334
218
163
113
98
25
3
457
1.5 McElmo Dome and Doe Canyon source fields to the
Denver City, Texas hub
0.7 Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers,
and Pecos pipelines
0.4 Bravo Dome to the Denver City, Texas hub
0.3 McCamey, Texas, to the SACROC, Sharon Ridge,
Cogdell and Reinecke units
0.3
0.1
between Denver City, Texas and Snyder, Texas
between Snyder, Texas and Knox City, Texas
0.1 McCamey, Texas, to Iraan, Texas, delivers to the Yates
unit
0.2 Goldsmith Landreth San Andres field in the Permian
Basin of West Texas
(Bbls/d)
145,000 West Texas to Western Refining’s refinery in El Paso,
Texas
Our ownership interests in oil-producing fields located in the Permian Basin of West Texas, include the following:
SACROC
Yates
Goldsmith Landreth San Andres
Katz Strawn
Sharon Ridge
Tall Cotton (ROZ)
MidCross
Reinecke(a)
_______
(a) Working interest less than 1 percent.
Working
Interest %
97
KMI Gross
Developed
Acres
49,156
50
99
99
14
100
13
—
9,576
6,166
7,194
2,619
641
320
80
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, 2016. 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:
Crude Oil
Natural Gas
Total Wells
Productive Wells(a)
Net
Gross
Service Wells(b)
Net
Gross
Drilling Wells(c)
Net
Gross
2,239
5
2,244
1,447
2
1,449
12
1,227
—
1,227
984
—
984
6
—
6
6
—
6
_______
(a) Includes active wells and wells temporarily shut-in. As of December 31, 2016, 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, 2016. A development well is a well drilled in an
already discovered oil field.
The following table reflects our net productive wells that were completed in each of the years ended December 31, 2016,
2015 and 2014:
Year Ended December 31,
2015
2014
2016
Productive
Development
Exploratory
Total Productive
Dry Exploratory
Total Wells
40
3
43
—
43
87
20
107
—
107
84
10
94
1
95
_______
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 and completion operations were not finalized as of the end of the applicable year. A completed well
refers to the installation of permanent equipment for the production of oil and gas. A development well is a well drilled in an already
discovered oil field. A dry hole is reflected once the well has been abandoned and reported to the appropriate governmental agency.
Prior year amounts have been adjusted to be consistent with the current period presentation.
The following table reflects the developed and undeveloped oil and gas acreage that we held as of December 31, 2016:
Developed Acres
Undeveloped Acres
Total
Gross
Net
75,752
17,282
93,034
72,561
15,093
87,654
_______
Note: As of December 31, 2016, we have no material amount of acreage expiring in the next three years.
Our oil and gas producing activities are not significant and therefore, we do not include the supplemental information on oil
and gas producing activities under Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas.
Gas and Gasoline Plant Interests
Operated gas plants in the Permian Basin of West Texas:
Snyder gasoline plant(a)
Diamond M gas plant
North Snyder plant
Ownership
Interest %
Source
22 The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and
Cogdell units
51
100
Snyder gasoline plant
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.
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
13
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 refined petroleum product, crude oil, chemical, ethanol and other
liquid 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 terminal facilities. Our terminals are located throughout the U.S. and in portions of
Canada. We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain
existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on
the handling of either liquids or dry-bulk material products. In addition, Terminals’ marine operations include Jones Act
qualified product tankers that provide marine transportation of crude oil, condensate and refined petroleum products in the U.S.
The following summarizes our Terminals segment assets, as of December 31, 2016:
Liquids terminals
Bulk terminals
Jones Act tankers
Competition
Number
51
37
12
Capacity
(MMBbl)
85.2
—
4.0
We are one of the largest independent operators of liquids terminals in North America, 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, pipeline, and refining 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 terminaling services. In some locations, competitors are smaller, independent
operators with lower cost structures. Our Jones Act qualified product tankers compete with other Jones Act qualified vessel
fleets.
14
Products Pipelines
Our Products Pipelines segment consists of our refined petroleum products, crude oil and condensate, and NGL pipelines
and associated terminals, Southeast terminals, our condensate processing facility and our transmix processing facilities. The
following summarizes our significant Products Pipelines segment assets we own and operate as of December 31, 2016:
Asset (KMI ownership shown if
not 100%)
Plantation pipeline (51%)
West Coast Products Pipelines(b)
Miles of
Pipeline
3,182
Pacific (SFPP)
Calnev
West Coast Terminals
Cochin pipeline
KM Crude & Condensate pipeline
Double H Pipeline
Central Florida pipeline
Double Eagle pipeline (50%)
Cypress pipeline (50%)
Southeast Terminals
KM Condensate Processing
Facility
Transmix Operations
2,823
570
43
1,877
252
511
206
194
104
—
—
—
Number of
Terminals
(a) or
locations
—
Terminal
Capacity
(MMBbl)
—
Supply and Market Region
Louisiana to Washington D.C.
13
15.5
six western states
—
2
7
4
5
2
2
32
1
5
2.1 Colton, CA to Las Vegas, NV; Mojave region
10.1
1.1
Seattle, Portland, San Francisco and Los Angeles areas
three provinces in Canada and seven states in the U.S.
2.6 Eagle Ford shale field in South Texas (Dewitt, Karnes,
and Gonzales Counties) to the Houston ship channel
refining complex
—
Bakken shale in Montana and North Dakota to
Guernsey, Wyoming
2.5 Tampa to Orlando
0.6 Live Oak County, Texas; Corpus Christi, Texas;
Karnes County, Texas; and LaSalle County
Mont Belvieu, Texas to Lake Charles, Louisiana
10.8
from Mississippi through Virginia, including
Tennessee
1.9 Houston Ship Channel, Galena Park, Texas
1.0 Colton, California; Richmond, Virginia; Dorsey
Junction, Maryland; 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
15
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.
Major Customers
Our revenue is derived from a wide customer base. For each of the years ended December 31, 2016, 2015 and 2014, 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 operations (includes the operations of Kinder Morgan Tejas Pipeline LLC, Kinder
Morgan Border Pipeline LLC, Kinder Morgan Texas Pipeline LLC, Kinder Morgan North Texas Pipeline LLC and the Mier-
Monterrey Mexico pipeline system) 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 2016, 2015 and 2014 accounted for 19%, 20% and 25%, 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 gathering and transmission 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 gathering or 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.
The Energy Policy Act of 1992 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.
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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 17 “Litigation, Environmental and Other Contingencies” 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, 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 charge 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 agreed upon rates 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, but while the rates
may vary by shipper and circumstance, pipelines must generally use the form of service agreement that is contained within
their FERC approved tariff. Any deviation from the pro forma service agreements must be filed with the FERC and only
certain types of deviations are acceptable to the FERC.
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, the FERC initiated a number of regulatory changes intended to ensure that interstate
natural gas pipelines operated on a not unduly discriminatory basis and to create a more competitive and transparent
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;
• Order Nos. 587, et seq., Order No. 809 (1996-2015) which adopt regulations to standardize the business practices and
communication methodologies of interstate natural gas pipelines to create a more integrated and efficient pipeline grid
and wherein the FERC has incorporated by reference in its regulations standards for interstate natural gas pipeline
business practices and electronic communications that were developed and adopted by the North American Energy
Standards Board (NAESB). Interstate natural gas pipelines are required to incorporate by reference or verbatim in
their respective tariffs the applicable version of the NAESB standards;
• 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);
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• Order No. 637 (2000) which revised, among other things, FERC regulations relating to scheduling procedures,
capacity segmentation, and pipeline penalties in order to improve the competitiveness and efficiency of the interstate
pipeline grid; and
• Order No. 717 (2008) amending the Standards of Conduct for Transmission Providers (the Standards of Conduct or
the Standards) to make them clearer and to refocus the marketing affiliate rules on the areas where there is the greatest
potential for abuse. The FERC standards of conduct address and clarify multiple issues with respect to the actions and
operations of interstate natural gas pipelines and public utilities using a functional approach to ensure that natural gas
transmission is provided on a nondiscriminatory basis, 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 and non-disclosure requirements regarding non-public information;
(iv) independent functioning and no conduit requirements; (v) transparency requirements; and (vi) the interaction of
FERC standards with the NAESB business practice standards. The Standards of Conduct 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 17 “Litigation, Environmental and Other Contingencies” to our consolidated
financial statements.
Railroad Commission of Texas (RCT) Rate Regulation
The intrastate operations of our crude oil and liquids pipelines and natural gas pipelines and storage facilities in Texas are
subject to regulation with respect to such intrastate transportation by the RCT. The RCT 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 Regulatory Commission
The Mier-Monterrey Pipeline has a natural gas transportation permit granted by the Energy Regulatory Commission (the
Commission) that defines the conditions for the pipeline to carry out activity and provide natural gas transportation service.
This permit expires in 2026.
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.
Mexico - Nacional Agency for Industrial Safety and Environmental Protection (ASEA)
ASEA regulates environmental compliance and industrial and operational safety. The Mier-Monterrey Pipeline must
satisfy and maintain ASEA’s requirements, including compliance with certain safety measures, contingency plans, maintenance
plans and the official Mexican standards regarding safety, including a Safety Administration Program.
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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
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 Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 or “PIPES Act of 2016” requires
PHMSA, among others, to set minimum safety standards for underground natural gas storage facilities and allows states to go
above those standards for intrastate pipelines. The Act also authorizes emergency order authority that is tailored to the pipeline
sector, taking into account public health and safety, network, and customer impacts. The financial impact of these two
requirements, if any, is unknown at this time.
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which was signed into law in 2012, 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
Advisory Bulletin requirements, 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.
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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 and under certain circumstances, consistent with our certificate of incorporation,
we have the right to redeem shares of our common stock owned by non-U.S. citizens. 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.
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 $302 million as of December 31, 2016. Our aggregate reserve estimate ranges in value from approximately $302
million to approximately $477 million, and we recorded our liability equal to the low end of the range, as we did not identify
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any amounts within the range as a better estimate of the liability. For additional information related to environmental matters,
see Note 17 “Litigation, Environmental and Other Contingencies” 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
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.
waste. Furthermore, it is possible
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. 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.
EPA Revisions to Ozone National Ambient Air Quality Standard (NAAQS)
As required by the Clean Air Act, EPA establishes National Ambient Air Quality Standards (NAAQS) for how much
pollution is permissible and then the states have to adopt rules so their air quality meets the NAAQS. In October 2015, EPA
published a rule lowering the ground level ozone NAAQS from 75 ppb to a more stringent 70 ppb standard. This change
triggers a process under which EPA will designate the areas of the country that are in or out of attainment with the new
NAAQS standard. Then, certain states will have to adopt more stringent air quality regulations to meet the NAAQS standard.
These new state rules, which are expected in 2020 or 2021, will likely require the installation of more stringent air pollution
controls on newly installed equipment and possibly require retrofitting existing KMI facilities with air pollution controls.
Given the nationwide implications of the new rule, it is expected that it will have financial impacts for each of our business
units.
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
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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 has in the past
considered 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 these
requirements. Operational and/or regulatory changes could require additional facilities to comply with greenhouse gas
emissions reporting and permitting requirements. Additionally, in June 2016, the EPA published a proposed rule regarding the
“Oil and Natural Gas Sector: Emission Standards for New and Modified Sources,” otherwise known as the Proposed New
Source Performance Standard (NSPS) Part OOOOa Rule. This rule is the first federal rule under the Clean Air Act to regulate
methane as a pollutant and would impose additional pollution control and work practice requirements on applicable KMI
facilities.
On October 23, 2015, the EPA published as a final rule the Clean Power Plan, which sets interim and final CO2 emission
performance rates for power generating units that fire coal, oil or natural gas. The final rule is the focus of legislative discussion
in the U.S. Congress and litigation in federal court. On February 10, 2016, the U.S. Supreme Court stayed the final rule,
effectively suspending the duty to comply with the rule until certain legal challenges are resolved. The ultimate resolution of
the final rule’s validity remains uncertain. While we do not operate power plants that would be subject to the Clean Power Plan
final rule, it remains unclear what effect the final rule, if it comes into force, might have on the anticipated demand for natural
gas, including natural gas that we gather, process, store and transport.
At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already
have begun implementing legal measures to reduce emissions of 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
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 such as the proposed Clean Power Plan 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
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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 11,121 full-time people at December 31, 2016, including approximately 907 full-time hourly personnel at
certain terminals and pipelines covered by collective bargaining agreements that expire between 2017 and 2022. We consider
relations with our employees to be good.
Most of our employees are employed by us and 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
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 16 “Reportable Segments” to our consolidated
financial statements.
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(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 Operating our Business
Our businesses are dependent on the supply of and demand for the commodities that we handle.
Our pipelines, terminals and other assets and facilities depend in part on continued production of natural gas, oil and other
products in the geographic areas that they serve. Our business also depends in part on the levels of demand for oil, natural gas,
coal, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other
facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand.
Without additions to oil and gas reserves, 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 pipelines and related facilities 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.
Trends in the business environment, such as declining or sustained low commodity prices, supply disruptions, higher
development costs, or high feedstock prices that adversely impact demand, could result in a slowing of supply to our pipelines,
terminals and other assets. In addition, changes in the regulatory environment or governmental policies may have an impact on
the supply of crude oil, natural gas, coal and other products. Each of these factors impacts our customers shipping through our
pipelines or using our terminals, which in turn could impact the prospects of new contracts for transportation, terminaling or
other midstream services, or renewals of existing contracts.
Implementation of new regulations or changes to existing regulations affecting the energy industry could reduce
production of and/or demand for natural gas, crude oil, refined petroleum products, coal and other hydrocarbons, 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 production of and/or
demand for natural gas, crude oil, refined petroleum products and other products we handle.
Our ability to begin and complete construction on expansion and new-build projects may be inhibited by difficulties in
obtaining permits and rights-of-way, public opposition, cost overruns, inclement weather and other delays.
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 difficulties in obtaining permits and rights-of-way or other regulatory approvals that can
be exacerbated by public opposition to our projects, have caused, and may continue to cause, delays in our construction
projects. Inclement weather, natural disasters and delays in performance by third-party contractors have also resulted in, and
may continue to result in, increased costs or delays in construction. Significant cost overruns or delays could have a material
adverse effect on our return on investment, results of operations and cash flows, and could result in project cancellations or
limit our ability to pursue other growth opportunities.
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We do not own substantially all of the land on which our pipelines are located. If we are unable to procure and maintain
access to land owned by third parties, our revenue and operating costs, and our ability to complete construction projects, could
be adversely affected.
We must obtain and maintain the rights to construct and operate pipelines on other owners’ land, including private
landowners, railroads, public utilities and others. While our interstate natural gas pipelines have federal eminent domain
authority, the availability of eminent domain authority for our other 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. In any case, we must
compensate landowners for the use of their property, and in eminent domain actions, such compensation may be determined by
a court. If we are unable to obtain rights-of-way on acceptable terms, our ability to complete construction projects on time, on
budget, or at all, could be adversely affected. In addition, we are subject to the possibility of increased costs under our right-of-
way or rental agreements with landowners, primarily through renewals of expiring agreements and rental increases. If we were
to lose these rights, our operations could be disrupted or we could be required to relocate the affected pipelines, which could
cause a substantial decrease in our revenues and cash flows and increase our costs.
Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event
they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.
We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as
hedging counterparties, joint venture partners and suppliers. Some of these counterparties may be highly leveraged and subject
to their own operating, market and regulatory risks, and some are experiencing, or may experience in the future, severe
financial problems that have had or may have a significant impact on their creditworthiness.
In the last two years, several of our counterparties defaulted on their obligations to us, and some have filed for bankruptcy
protection. For more information regarding the impact to our operating results from customer bankruptcies, see Item 7
“Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Segment
Earnings Results-Terminals.” We cannot provide any assurance that other financially distressed counterparties will not also
default on their obligations to us or file for bankruptcy protection. If a counterparty files for bankruptcy protection, we likely
would be unable to collect all, or even a significant portion, of amounts that they owe to us. Additional counterparty defaults
and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash
flows. Furthermore, in the case of financially distressed customers, 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, the coal 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. Volatility in
commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers,
which in turn could have a negative impact on their ability to meet their obligations to us. See “—Financial distress
experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us
for the products or services we provide or otherwise fulfill their obligations to us.” In addition, decreases in the prices of crude
oil, NGL and natural gas will have a negative impact on our operating results and cash flow. See “—The volatility of oil and
natural gas prices could have a material adverse effect on our CO2 business segment and businesses within our Natural Gas
Pipeline and Products Pipelines business segments.”
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.
The acquisition of additional businesses and assets is part of our growth strategy. We may experience difficulties
integrating new properties and businesses, and we may be unable to achieve the benefits we expect from any future
acquisitions.
Part of our business strategy includes acquiring additional businesses and assets. If we do not successfully integrate
acquisitions, we may not realize anticipated operating advantages and cost savings. Integration of acquired companies or assets
involves a number of risks, including (i) demands on management related to the increase in our size; (ii) the diversion of
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management’s attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of
accounting, budgeting, reporting and other systems; and (iv) difficulties in the retention and assimilation of necessary
employees.
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 will depend upon our ability to manage those operations and to eliminate
redundant and excess costs. Difficulties in integration may be magnified if we make multiple acquisitions over a relatively
short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost
savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial
condition and results of operations.
We 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 re-contract 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; for example, several pipelines access many of the same areas of supply as our
pipeline systems and transport to destinations not served by us.
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 transportation and storage of crude oil, natural gas, refined
petroleum products, CO2, coal, chemicals and other products -such as leaks, releases, explosions, mechanical problems and
damage caused by third parties. Additional risks to vessels include adverse sea conditions, capsizing, grounding and navigation
errors. 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 cash flows 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.
The volatility of oil, NGL and natural gas prices could adversely affect our CO2 business segment and businesses within
our Natural Gas Pipelines and Products Pipelines business segments.
The revenues, cash flows, profitability and future growth of some of our businesses depend to a large degree on prevailing
oil, natural gas and NGL prices. Our CO2 business segment (and the carrying value of its oil, NGL and natural gas producing
properties) and certain midstream businesses within our Natural Gas Pipelines segment depend to a large degree, and certain
businesses within our Product Pipelines segment depend to a lesser degree, on prevailing oil, NGL and natural gas prices. For
2017, we estimate that every $1 change in the average WTI crude oil price per barrel would impact our distributable cash flow
by approximately $6 million, each $0.10 per MMBtu change in the average price of natural gas would impact distributable cash
flow by approximately $1 million and each 1% change in the ratio of the weighted-average NGL price per barrel to the WTI
crude oil price per barrel would impact 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 instability 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. We use hedging arrangements to partially
mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. Please read “—Our use of
hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility
in our income.”
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A sharp decline in the prices of oil, NGL or natural gas, or a prolonged unfavorable price environment, would result in a
commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and
sell oil, NGL, or natural gas, and could have a material adverse effect on the carrying value of our CO2 business segment’s
proved reserves. If prices fall substantially or remain low for a sustained period and we are not sufficiently protected through
hedging arrangements, we may be unable to realize a profit from these businesses 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.”
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, revenues and cash flows of the oil and gas producing assets within our CO2 business
segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary
financing for these activities in the future. Additionally, if we do not realize production volumes greater than, or equal to, our
hedged volumes, we may suffer financial losses not offset by physical transactions.
The development of oil and gas properties involves risks that may result in a total loss of investment.
The business of developing and operating oil and gas properties involves a high degree of business and financial risk that
even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and
development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by
their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well.
Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological,
operational and market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures,
equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or
delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions,
may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A
productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or
prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is
contaminated with water or other deleterious substances.
Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial
losses or volatility in our income.
We engage in hedging arrangements to reduce our exposure to fluctuations in the prices of oil, NGL 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 markets for instruments we use to hedge our commodity price exposure generally reflect then-prevailing conditions in
the underlying commodity markets. As our existing hedges expire, we will seek to replace them with new hedging
arrangements. To the extent underlying market conditions are unfavorable, new hedging arrangements available to us will
reflect such unfavorable conditions.
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 possible for us to
engage in hedging transactions that eliminate our exposure to commodity prices. Our consolidated financial statements may
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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.
Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business or harm our business
reputation.
The U.S. government has issued public warnings that indicate that pipelines and other infrastructure assets might be
specific targets of terrorist organizations or “cyber security” events. These potential targets might include our pipeline systems,
terminals, processing plants or operating systems. A cyber security event could affect our ability to operate or control our
facilities or disrupt our operations; also, customer information could be stolen. The occurrence of one of these events could
cause a substantial decrease in revenues and cash flows, increased costs to respond or other financial loss, damage to our
reputation, increased regulation or litigation or inaccurate information reported from our operations. There is no assurance that
adequate cyber 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 or harm our
business reputation.
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, and our shipping vessels operate in, areas that are
susceptible to hurricanes, earthquakes and other natural disasters. These natural disasters could potentially damage or destroy
our assets and disrupt the supply of the products we transport. Natural disasters can similarly affect the facilities of our
customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of
operations could be adversely affected, perhaps materially.
Our business requires the retention and recruitment of a skilled workforce, and difficulties recruiting and retaining our
workforce could result in a 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 executive chairman or other executive officers, our ability to execute our business strategy,
including our growth strategy, may be hindered.
Our success depends in part on the performance of and our ability to retain our executive officers, particularly Richard D.
Kinder, our Executive Chairman and one of our founders, and Steve Kean, our President and Chief Executive Officer. 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 and Terminals segments are 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 segments, a
portion of our consolidated assets, liabilities, revenues, cash flows 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 Financing Our Business
Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic
conditions.
As of December 31, 2016, we had approximately $39 billion of consolidated debt (excluding debt fair value adjustments).
Additionally, we and substantially all of our wholly owned subsidiaries are parties to a cross guarantee agreement under which
each party to the agreement unconditionally guarantees the indebtedness of each other party, which means that we are liable for
the debt of each of such subsidiaries. This level of consolidated 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 consolidated debt, and our ability to meet our consolidated leverage targets, 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 consolidated cash flow is
not sufficient to service our consolidated debt, and any future indebtedness that we incur, we will be forced to take actions such
as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling
assets or seeking additional equity capital. We may also take such actions to reduce our indebtedness if we determine that our
earnings (or consolidated earnings before interest, taxes, depreciation and amortization, or EBITDA, as calculated in
accordance with our revolving credit facility) may not be sufficient to meet our consolidated leverage targets, or to comply with
consolidated leverage ratios required under certain of our debt agreements. We may not be able to effect any of these actions
on satisfactory terms or at all. For more information about our debt, see Note 8 “Debt” to our consolidated financial
statements.
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 (which would have a
corresponding impact on the credit ratings of our subsidiaries that are party to the cross guarantee) could cause our cost of
doing business to increase by limiting our access to capital, including our ability to refinance maturities of existing
indebtedness on similar terms, which could in turn limit our ability to pursue acquisition or expansion opportunities and reduce
our cash flows. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions.
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 and the terms available to us for future issuances of
debt securities.
Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in
credit availability impacting our ability to finance our operations on favorable terms. A significant reduction in the availability
of credit could materially and adversely affect our business, financial condition and results of operations.
Our acquisition strategy and growth capital expenditures may require access to external capital. Limitations on our
access to external financing sources could impair our ability to grow.
We have limited amounts of internally generated cash flows to fund acquisitions and growth capital expenditures. We may
have to rely on external financing sources, including commercial borrowings and issuances of debt and equity securities, to
fund our acquisitions and growth capital expenditures. Limitations on our access to external financing sources, whether due to
tightened capital markets, more expensive capital or otherwise, could impair our ability to execute our growth strategy.
Our large amount of variable rate debt makes us vulnerable to increases in interest rates.
As of December 31, 2016, approximately $11 billion of our approximately $39 billion of consolidated debt (excluding debt
fair value adjustments) was subject to variable interest rates, either as short-term or long-term variable-rate debt obligations, or
as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. Should interest rates
increase, the amount of cash required to service this debt would increase, and our earnings and cash flows could be adversely
affected. For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About
Market Risk-Interest Rate Risk.”
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Our 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.
Risks Related to Ownership of Our Capital Stock
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 the expected cash dividends on our common stock and on our preferred stock (or
depositary shares). This reflects our current judgment, but as with any estimate, it may be affected by inaccurate assumptions
and other risks and uncertainties, many of which are beyond our control. See “Information Regarding Forward-Looking
Statements.” If we elect to pay dividends at the anticipated level and that action 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, to maintain our leverage metrics or otherwise to address properly our business prospects,
our business could be harmed.
Conversely, a decision to address such needs might lead to the payment of dividends below the anticipated levels. As
events present themselves or become reasonably foreseeable, our board of directors, which determines our business strategy
and our dividends, may decide to address those matters by reducing our anticipated dividends. Alternatively, because nothing
in our governing documents or credit agreements prohibits us from borrowing to pay dividends, we could choose to incur debt
to enable us to pay our anticipated dividends. This would add to our substantial debt discussed above under “—Risks Related
to Financing Our Business—Our substantial debt could adversely affect our financial health and make us more vulnerable to
adverse economic conditions.”
Our certificate of incorporation restricts the ownership of our common stock by non-U.S. citizens within the meaning of
the Jones Act. These restrictions may affect the liquidity of our common stock and may result in non-U.S. citizens being
required to sell their shares at a loss.
The Jones Act requires, among other things, that at least 75% of our common stock be owned at all times by U.S. citizens,
as defined under the Jones Act, in order for us to own and operate vessels in the U.S. coastwise trade. As a safeguard to help us
maintain our status as a U.S. citizen, our certificate of incorporation provides that, if the number of shares of our common stock
owned by non-U.S. citizens exceeds 22%, we have the ability to redeem shares owned by non-U.S. citizens to reduce the
percentage of shares owned by non-U.S. citizens to 22%. These redemption provisions may adversely impact the marketability
of our common stock, particularly in markets outside of the U.S. Further, stockholders would not have control over the timing
of such redemption, and may be subject to redemption at a time when the market price or timing of the redemption is
disadvantageous. In addition, the redemption provisions might have the effect of impeding or discouraging a merger, tender
offer or proxy contest by a non-U.S. citizen, even if it were favorable to the interests of some or all of our stockholders.
Risks Related to Regulation
New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in effect, could adversely
impact our earnings, cash flows and operations.
Our assets and operations are subject to regulation and oversight by federal, state, provincial and local regulatory
authorities. Legislative changes, as well as regulatory actions taken by these agencies, have the potential to adversely affect our
profitability. In addition, a certain degree of regulatory uncertainty is created by the recent change in U.S. presidential
administrations. It remains unclear specifically what the new administration may do with respect to future policies and
regulations that may affect us. Regulation affects almost every part of our business and extends to such matters as (i) federal,
state, provincial and local taxation; (ii) rates (which include tax, reservation, commodity, surcharges, fuel and gas lost and
unaccounted for), operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the
contracts for service entered into with our customers; (v) the certification and construction of new facilities; (vi) the integrity,
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safety and security of facilities and operations; (vii) the acquisition of other businesses; (viii) the acquisition, extension,
disposition or abandonment of services or facilities; (ix) reporting and information posting requirements; (x) the maintenance
of accounts and records; and (xi) 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 regulatory authorities, we could be
subject to substantial penalties and fines and potential loss of government contracts. Furthermore, new laws, regulations or
policy changes sometimes arise from unexpected sources. New laws or regulations, or different interpretations of existing laws
or regulations, including unexpected policy changes, applicable to our income, operations, assets or another aspect of our
business, could have a material adverse impact on our earnings, cash flow, 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 17 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.
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, shipping vessels or 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 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 believe 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
31
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.”
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
issued by the DOT for 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
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.
Climate change regulation at the federal, state, provincial or regional levels could result in significantly increased
operating and capital costs for us and could reduce demand for our products and services.
Various laws and regulations exist or are under development that seek to regulate the emission of greenhouse gases such as
methane and CO2, including the EPA programs to control greenhouse gas emissions and state actions to develop statewide or
regional programs. Existing EPA regulations require us to report greenhouse gas emissions in the U.S. from sources such as
our larger natural gas compressor stations, fractionated NGL, and production of naturally occurring CO2 (for example, from our
McElmo Dome CO2 field), even when such production is not emitted to the atmosphere. Proposed approaches to further
regulate greenhouse gas emissions include establishing greenhouse gas “cap and trade” programs, increased efficiency
standards, and incentives or mandates for pollution reduction, use of renewable energy sources, or use of alternative fuels with
lower carbon content. For more information about climate change regulation, see Items 1 and 2 “Business and Properties-(c)
Narrative Description of Business-Environmental Matters-Climate Change.”
Adoption of any such laws or regulations could increase our costs to operate and maintain 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. Such laws or regulations could also lead to
reduced demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, which
in turn could adversely affect demand for our products and services.
Finally, some climatic models indicate that global warming is likely to result in rising sea levels and increased frequency
and severity of weather events, which may lead to higher insurance costs, 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.
32
Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows.
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 natural gas pipelines and our own oil and gas
development and production activities.
We gather, process or transport crude oil, natural gas or NGL from several areas in which the use of hydraulic fracturing is
prevalent. 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 crude oil, natural gas or NGL and, in turn, adversely affect our revenues, cash flows and results of operations by
decreasing the volumes of these commodities that we handle.
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.
Derivatives regulation 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. In December 2016, the CFTC re-
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. The Dodd-Frank
Act, related regulations and the reduction in competition due to derivatives industry consolidation have (i) significantly
increased the cost of derivative contracts (including those requirements to post collateral, which could adversely affect our
available liquidity); (ii) reduced the availability of derivatives to protect against risks we encounter; and (iii) reduced 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 and cash flows 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 U.S. point to point maritime shipping vessels,
and failure to comply with the Jones Act, or changes to or a repeal of the Jones Act, could limit our ability to operate our
vessels in the U.S. coastwise trade, result in the forfeiture of our vessels or otherwise adversely impact our earnings, cash flows
and operations.
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
33
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.
Item 1B. Unresolved Staff Comments.
None.
Item 3. Legal Proceedings.
See Note 17 “Litigation, Environmental and Other Contingencies” 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.
34
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.” The high and low sale prices per
Class P share as reported on the NYSE and the dividends declared per share by period for 2016, 2015 and 2014, are provided
below.
2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2015
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2014
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Price Range
Low
High
Declared Cash
Dividends(a)
$
11.20
$
19.32
$
16.63
17.95
19.43
39.45
38.33
25.81
14.22
$
19.40
23.20
23.36
42.93
44.71
38.58
32.89
$
$
$
30.81
$
36.45
$
32.10
35.20
33.25
36.50
42.49
43.18
0.125
0.125
0.125
0.125
0.48
0.49
0.51
0.125
0.42
0.43
0.44
0.45
_______
(a) Dividend information is for dividends declared with respect to that quarter. Generally, our declared dividends for our Class P common
stock are paid on or about the 15th day of each February, May, August and November.
As of February 9, 2017, we had 12,386 holders of our Class P common stock, which does not include beneficial owners
whose shares are held by a nominee, such as a broker or bank.
For information on our equity compensation plans, see Note 10 “Share-based Compensation and Employee Benefits—
Share-based Compensation” to our consolidated financial statements.
On June 12, 2015, we announced that our board of directors had approved a warrant repurchase program authorizing us to
repurchase up to $100 million of warrants. As of December 31, 2016, we had approximately $90 million of remaining
approved funds under this warrant repurchase program. The warrants expire on May 25, 2017.
35
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
Income and Cash Flow Data:
Revenues
Operating income
Earnings from equity investments
Income from continuing operations
Loss from discontinued operations, net of tax
Net income
Net income attributable to Kinder Morgan, Inc.
Net income available to common stockholders
Class P Shares
As of or for the Year Ended December 31,
2016
2015
2014
2013
2012
(In millions, except per share amounts)
$
13,058
$
14,403
$
16,226
$
14,070
$
3,572
2,447
497
721
—
721
708
552
414
208
—
208
253
227
4,448
406
2,443
—
2,443
1,026
1,026
3,990
327
2,696
(4)
2,692
1,193
1,193
9,973
2,593
153
1,204
(777)
427
315
315
0.25
$
0.10
$
0.89
$
1.15
$
0.56
Basic and Diluted Earnings Per Common Share From
Continuing Operations
Basic and Diluted Loss Per Common Share From
Discontinued Operations
Total Basic and Diluted Earnings Per Common Share
$
$
Class A Shares
Basic and Diluted Earnings Per Common Share From
Continuing Operations
Basic and Diluted Loss Per Common Share From
Discontinued Operations
Total Basic and Diluted Earnings Per Common Share
Basic Weighted Average Common Shares Outstanding:
Class P shares
Class A shares
Diluted Weighted Average Common Shares Outstanding:
Class P shares
Class A shares
—
—
—
—
0.25
$
0.10
$
0.89
$
1.15
$
$
$
2,230
2,187
1,137
1,036
2,230
2,193
1,137
1,036
Dividends per common share declared for the period(a)
$
Dividends per common share paid in the period(a)
0.50
0.50
$
1.605
$
1.93
$
1.74
1.70
$
1.60
1.56
Balance Sheet Data (at end of period):
Property, plant and equipment, net
$
38,705
$
40,547
$
38,564
$
35,847
$
Total assets
Long-term debt(b)
80,305
36,205
84,104
40,732
83,049
38,312
75,071
31,910
_______
(a) Dividends for the fourth quarter of each year are declared and paid during the first quarter of the following year.
(b) Excludes debt fair value adjustments. Increases to long-term debt for debt fair value adjustments totaled $1,149 million, $1,674 million,
$1,785 million, $1,863 million and $2,479 million as of December 31, 2016, 2015, 2014, 2013 and 2012, respectively.
36
(0.21)
0.35
0.47
(0.21)
0.26
461
446
908
446
1.40
1.34
30,996
68,133
29,409
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 2016, 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 natural gas, liquids products and bulk commodity 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—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and
storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii)
NGL fractionation facilities and transportation systems; and (iv) LNG facilities;
• 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—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and
portions of Canada that transload and store refined petroleum products, crude oil, chemicals, and ethanol and bulk
products, including coal, petroleum coke, fertilizer, steel and ores and (ii) Jones Act tankers;
•
Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate
pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, crude oil and condensate
to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline
transmix facilities; and
37
• Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil
and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British
Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the
Vancouver (Canada) International Airport.
As an energy infrastructure owner and operator in multiple facets of the 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, related storage facilities and LNG terminals, 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 or store 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 Pipeline operations,
currently derives approximately 77% of its sales and transport margins from long-term transport and sales contracts. As
contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of
December 31, 2016, the remaining weighted average contract life of our natural gas transportation contracts (including
intrastate pipelines’ purchase and sales contracts) was approximately six years.
Our midstream assets provide gathering and processing services for natural gas and gathering services for crude oil. These
assets are generally fee-based and 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 affected by the
volumes of natural gas made available to our systems. Such volumes are impacted by producer rig count and drilling activity.
In addition to fee based arrangements, we also provide some services based on percent-of-proceeds, percent-of-index and keep-
whole contracts some of which may include minimum volume requirements. Our service 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.
The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which
as of December 31, 2016, had a remaining average contract life of approximately nine 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 2017, and utilizing the average oil price per barrel contained in our 2017 budget,
approximately 98% of our revenue is based on a fixed fee or floor price, and 2% 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
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 the hedges allocated to oil, was $61.52 per barrel in 2016, $73.11 per
barrel in 2015, and $88.41 per barrel in 2014. Had we not used energy derivative contracts to transfer commodity price risk,
our crude oil sales prices would have averaged $41.36 per barrel in 2016, $47.56 per barrel in 2015, and $86.48 per barrel in
2014.
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. 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. 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
38
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 steel, coal and petroleum coke. For the most part, we have
contracts for this business that contain minimum volume guarantees and/or service exclusivity arrangements under which
customers are required to utilize our terminals for all or a specified percentage of their handling and storage needs. The
profitability of our minimum volume contracts is generally unaffected by short-term variation in economic conditions;
however, to the extent we expect volumes above the minimum and/or have contracts which are volume-based we can be
sensitive to changing market conditions. 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. In addition to
liquid and bulk terminals, we also own Jones Act tankers. As of December 31, 2016, we have twelve Jones Act qualified
tankers that operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are currently
operating pursuant to multi-year predominately fixed price charters with major integrated oil companies, major refiners and the
U.S. Military Sealift Command.
The profitability of our refined petroleum products pipeline transportation and storage business is generally driven by the
volume of refined petroleum products that we transport and the prices we receive for our services. We also have approximately
55 liquids terminals in this business segment that store fuels and offer blending services for ethanol and biofuels.
The transportation and storage 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 crude and condensate transportation services are primarily provided either pursuant to (i) long-term contracts that
normally contain minimum volume commitments or (ii) through terms prescribed by the toll settlements with shippers and
approved by regulatory authorities. As a result of these contracts, our settlement volumes are generally not sensitive to
changing market conditions in the shorter term, however, in the longer term the revenues and earnings we realize from our
crude and condensate pipelines in the U.S. and Canada are affected by the volumes of crude and condensate available to our
pipeline systems, which are impacted by the level of oil and gas drilling activity in the respective producing regions that we
serve. Our petroleum condensate processing facility splits condensate into its various components, such as light and heavy
naphtha, under a long-term fee-based agreement with a major integrated oil company.
A portion of our business portfolio transacts in and/or uses the Canadian dollar as the functional currency, which affects
segment results due to the variability in U.S. - Canadian dollar exchange rates. Our Canadian operations are included in three
of our business segments: (i) our Kinder Morgan Canada segment, which is comprised of the Trans Mountain pipeline, an
oversubscribed common carrier crude oil and refined petroleum pipeline serving western Canada, the Trans Mountain (Puget)
pipeline serving Washington state; and the Jet Fuel pipeline serving Vancouver International Airport; (ii) terminal facilities
located in western Canada that are included in our Terminals business segment; and (iii) the Canadian portion of our Cochin
pipeline, which is included in our Products Pipelines business segment.
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.
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.
39
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) revenue recognition and income taxes, (ii) the
economic useful lives of our assets and related depletion rates; (iii) the fair values used to assign purchase price from business
combinations, determine possible asset and equity investment impairment charges, and calculate the annual goodwill
impairment test; (iv) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (v)
provisions for uncollectible accounts receivables; and (vi) exposures under contractual indemnifications.
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.
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 17 “Litigation, Environmental and Other Contingencies” to our
consolidated financial statements.
Legal and Regulatory 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 17 “Litigation, Environmental
and Other Contingencies” to our consolidated financial statements.
40
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 goodwill for
impairment on May 31 of each year. At year end and during other interim periods we evaluate our reporting units for events
and changes that could indicate that it is more likely than not that the fair value of a reporting unit could be less than its
carrying amount.
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.
Hedging Activities
We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy
commodity prices, foreign currency exposure on Euro denominated debt, 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.
All of our derivative contracts are recorded at estimated fair value. We utilize published prices, broker quotes, and
estimates of market prices to estimate the fair value of these contracts; however, actual amounts could vary materially from
estimated fair values as a result of changes in market prices. In addition, changes in the methods used to determine the fair
value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the
methods used to determine the fair value of these derivative contracts. For more information on our hedging activities, see Note
14, “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, 2016, our pension plans were underfunded by $724 million and our other
postretirement benefits plans were underfunded by $141 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 utilize a
full yield curve approach in the estimation of the service and interest cost components of net periodic benefit cost (credit) for
our pension and other postretirement benefit plans which applies the specific spot rates along the yield curve used in the
determination of the benefit obligation to their underlying projected cash flows. The selection of these assumptions is further
discussed in Note 10 “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
expected future service of active participants, or over the expected future lives of inactive plan participants. As of
December 31, 2016, we had deferred net losses of approximately $613 million in pretax accumulated other comprehensive loss
and noncontrolling interests related to our pension and other postretirement benefits.
41
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, 2016:
One percent increase in:
Discount rates
Expected return on plan assets
Rate of compensation increase
Health care cost trends
One percent decrease in:
Discount rates
Expected return on plan assets
Rate of compensation increase
Health care cost trends
Pension Benefits
Net benefit
cost (income)
Change in
funded status(a)
Other Postretirement Benefits
Change in
funded status(a)
Net benefit cost
(income)
(In millions)
$
(10) $
236
$
(21)
4
—
12
21
(3)
—
—
(11)
—
(278)
—
10
—
(1) $
(3)
—
3
—
3
—
(4)
37
—
—
(31)
(42)
—
—
27
_______
(a) Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for
certain of our regulated operations.
Income Taxes
Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the
relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are
effective. 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.
Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and
liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance for the 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 determining the deferred income tax asset and liability balances attributable to our investments, we apply 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
Overview
Our management evaluates our performance primarily using the measures of Segment EBDA and, as discussed below
under “—Non-GAAP Measures,” distributable cash flow, or DCF, and Segment EBDA before certain items. Segment EBDA is
a useful measure of our operating performance because it measures the operating results of our segments before DD&A and
certain expenses that are generally not controllable by our business segment operating managers, such as general and
administrative expenses, interest expense, net, and income taxes. Our general and administrative expenses include such items
as employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services
including accounting, information technology, human resources and legal services.
42
Segment results for the years ended December 31, 2015 and 2014 have been retrospectively adjusted to reflect the
elimination of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now
presented within the Corporate non-segment activities in reconciling to the consolidated totals in the respective segment
reporting tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not
associated with our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition,
the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries
as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interest
income and income tax expense previously allocated to our business segments are now included in “Interest expense, net” and
“Income tax expense” for all periods presented in the following tables.
Consolidated Earnings Results
Year Ended December 31,
2016
2015
2014
(In millions)
Segment EBDA(a)
Natural Gas Pipelines
CO2
Terminals
Products Pipelines
Kinder Morgan Canada
Total segment EBDA(b)
DD&A
Amortization of excess cost of equity investments
General and administrative expenses(c)
Interest expense, net(d)
Corporate(e)
Income before income taxes
Income tax expense
Net income
$
3,211
$
3,067
$
827
1,078
1,067
181
6,364
(2,209)
(59)
(669)
(1,806)
17
1,638
(917)
721
(13)
708
(156)
552
658
878
1,106
182
5,891
(2,309)
(51)
(690)
(2,051)
(18)
772
(564)
208
45
253
(26)
227
$
$
4,264
1,248
973
856
200
7,541
(2,040)
(45)
(610)
(1,798)
43
3,091
(648)
2,443
(1,417)
1,026
—
1,026
Net (income) loss attributable to noncontrolling interests
Net income attributable to Kinder Morgan, Inc.
Preferred Stock Dividends
Net Income Available to Common Stockholders
$
_______
(a) Includes revenues, earnings from equity investments, and other, net, less operating expenses, other expense (income), net, losses on
impairments of goodwill, losses on impairments and divestitures, net and losses on impairments and divestitures of equity investments,
net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
Certain items affecting Total Segment EBDA (see “—Non-GAAP Measures” below)
(b) 2016, 2015 and 2014 amounts include decreases in earnings of $1,121 million, $1,748 million and $67 million, respectively, related to
the combined net effect of the certain items impacting Total Segment EBDA. The extent to which these items affect each of our business
segments is discussed below in the footnotes to the tables within “—Segment Earnings Results.”
(c) 2016, 2015 and 2014 amounts include decreases (increase) to expense of $5 million, $(25) million and $28 million, respectively, related
to the combined net effect of the certain items related to general and administrative expenses disclosed below in “—General and
Administrative, Interest, Corporate and Noncontrolling Interests.”
(d) 2016, 2015 and 2014 amounts include decreases in expense of $193 million, $27 million and $3 million, respectively, related to the
combined net effect of the certain items related to interest expense, net disclosed below in “—General and Administrative, Interest,
Corporate and Noncontrolling Interests.”
(e) 2016, 2015 and 2014 amounts include decreases (increase) to expense of $8 million, $(35) million and $22 million, respectively, related
to the combined net effect of the certain items related to Corporate activities disclosed below in “—General and Administrative, Interest,
Corporate and Noncontrolling Interests.
43
Year Ended December 31, 2016 vs. 2015
The certain item totals reflected in footnotes (b), (c), (d) and (e) to the table above accounted for $866 million of the
increase in income before income taxes in 2016 as compared to 2015 (representing the difference between decreases of $915
million and $1,781 million in income before income taxes for 2016 and 2015, respectively). After giving effect to these certain
items, which are discussed in more detail in the discussion that follows, income before income taxes for 2016 when compared
to the prior year was flat. Increased results in our Products Pipelines and Terminals business segments and decreased DD&A
expense and interest expense, net, were offset by unfavorable commodity prices affecting our CO2 business segment and
decreased results on our Natural Gas Pipelines business segment. The decrease in DD&A was primarily driven by lower
DD&A in our CO2 business segment and the decrease in interest expense was due to lower weighted average debt balances,
partially offset by a slightly higher overall weighted average interest rate on outstanding debt.
Year Ended December 31, 2015 vs. 2014
The certain item totals reflected in footnotes (b), (c), (d) and (e) to the table above accounted for $1,767 million of the
decrease in income before income taxes in 2015 as compared to 2014 (representing the difference between decreases of $1,781
million and $14 million in income before income taxes for 2015 and 2014, respectively). After giving effect to these certain
items, which are discussed in more detail in the discussion that follows, the remaining decrease of $552 million (18%) from the
prior year in income before income taxes is primarily attributable to increased DD&A expense, general and administrative
expense and interest expense, net. As explained further below, our total segment earnings before DD&A did not change
significantly when compared to the prior year as unfavorable commodity prices affecting our CO2 business segment were offset
by increased results from our Products Pipelines, Terminals and Natural Gas Pipelines business segments.
Non-GAAP Financial Measures
Our non-GAAP performance measures are DCF, both in the aggregate and per share, and Segment EBDA before certain
items. Certain items are items that are required by GAAP to be reflected in net income, but typically either (i) do not have a
cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business
operations and in our view are likely to occur only sporadically (for example certain legal settlements, hurricane impacts and
casualty losses).
Our non-GAAP performance measures described below should not be considered alternatives to GAAP net income or
other GAAP measures and have important limitations as analytical tools. Our computations of DCF and Segment EBDA
before certain items may differ from similarly titled measures used by others. You should not consider these non-GAAP
performance measures in isolation or as substitutes for an analysis of our results as reported under GAAP. DCF should not be
used as an alternative to net cash provided by operating activities computed under GAAP. Management compensates for the
limitations of these non-GAAP performance 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 is a significant performance measure used by us and by external users of our financial statements to evaluate our
performance and to measure and estimate the ability of our assets to generate cash earnings after servicing our debt and
preferred stock dividends, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes
such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. Management uses
this performance measure and believes it provides users of our financial statements a useful performance measure reflective of
our business’s ability to generate cash earnings to supplement the comparable GAAP measure. We believe the GAAP measure
most directly comparable to DCF is net income available to common stockholders. A reconciliation of DCF to net income
available to common stockholders is provided in the table below. DCF per share is DCF divided by average outstanding shares,
including restricted stock awards that participate in dividends.
Segment EBDA Before Certain Items
Segment EBDA before certain items is used by management in its analysis of segment performance and management of
our business. General and administrative expenses are generally not under the control of our segment operating managers, and
therefore, are not included when we measure business segment operating performance. We believe Segment EBDA before
certain items is a significant performance metric because it provides us and external users of our financial statements additional
insight into the ability of our segments to generate segment cash earnings on an ongoing basis. We believe it is useful to
44
investors because it is a performance measure that management uses to allocate resources to our segments and assess each
segment’s performance. We believe the GAAP measure most directly comparable to Segment EBDA before certain items is
segment earnings before DD&A and amortization of excess cost of equity investments (Segment EBDA).
In the tables for each of our business segments under “— Segment Earnings Results” below, Segment EBDA before certain
items is calculated by adjusting the Segment EBDA for the applicable certain item amounts, which are totaled in the tables and
described in the footnotes to those tables.
Reconciliation of Net Income Available to Common Stockholders to DCF
Net Income Available to Common Stockholders
Add/(Subtract):
Certain items before book tax(a)
Book tax certain items(b)
Certain items after book tax
Noncontrolling interest certain items(c)
Net income available to common stockholders before certain items
Add/(Subtract):
DD&A expense(d)
Total book taxes(e)
Cash taxes(f)
Other items(g)
Sustaining capital expenditures(h)
Net income attributable to noncontrolling interests of our former master limited partnerships
Declared distributions to noncontrolling interests(i)
DCF
Year Ended December 31,
2014
2015
2016
(In millions)
$
552
$ 227
$ 1,026
915
18
933
1,781
(340)
1,441
(8)
1,477
(63)
1,605
14
(117)
(103)
—
923
2,617
2,683
2,390
993
(79)
43
(540)
—
—
$ 4,511
976
(32)
32
(565)
840
(448)
17
(509)
— 1,405
— (2,000)
$ 2,618
$ 4,699
Weighted average common shares outstanding for dividends(j)
DCF per common share
Declared dividend per common share
2,238
2,200
1,312
$
2.02
$ 2.14
$ 2.00
0.500
1.605
1.740
_______
(a) Consists of certain items summarized in footnotes (b) through (e) to the “—Results of Operations—Consolidated Earnings Results”
table included above, and described in more detail below in the footnotes to tables included in both our management’s discussion and
analysis of segment results and “—General and Administrative, Interest, Corporate and Noncontrolling Interests.”
(b) Represents income tax provision on certain items plus discrete income tax items. For 2016, discrete income tax items included a $276
million increase in tax expense primarily due to the impact of the sale of a 50% interest in SNG discussed in Note 5 “Income Taxes” to
our consolidated financial statements.
(c) Represents noncontrolling interests share of certain items.
(d) Includes DD&A, amortization of excess cost of equity investments and our share of equity investee’s DD&A of $349 million, $323
million and $305 million in 2016, 2015 and 2014, respectively.
(e) Excludes book tax certain items. 2016, 2015 and 2014 amounts also include $94 million, $72 million and $75 million, respectively, of
(f)
our share of taxable equity investee’s book tax expense.
Includes our share of taxable equity investee’s cash taxes of $(76) million, $(19) million and $(27) million in 2016, 2015 and 2014,
respectively.
(g) For 2016 and 2015, consists primarily of non-cash compensation associated with our restricted stock awards program and for 2014
consists primarily of excess coverage from our former master limited partnerships.
(h) Includes our share of equity investee’s sustaining capital expenditures of $(90) million, $(70) million and $(59) million in 2016, 2015
and 2014, respectively.
(i) Represents distributions to KMP and EPB limited partner units formerly owned by the public for the respective period.
(j)
Includes restricted stock awards that participate in common share dividends and, for 2015, the dilutive effect of warrants. 2014 amount
also includes the common shares issued on November 26, 2014 for the Merger Transactions as if outstanding for the entire fourth quarter
which differs from our GAAP presentation on our Consolidated Statement of Income.
45
Segment Earnings Results
Natural Gas Pipelines
Revenues(a)
Operating expenses
Loss on impairment of goodwill(b)
Loss on impairments and divestitures, net(b)
Other income
Earnings from equity investments
Loss on impairments of equity investments(b)
Other, net
Segment EBDA(b)(c)
Certain items(b)
Segment EBDA before certain items(c)
Change from prior period
Revenues before certain items
Segment EBDA before certain items
Natural gas transport volumes (BBtu/d)(d)
Natural gas sales volumes (BBtu/d)
Natural gas gathering volumes (BBtu/d)(d)
Crude/condensate gathering volumes (MBbl/d)(d)
Year Ended December 31,
2016
2015
2014
(In millions, except operating statistics)
$
$
$
$
$
8,005
(4,393)
—
(200)
1
385
(606)
19
3,211
825
$
8,725
(4,738)
(1,150)
(122)
3
351
(26)
24
3,067
1,062
4,036
$
4,129
$
Increase/(Decrease)
(477) $
(93) $
(1,479)
55
10,168
(6,241)
—
(5)
—
318
—
24
4,264
(190)
4,074
28,095
2,335
2,970
308
28,196
2,419
3,540
340
26,917
2,334
3,394
298
_______
Certain items affecting Segment EBDA
(a) 2016 and 2014 amounts include decreases in revenues of $50 million and $2 million, respectively, and 2015 amount includes an increase
in revenues of $32 million, all related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and
crude oil sales. 2016 amount also includes an increase in revenue of $39 million associated with revenue collected on a customer’s early
buyout of a long-term natural gas storage contract. 2015 and 2014 amounts also include increases in revenues of $200 million and $198
million, respectively, associated with amounts collected on the early termination of long-term natural gas transportation contracts on
KMLP.
(b) In addition to the revenue certain items described in footnote (a) above, 2016 amount also includes (i) $613 million related to equity
investment impairments primarily related to our investments in MEP and Ruby; (ii) a decrease in earnings of $106 million of project
write-offs; (iii) an $84 million pre-tax loss on the sale of a 50% interest in our SNG natural gas pipeline system; (iv) an increase in
earnings of $18 million related to the early termination of a customer contract at an equity investee; and (v) a decrease in earnings of $29
million from other certain items. 2015 amount also includes (i) $1,150 million of losses related to goodwill impairments on our non-
regulated midstream reporting unit; (ii) $52 million of losses related to divestitures of our non-regulated midstream assets; (iii) $47
million of losses related to other impairments on our non-regulated midstream assets; (iv) $26 million of impairments on equity
investments; and (v) a $19 million net decrease in earnings related to project write-offs and other certain items. 2014 amount also
includes a $6 million decrease in earnings from other certain items.
Other
(c) Income tax expense and interest income that were allocated to and presented in Segment EBDA in prior periods are presented herein in
income tax expense and interest expense, net, respectively, to conform to our current presentation as discussed above in “—Overview.”
The amounts for 2016, 2015 and 2014 were $7 million, $4 million and $6 million, respectively, in income tax expense and for 2014, $1
million in interest income.
(d) Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included at our ownership share for the
entire period, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.
46
Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2016 and 2015,
when compared with the respective prior year:
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Segment EBDA before
certain items
increase/(decrease)
Revenues before
certain items
increase/(decrease)
SNG
South Texas Midstream
KinderHawk
KMLP
CIG
CPG
TransColorado
TGP
Hiland Midstream
Texas Intrastate Natural Gas Pipeline Operations
All others (including eliminations)
Total Natural Gas Pipelines
$
$
(109)
(62)
(48)
(31)
(27)
(22)
(15)
171
59
7
(16)
(93)
$
(25)%
(18)%
(36)%
(In millions, except percentages)
(188)
(229)
(51)
(34)
(31)
(23)
(16)
205
(135)%
(48)%
(37)%
(9)%
18%
42%
2%
(1)%
(2)%
$
152
(278)
16
(477)
(33)%
(18)%
(33)%
(100)%
(8)%
(29)%
(42)%
17%
38%
(9)%
1%
(6)%
The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following
discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:
•
•
•
•
•
•
•
•
•
•
decrease of $109 million (25%) from SNG primarily due to our sale of a 50% interest in SNG to The Southern
Company (Southern Company) on September 1, 2016;
decrease of $62 million (18%) from South Texas Midstream primarily due to lower volumes and price. Revenue
decreased approximately $229 million partially offset by a decrease in costs of sales;
decrease of $48 million (36%) from KinderHawk due to lower volumes;
decrease of $31 million (135%) from KMLP as a result of a customer contract buyout in the fourth quarter of 2015;
decrease of $27 million (9%) from CIG primarily due to a recent rate case settlement and lower firm reservation
revenues due to contract expirations and contract renewals at lower rates;
decrease of $22 million (37%) from CPG primarily due to lower transport revenues as a result of contract expirations;
decrease of $15 million (48%) from TransColorado primarily due to lower transport revenues as a result of contract
expirations;
increase of $171 million (18%) from TGP primarily due to a full year of earnings from expansion projects placed in
service during 2015 and favorable 2016 firm transport revenues;
increase of $59 million (42%) from Hiland Midstream primarily due to favorable margins on renegotiated contracts,
along with results of a full year from our February 2015 Hiland acquisition; and
increase of $7 million (2%) from our Texas intrastate natural gas pipeline operations (including the operations of its
Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems)
primarily due to higher storage margins partially offset by lower sales and transportation margins as a result of lower
volumes. The decrease in revenues of $278 million resulted primarily from a decrease in sales revenue due to lower
commodity prices which was largely offset by a corresponding decrease in costs of sales.
47
Year Ended December 31, 2015 versus Year Ended December 31, 2014
Segment EBDA before
certain items
increase/(decrease)
Revenues before
certain items
increase/(decrease)
(In millions, except percentages)
140
36
35
31
15
(67)
(38)
(33)
(24)
(21)
(9)
(10)
55
n/a
4%
9%
443%
4%
(34)%
(57)%
(59)%
(29)%
(35)%
(3)%
(1)%
1%
$
$
404
48
56
n/a
(1,231)
(69)
(247)
(34)
(24)
(60)
(417)
95
(1,479)
n/a
4%
10%
n/a
(30)%
(31)%
(47)%
(50)%
(24)%
(37)%
(25)%
7%
(15)%
$
$
Hiland Midstream
TGP
EPNG
EagleHawk(a)
Texas Intrastate Natural Gas Pipeline Operations
KinderHawk
Oklahoma Midstream
KMLP
CPG
Altamont Midstream
South Texas Midstream
All others (including eliminations)
Total Natural Gas Pipelines
_______
n/a - not applicable
(a) Equity investment.
The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following
discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2015 and 2014:
•
•
•
•
•
•
•
•
•
•
•
increase of $140 million from our February 2015 acquisition of the Hiland Midstream asset;
increase of $36 million (4%) from TGP primarily due to higher revenues from firm transportation and storage services
due largely to expansion projects placed in service in the fourth quarter 2014 and during 2015. Partially offsetting this
was an increase in the provision for revenue sharing during 2015, lower transportation usage revenues and natural gas
park and loan revenues due to milder winter weather in 2015 and higher ad valorem taxes;
increase of $35 million (9%) from EPNG due largely to additional firm transport revenues due, in part, to additional
demand from Mexico;
increase of $31 million (443%) from EagleHawk driven by higher volumes and lower pipeline integrity costs;
increase of $15 million (4%) from our Texas Intrastate Natural Gas Pipeline operations (including the operations of its
Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems) due
largely to higher transportation and natural gas sales margins as a result of new customer contracts, partially offset by
lower processing margins due to the non-renewal of a customer contract in the second quarter of 2014 and lower
storage margins. The decrease in revenues of $1,231 million and associated decrease in costs of goods sold were
caused by lower natural gas prices;
decrease of $67 million (34%) from KinderHawk primarily due to the expiration of a minimum volume contract;
decrease of $38 million (57%) from Oklahoma Midstream primarily due to lower commodity prices and lower
volumes. Lower revenues of $247 million and associated decrease in costs of goods sold were also due to lower
commodity prices;
decrease of $33 million (59%) from KMLP as a result of a customer contract buyout in the third quarter of 2014;
decrease of $24 million (29%) from CPG due primarily to lower transport revenues as a result of contract expirations;
decrease of $21 million (35%) from Altamont Midstream primarily due to lower commodity prices partially offset by
higher volumes; and
decrease of $9 million (3%) from South Texas Midstream primarily due to lower commodity prices, partially offset by
higher gathering and processing volumes. Lower revenues of $417 million and associated decrease in costs of goods
sold were due to lower commodity prices.
48
CO2
Revenues(a)
Operating expenses
Loss on impairments and divestitures, net(b)
Earnings from equity investments(b)
Segment EBDA(b)(c)
Certain items(b)
Segment EBDA before certain items(c)
Change from prior period
Revenues before certain items
Segment EBDA before certain items
Southwest Colorado CO2 production (gross) (Bcf/d)(d)
Southwest Colorado CO2 production (net) (Bcf/d)(d)
SACROC oil production (gross)(MBbl/d)(e)
SACROC oil production (net)(MBbl/d)(f)
Yates oil production (gross)(MBbl/d)(e)
Yates oil production (net)(MBbl/d)(f)
Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d)(e)
Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d)(f)
NGL sales volumes (net)(MBbl/d)(f)
Realized weighted-average oil price per Bbl(g)
Realized weighted-average NGL price per Bbl(h)
Year Ended December 31,
2016
2015
2014
(In millions, except operating statistics)
$
$
$
$
$
$
$
1,221
(399)
(19)
24
827
92
$
1,699
(432)
(606)
(3)
658
484
919
$
1,142
$
Increase/(Decrease)
(267) $
(223) $
(384)
(324)
1.2
0.6
29.3
24.4
18.4
8.2
7.0
5.9
1.2
0.6
33.8
28.1
19.0
8.5
5.7
4.8
10.3
61.52
17.91
$
$
10.4
73.11
18.35
$
$
1,960
(494)
(243)
25
1,248
218
1,466
1.3
0.5
33.2
27.6
19.5
8.8
4.9
4.1
10.1
88.41
41.87
_______
Certain items affecting Segment EBDA
(a) 2016, 2015 and 2014 amounts include an unrealized loss of $63 million, and unrealized gains of $138 million and $25 million,
respectively, all relating to derivative contracts used to hedge forecasted commodity sales. 2015 amount also includes a favorable
adjustment of $10 million related to carried working interest at McElmo Dome.
(b) In addition to the revenue certain items described in footnote (a) above: 2016 amount also includes a decrease of $9 million in equity
earnings for our share of a project write-off recorded by an equity investee and a $20 million increase in expense related to source and
transportation project write-offs. 2015 amount also includes (i) oil and gas property impairments of $399 million; (ii) project write-offs
of $207 million; and (iii) a $26 million decrease in equity earnings for our share of a project write-off. 2014 amount also includes oil
and gas property impairments of $243 million.
Other
(c) Income tax expense that was allocated to and presented in Segment EBDA in prior periods is presented herein in income tax expense to
conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $2 million, $1
million and $8 million, respectively, in income tax expense.
(d) Includes McElmo Dome and Doe Canyon sales volumes.
(e) Represents 100% of the production from the field. We own approximately 97% working interest in the SACROC unit, an approximately
50% working interest in the Yates unit, an approximately 99% working interest in the Katz unit and a 99% working interest in the
Goldsmith Landreth unit and a 100% working interest in the Tall Cotton field.
(f) Net after royalties and outside working interests.
(g) Includes all crude oil production properties.
(h) Includes production attributable to leasehold ownership and production attributable to our ownership in processing plants and third party
processing agreements.
49
Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2016 and 2015,
when compared with the respective prior year:
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Segment EBDA before
certain items
increase/(decrease)
Revenues before
certain items
increase/(decrease)
Source and Transportation Activities
Oil and Gas Producing Activities
Intrasegment eliminations
Total CO2
$
$
(27)
(196)
—
(223)
$
(8)%
(In millions, except percentages)
(36)
(241)
10
(267)
(20)%
(24)%
—%
$
(9)%
(20)%
21%
(17)%
The changes in Segment EBDA for our CO2 business segment are further explained by the significant factors driving
Segment EBDA before certain items in the comparable years of 2016 and 2015 which factors include lower revenues of $205
million from lower commodity prices and $72 million due to decreased volumes, partially offset by (i) $27 million in reduced
operating costs; (ii) $15 million of lower severance and ad valorem tax expenses; and (iii) $11 million primarily related to
increased earnings from an equity investee.
Year Ended December 31, 2015 versus Year Ended December 31, 2014
Segment EBDA before
certain items
increase/(decrease)
Revenues before
certain items
increase/(decrease)
Source and Transportation Activities
Oil and Gas Producing Activities
Intrasegment Eliminations
Total CO2
$
$
(122)
(202)
—
(324)
$
(27)%
(In millions, except percentages)
(116)
(303)
35
(384)
(20)%
(22)%
—%
$
(23)%
(20)%
42%
(20)%
The changes in Segment EBDA for our CO2 business segment are further explained by the significant factors driving
Segment EBDA before certain items in the comparable years of 2015 and 2014 which factors include lower revenues of $405
million from lower commodity prices partially offset by $62 million of increased volumes and $27 million in reduced operating
expenses.
50
Terminals
Revenues(a)
Operating expenses
Loss on impairments and divestitures, net(b)
Other income
Earnings from equity investments
Loss on impairments and divestitures of equity investments, net(b)
Other, net
Segment EBDA(b)(c)
Certain items, net(b)
Segment EBDA before certain items(c)
Change from prior period
Revenues before certain items
Segment EBDA before certain items
Bulk transload tonnage (MMtons)(d)
Ethanol (MMBbl)
Liquids leaseable capacity (MMBbl)
Liquids utilization %(e)
$
$
$
$
Year Ended December 31,
2016
2015
2014
(In millions, except operating statistics)
$
1,922
(768)
(99)
—
35
(16)
4
1,078
91
$
1,879
(836)
(191)
1
21
(4)
8
878
206
1,718
(746)
(29)
—
18
—
12
973
35
1,169
$
1,084
$
1,008
Increase/(Decrease)
38
85
$
$
61.8
66.7
87.8
156
76
63.2
63.1
81.5
79.8
66.5
77.8
94.8%
93.6%
95.3%
_______
Certain items affecting Segment EBDA
(a) 2016, 2015 and 2014 amounts include increases in revenues of $28 million, $23 million and $18 million, respectively, from the
amortization of a fair value adjustment (associated with the below market contracts assumed upon acquisition) from our Jones Act
tankers.
(b) In addition to the revenue certain items described in footnote (a) above: 2016 amount also includes increases in expense of $103 million
related to losses on impairments and divestitures, net and $16 million related to losses on impairments and divestitures of equity
investments, net. 2015 amount also includes (i) a $175 million non-cash pre-tax impairment of a terminal facility reflecting the impact
of an agreement to adjust certain payment terms under a contract with a coal customer; (ii) a $34 million increase in bad debt expense
due to certain coal customers bankruptcies related to revenues recognized in prior years but not yet collected; and (iii) $20 million
primarily related to other impairment charges. 2014 amount also includes a $29 million write-down associated with a sale of certain
terminals to a third-party and $24 million of increased expense from other certain items.
Other
(c) Income tax expense that was allocated to and presented in Segment EBDA in prior periods is presented herein in income tax expense to
conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $42 million, $29
million and $29 million, respectively, in income tax expense.
(d) Includes our proportionate share of joint venture tonnage.
(e) The ratio of our actual leased capacity to our estimated capacity.
51
Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2016 and 2015,
when compared with the respective prior year:
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Marine Operations
Alberta, Canada
Gulf Liquids
Northeast
Lower River
Gulf Bulk
Held for sale operations
All others (including intrasegment eliminations)
Total Terminals
Segment EBDA before
certain items
increase/(decrease)
Revenues before
certain items
increase/(decrease)
(In millions, except percentages)
$
$
52
14
14
11
4
(13)
(2)
5
85
51%
12%
6%
10%
7%
(17)%
(67)%
1%
8%
$
$
73
19
18
19
(12)
(50)
(18)
(11)
38
46%
14%
5%
10%
(9)%
(29)%
(100)%
(2)%
2%
The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of
the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:
•
•
•
•
•
•
•
•
increase of $52 million (51%) from our Marine Operations related to the incremental earnings from the December
2015, May 2016, July 2016, September 2016 and December 2016 in-service of the Jones Act tankers the Lone Star
State, Magnolia State, Garden State, Bay State,and American Endurance, respectively, and increased charter rates on
the Empire State Jones Act tanker;
increase of $14 million (12%) from our Alberta, Canada terminals, driven by a full year of earnings from our
Edmonton South rail terminal joint venture expansion, which began operations in second quarter 2015;
increase of $14 million (6%) from our Gulf Liquids terminals, primarily related to higher volumes as a result of
various expansion projects, including marine infrastructure improvements at our Galena Park and North Docks
terminals, as well as higher rates and ancillary service activities on existing business;
increase of $11 million (10%) from our Northeast terminals, primarily due to contributions from two terminals
acquired as part of the BP Products North America Inc. acquisition which was completed in February 2016;
increase of $4 million (7%) from our Lower River terminals, due to a $15 million write-off of certain coal customers
accounts receivable which occurred in 2015 and favorable results from certain Lower River terminals, partially offset
by decreased revenues and earnings of $18 million due to certain coal customer bankruptcies;
decrease of $13 million (17%) from our Gulf Bulk terminals, driven by decreased revenues and earnings of $41
million due to certain coal customer bankruptcies offset by a $28 million write-off of a certain coal customer’s
accounts receivable which occurred in the fourth quarter of 2015;
decrease of $2 million (67%) from our sale of certain bulk and transload terminal facilities to Watco Companies, LLC
in early 2015; and
included in “All others” is a decrease in revenues and earnings of $11 million due to certain coal customer
bankruptcies as compared to a $4 million write-off of certain coal customers accounts receivable which occurred in
2015.
52
Year Ended December 31, 2015 versus Year Ended December 31, 2014
Alberta, Canada
Marine Operations
Gulf Liquids
Gulf Central
Held for sale operations
Gulf Bulk
Mid Atlantic
All others (including intrasegment eliminations)
Total Terminals
_______
n/a – not applicable
Segment EBDA before
certain items
increase/(decrease)
Revenues before
certain items
increase/(decrease)
(In millions, except percentages)
$
$
52
44
24
23
(17)
(16)
(21)
(13)
76
76%
n/a
11%
52%
(77)%
(18)%
(29)%
(3)%
8%
$
$
67
57
41
30
(57)
22
(25)
21
156
102%
n/a
14%
51%
(67)%
15%
(18)%
3%
9%
The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of
the significant factors driving Segment EBDA before certain items in the comparable years of 2015 and 2014:
•
•
•
•
•
•
•
•
increase of $52 million (76%) from our Alberta, Canada terminals, driven by our Edmonton-area expansion projects,
including storage and connectivity additions at our Edmonton South and North 40 terminals as well as the
commissioning of two joint venture rail terminals;
increase of $44 million from our Marine Operations related primarily to the incremental earnings from the Jones Act
tankers we acquired in the first and fourth quarters of 2014 as well as the December 2015 delivery from the NASSCO
shipyard of the first new build tanker, the Lone Star State;
increase of $24 million (11%) from our Gulf Liquids terminals, related to the Vopak terminal acquisition completed in
first quarter 2015 and the addition of nine new tanks at Galena Park placed into service during fourth quarter 2014 and
first quarter 2015;
increase of $23 million (52%) from our Gulf Central terminals, driven by higher earnings from our expansion projects
at our joint venture terminals, Battleground Oil Specialty Terminal Company LLC (BOSTCO) and Deeprock
Development LLC;
decrease of $17 million (77%) from our sale of certain bulk and transload terminal facilities to Watco Companies, LLC
in early 2015;
decrease of $16 million (18%) from our Gulf Bulk terminals, primarily from reduced coal earnings due to certain coal
customers bankruptcies of $27 million partially offset by increased shortfall revenue from take-or-pay coal contracts;
decrease of $21 million (29%) from our Mid Atlantic terminals, driven by lower revenues as a result of lower tonnage
partially offset by higher shortfall revenue from take-or-pay coal contracts; and
decrease of $21 million primarily from reduced coal earnings due to certain coal customers bankruptcies, which
impacted our International Marine Terminals and Mid River terminals included in “All others” and the Mid Atlantic
terminals noted above by $16 million, $3 million and $2 million, respectively.
53
Products Pipelines
Revenues
Operating expenses
Loss on impairments and divestitures, net(a)
Other (expense) income
Earnings from equity investments
Gain on divestiture of equity investment(a)
Other, net
Segment EBDA(a)(b)
Certain items(a)
Segment EBDA before certain items(b)
Change from prior period
Revenues
Segment EBDA before certain items
Gasoline (MMBbl) (c)
Diesel fuel (MMBbl)
Jet fuel (MMBbl)
Total refined product volumes (MMBbl)(d)
NGL (MMBbl)(d)
Condensate (MMBbl)(d)
Total delivery volumes (MMBbl)
Ethanol (MMBbl)(e)
Year Ended December 31,
2016
2015
2014
(In millions, except operating statistics)
$
$
$
$
$
1,649
(573)
(76)
—
53
12
2
1,067
113
1,180
$
$
1,831
(772)
—
(2)
45
—
4
1,106
(4)
1,102
$
Increase/(Decrease)
(182) $
$
78
(237)
242
374.3
124.9
105.2
604.4
39.7
118.3
762.4
41.3
368.9
129.1
103.1
601.1
38.6
99.7
739.4
41.4
2,068
(1,258)
—
3
44
—
(1)
856
4
860
359.2
126.9
100.5
586.6
25.3
33.2
645.1
41.6
_______
Certain items affecting Segment EBDA
(a) 2016 amount includes increases in expense of (i) $65 million related to the Palmetto project write-off; (ii) $31 million of rate case
liability estimate adjustments associated with prior periods; (iii) $20 million related to a legal settlement; and (iv) $9 million of non-cash
impairment charges related to the sale of a Transmix facility; offset by a $12 million gain related to the sale of an equity investment.
2015 and 2014 amounts include a $4 million decrease in expense and a $4 million increase in expense, respectively, associated with a
certain Pacific operations litigation matter.
Other
(b) Income tax expense and interest income that were allocated to and presented in Segment EBDA in prior periods are presented herein in
income tax expense and interest expense, net, respectively, to conform to our current presentation as discussed above in “—Overview.”
The amounts for 2016, 2015 and 2014 were $(5) million, $8 million and $2 million, respectively, in income tax (benefit) expense and for
2015 and 2014, $2 million and $(2) million, respectively in interest income (expense).
(c) Volumes include ethanol pipeline volumes.
(d) Joint Venture throughput is reported at our ownership share.
(e) Represents total ethanol volumes, including ethanol pipeline volumes included in gasoline volumes above.
54
Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2016 and 2015,
when compared with the respective prior year:
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Crude & Condensate Pipeline
KMCC - Splitter
Double H pipeline
Plantation Pipe Line
Transmix
Cochin
All others (including eliminations)
Total Products Pipelines
Segment EBDA before
certain items
increase/(decrease)
Revenues before
certain items
increase/(decrease)
(In millions, except percentages)
37
20
15
9
8
(13)
2
78
20%
53%
34%
17%
26%
(11)%
—%
7%
$
$
36
30
22
1
(286)
3
12
(182)
18%
71%
39%
5%
(57)%
2%
1%
(10)%
$
$
The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following
discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2016 and 2015:
•
•
•
•
•
•
increase of $37 million (20%) from Kinder Morgan Crude & Condensate Pipeline driven primarily by an increase in
pipeline throughput volumes from existing customers and additional volumes associated with expansion projects;
increase of $20 million (53%) from our KMCC - Splitter due to first and second phases being in full operation for
2016. Start up of first phase was in March 2015 and second phase was in July 2015;
increase of $15 million (34%) due to full year of results from our Double H pipeline, which began operations in March
2015;
increase of $9 million (17%) from our equity investment in Plantation Pipe Line primarily due to lower operating
costs;
increase of $8 million (26%) from our Transmix processing operations largely due to unfavorable market price impacts
during the fourth quarter of 2015. The decrease in revenues of $286 million and associated decrease in costs of goods
sold were driven by lower sales volumes primarily due to the sale of our Indianola plant in August 2016; and
decrease of $13 million (11%) from Cochin primarily due to higher pipeline integrity costs.
Year Ended December 31, 2015 versus Year Ended December 31, 2014
Segment EBDA before
certain items
increase/(decrease)
Revenues before
certain items
increase/(decrease)
(In millions, except percentages)
Crude & Condensate Pipeline
$
102
124%
$
KMCC - Splitter
Double H pipeline
Cochin
Pacific operations
Transmix operations
All others (including eliminations)
Total Products Pipelines
_______
n/a - not applicable
33
44
35
23
8
(3)
242
n/a
n/a
40%
7%
33%
(1)%
28%
$
$
55
90
43
56
54
27
(490)
(17)
(237)
81%
n/a
n/a
50%
6%
(49)%
(4)%
(12)%
The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following
discussion of the significant factors driving Segment EBDA before certain items in the comparable years of 2015 and 2014:
•
•
•
•
•
•
increase of $102 million (124%) from Kinder Morgan Crude & Condensate Pipeline driven primarily by an increase of
pipeline throughput volumes due to the ramp up of existing customer volumes and additional volumes from new
customers;
increase of $33 million from our KMCC - Splitter due to the startup of the first and second phases in March 2015 and
July 2015;
increase of $44 million from our Double H pipeline which was acquired in February 2015 as part of the Hiland
acquisition;
increase of $35 million (40%) from Cochin driven by higher service revenues due to the completion of the Cochin
Reversal project in the third quarter of 2014;
increase of $23 million (7%) from our Pacific operations due to higher service revenues, resulting from higher
volumes and margins; and
increase of $8 million (33%) from our Transmix processing operations primarily due to favorable inventory
adjustments impacting margins. The decrease in revenues of $490 million and associated decrease in costs of goods
sold were caused by lower commodity prices.
Kinder Morgan Canada
Revenues
Operating expenses
Other income
Other, net
Segment EBDA(a)
Change from prior period
Revenues
Segment EBDA
Year Ended December 31,
2016
2015
2014
(In millions, except operating statistics)
$
253
(87)
—
15
$
260
(87)
1
8
181
$
182
$
291
(106)
—
15
200
Increase/(Decrease)
(7) $
(1) $
(31)
(18)
$
$
$
$
Transport volumes (MMBbl)(b)
115.2
115.4
106.8
______
(a) Income tax expense that was allocated to and presented in Segment EBDA in prior periods is presented herein in income tax expense to
conform to our current presentation as discussed above in “—Overview.” The amounts for 2016, 2015 and 2014 were $20 million, $19
million and $18 million, respectively, in income tax expense.
(b) Represents Trans Mountain pipeline system volumes.
For the comparable years of 2016 and 2015, the Kinder Morgan Canada business segment had a decrease in Segment EBDA
of $1 million (1%) and a decrease in revenues of $7 million (3%).
56
Below are the changes in both Segment EBDA before certain items and revenues before certain items in 2015, when
compared with 2014:
Year Ended December 31, 2015 versus Year Ended December 31, 2014
Segment EBDA before
certain items
increase/(decrease)
Revenues before
certain items
increase/(decrease)
Trans Mountain Pipeline
Express Pipeline(a)
Jet Fuel Pipeline
Total Kinder Morgan Canada
$
$
(12)
(6)
—
(18)
$
(7)%
(In millions, except percentages)
(30)
n/a
(1)
(31)
(100)%
(9)%
—%
$
(11)%
n/a
(17)%
(11)%
______
n/a - not applicable
(a) Amount consists of unrealized foreign currency gains, net of book tax, on outstanding, short-term intercompany borrowings that were repaid
in December 2014. We sold our debt and equity investments in Express Pipeline on March 14, 2013.
The changes in Segment EBDA for our Kinder Morgan Canada business segment are further explained by the significant
factors driving Segment EBDA before certain items which factors include an unfavorable impact from foreign currency
exchange rates, and repayment of the Express note as discussed in footnote (a) above.
General and Administrative, Interest, Corporate and Noncontrolling Interests
General and administrative expense(a)(e)
Certain items(a)
Management fee reimbursement(e)
General and administrative expense before certain items
Interest expense, net(b)
Certain items(b)
Interest expense, net, before certain items
Corporate(c)(e)
Certain items(c)
Management fee revenue(e)
Corporate before certain items
Net income (loss) attributable to noncontrolling interests
Noncontrolling interests associated with certain items(d)
Net income attributable to noncontrolling interests before certain items
Year Ended December 31,
2016
2015
2014
(In millions)
$
$
$
$
$
$
$
$
669
$
5
(34)
640
1,806
193
1,999
$
$
$
(17) $
8
34
25
13
8
21
$
$
$
$
$
$
$
$
690
(25)
(37)
628
2,051
27
2,078
18
(35)
37
20
$
(45) $
63
18
$
610
28
(36)
602
1,798
3
1,801
(43)
22
36
15
1,417
—
1,417
_______
Certain items
(a) 2016 amount includes increases in expense of (i) $14 million related to severance costs; and (ii) $12 million related to acquisition costs;
offset by a decrease in expense of $31 million related to certain corporate litigation matters. 2015 and 2014 amounts include decreases in
expense of $35 million and $39 million related to pension credit income. 2015 amount also includes increases in expense of $45 million
related to certain corporate legal matters and $15 million related to costs associated with acquisitions. 2014 amount also includes a net
increase of $11 million in expense for various other certain items.
(b) 2016, 2015 and 2014 amounts include (i) decreases in interest expense of $115 million, $71 million and $65 million, respectively, related
to non-cash debt fair value adjustments associated with acquisitions; (ii) a $34 million decrease, a $21 million increase and a $15 million
increase, respectively, in interest expense related to certain litigation matters; and (iii) a $44 million decrease, a $23 million increase and
57
a $1 million decrease, respectively, in interest expense primarily related to non-cash true-ups of our estimates of swap ineffectiveness.
2014 amount also includes (i) increases in expense of $9 million of amortization of capitalized financing fees; (ii) $12 million of interest
expense on margin for marketing contracts associated with legacy operations; and (iii) $27 million of interest expense related to the
Merger Transactions.
(c) 2015 amount is primarily related to a litigation matter and 2014 amount is primarily related to our foreign operations.
(d) 2015 amount reflects the noncontrolling interest portion of certain items including (i) a $43 million impairment and a $6 million loss
associated with Terminals segment certain items and disclosed above in “—Terminals” and (ii) a $14 million loss associated with a
Natural Gas Pipelines segment impairment certain item and disclosed above in “—Natural Gas Pipelines.”
Other
(e) 2016, 2015 and 2014 amounts include certain equity investee management fee revenue of $34 million, $37 million and $36 million,
respectively. These amounts are recorded to the “Product sales and other” caption with the offsetting expenses primarily included in the
“General and administrative” expense caption in our accompanying consolidated statements of income.
General and administrative expenses before certain items increased $12 million in 2016 and $26 million in 2015 when
compared with the respective prior year. The increase in 2016 as compared to 2015 was primarily driven by higher benefit
costs and lower capitalized costs partially offset by lower labor, outside services and insurance costs. The increase in 2015 as
compared to 2014 was primarily driven by the acquisition of Hiland (effective February 13, 2015), lower capitalized costs and
higher labor expenses partially offset by lower benefit and insurance costs.
In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized
interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense net of interest
income before certain items, decreased $79 million in 2016 and increased $277 million in 2015, respectively, when compared
with the respective prior year. The decrease in interest expense in 2016 as compared to 2015 was primarily due to lower
weighted average debt balances, partially offset by a slightly higher overall weighted average interest rate on our outstanding
debt. The increase in 2015 as compared to 2014 was primarily due to higher weighted average debt balances as a result of
capital expenditures, joint venture contributions and acquisitions that were made during 2014 and 2015, and incremental debt
borrowings to fund the $3.9 billion cash portion of the Merger Transactions in November 2014.
We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate
debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of
December 31, 2016 and 2015, approximately 28% and 27%, respectively, of our debt balances (excluding debt fair value
adjustments) were subject to variable interest rates-either as short-term or long-term variable rate debt obligations or as fixed-
rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see
Note 14 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.
After taking into effect the certain items, the Corporate expense for 2016 and 2015 increased by $5 million for each
respective period when compared with the respective prior year.
Net income attributable to noncontrolling interests, represents the allocation of our consolidated net income attributable to
all outstanding ownership interests in our consolidated subsidiaries that are not held by us. Net income attributable to
noncontrolling interests before certain items for 2016 as compared to 2015 increased $3 million (17%). The $1,399 million
decrease (99%) for 2015 as compared to 2014 was primarily due to our purchase of the KMP and EPB limited partner units and
KMR shares formerly owned by the public in the fourth quarter of 2014 as part of the Merger Transactions.
Income Taxes
Year Ended December 31, 2016 versus Year Ended December 31, 2015
Our tax expense for the year ended December 31, 2016 is approximately $917 million, as compared with 2015 tax expense
of $564 million. The $353 million increase in tax expense is primarily due to (i) an increase in our earnings as a result of lower
impairments in 2016; (ii) the year over year increase in the deferred state tax expense as a result of our sale of a 50% interest in
SNG in 2016 and the Hiland acquisition in 2015; and (iii) valuation allowances recorded in 2016 for foreign tax credits and
capital loss carryforwards for which we do not expect to recognize any future tax benefits. These increases are partially offset
by adjustments to our income tax reserve for uncertain tax positions.
Year Ended December 31, 2015 versus Year Ended December 31, 2014
Our tax expense for the year ended December 31, 2015 was $564 million, as compared with 2014 tax expense of $648
million. The $84 million decrease in tax expense is due primarily to (i) the tax impact of lower pretax earnings in 2015
primarily due to our recognition of $929 million of impairments on long-lived assets and investments and $1,150 million
58
goodwill impairment of natural gas pipelines non-regulated midstream assets, of which $882 million is not tax deductible; (ii)
the tax benefit of an increase in the deferred state tax rate as a result of the Hiland acquisition; (iii) the 2014 recording of a
valuation allowance related to our investment in NGPL; and (iv) the elimination, as a result of the Merger Transactions, of the
amortization of the deferred charge recorded as a result of the drop-downs of TGP, EPNG, and the midstream assets. These
decreases are partially offset by the 2014 benefit of a worthless stock deduction related to our Brazil operations.
Liquidity and Capital Resources
General
As of December 31, 2016, we had $684 million of “Cash and cash equivalents,” an increase of $455 million (199%) from
December 31, 2015. We believe our cash position, remaining borrowing capacity on our credit facility (discussed below in “—
Short-term Liquidity”), and our cash flows from operating activities are adequate to allow us to manage our day-to-day cash
requirements and anticipated obligations as discussed further below.
We have consistently generated substantial cash flow from operations, providing a source of funds of $4,787 million and
$5,303 million in 2016 and 2015, respectively. The year-to-year decrease is discussed below in “Cash Flows—Operating
Activities.” We have relied on cash provided from operations to fund our operations as well as our debt service, sustaining
capital expenditures, and dividend payments, and during 2016, to fund our expansion capital expenditures.
On September 1, 2016, we completed the sale of a 50% interest in our SNG natural gas pipeline system to Southern
Company, receiving proceeds of approximately $1.4 billion. We used the proceeds from this transaction to reduce outstanding
debt. In addition to repaying outstanding commercial paper and credit facility borrowings, proceeds from the sale were also
used on September 30, 2016 to repay the $332 million principal amount of Copano’s 7.125% notes due 2021, and on October 1,
2016, to repay the $749 million principal amount of Hiland’s 7.25% senior notes due 2020 (see Note 9 “Debt”). As of
September 1, 2016, SNG had $1,211 million of debt outstanding (including a current portion of $500 million) which is no
longer consolidated on our balance sheet.
On August 16, 2016, CIG completed a private offering of $375 million in principal amount of 4.15% senior notes due
August 15, 2026. We received net proceeds of $372 million from the offering and used the proceeds from the sale of the notes
to reduce debt incurred as the result of the repayment of CIG’s senior notes that matured in 2015 and for general corporate
purposes.
On January 26, 2016, we announced the issuance of a new $1.0 billion term loan facility and the expansion of our
revolving credit facility from $4.0 billion to $5.0 billion. The proceeds of the three-year unsecured term loan facility were used
to refinance maturing long-term debt.
In general, we expect that our short-term liquidity needs will be met primarily through retained cash from operations,
short-term borrowings or by issuing new long-term debt to refinance certain of our maturing long-term debt obligations. We
also expect that our current common stock dividend level will allow us to use retained cash to fund our growth projects in 2017.
Moreover, as a result of our current common stock dividend policy and by continuing to focus on high-grading our growth
project backlog to allocate capital to the highest return opportunities, we do not expect to need to access the equity capital
markets to fund our growth projects for the foreseeable future.
Credit Ratings and Capital Market Liquidity
We believe that our capital structure will continue to allow us to achieve our business objectives. We expect that our short-
term liquidity needs will be met primarily through retained cash from operations or short-term borrowings. However, over the
long term, we are subject to uncertain capital market conditions and there can be no assurance we will be able or willing to
access the public or private markets for equity and/or long-term senior notes in the future. If we were unable or unwilling to
access the capital markets, we would be required to either continue utilizing internally generated cash, restrict expansion capital
expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher
costs or negatively affect our and/or our subsidiaries’ credit ratings.
As of December 31, 2016, our short-term corporate debt ratings were A-3, Prime-3 and F3 at Standard and Poor’s,
Moody’s Investor Services and Fitch Ratings, Inc., respectively.
59
The following table represents KMI’s and KMP’s senior unsecured debt ratings as of December 31, 2016.
Rating agency
Standard and Poor’s
Moody’s Investor Services
Fitch Ratings, Inc.
Short-term Liquidity
Senior debt
rating
BBB-
Baa3
BBB-
Date of last change
Outlook
November 20, 2014
November 21, 2014
November 20, 2014
Stable
Stable
Stable
As of December 31, 2016, our principal sources of short-term liquidity are (i) our $5.0 billion revolving credit facility and
associated $4.0 billion commercial paper program; and (ii) cash from operations. The loan commitments under our revolving
credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper
program. Borrowings under our commercial paper program and letters of credit reduce borrowings allowed under our credit
facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as
previously discussed, have consistently generated strong cash flows from operations.
As of December 31, 2016, our $2,696 million of short-term debt consisted primarily of senior notes that mature in 2017.
We intend to refinance our short-term debt through credit facility borrowings, commercial paper borrowings, or by issuing new
long-term debt or paying down short-term debt using cash retained from operations or received from asset sales. Our short-
term debt balance as of December 31, 2015 was $821 million.
We had working capital (defined as current assets less current liabilities) deficits of $2,695 million and $1,241 million as of
December 31, 2016 and 2015, respectively. Our current liabilities may include short-term borrowings used to finance our
expansion capital expenditures, which we may periodically replace with long-term financing and/or partially pay down using
retained cash from operations. The overall $1,454 million (117%) unfavorable change from year-end 2015 was primarily due
to a net increase in our current portion of long-term debt, offset partially by a favorable change in cash. Generally, our working
capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and
payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash
equivalent balances as a result of excess cash from operations after payments for investing and financing activities (discussed
below in “—Long-term Financing” and “— Capital Expenditures”).
We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of
our wholly owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of
borrowing. These programs provide that funds in excess of the daily needs of our wholly owned subsidiaries are concentrated,
consolidated or otherwise made available for use by other entities within the consolidated group. We place no material
restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends
to KMI other than restrictions that may be contained in agreements governing the indebtedness of those entities.
Certain of our wholly owned subsidiaries are subject to FERC-enacted reporting requirements for oil and natural gas
pipeline companies that participate in cash management programs. FERC-regulated entities subject to these rules must, among
other things, place their cash management agreements in writing, maintain current copies of the documents authorizing and
supporting their cash management agreements, and file documentation establishing the cash management program with the
FERC.
Long-term Financing
Our equity consists of Class P common stock and mandatory convertible preferred stock each with a par value of $0.01 per
share. In 2015, through an equity distribution agreement, we issued and sold through or to our sales agents and/or principals
shares of our Class P common stock. For more information on our equity issuances during 2015 and our equity distribution
agreement, see Note 11, “Stockholders’ Equity” to our consolidated financial statements.
From time to time, we issue long-term debt securities, often referred to as senior notes. All of our senior notes issued to
date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity
dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a
price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a
make-whole premium. In addition, from time to time our subsidiaries, have issued long-term debt securities. Furthermore, we
and almost all of our direct and indirect wholly owned domestic subsidiaries are parties to a cross guaranty wherein we each
60
guarantee the debt of each other. See Note 19 “Guarantee of Securities of Subsidiaries” to our consolidated financial
statements. As of December 31, 2016 and 2015, the aggregate principal amount outstanding of our various long-term debt
obligations (excluding current maturities) was $36,205 million and $40,732 million, respectively. For more information
regarding our debt-related transactions in 2016, see Note 9 “Debt” to our consolidated financial statements.
We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate
interest payments for variable rate interest payments and through the issuance of commercial paper or credit facility
borrowings.
To date, our debt balances have not adversely affected our operations, our ability to grow or our ability to repay or
refinance our indebtedness. For additional information about our debt-related transactions in 2016, see Note 9 “Debt” to our
consolidated financial statements. For information about our interest rate risk, see Item 7A “Quantitative and Qualitative
Disclosures About Market Risk—Interest Rate Risk.”
Capital Expenditures
We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that
are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as
discretionary capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or
capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF
(see “Results of Operations—Distributable Cash Flow”). With respect to our oil and gas producing activities, we classify a
capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e. production
capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements.
Maintenance capital expenditures are those which maintain throughput or capacity. The distinction between maintenance and
expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which
the throughput or capacity is increased.
Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget
for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet
customer needs and comply with our operating policies and applicable law. We may budget for and make additional
maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering
future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year
on a project-by-project basis in response to specific investment opportunities identified by our business segments from which
we generally expect to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital
expenditure is classified as maintenance/sustaining or as expansion capital expenditures is made on a project level. The
classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made
consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter
of management judgment and discretion . The classification has an impact on DCF because capital expenditures that are
classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital
expenditures are. See “—Common Dividends” and “—Preferred Dividends”
Our capital expenditures for the year ended December 31, 2016, and the amount we expect to spend for 2017 to sustain and
grow our business are as follows (in millions):
Sustaining capital expenditures(a)
Discretionary capital expenditures(b)(c)
2016
Expected 2017
$
$
540
2,807
$
$
630
3,240
_______
(a) 2016 and Expected 2017 amounts include $90 million and $112 million, respectively, for our proportionate share of sustaining capital
expenditures of certain unconsolidated joint ventures.
(b) 2016 amount includes $574 million of discretionary capital expenditures of unconsolidated joint ventures and small acquisitions (i.e.
excludes Hiland acquisition) and divestitures and excludes a combined $199 million of net changes from accrued capital expenditures
and contractor retainage.
(c) Expected 2017 amount includes our contributions to certain unconsolidated joint ventures and small acquisitions and divestitures, net of
contributions estimated from unaffiliated joint venture partners for consolidated investments.
61
Off Balance Sheet Arrangements
We have invested in entities that are not consolidated in our financial statements. For information on our obligations with
respect to these investments, as well as our obligations with respect to related letters of credit, see Note 13 “Commitments and
Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business
purpose of our investments is included in Note 7 “Investments” to our consolidated financial statements.
Contractual Obligations and Commercial Commitments
Payments due by period
Total
Less than 1
year
2-3 years
4-5 years
(In millions)
More than 5
years
Contractual obligations:
Debt borrowings-principal payments(a)
$
38,901
$
2,696
$
6,148
$
4,626
$
Interest payments(b)
26,441
2,026
3,644
3,154
Leases and rights-of-way obligations(c)
Pension and postretirement welfare plans(d)
Transportation, volume and storage agreements(e)
Other obligations(f)
Total
Other commercial commitments:
Standby letters of credit(g)
Capital expenditures(h)
764
970
1,106
307
68,489
219
1,112
$
$
$
$
$
$
106
38
169
70
5,105
199
1,112
180
34
302
94
136
35
261
42
25,431
17,617
342
863
374
101
$
$
$
10,402
20
$
$
— $
8,254
$
44,728
— $
— $
—
—
_______
(a) Less than 1 year amount primarily includes $2,541 million of current maturities on senior notes and $111 million associated with our
Trust I Preferred Securities that are classified as current obligations because these securities have rights to convert into cash, KMI
common stock and/or warrants. See Note 9 “Debt” to our consolidated financial statements.
(b) Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from
those in effect at December 31, 2016.
(c) Represents commitments pursuant to the terms of operating lease agreements and liabilities for rights-of-way.
(d) Represents the amount by which the benefit obligations exceeded the fair value of fund assets for pension and other postretirement
benefit plans at year-end. The payments by period include expected contributions to funded plans in 2017 and estimated benefit
payments for unfunded plans in all years.
(e) Primarily represents transportation agreements of $469 million, volume agreements of $434 million and storage agreements for capacity
on third party and an affiliate pipeline systems of $147 million.
(f) Primarily includes environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency
or property owner upon which we will perform remediation activities. These liabilities are included within “Other long-term liabilities
and deferred credits” in our consolidated balance sheets.
(g) The $219 million in letters of credit outstanding as of December 31, 2016 consisted of the following (i) $50 million under twelve letters
of credit for insurance purposes; (ii) a $32 million letter of credit supporting our pipeline and terminal operations in Canada; (iii) our $30
million guarantee under letters of credit totaling $46 million supporting our International Marine Terminals Partnership Plaquemines,
Louisiana Port, Harbor, and Terminal Revenue Bonds; (iv) a $25 million letter of credit supporting our Kinder Morgan Liquids
Terminals LLC New Jersey Economic Development Revenue Bonds; (v) a $24 million letter of credit supporting our Kinder Morgan
Operating L.P. “B” tax-exempt bonds; (vi) a $10 million letter of credit supporting Nassau County, Florida Ocean Highway and Port
Authority tax-exempt bonds; and (vii) a combined $32 million in twenty-four letters of credit supporting environmental, power and
marketing purposes, and other obligations of us and our subsidiaries.
(h) Represents commitments for the purchase of plant, property and equipment as of December 31, 2016 and obligations for the definitive
construction agreement with Philly Tankers LLC for 2017.
62
Cash Flows
Operating Activities
The net decrease of $516 million (10%) in cash provided by operating activities in 2016 compared to 2015 was primarily
attributable to:
•
•
a $414 million decrease in cash from overall net income after adjusting our period-to-period $513 million increase in
net income for non-cash items primarily consisting of the following: (i) loss on impairment of goodwill; (ii) net losses
on impairments and divestitures; (iii) losses on impairment and divestitures of equity investments; (iv) gains on early
extinguishment of debt; (See discussion above in “—Results of Operations” for further information regarding these
items); (v) DD&A expenses (including amortization of excess cost of equity investments); (vi) deferred income taxes;
and (vii) equity earnings from our equity investments; and
a $102 million decrease in cash associated with net changes in working capital items and other non-current assets and
liabilities. The decrease was driven, among other things, primarily by a $195 million income tax refund received in
2015, and lower cash flow due to unfavorable changes in the collection of trade and exchange gas receivables. These
decreases were offset partially by higher cash flows associated with the timing of payments from our trade payables.
Investing Activities
The $4,001 million net decrease in cash used in investing activities in 2016 compared to 2015 was primarily attributable
to:
•
•
•
•
•
•
a $1,746 million decrease in expenditures for acquisitions and investments in 2016 compared to the respective 2015
period. The overall decrease in acquisitions was primarily related to the $324 million portion of the purchase price we
paid in 2016 for the BP terminals acquisition, versus the $1,706 million (net of cash assumed) and $158 million we
paid for the Hiland and Vopak acquisitions, respectively, and the $134 million we paid to increase our ownership in
NGPL Holdings LLC to 50% in the 2015 period;
a $1,401 million net increase in cash due to proceeds from the sale of a 50% equity interest in SNG;
a $1,014 million reduction in capital expenditures; and
a $291 million increase in cash due to an increase in proceeds from sales of other long-lived assets; partially offset by,
a $312 million increase in contributions to equity investments in 2016 compared to 2015, primarily due to a $312
million contribution to our 50% investment in NGPL Holdings LLC in 2016; and
a $142 million decrease in Other, net primarily due to unfavorable changes in restricted deposits associated with our
hedging activities.
Financing Activities
The net decrease of $2,956 million in cash provided by financing activities in 2016 compared to 2015 was primarily
attributable to:
•
•
•
•
•
•
a $3,870 million decrease in financing activities resulting from the issuances of our Class P shares under our equity
distribution agreement in 2015 with no Class P Share issuance activity in 2016;
a $1,541 million decrease in financing activities due to the issuance of our mandatory convertible preferred stock in
2015;
a $626 million decrease in net debt proceeds. See Note 9 “Debt” for further information regarding our debt activity;
and
a $154 million increase in dividends paid to our mandatory convertible preferred shareholders in 2016;
partially offset by,
a $3,106 million reduction in dividend payments paid to our common shareholders; and
a $106 million increase in contributions provided by noncontrolling interests, primarily reflecting the contributions
received from BP for its 25% share of a newly formed joint venture.
63
Common Dividends
The table below reflects the payment of cash dividends of $0.50 per common share for 2016.
Three months ended
March 31, 2016
June 30, 2016
September 30, 2016
December 31, 2016
Total quarterly
dividend per share
for the period
Date of declaration
Date of record
Date of dividend
$
$
$
$
0.125
0.125
0.125
0.125
April 20, 2016
July 20, 2016
May 2, 2016
May 16, 2016
August 1, 2016
August 15, 2016
October 19, 2016
November 1, 2016
November 15, 2016
January 18, 2017
February 1, 2017
February 15, 2017
The actual amount of common dividends to be paid on our capital stock will depend on many factors, including our
financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory
and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—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.” All of these matters will be taken into consideration by our board of
directors in declaring dividends.
Our common stock dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the
intended levels, our common stockholders are not entitled to receive those payments in the future. Our common stock
dividends generally will be paid on or about the 15th day of each February, May, August and November.
Preferred Dividends
Dividends on our mandatory convertible preferred stock are payable on a cumulative basis when, as and if declared by our
board of directors (or an authorized committee thereof) at an annual rate of 9.750% of the liquidation preference of $1,000 per
share on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and including,
October 26, 2018. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any
combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless
full cumulative dividends have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for
all prior dividend periods, no dividends may be declared or paid on common stock.
Period
January 26, 2016 through April 25, 2016
April 26, 2016 through July 25, 2016
July 26, 2016 through October 25, 2016
October 26, 2016 through January 25, 2017
Total dividend
per share for
the period
$
$
$
$
24.375
24.375
24.375
24.375
Date of declaration
January 20, 2016
April 20, 2016
July 20, 2016
October 19, 2016
Date of record
April 11, 2016
July 11, 2016
October 11, 2016
January 11, 2017
Date of dividend
April 26, 2016
July 26, 2016
October 26, 2016
January 26, 2017
The cash dividend of $24.375 per share of our mandatory convertible preferred stock is equivalent to $1.21875 per
depository share.
Recent Accounting Pronouncements
Please refer to Note 18 “Recent Accounting Pronouncements” to our consolidated financial statements for information
concerning recent accounting pronouncements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.” Our
exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes
in fair value or future earnings that would occur assuming hypothetical future movements in energy commodity prices or
interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the
maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on
actual fluctuations in energy commodity prices or interest rates and the timing of transactions.
64
Energy Commodity Market Risk
We are exposed to energy commodity market risk and other external risks in the ordinary course of business. However, we
manage these risks by executing a hedging strategy that seeks to protect us financially against adverse price movements and
serves to minimize potential losses. Our strategy involves the use of certain energy commodity derivative contracts to reduce
and minimize the risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. The
derivative contracts that we use include energy products traded on the NYMEX and OTC markets, including, but not limited to,
futures and options contracts, fixed price swaps and basis swaps. In addition, prior to May 2016, we had power forward and
swap contracts related to legacy operations of acquired businesses.
Our hedging strategy involves entering into a financial position intended to offset our physical position, or anticipated
position, in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil and
natural gas, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil
or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby in whole or in part offsetting
any change in prices, either positive or negative.
Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or
similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that
correspond to our counterparties’ credit ratings. While it is our policy to enter into derivative transactions principally with
investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from
counterparty credit risk in the future.
The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on
contract market values) are as follows (credit ratings per Standard & Poor’s Rating Service):
Bank of America / Merrill Lynch
Societe Generale
J Aron / Goldman Sachs
Bank of Nova Scotia
J.P. Morgan
Credit Rating
BBB+
A
BBB+
A+
A-
As discussed above, the principal use of energy commodity derivative contracts is to mitigate the market price risk
associated with anticipated transactions for the purchase and sale of natural gas, NGL and crude oil. Using derivative contracts
for this purpose helps provide increased certainty with regard to operating cash flows which helps us to undertake further
capital improvement projects, attain budget results and meet dividend targets. We may categorize such use of energy
commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash
flow of a transaction that is expected to occur but which value is uncertain.
We measure the risk of price changes in the natural gas, NGL and crude oil derivative instruments portfolios utilizing a
sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the
change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted
market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional
amounts of the instruments and the discount rates used to determine the present values. A hypothetical 10% movement in the
underlying commodity prices would have the following effect on the associated derivative contracts’ estimated fair value (in
millions):
Commodity derivative
Crude oil
Natural gas
NGL
Total
As of December 31,
2016
2015
$
$
117
$
16
11
144
$
97
13
4
114
65
As discussed above, we enter into derivative contracts largely for the purpose of mitigating the risks that accompany
certain of our business activities and, therefore both in the sensitivity analysis model and in reality, the change in the market
value of the derivative contracts’ portfolio is offset largely by changes in the value of the underlying physical transactions.
Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the
natural gas, NGL and crude oil portfolios of derivative contracts assuming hypothetical movements in future market rates and is
not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected
loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ
from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our
portfolio of derivatives during the year.
Interest Rate Risk
In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and
variable rate debt. The market risk inherent in our debt instruments and positions is the potential change arising from increases
or decreases in interest rates as discussed below.
For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or
cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt
instrument, but may affect our future earnings and cash flows. Generally, there is not an obligation to prepay fixed rate debt
prior to maturity and, as a result, changes in fair value should not have a significant impact on the fixed rate debt. We are
generally subject to interest rate risk upon refinancing maturing debt. Below are our debt balances and sensitivity to interest
rates (in millions):
Fixed rate debt(a)
Variable rate debt
Notional principal amount of fixed-to-variable interest rate
swap agreements
Debt subject to variable interest rates(b)
December 31, 2016
December 31, 2015
Carrying
value
Estimated
fair value(c)
Carrying
value
Estimated
fair value(c)
$
$
39,854
1,161
$
$
$
38,861
1,189
9,775
10,964
$
$
37,329
152
$
$
$
43,039
188
11,000
11,188
_______
(a) A hypothetical 10% change in the average interest rates applicable to such debt as of December 31, 2016 and 2015, would result in
changes of approximately $1,527 million and $1,667 million, respectively, in the fair values of these instruments.
(b) A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 50 basis points in 2016 and
approximately 49 basis points in 2015) when applied to our outstanding balance of variable rate debt as of December 31, 2016 and 2015,
including adjustments for the notional swap amounts described above, would result in changes of approximately $54 million and $55
million, respectively, in our 2016 and 2015 annual pre-tax earnings.
(c) Fair values were determined using quoted market prices, where applicable, or future cash flows discounted at market rates for similar
types of borrowing arrangements.
Fixed-to-variable interest rate swap agreements are entered into for the purpose of converting a portion of the underlying
cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and
variable rate debt. Since the fair value of fixed rate debt varies with changes in the market rate of interest, swap agreements are
entered into to receive a fixed and pay a variable rate of interest. Such swap agreements result in future cash flows that vary
with the market rate of interest, and therefore hedge against changes in the fair value of the fixed rate debt due to market rate
changes.
We monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to
time, may alter that mix by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa)
or by entering into interest rate swap agreements or other interest rate hedging agreements. As of December 31, 2016, including
debt converted to variable rates through the use of interest rate swaps but excluding our debt fair value adjustments, approximately
28% of our debt balances were subject to variable interest rates.
For more information on our interest rate risk management and on our interest rate swap agreements, see Note 14 “Risk
Management” to our consolidated financial statements.
66
Foreign Currency Risk
In connection with the issuance of our Euro denominated senior notes in March 2015, we entered into $1,358 million of
cross-currency swap agreements that effectively convert all of our fixed rate Euro denominated debt, including annual interest
payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates. These swaps eliminate the
foreign currency risk associated with our foreign currency denominated debt.
Item 8. Financial Statements and Supplementary Data.
The information required in this Item 8 is in this report as set forth in the “Index to Financial Statements” on page 73.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2016, our management, including our Chief Executive Officer and Chief Financial Officer, has
evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15
(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure
controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and
procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving
their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial
Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable
assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934
is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our
management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions
regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such
term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate. Under the supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an assessment of the effectiveness of our internal control over
financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that our
internal control over financial reporting was effective as of December 31, 2016.
The effectiveness of our internal control over financial reporting as of December 31, 2016, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears
herein.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth quarter of 2016 that has
materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None.
67
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2017
Annual Meeting of Stockholders, which shall be filed no later than April 30, 2017.
Item 11. Executive Compensation.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2017
Annual Meeting of Stockholders, which shall be filed no later than April 30, 2017.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2017
Annual Meeting of Stockholders, which shall be filed no later than April 30, 2017.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2017
Annual Meeting of Stockholders, which shall be filed no later than April 30, 2017.
Item 14. Principal Accounting Fees and Services.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2017
Annual Meeting of Stockholders, which shall be filed no later than April 30, 2017.
PART IV
Item 15. Exhibits, Financial Statement Schedules.
(a) (1) Financial Statements and (2) Financial Statement Schedules
See “Index to Financial Statements” set forth on Page 73.
(3) Exhibits
Exhibit
Number
Description
2.1 * Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Energy Partners, L.P.,
Kinder Morgan G.P., Inc., Kinder Morgan Management, LLC, Kinder Morgan, Inc. (KMI) and P Merger Sub
LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.1 to KMI’s Current
Report on Form 8-K, filed August 12, 2014 (File No. 001-35081))
2.2 * Agreement and Plan of Merger, dated as of August 9, 2014, by and among Kinder Morgan Management, LLC,
KMI, and R Merger Sub LLC (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as
Exhibit 2.2 to KMI’s Current Report on Form 8-K, filed August 12, 2014 (File No. 001-35081))
2.3 * Agreement and Plan of Merger, dated as of August 9, 2014, by and among El Paso Pipeline Partners, L.P., El
Paso Pipeline GP Company, L.L.C., KMI, and E Merger Sub LLC (schedules omitted pursuant to Item 601(b)
(2) of Regulation S-K) (filed as Exhibit 2.3 to KMI’s Current Report on Form 8-K, filed August 12, 2014 (File
No. 001-35081))
3.1 * Amended and Restated Certificate of Incorporation of KMI (filed as Exhibit 3.1 to KMI’s Quarterly Report on
Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
3.2 * Amended and Restated Bylaws of KMI (filed as Exhibit 3.1 to KMI’s Current Report on Form 8-K, filed
January 24, 2017 (File No. 001-35081))
3.3 * Certificate of Designations of KMI 9.75% Series A Mandatory Convertible Preferred Stock, par value $0.01 per
share (KMI Preferred Stock) (filed as Exhibit 3.1 to KMI’s Current Report on Form 8-K filed October 30, 2015
(File No. 001-35081))
68
Exhibit
Number
Description
4.1 * Form of certificate representing Class P common shares of KMI (filed as Exhibit 4.1 to KMI’s Registration
Statement on Form S-1 filed on January 18, 2011 (File No. 333-170773))
4.2 * Shareholders Agreement among KMI and certain holders of common stock (filed as Exhibit 4.2 to KMI’s
Quarterly Report on Form 10-Q for the three Months ended March 31, 2011 (File No. 001-35081))
4.3 * Amendment No. 1 to the Shareholders Agreement among KMI and certain holders of common stock (filed as
Exhibit 4.3 to KMI’s Current Report on Form 8-K filed on May 30, 2012 (File No. 001-35081))
4.4 * Amendment No. 2 to the Shareholders Agreement among KMI and certain holders of common stock (filed as
Exhibit 4.1 to KMI’s Current Report on Form 8-K filed on December 3, 2014 (File No. 001-35081))
4.5 * Warrant Agreement, dated as of May 25, 2012, among KMI, Computershare Trust Company, N.A. and
Computershare Inc., as Warrant Agent (filed as Exhibit 4.1 to KMI’s Current Report on Form 8-K filed on May
30, 2012 (File No. 001-35081))
4.6 * Form of certificate for KMI Preferred Stock (included as Exhibit A to Exhibit 3.1 to KMI’s Current Report on
Form 8-K filed October 30, 2015 (File No. 001-35081))
4.7 * Deposit Agreement, dated as of October 30, 2015, between KMI and Computershare Inc. and Computershare
Trust Company, N.A., as joint depositary, on behalf of all holders from time to time of the depositary receipts
issued thereunder (filed as Exhibit 4.2 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No.
001-35081))
4.8 * Form of Depositary Receipt for depositary shares, each representing 1/20th of a share of KMI Preferred Stock
(included as Exhibit A to Exhibit 4.2 to KMI’s Current Report on Form 8-K filed October 30, 2015 (File No.
001-35081))
4.9 * Form of Senior Indenture between Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as
Trustee (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on
February 4, 2003 (File No. 333-102963))
4.10 * Form of Senior Note of Kinder Morgan Kansas, Inc. (included in the Form of Senior Indenture filed as Exhibit
4.2 to Kinder Morgan Kansas, Inc.’s Registration Statement on Form S-3 filed on February 4, 2003 (File No.
333-102963))
4.11 *
Indenture dated as of December 9, 2005, among Kinder Morgan Finance Company LLC (formerly Kinder
Morgan Finance Company, ULC), Kinder Morgan Kansas, Inc. and Wachovia Bank, National Association, as
Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December
15, 2005 (File No. 1-06446))
4.12 * Forms of Kinder Morgan Finance Company LLC Notes (included in the Indenture filed as Exhibit 4.1 to Kinder
Morgan Kansas, Inc.’s Current Report on Form 8-K filed on December 15, 2005 (File No. 1-06446))
4.13 *
Indenture dated January 2, 2001 between Kinder Morgan Energy Partners, L.P. and First Union National Bank,
as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to
Kinder Morgan Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2000
(File No. 1-11234))
4.14 * Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing
the terms of the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s
Current Report on Form 8-K filed on March 14, 2001 (File No. 1-11234))
4.15 * Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan
Energy Partners, L.P.’s Current Report on Form 8-K filed on March 14, 2001(File No. 1-11234))
4.16 * Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing
the terms of the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners,
L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No. 1-11234))
4.17 * Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan
Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 (File No.
1-11234))
69
Exhibit
Number
4.18 *
Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National
Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on
Form S-4 filed on October 4, 2002 (File No. 333-100346))
Description
4.19 * First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder
Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to
Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No.
333-100346))
4.20 * Form of 7.30% Notes due 2033 (contained in the Indenture filed as Exhibit 4.1 to Kinder Morgan Energy
Partners, L.P.’s Registration Statement on Form S-4 filed on October 4, 2002 (File No. 333-100346))
4.21 * Senior Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank,
National Association (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on
Form S-3 filed on February 4, 2003 (File No. 333-102961))
4.22 * Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as
Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Registration Statement on Form S-3 filed on February 4,
2003 (File No. 333-102961))
4.23 * Certificate of Vice President, Treasurer and Chief Financial Officer and Vice President, General Counsel and
Secretary of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
Energy Partners, L.P. establishing the terms of the 5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to
Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005
(File No. 1-11234))
4.24 * Certificate of Vice President and Chief Financial Officer of Kinder Morgan Management, LLC and Kinder
Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.00% Senior
Notes due 2017 and 6.50% Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners,
L.P.’s Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-11234))
4.25 * Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder
Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder Morgan Energy
Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-11234))
4.26 * Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder
Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy
Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-11234))
4.27 * Certificate of the Vice President and Treasurer and the Vice President and Chief Financial Officer of Kinder
Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 9.00% Senior Notes due 2019 (filed as Exhibit 4.29 to Kinder Morgan Energy
Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 1-11234))
4.28 * Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder
Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 6.85% Senior Notes due 2020 (filed as Exhibit 4.2 to Kinder Morgan Energy
Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-11234))
4.29 * Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder
Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 5.80% Senior Notes due 2021, and the 6.50% Senior Notes due 2039 (filed as
Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2009 (File No. 1-11234))
4.30 * Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder
Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 5.30% Senior Notes due 2020, and the 6.55% Senior Notes due 2040 (filed as
Exhibit 4.2 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2010 (File No. 1-11234))
4.31 *
Indenture, dated December 20, 2010, among Kinder Morgan Finance Company LLC, Kinder Morgan Kansas,
Inc. and U.S. Bank National Association, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Kansas, Inc.’s
Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
70
Exhibit
Number
Description
4.32 * Officers’ Certificate establishing the terms of the 6.000% Senior Notes due 2018 of Kinder Morgan Finance
Company LLC (with the form of note attached thereto) (filed as Exhibit 4.2 to Kinder Morgan Kansas, Inc.’s
Current Report on Form 8-K filed on December 23, 2010 (File No. 1-06446))
4.33 * Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder
Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 6.375% Senior Notes due 2041 (filed as Exhibit 4.1 to Kinder Morgan Energy
Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 1-11234))
4.34 * Certificate of the Vice President and Chief Financial Officer and the Vice President and Treasurer of Kinder
Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 4.150% Senior Notes due 2022, and the 5.625% Senior Notes due 2041 (filed as
Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2011 (File No. 1-11234))
4.35 * Certificate of the Vice President, Finance and Investor Relations and the Vice President and Secretary of Kinder
Morgan Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 3.500% Senior Notes due 2021 and the 5.500% Senior Notes due 2044 (Filed as
Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2014 (File No. 1-11234))
4.36 * Certificate of the Vice President and Treasurer and the Vice President and Secretary of Kinder Morgan
Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.,
establishing the terms of the 4.250% Senior Notes due 2024 and the 5.400% Senior Notes due 2044 (Filed as
Exhibit 4.1 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended
September 30, 2014 (File No. 1-11234))
4.37 *
Indenture, dated March 1, 2012, among KMI and U.S. Bank National Association, as Trustee (filed as Exhibit
4.1 to KMI’s Registration Statement on Form S-3 filed on March 1, 2012 (File No. 001-35081))
4.38 * Certificate of the Vice President and Treasurer and the Vice President and Secretary of KMI establishing the
terms of the 2.000% Senior Notes due 2017, the 3.050% Senior Notes due 2019, the 4.300% Senior Notes due
2025, the 5.300% Senior Notes due 2034 and the 5.550% Senior Notes due 2045 (filed as Exhibit 10.53 to
KMI’s Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 001-35081))
4.39 * Certificate of Vice President and Treasurer and Vice President and Secretary of KMI establishing the terms of
the 5.050% Senior Notes due 2046 (filed as Exhibit 4.1 to KMI’s Quarterly Report on Form 10-Q for the three
months ended March 31, 2015 (File No. 001-35081))
4.40 * Certificate of Vice President and Treasurer and Vice President and Secretary of KMI establishing the terms of
the 1.500% Senior Notes due 2022 and 2.250% Senior Notes due 2027 (filed as Exhibit 4.2 to KMI’s Form 8-A,
filed March 16, 2015 and incorporated herein by reference (File No. 001-35081))
4.41
Certain instruments with respect to long-term debt of KMI and its consolidated subsidiaries which relate to debt
that does not exceed 10% of the total assets of KMI and its consolidated subsidiaries are omitted pursuant to
Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec. #229.601. KMI hereby agrees to furnish
supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
10.1 * KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 4.5 to KMI’s Registration Statement on
Form S-8, filed on July 1, 2015, and incorporated herein by reference (File No. 333-205430))
10.2 * Amendment No. 1 to KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 10.2 to KMI’s
Current Report on Form 8-K filed on January 24, 2017 (File No. 001-35081))
10.3 *
10.4 *
2015 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 4.6 to KMI’s Registration Statement
on Form S-8, filed on July 1, 2015, and incorporated herein by reference (File No. 333-205430))
2016 Form of Employee Restricted Stock Unit Agreement (filed as Exhibit 10.2 to KMI’s Quarterly Report on
Form 10-Q for the three months ended June 30, 2016 (File No. 001-35081))
10.5 * Amended and Restated Stock Compensation Plan for Non-Employee Directors (filed as Exhibit 10.5 to KMI’s
Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
10.6 *
2015 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.6 to KMI’s
Quarterly Report on Form 10-Q for the three months ended June 30, 2015 (File No. 001-35081))
71
Exhibit
Number
10.7 *
2011 Form of Non-Employee Director Stock Compensation Agreement (filed as Exhibit 10.3 to KMI’s
Quarterly Report on Form 10-Q for the three months ended March 31, 2011 (File No. 001-35081))
Description
10.8 * KMI Employees Stock Purchase Plan (filed as Exhibit 10.5 to KMI’s Quarterly Report on Form 10-Q for the
three months ended March 31, 2011 (File No. 001-35081))
10.9 * Amended and Restated Annual Incentive Plan of KMI (filed as Exhibit 10.4 to KMI’s Quarterly Report on Form
10-Q for the three months ended June 30, 2015 (File No. 001-35081))
10.10 * Amendment No. 1 to Amended and Restated Incentive Plan of KMI (filed as Exhibit 10.1 to KMI’s Current
Report on Form 8-K filed January 24, 2017 (File No. 001-35081))
10.11 * Support Agreement, dated as of August 9, 2014, by and among Kinder Morgan Energy Partners, L.P., Kinder
Morgan G.P., Inc., Kinder Morgan Management, LLC, El Paso Pipeline Partners, L.P., El Paso Pipeline GP
Company, L.L.C., Richard D. Kinder and RDK Investments, Ltd. (filed as Exhibit 10.1 to KMI’s Current Report
on Form 8-K filed August 12, 2014 (File No. 001-35081))
10.12 * Bridge Credit Agreement, dated September 19, 2014 among KMI, as borrower, Barclays Bank PLC, as
administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K
filed September 25, 2014 (File No. 001-35081))
10.13 * Revolving Credit Agreement, dated September 19, 2014 among KMI, as borrower, Barclays Bank PLC, as
administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.2 to KMI’s Current
Report on Form 8-K filed September 25, 2014(File No. 001-35081))
10.14 * Term Loan Agreement, dated as of January 26, 2016 among KMI, as borrower, the lenders party thereto and
Barclays Bank PLC, as administrative agent (filed as exhibit 10.2 to KMI’s Quarterly Report on Form 10-Q for
the three months ended March 31, 2016 (File No. 001-35081))
10.15 *
Joinder Agreement, dated as of January 26, 2016, to KMI’s Revolving Credit Agreement, dated as of September
19, 2014 among KMI, the lenders party thereto and Barclay Bank PLC, as administrative agent. (filed as exhibit
10.3 to KMI’s Quarterly Report on Form 10-Q for the three months ended March 31, 2016 (File No.
001-35081))
10.16
Cross Guarantee Agreement, dated as of November 26, 2014 among KMI and certain of its subsidiaries with
schedules updated as of December 31, 2016
12.1
21.1
23.1
31.1
31.2
32.1
32.2
95.1
101
Statement re: computation of ratio of earnings to fixed charges
Subsidiaries of KMI
Consent of PricewaterhouseCoopers LLP
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act
of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act
of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
Mine Safety Disclosures
Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the
years ended December 31, 2016, 2015, and 2014; (ii) our Consolidated Statements of Comprehensive Income
for the years ended December 31, 2016, 2015, and 2014; (iii) our Consolidated Balance Sheets as of December
31, 2016 and 2015; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2016,
2015, and 2014; (v) our Consolidated Statement of Stockholders’ Equity as of and for the years ended December
31, 2016, 2015, and 2014; and (vi) the notes to our Consolidated Financial Statements
_______
*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted
otherwise.
72
KINDER MORGAN, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and
2014
Consolidated Balance Sheets as of December 31, 2016 and 2015
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014
Consolidated Statement of Stockholders’ Equity as of and for the years ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
Supplemental Selected Quarterly Financial Data (Unaudited)
Page
Number
74
75
76
77
78
80
81
147
73
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Kinder Morgan, Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of
comprehensive income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position
of Kinder Morgan, Inc. and its subsidiaries (the “Company”) at December 31, 2016 and 2015, and the results of their operations
and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting
principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal
Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in
Management's Report on Internal Control over Financial Reporting appearing in Item 9A of the Company’s 2016 Annual
Report on Form 10-K. Our responsibility is to express opinions on these financial statements and on the Company's internal
control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of
the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits
to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall financial statement
presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 10, 2017
74
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions, Except Per Share Amounts)
Year Ended December 31,
2015
2014
2016
Revenues
Natural gas sales
Services
Product sales and other
Total Revenues
Operating Costs, Expenses and Other
Costs of sales
Operations and maintenance
Depreciation, depletion and amortization
General and administrative
Taxes, other than income taxes
Loss on impairment of goodwill
Loss on impairments and divestitures, net
Other (income) expense, net
Total Operating Costs, Expenses and Other
Operating Income
Other Income (Expense)
Earnings from equity investments
Loss on impairments and divestitures of equity investments, net
Amortization of excess cost of equity investments
Interest, net
Other, net
Total Other Expense
Income Before Income Taxes
Income Tax Expense
Net Income
Net (Income) Loss Attributable to Noncontrolling Interests
Net Income Attributable to Kinder Morgan, Inc.
Preferred Stock Dividends
Net Income Available to Common Stockholders
Class P Shares
Basic Earnings Per Common Share
Basic Weighted Average Common Shares Outstanding
Diluted Earnings Per Common Share
Diluted Weighted Average Common Shares Outstanding
Dividends Per Common Share Declared for the Period
$
$
$
2,454
8,146
2,458
13,058
2,839
8,290
3,274
14,403
4,115
7,650
4,461
16,226
3,498
2,303
2,209
669
421
—
387
(1)
9,486
4,115
2,337
2,309
690
439
1,150
919
(3)
11,956
6,278
2,157
2,040
610
418
—
274
1
11,778
3,572
2,447
4,448
497
(610)
(59)
(1,806)
44
(1,934)
414
(30)
(51)
(2,051)
43
(1,675)
406
—
(45)
(1,798)
80
(1,357)
1,638
772
3,091
(917)
(564)
(648)
721
(13)
708
208
45
253
(156)
(26)
2,443
(1,417)
1,026
—
552
$
227
$
1,026
0.25
$
0.10
$
0.89
2,230
2,187
1,137
0.25
$
0.10
$
0.89
2,230
2,193
1,137
0.50
$
1.605
$
1.74
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
75
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In Millions)
Net income
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $60, $(94) and $(163),
respectively)
Reclassification of change in fair value of derivatives to net income (net of tax benefit of $67,
$156 and $13, respectively)
Foreign currency translation adjustments (net of tax (expense) benefit of $(20), $123 and $48,
respectively)
Benefit plan adjustments (net of tax benefit of $19, $69 and $126, respectively)
Total other comprehensive (loss) income
Comprehensive income (loss)
Comprehensive (income) loss attributable to noncontrolling interests
Year Ended December 31,
2016
2015
2014
$
721
$
208
$ 2,443
(104)
164
409
(116)
(272)
(25)
34
(14)
(200)
521
(13)
(214)
(122)
(444)
(138)
(226)
20
(236)
45
2,463
(1,486)
Comprehensive income (loss) attributable to KMI
$
508
$
(191) $
977
The accompanying notes are an integral part of these consolidated financial statements.
76
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Millions, Except Share and Per Share Amounts)
ASSETS
December 31,
2016
2015
Current assets
Cash and cash equivalents
Restricted deposits
Accounts receivable, net
Fair value of derivative contracts
Inventories
Income tax receivable
Other current assets
Total current assets
Property, plant and equipment, net
Investments
Goodwill
Other intangibles, net
Deferred income taxes
Deferred charges and other assets
Total Assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt
Accounts payable
Accrued interest
Accrued contingencies
Other current liabilities
Total current liabilities
Long-term liabilities and deferred credits
Long-term debt
Outstanding
Preferred interest in general partner of KMP
Debt fair value adjustments
Total long-term debt
Other long-term liabilities and deferred credits
Total long-term liabilities and deferred credits
Total Liabilities
Commitments and contingencies (Notes 9, 13 and 17)
Stockholders’ Equity
$
$
$
$
$
$
684
103
1,370
198
357
180
337
3,229
38,705
7,027
22,152
3,318
4,352
1,522
80,305
2,696
1,257
625
261
1,085
5,924
36,105
100
1,149
37,354
2,225
39,579
45,503
229
60
1,315
507
407
40
266
2,824
40,547
6,040
23,790
3,551
5,323
2,029
84,104
821
1,192
695
298
1,059
4,065
40,632
100
1,674
42,406
2,230
44,636
48,701
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,230,102,384 and
2,229,223,864 shares, respectively, issued and outstanding
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory
22
22
Convertible, $1,000 per share liquidation preference, 1,600,000 shares issued and
outstanding
Additional paid-in capital
Retained deficit
Accumulated other comprehensive loss
—
41,739
(6,669)
(661)
34,431
371
34,802
80,305
The accompanying notes are an integral part of these consolidated financial statements.
$
Noncontrolling interests
Total Stockholders’ Equity
Total Liabilities and Stockholders’ Equity
Total Kinder Morgan, Inc.’s stockholders’ equity
—
41,661
(6,103)
(461)
35,119
284
35,403
84,104
$
77
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
Year Ended December 31,
2016
2015
2014
Cash Flows From Operating Activities
Net income
Adjustments to reconcile net income to net cash provided by operating activities
$
721
$
208
$
Depreciation, depletion and amortization
Deferred income taxes
Amortization of excess cost of equity investments
Gain on early extinguishment of debt
Loss on impairment of goodwill (Note 4)
Loss on impairments and divestitures, net (Note 4)
Loss on impairments and divestitures of equity investments, net (Note 4)
Earnings from equity investments
Distributions of equity investment earnings
Pension contributions and noncash pension benefit credits
Changes in components of working capital, net of the effects of acquisitions
Accounts receivable
Income tax receivable
Inventories
Other current assets
Accounts payable
Accrued interest, net of interest rate swaps
Accrued contingencies and other current liabilities
Rate reparations, refunds and other litigation reserve adjustments
Other, net
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired
Capital expenditures
Proceeds from sale of equity interests in subsidiaries, net
Sales of property, plant and equipment, investments, and other net assets, net of removal costs
Contributions to investments
Distributions from equity investments in excess of cumulative earnings
Other, net
Net Cash Used in Investing Activities
Cash Flows From Financing Activities
Issuances of debt
Payments of debt
Debt issue costs
Issuances of common shares (Note 11)
Issuance of mandatory convertible preferred stock (Note 11)
Cash dividends - common shares (Note 11)
Cash dividends - preferred shares (Note 11)
Repurchases of shares and warrants
Cash consideration of Merger Transactions (Note 1)
Merger Transactions costs
Contributions from noncontrolling interests
Distributions to noncontrolling interests
Other, net
Net Cash (Used in) Provided by Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net increase (decrease) in Cash and Cash Equivalents
Cash and Cash Equivalents, beginning of period
Cash and Cash Equivalents, end of period
2,209
1,087
59
(45)
—
387
610
(497)
431
—
(107)
(148)
49
(81)
144
(18)
71
(32)
(53)
4,787
(333)
(2,882)
1,401
330
(408)
231
(44)
(1,705)
8,629
(10,060)
(19)
—
—
(1,118)
(154)
—
—
—
117
(24)
—
(2,629)
2,309
692
51
—
1,150
919
30
(414)
391
(85)
382
195
34
113
(156)
37
(129)
18
(442)
5,303
(2,079)
(3,896)
—
39
(96)
228
98
(5,706)
14,316
(15,116)
(24)
3,870
1,541
(4,224)
—
(12)
—
(2)
11
(34)
1
327
2
455
229
684
$
(10)
(86)
315
229
$
$
78
2,443
2,040
615
45
—
—
274
—
(406)
381
(88)
(84)
(195)
(30)
(17)
(1)
61
108
(280)
(399)
4,467
(1,388)
(3,617)
—
5
(389)
182
(3)
(5,210)
24,573
(17,801)
(89)
—
—
(1,760)
—
(192)
(3,937)
(74)
1,767
(2,013)
(3)
471
(11)
(283)
598
315
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(In Millions)
Noncash Investing and Financing Activities
Assets acquired by the assumption or incurrence of liabilities
$
Net assets contributed to equity investments
Net assets and liabilities or noncontrolling interests acquired by the issuance of shares and
warrants (Notes 1)
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)
Cash paid (refunded) during the period for income taxes, net
Year Ended December 31,
2016
2015
2014
43
37
—
2,050
4
$
1,681
$
46
—
1,985
(331)
106
—
16,023
1,718
227
The accompanying notes are an integral part of these consolidated financial statements.
79
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In Millions)
Common stock
Preferred stock
Issued
shares
Par
value
Issued
shares
Par
value
Additional
paid-in
capital
Retained
deficit
Accumulated
other
comprehensive
loss
Stockholders’
equity
attributable
to KMI
Non-
controlling
interests
Total
— $ — $
14,479
$ (1,372) $
(24) $
13,093
$
15,192
$ 28,285
21,891
(15,936)
5,955
Balance at December 31, 2013
1,031
$
Impact of Merger Transactions
1,097
10
11
Merger Transactions costs
Repurchase of shares and
warrants
Restricted shares
Impact from equity transactions
of KMP, EPB and KMR
(3)
Net income
Distributions
Contributions
Common stock dividends
Other
Other comprehensive (loss)
income
Impact of Merger Transactions
on Accumulated other
comprehensive loss
Balance at December 31, 2014
Issuances of common shares
Issuances of preferred shares
Repurchase of warrants
EP Trust I Preferred security
conversions
Warrants exercised
Restricted shares
Net income
Distributions
Contributions
Preferred stock dividends
Common stock dividends
Other
Other comprehensive loss
2,125
103
21
1
—
2
1
21,880
(75)
(192)
52
36
(2)
1,026
(1,760)
—
36,178
(2,106)
3,869
1,541
(12)
23
2
57
3
253
(26)
(4,224)
Balance at December 31, 2015
2,229
22
2
—
41,661
(6,103)
1
Restricted shares
Net income
Distributions
Contributions
Preferred stock dividends
Common stock dividends
Other
Other comprehensive loss
66
12
708
(156)
(1,118)
(75)
(192)
52
36
1,026
—
—
(1,760)
(2)
(49)
56
34,076
3,870
1,541
(12)
23
2
57
253
—
—
(26)
(4,224)
3
(444)
35,119
66
708
—
—
(156)
(1,118)
12
(200)
(49)
56
(17)
(444)
(461)
(200)
(75)
(192)
52
(19)
2,443
(2,013)
1,767
(1,760)
(6)
20
(31)
34,426
3,870
1,541
(12)
23
2
57
208
(34)
11
(26)
(4,224)
5
(444)
(55)
1,417
(2,013)
1,767
(4)
69
(87)
350
(45)
(34)
11
2
284
35,403
13
(24)
117
(19)
66
721
(24)
117
(156)
(1,118)
(7)
(200)
$ 34,802
Balance at December 31, 2016
2,230
$
22
2
$ — $
41,739
$ (6,669) $
(661) $
34,431
$
371
The accompanying notes are an integral part of these consolidated financial statements.
80
KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General
We are one of the largest energy infrastructure companies in North America and unless the context requires otherwise,
references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated
subsidiaries. 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 steel, coal and
petroleum coke. We are also a leading producer of CO2, which we and others utilize for enhanced oil recovery projects
primarily in the Permian basin.
On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the
outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we did not already own. The
transactions are referred to collectively as the “Merger Transactions.”
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 related to the Merger Transactions. After closing the Merger
Transactions, KMR was merged with and into KMI. On January 1, 2015, EPB and its subsidiary, EPPOC, merged with and
into KMP. References to EPB refer to EPB for periods prior to its merger into KMP.
Prior to the Merger Transactions, 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 were eliminated.
The equity interests in KMP, EPB and KMR (which are all consolidated in our financial statements) owned by the public
prior to the Merger Transactions are reflected within “Noncontrolling interests” in our accompanying consolidated statements
of stockholders’ equity. The earnings recorded by KMP, EPB and KMR that are attributed to their units and shares,
respectively, held by the public prior to the Merger Transactions are reported as “Net (income) loss attributable to
noncontrolling interests” in our accompanying consolidated statement of income for the year ended December 31, 2014.
Our common stock trades on the NYSE under the symbol “KMI.”
2. Summary of Significant Accounting Policies
Basis of Presentation
Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our
accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules
and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification, the single
source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in
consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
Use of Estimates
Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us
to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our
financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities,
our revenues and expenses during the reporting period, and our disclosures, including as it relates to contingent assets and
liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, 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. 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.
81
Certain accounting policies are of more significance in our financial statement preparation process than others, and set
out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.
Cash Equivalents and Restricted Deposits
We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.
Restricted deposits were $103 million and $60 million as of December 31, 2016 and 2015, respectively.
Accounts Receivable, net
The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of
December 31, 2016 and 2015 primarily consist of amounts due from customers net of the allowance for doubtful accounts.
Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business
being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the
appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record
adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are
determined to be uncollectible, the reserve and receivable are relieved.
The allowance for doubtful accounts was $39 million and $91 million as of December 31, 2016 and 2015, respectively.
The decrease was primarily associated with certain coal customers’ receivables that were written off in 2016 and had been
reserved in prior periods.
Inventories
Our inventories consist of materials and supplies and products such as, NGL, crude oil, condensate, refined petroleum
products, transmix and natural gas. We report products inventory at the lower of weighted-average cost or net realizable
value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and
obsolescence.
Gas Imbalances
We value gas imbalances due to or due from interconnecting pipelines at market prices. As of December 31, 2016 and
2015, our gas imbalance receivables—including both trade and related party receivables—totaled $108 million and $21
million, respectively, and we included these amounts within “Other current assets” on our accompanying consolidated
balance sheets. As of December 31, 2016 and 2015, our gas imbalance payables—including both trade and related party
payables—totaled $45 million and $17 million, respectively, and we included these amounts within “Other current
liabilities” on our accompanying consolidated balance sheets.
Property, Plant and Equipment, net
Capitalization, Depreciation and Depletion and Disposals
We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in
the period incurred.
We generally compute depreciation using either the straight-line method based on estimated economic lives or, for
certain depreciable assets, we employ the composite depreciation method, applying a single depreciation rate for a group of
assets. Generally, we apply composite depreciation rates to functional groups of property having similar economic
characteristics. The rates range from 1.09% to 23.0% excluding certain short-lived assets such as vehicles. For FERC-
regulated entities, the FERC-accepted composite depreciation rate is applied to the total cost of the composite group until the
net book value equals the salvage value. For other entities, depreciation estimates are based on various factors, including age
(in the case of acquired assets), manufacturing specifications, technological advances, contract term for assets on leased or
customer property and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates
include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and
supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives (and salvage
values where appropriate) that we believe are reasonable. Subsequent events could cause us to change our estimates, thus
82
impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not
had a material impact on our aggregate depreciation levels from year to year.
Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this
method costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are
associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with
the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-
producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are
depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are
depreciated over the estimated useful lives of the asset.
We engage in enhanced recovery techniques in which CO2 is injected into certain producing oil reservoirs. In some
cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is
injected. The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is
injected. When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated
costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and
development costs, and total proved reserves are used for depletion of leasehold costs. The units-of-production depreciation
rate is determined by field and for our oil and gas producing fields that have no proved reserves, the units-of-production
depreciation rate is based on each field’s probable reserves and NYMEX forward curve prices.
A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our bulk and liquids
terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales
proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale
of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation,
and the sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is
sold or when the net cost of an asset held for sale is greater than the market value of the asset. For our pipeline system assets
under the composite method of depreciation, we generally charge the original cost of property sold or retired to accumulated
depreciation and amortization, net of salvage and cost of removal. Gains and losses are booked for operating unit sales and
land sales and are recorded to income or expense accounts in accordance with regulatory accounting guidelines. In those
instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory
asset for the estimated recoverable amount.
Asset Retirement Obligations
We record liabilities for obligations related to the retirement and removal of long-lived assets used in our
businesses. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are
incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Amounts
recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the
change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The
liabilities are eventually extinguished when the asset is taken out of service.
We have various other obligations throughout our businesses to remove facilities and equipment on rights-of-way and
other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated
assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and
certain bulk and liquids terminal facilities. An asset retirement obligation, if any, will be recognized once sufficient
information is available to reasonably estimate the fair value of the obligation.
Long-lived Asset Impairments
We evaluate long-lived assets and investments for impairment whenever events or changes in circumstances indicate
that our carrying amount of an asset or investment may not be recoverable. We recognize impairment losses when estimated
future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount.
Prior to us conducting the goodwill impairment test, to the extent triggering events exist, we complete a review of the
carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as
applicable, the appropriate impairments. Because the impairment test for long-lived assets held in use is based on
undiscounted cash flows, there may be instances where an asset or asset group is not considered impaired, even when its fair
value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be
generated over the estimated life of the asset or asset group.
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We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain
instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows
based on total proved and risk-adjusted probable reserves.
Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by
discounted future cash flows based on total proved and risk-adjusted probable and possible reserves or, if available,
comparable market values. Unproved oil and gas properties that are individually significant are periodically assessed for
impairment of value, and a loss is recognized at the time of impairment.
Equity Method of Accounting and Excess Investment Cost
We account for investments which we do not control, but do have the ability to exercise significant influence using the
equity method of accounting. Under this method, our equity investments are carried originally at our acquisition cost,
increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our
proportionate share of the investee’s net losses and by distributions received.
With regard to our equity investments in unconsolidated affiliates, in almost all cases, either (i) the price we paid to
acquire our share of the net assets of such equity investees or (ii) the revaluation of our share of the net assets of any retained
noncontrolling equity investment (from the sale of a portion of our ownership interest in a consolidated subsidiary, thereby
losing our controlling financial interest in the subsidiary) differed from the underlying carrying value of such net assets. This
differential consists of two pieces. First, an amount related to the difference between the investee’s recognized net assets at
book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any
premium in excess of fair value (referred to as equity method goodwill) we paid to acquire the investment. We include both
amounts within “Investments” on our accompanying consolidated balance sheets.
The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its
underlying book value at either the date of acquisition or the date of the loss of control totaled $767 million and $808 million
as of December 31, 2016 and 2015, respectively. Generally, this basis difference relates to our share of the underlying
depreciable assets, and, as such, we amortize this portion of our investment cost against our share of investee earnings. As of
December 31, 2016, this excess investment cost is being amortized over a weighted average life of approximately fourteen
years.
The second differential, representing equity method goodwill, totaled $956 million and $138 million, as of
December 31, 2016 and 2015, respectively. This differential is not subject to amortization but rather to impairment testing as
part of our periodic evaluation of the recoverability of our investment as compared to the fair value of net assets accounted
for under the equity method. Our impairment test considers whether the fair value of the equity investment as a whole has
declined and whether that decline is other than temporary. The increase in the equity method goodwill balance from
December 31, 2015 is due to the sale of a 50% interest in our SNG natural gas pipeline system, see Note 3.
Goodwill
Goodwill is the cost of an acquisition in excess of the fair value of acquired assets and liabilities and is recorded as an
asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually. This
test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting
unit’s goodwill is less than its carrying amount.
We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have seven reporting units as
follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from
Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated;
(v) CO2; (vi) Terminals; and (vii) Kinder Morgan Canada. We also evaluate goodwill for impairment to the extent events or
conditions indicate a risk of possible impairment during the interim periods subsequent to our annual impairment test.
Generally, the evaluation of goodwill for impairment involves a two-step test, although under certain circumstance an initial
qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.
Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including
goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If
the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and,
if so, the amount of the impairment. Step 2 involves calculating an implied fair value of goodwill by performing a
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hypothetical allocation of the estimated fair value of the reporting unit determined in step 1 to the respective tangible and
intangible net assets of the reporting unit. The remaining implied goodwill is then compared to the actual carrying amount of
the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeds the implied goodwill, the
difference is the amount of the goodwill impairment.
A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all
or a portion of the impairment may not result in a corresponding tax benefit.
Refer to Note 8 for further information.
Other Intangibles
Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value,
and technology-based assets. As of December 31, 2016 and 2015, the gross carrying amounts of these intangible assets was
$4,305 million and $4,335 million, respectively and the accumulated amortization was $986 million and $784 million,
respectively, resulting in net carrying amounts of $3,318 million and $3,551 million, respectively. These intangible assets
primarily consisted of customer contracts, relationships and agreements associated with our Natural Gas Pipelines and
Terminals business segments.
Primarily, these contracts, relationships and agreements relate to the gathering of natural gas, and the handling and
storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline and other refined petroleum products,
petroleum coke, steel and ores. We determined the values of these intangible assets by first, estimating the revenues derived
from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and
second, discounting the revenues at a risk adjusted discount rate.
We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful
lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in
the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that
business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer
relationship. Among the factors we weigh, depending on the nature of the asset, are the effect of obsolescence, new
technology, and competition.
For the years ended December 31, 2016, 2015 and 2014, the amortization expense on our intangibles totaled $223
million, $221 million and $143 million, respectively. Our estimated amortization expense for our intangible assets for each
of the next five fiscal years (2017 – 2021) is approximately $215 million, $213 million, $211 million, $209 million, and
$208 million, respectively. As of December 31, 2016, the weighted average amortization period for our intangible assets was
approximately seventeen years.
Other intangibles are evaluated for recoverability consistent with the discussion above on long-lived asset impairments.
Revenue Recognition
We recognize revenue as services are rendered or goods are delivered and, if applicable, risk of loss has passed. We
recognize natural gas, crude and NGL sales revenue when the commodity is sold to a purchaser at a fixed or determinable
price, delivery has occurred and risk of loss has transferred, and collectability of the revenue is reasonably assured. Our
sales and purchases of natural gas, crude and NGL are primarily accounted for on a gross basis as natural gas sales or product
sales, as applicable, and cost of sales, except in circumstances where we solely act as an agent and do not have price and
related risk of ownership, in which case we recognize revenue on a net basis.
In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we
provide various types of natural gas storage and transportation services for third-party customers. Under these contracts, the
natural gas remains the property of these customers at all times. In many cases, generally described as firm service, the
customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities
and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of
the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue
when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/
withdrawn from our storage facilities.
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In other cases, generally described as interruptible service, there is no fixed fee associated with the services because the
customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have
purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-
unit rate for volumes actually transported under firm service agreements.
We provide crude oil and refined petroleum products transportation and storage services to customers. Revenues are
recorded when products are delivered and services have been provided, and adjusted according to terms prescribed by the
toll settlements with shippers and approved by regulatory authorities.
We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids
terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on
volumes received and volumes delivered. We recognize transmix processing revenues based on volumes processed or sold,
and if applicable, when risk of loss has passed. We recognize energy-related product sales revenues based on delivered
quantities of product.
Revenues from the sale of crude oil, NGL, CO2 and natural gas production within the CO2 business segment are
recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our
net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a
ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at
which time title and risk of loss pass to the buyer.
Cost of Sales
Cost of sales primarily includes the cost of energy commodities sold, including natural gas, NGL and other refined
petroleum products, adjusted for the effects of our energy commodity activities, as applicable, other than production from
our CO2 business segment.
Operations and Maintenance
Operations and maintenance include costs of services and is primarily comprised of (i) operational labor costs and (ii)
operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our oil, gas and
carbon dioxide producing activities included within operations and maintenance totaled $349 million, $366 million and $403
million for the years ended December 31, 2016, 2015 and 2014, respectively.
Environmental Matters
We capitalize or expense, as appropriate, environmental expenditures. We capitalize certain environmental expenditures
required in obtaining rights-of-way, regulatory approvals or permitting as part of the construction. We accrue and expense
environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or
future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record
environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably
estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our
commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such
recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities
assumed in a business combination.
We routinely conduct reviews of potential environmental issues and claims that could impact our assets or
operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation
efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making
environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions
against us, and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional
information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in
which they are reasonably determinable.
Pensions and Other Postretirement Benefits
We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other
postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheet.
We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and
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any remaining unamortized transition obligations—in “Accumulated other comprehensive loss” or as a regulatory asset or
liability for certain of our regulated operations, until they are amortized as a component of benefit expense.
Noncontrolling Interests
Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us. In our
accompanying consolidated income statements, the noncontrolling interest in the net income (or loss) of our consolidated
subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net (Income) Loss
Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is
presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”
Income Taxes
Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the
relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are
effective. 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.
Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and
liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance for the 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 determining the deferred income tax asset and liability balances attributable to our investments, we apply 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.
Foreign Currency Transactions and Translation
Foreign currency transaction gains or losses result from a change in exchange rates between (i) the functional currency,
for example the Canadian dollar for a Canadian subsidiary and (ii) the currency in which a foreign currency transaction is
denominated, for example the U.S. dollar for a Canadian subsidiary. In our accompanying consolidated statements of
income, gains and losses from our foreign currency transactions are included within “Other Income (Expense)—Other, net.”
Foreign currency translation is the process of expressing, in U.S. dollars, amounts recorded in a local functional
currency other than U.S. dollars, for example the Canadian dollar for a Canadian subsidiary. We translate the assets and
liabilities of each of our consolidated foreign subsidiaries that have a local functional currency to U.S. dollars at year-end
exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year
and stockholders’ equity accounts are translated by using historical exchange rates. The cumulative translation adjustments
balance is reported as a component of “Accumulated other comprehensive loss.”
Risk Management Activities
We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in
the market price of commodities including natural gas, NGL and crude oil. In addition, we enter into interest rate swap
agreements for the purpose of hedging the interest rate risk associated with our debt obligations. We also enter into cross-
currency swap agreements to manage our foreign currency risk with certain debt obligations. We measure our derivative
contracts at fair value and we report them on our balance sheet as either an asset or liability. For certain physical forward
commodity derivatives contracts, we apply the normal purchase/normal sale exception, whereby the revenues and expenses
associated with such transactions are recognized during the period when the commodities are physically delivered or
received.
For qualifying accounting hedges, we formally document the relationship between the hedging instrument and the
hedged item, the risk management objectives and the methods used for assessing and testing effectiveness, and how any
87
ineffectiveness will be measured and recorded. If we designate a derivative contract as a cash flow accounting hedge, the
effective portion of the change in fair value of the derivative is deferred in accumulated other comprehensive income/(loss)
and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the
derivative’s change in fair value or amount excluded from the assessment of hedge effectiveness is recognized currently in
earnings. If we designate a derivative contract as a fair value accounting hedge, the effective portion of the change in fair
value of the derivative is recorded as an adjustment to the item being hedged. Any ineffective portion of the derivative’s
change in fair value is recognized currently in earnings.
For derivative instruments that are not designated as accounting hedges, or for which we have not elected the normal
purchase/normal sales exception, changes in fair value are recognized currently in earnings.
Regulatory Assets and Liabilities
Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits
that will be recovered from or refunded to customers through the ratemaking process. We included the amounts of our
regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities”
and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.
The following table summarizes our regulatory asset and liability balances as of December 31, 2016 and 2015 (in
millions):
Current regulatory assets
Non-current regulatory assets
Total regulatory assets(a)
Current regulatory liabilities
Non-current regulatory liabilities
Total regulatory liabilities(b)
December 31,
2016
2015
49
330
379
101
108
209
$
$
$
$
55
378
433
161
166
327
$
$
$
$
_______
(a) Regulatory assets as of December 31, 2016 include (i) $188 million of unamortized losses on disposal of assets; (ii) $107
million income tax gross up on equity AFUDC; and (iii) $84 million of other assets including amounts related to fuel tracker
arrangements. Approximately $172 million of the regulatory assets, with a weighted average remaining recovery period of 20
years, are recoverable without earning a return, including the income tax gross up on equity AFUDC for which there is an
offsetting deferred income tax balance for FERC rate base purposes, and therefore, it does not earn a return.
(b) Regulatory liabilities as of December 31, 2016 are comprised of customer prepayments to be credited to shippers or other over-
collections that are expected to be returned to shippers or netted against under-collections over time. Approximately $24
million of the $108 million classified as non-current is expected to be credited to shippers over a remaining weighted average
period of 22 years, while the remaining $84 million is not subject to a defined period.
Transfer of Net Assets Between Entities Under Common Control
We account for the transfer of net assets between entities under common control by carrying forward the net assets
recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or
liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do
not affect the historical income statement or balance sheet of the combined entity.
Earnings per Share
We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares of common stock
and participating securities based on the amount of dividends paid in the current period plus an allocation of the
undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess
distributions over earnings. Our unvested restricted stock awards, which may be stock or stock units issued to management
employees and include dividend equivalent payments, do not participate in excess distributions over earnings.
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The following tables set forth the allocation of net income available to shareholders of Class P shares and participating
securities and the reconciliation of Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average
Common Shares Outstanding (in millions):
Class P
Participating securities:
Restricted stock awards(a)
Net Income Available to Common Stockholders
$
$
Basic Weighted Average Common Shares Outstanding
Effect of dilutive securities:
Warrants
Diluted Weighted Average Common Shares Outstanding
________
Year Ended December 31,
2016
2015
2014
548
$
214
$
4
552
$
13
227
$
Year Ended December 31,
2015
2014
2016
2,230
—
2,230
2,187
6
2,193
1,015
11
1,026
1,137
—
1,137
(a) As of December 31, 2016, there were approximately 9 million such restricted stock awards.
The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded
from the determination of diluted earnings per share (in millions on a weighted average basis):
Unvested restricted stock awards
Warrants to purchase our Class P shares(a)
Convertible trust preferred securities
Mandatory convertible preferred stock(b)
_______
Year Ended December 31,
2016
2015
2014
8
293
8
58
7
291
8
10
7
312
10
n/a
n/a - not applicable
(a) Each warrant entitles the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash
or by cashless exercise, at any time until May 25, 2017. The potential dilutive effect of the warrants does not consider the assumed
proceeds to KMI upon exercise.
(b) Until our mandatory convertible preferred shares are converted to common shares, on or before the expected mandatory conversion
date of October 26, 2018, the holder of each preferred share participates in our earnings by receiving preferred dividends.
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3. Acquisitions and Divestitures
Business Combinations
During 2016, 2015 and 2014, we completed the following significant acquisitions.
Allocation of Purchase Price
As of December 31, 2016, the evaluation of the assigned fair values for the BP terminals acquisition was ongoing and
subject to adjustment. As of December 31, 2016, our preliminary allocation of the purchase price for the BP terminals
acquisition and the purchase allocation for other significant acquisitions completed during 2016, 2015 and 2014 are detailed
below (in millions):
Acquisition
Purchase
price
Current
assets
Property
plant &
equipment
Deferred
charges
& other
Goodwill
Debt
Other
liabilities
Assignment of Purchase Price
Date
2/16
2/15
2/15
Ref.
(1)
(2)
(3)
(4)
(5)
BP Products North America Inc.
Terminal Assets
$
Vopak Terminal Assets
Hiland
11/14
Pennsylvania and Florida Jones Act
Tankers
1/14
American Petroleum Tankers and
State Class Tankers
$
349
158
1,709
270
961
$
2
2
79
—
6
396
155
1,492
270
951
$
— $
— $
— $
—
1,498
8
6
6
310
25
64
—
(1,413)
—
—
(49)
(5)
(257)
(33)
(66)
After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the
acquisition date, goodwill is an intangible asset representing the future economic benefits expected to be derived from an
acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that
generated our goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and
our expected ability to grow the business we acquired by leveraging our pre-existing business experience. We apply a look
through method of recording deferred income taxes on the outside book-tax basis differences in our investments. As a result,
no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level.
(1) BP Products North America Inc. (BP) Terminal Assets
On February 1, 2016, we completed the acquisition of 15 products terminals and associated infrastructure from BP for
$349 million, including a transaction deposit paid in 2015 and working capital adjustments paid in 2016. In conjunction with
this transaction, we and BP formed a joint venture with an equity ownership interest of 75% and 25%, respectively. Subsequent
to the acquisition, we contributed 14 of the acquired terminals to the joint venture, which we operate, and the remaining
terminal is solely owned by us. BP acquired its 25% interest in the joint venture for $84 million, which we reported as
“Contributions from noncontrolling interests” within our accompanying consolidated statement of cash flows for the year
ended December 31, 2016. Of the acquired assets, 10 terminals are included in our Terminals business segment and 5 terminals
are included in our Products Pipelines business segment based on synergies with each segment’s respective existing operations.
(2) Vopak Terminal Assets
On February 27, 2015, we acquired three U.S. terminals and one undeveloped site from Royal Vopak (Vopak) for
approximately $158 million in cash. The acquisition included (i) a 36-acre, 1,069,500-barrel storage facility at Galena Park,
Texas that handles base oils, biodiesel and crude oil and is immediately adjacent to our Galena Park terminal facility; (ii) two
terminals in North Carolina: one in North Wilmington that handles chemicals and black oil and the other in South Wilmington
that is not currently operating; and (iii) an undeveloped waterfront access site in Perth Amboy, New Jersey. We include the
acquired assets as part of our Terminals business segment.
(3) Hiland
On February 13, 2015, we acquired Hiland, a privately held Delaware limited partnership for aggregate consideration of
approximately $3,122 million, including assumed debt. Approximately $368 million of the debt assumed was immediately
paid down after closing. Hiland’s assets consist primarily of crude oil gathering and transportation pipelines and gas gathering
and processing systems, primarily handling production from the Bakken Formation in North Dakota and Montana. The
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acquired gathering and processing assets are included in our Natural Gas Pipelines business segment while the acquired crude
oil transport pipeline (Double H pipeline) is included in our Products Pipelines business segment. Deferred charges and other
relates to customer contracts and relationships with a weighted average amortization period as of the acquisition date of 16.4
years.
(4) Pennsylvania and Florida Jones Act Tankers
On November 5, 2014, we acquired two Jones Act tankers from Crowley Maritime Corporation (Crowley) for
approximately $270 million. The MT Pennsylvania and the MT Florida engage in the marine transportation of crude oil,
condensate and refined products in the U.S. domestic trade, commonly referred to as the Jones Act trade, and are currently
operating pursuant to multi-year charters with a major integrated oil company. The vessels each have approximately 330 MBbl
of cargo capacity and are included in our Terminals business segment.
(5) American Petroleum Tankers and State Class Tankers
Effective January 17, 2014, we acquired APT and State Class Tankers (SCT) for aggregate consideration of $961 million in
cash (the APT acquisition). APT is engaged in Jones Act trade and its primary assets consist of a fleet of five medium range
Jones Act qualified product tankers, each with 330 MBbl of cargo capacity, and each operating pursuant to long-term time
charters with high quality counterparties, including major integrated oil companies, major refiners and the U.S. Military Sealift
Command. As of the closing date, the vessels’ time charters had an average remaining term of approximately four years, with
renewal options to extend the terms by an average of two years.
SCT commissioned the construction of four medium range Jones Act qualified product tankers, by General Dynamics’
NASSCO shipyard, each with 330 MBbl of cargo capacity and were delivered in 2015 and 2016. The time charters for each
vessel upon completion had an initial term of five years, with renewal options to extend the term by up to three years. The APT
acquisition complements and extends our existing crude oil and refined products transportation and storage business. We
include the acquired assets as part of our Terminals business segment.
Asset Purchase
On July 15, 2015, we purchased from Shell US Gas & Power LLC (Shell) its 49% interest in a joint venture, ELC, that was
in the pre-construction stage of development for liquefaction facilities at Elba Island, Georgia. The transaction was treated as
an asset purchase for the net cash consideration of $185 million. The purchase gives us full ownership and control of ELC.
Therefore, we prospectively changed our method of accounting for ELC from the equity method to full consolidation. Shell
remains subscribed to 100% of the liquefaction capacity.
Investment Acquisition
On December 10, 2015, we and Brookfield Infrastructure Partners L.P. (Brookfield) acquired from Myria Holdings, Inc.
the 53% equity interest in NGPL Holdings LLC not previously owned by us and Brookfield, increasing our ownership to 50%
with Brookfield owning the remaining 50%. We paid $136 million for our additional 30% interest in NGPL Holdings LLC.
See Note 7 for additional information regarding our equity interests in NGPL Holdings LLC.
Sale of Equity Interest and Terminal Assets
Sale of Equity Interest in SNG
On September 1, 2016, we completed the sale of a 50% interest in our SNG natural gas pipeline system to The Southern
Company (Southern Company), receiving proceeds of $1.4 billion, and the formation of a joint venture, which includes our
remaining 50% interest in SNG. We used the proceeds from the sale to reduce outstanding debt (see Note 9). We recognized a
pre-tax loss of $84 million on the sale of our interest in SNG which is included within “Loss on impairments and divestitures,
net” on the accompanying consolidated statement of income for the year ended December 31, 2016. As a result of this
transaction, we no longer hold a controlling interest in SNG or Bear Creek Storage Company, LLC (Bear Creek) (50% of which
is owned by SNG) and, as such, we now account for our remaining equity interests in SNG and Bear Creek as equity
investments.
91
Terminals Asset Sale
In October 2016, we entered into a definitive agreement to sell 20 bulk terminals to an affiliate of Watco Companies, LLC
for approximately $100 million. The terminals are predominantly located along the inland river system and handle mostly coal
and steel products, and are included within our Terminals business segment. The sale of seven of the locations closed in the
fourth quarter of 2016, for which we received $37 million of the total consideration, with the balance of this transaction
expected to close by April 2017 as certain conditions are satisfied. As a result of this transaction, we recognized a pre-tax loss
of $81 million, including a $7 million reduction of goodwill, which is included within “Loss on impairments and divestitures,
net” on our accompanying December 31, 2016 consolidated statement of income for the year ended December 31, 2016, and
we have classified $61 million as held for sale for the remaining thirteen locations which is included within “Other current
assets” on our accompanying consolidated balance sheet at December 31, 2016.
4. Impairments and Losses on Divestitures
During the years ended December 31, 2016, 2015, and 2014, we recorded impairments of certain equity investments, long-
lived assets, and intangible assets, and net losses on divestitures totaling $1,013 million, $2,125 million, and $274 million,
respectively. These adjustments were precipitated by a period of sustained deterioration in commodity prices which impacted
the values of certain of our assets because of lower customer demand and, in the case of our CO2 segment, reduced economics
on our oil and gas properties. This lower commodity price environment led us to cancel certain projects that were in progress
and divest of certain assets. For two of our equity investments in the Natural Gas Pipelines business segment, we determined
that the negative outlook for long-term transportation contracts for those entities resulted in an other than temporary impairment
of those investments in 2016 leading to a fair value write-down.
In addition, an interim goodwill impairment test was performed during the fourth quarter of 2015 resulting in a partial
impairment of goodwill in our Natural Gas Pipelines Non-Regulated reporting unit of approximately $1,150 million. See Note
8 for further information.
These impairments require management to estimate fair value of these assets. The impairments resulting from decisions to
classify assets as held-for-sale are based on the value expected to be realized in the transaction which is generally known at the
time. The estimates of fair value are based on Level 3 valuation estimates using industry standard income approach valuation
methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect
to general economic conditions and the related demand for products handled or transported by our assets as well as assumptions
regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. In
certain cases, management’s decisions to dispose of certain assets may trigger an impairment. We typically use discounted cash
flow analyses to determine the fair value of our assets. We may probability weight various forecasted cash flow scenarios
utilized in the analysis as we consider the possible outcomes. We use discount rates representing our estimate of the risk-
adjusted discount rates that would be used by market participants specific to the particular asset.
We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our
long-lived assets, investments and goodwill. Because certain of our assets, including certain equity investments and oil and gas
producing properties, have been written down to fair value, any deterioration in fair value relative to our carrying value
increases the likelihood of further impairments. Such non-cash impairments could have a significant effect on our results of
operations, which would be recognized in the period in which the carrying value is determined to not be fully recoverable.
92
We recognized the following non-cash pre-tax impairment charges and losses (gains) on divestitures of assets (in millions):
Natural Gas Pipelines
Impairment of goodwill
Impairments of long-lived assets(a)
Losses on divestitures of long-lived assets(b)
Impairment of equity investments(c)
Impairment at equity investee(d)
CO2
Impairments of long-lived assets(e)
Gains on divestitures of long-lived assets
Impairment at equity investee(d)
Terminals
Impairments of long-lived assets(f)
Losses on divestitures of long-lived assets(g)
Losses on impairments and divestitures of equity
investments, net
Products Pipelines
Impairments of long-lived assets(h)
Losses (gains) on divestitures of long-lived assets
Gain on divestiture of equity investment
Year Ended December 31,
2016
2015
2014
$
— $
1,150
$
106
94
606
7
20
(1)
9
19
80
16
66
10
(12)
79
43
26
—
606
—
26
188
3
4
—
1
—
Other gains on divestitures of long-lived assets
Pre-tax losses on impairments and divestitures, net
$
(7)
1,013
$
(1)
2,125
$
—
—
5
—
—
243
—
—
—
29
—
—
(3)
—
—
274
_______
(a) 2016 amount represents the project write-off of our portion of the Northeast Energy Direct (NED) Market project. 2015 amount
represents $47 million and $32 million of project write-offs in our non-regulated midstream and regulated natural gas pipelines assets,
respectively.
(b) 2016 amount primarily relates to our sale of a 50% interest in SNG.
(c) 2016 amount includes a $350 million impairment of our investment in MEP and a $250 million impairment of our investment in Ruby.
2015 amount is primarily related to an impairment of an investment in a gathering and processing asset in Oklahoma.
(d) 2016 and 2015 amounts are losses on impairments recorded by equity investees and included in “Earnings from equity investments” in
our accompanying consolidated statements of income.
(e) 2015 amount includes (i) $399 million related to oil and gas properties and (ii) $207 million related to the certain CO2 source and
transportation project write-offs. 2014 amount is primarily related to oil and gas properties.
(f) 2015 amount is primarily related to certain terminals with significant coal operations, including a $175 million impairment of a terminal
facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer in February 2016.
(g) 2016 amount primarily relates to an agreement to sell 20 bulk terminals that handle mostly coal and steel products, predominately located
along the inland river system. The sale of seven locations closed in the fourth quarter of 2016.
(h) 2016 amount represents project write-offs associated with the canceled Palmetto project.
5. Income Taxes
The components of “Income Before Income Taxes” are as follows (in millions):
U.S.
Foreign
Total Income Before Income Taxes
Year Ended December 31,
2016
2015
2014
$
$
1,466
172
1,638
$
$
611
161
772
$
$
2,941
150
3,091
93
Components of the income tax provision applicable for federal, foreign and state taxes are as follows (in millions):
Year Ended December 31,
2016
2015
2014
Current tax expense (benefit)
Federal
State
Foreign
Total
Deferred tax expense (benefit)
Federal
State
Foreign
Total
$
(148) $
(28)
6
(170)
998
51
38
1,087
Total tax provision
$
917
$
(125) $
(7)
4
(128)
653
(4)
43
692
564
$
(16)
36
13
33
572
14
29
615
648
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows (in
millions, except percentages):
Federal income tax
$
573
35.0 % $
271
35.0 % $
1,082
35.0 %
Year Ended December 31,
2016
2015
2014
Increase (decrease) as a result of:
State deferred tax rate change
Taxes on foreign earnings
Net effects of consolidating KMP
and EPB and other noncontrolling
interests
State income tax, net of federal
benefit
Dividend received deduction
Adjustments to uncertain tax
positions
Valuation allowance on investment
and tax credits
Disposition of certain international
holdings
Nondeductible goodwill
Other
Total
$
11
28
(4)
26
(48)
(23)
34
—
301
19
917
0.7 %
1.7 %
(0.3)%
1.6 %
(2.9)%
(1.4)%
2.1 %
— %
18.5 %
1.1 %
56.1 % $
(24)
26
15
12
(51)
(14)
—
—
323
6
564
(3.1)%
3.5 %
—
40
— %
1.3 %
2.0 %
(433)
(14.0)%
1.5 %
(6.6)%
(1.9)%
— %
— %
41.7 %
0.8 %
72.9 % $
37
(50)
(5)
61
(112)
—
28
648
1.2 %
(1.6)%
(0.2)%
2.0 %
(3.6)%
— %
0.9 %
21.0 %
94
Deferred tax assets and liabilities result from the following (in millions):
Deferred tax assets
Employee benefits
Accrued expenses
Net operating loss, capital loss and tax credit carryforwards
Derivative instruments and interest rate and currency swaps
Debt fair value adjustment
Investments
Other
Valuation allowances
Total deferred tax assets
Deferred tax liabilities
Property, plant and equipment
Other
Total deferred tax liabilities
Net deferred tax assets
$
December 31,
2016
2015
$
401
118
1,307
22
74
2,804
14
(184)
4,556
177
27
204
394
129
1,344
45
110
3,607
3
(152)
5,480
143
14
157
$
4,352
$
5,323
Deferred Tax Assets and Valuation Allowances: The step-up in tax basis from the Merger Transactions in November
2014 resulted in a deferred tax asset, primarily related to our investment in KMP. As book earnings from our investment in
KMP are projected to exceed taxable income (primarily as a result of the partnership’s tax depreciation in excess of book
depreciation), the deferred tax asset related to our investment in KMP is expected to be fully realized.
We recorded a full valuation allowance of $61 million against the deferred tax asset at December 31, 2014 related to our
investment in NGPL as we concluded it was no longer realizable.
We increased our valuation allowances in 2016 by $32 million, primarily due to $18 million for our foreign tax credits,
$10 million for foreign net operating losses, and $4 million for capital losses for which we do not expect to realize a future
tax benefit.
We have deferred tax assets of $1,128 million related to net operating loss carryovers, $175 million related to alternative
minimum and foreign tax credits, $4 million related to capital loss carryovers and $123 million of valuation allowances
related to these deferred tax assets at December 31, 2016. As of December 31, 2015, we had deferred tax assets of $1,005
million related to net operating loss carryovers, $339 million related to alternative minimum and foreign tax credits, and
valuation allowances related to these deferred tax assets of $91 million. We expect to generate taxable income beginning in
2020 and utilize all federal net operating loss carryforwards and alternative minimum tax carryforwards by the end of 2025.
Our alternative minimum tax credit carryforwards decreased by $151 million in 2016 as a result of our decision to elect
to forgo bonus depreciation on property placed in service in that year. Code Section 168(k)(4) allows for corporate taxpayers
with minimum tax credit carryforwards to forgo bonus depreciation and accelerate their use of the credits to reduce tax
liability in that same tax year if the amount of the allowable credit exceeds the taxpayer’s tax liability. The corporation may
receive a cash refund of the excess notwithstanding that it may not otherwise be paying taxes.
In addition we have unrecorded deferred tax assets of $9 million as of December 31, 2016 related to net operating loss
carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Upon the
adoption of ASU 2016-09, the $9 million unrecorded deferred tax assets will be recorded through a cumulative-effect
adjustment to retained earnings.
Expiration Periods for Deferred Tax Assets: As of December 31, 2016, we have U.S. federal net operating loss
carryforwards of $2.7 billion, which will expire from 2018 - 2036; state losses of $3.0 billion which will expire from 2017 -
2036; and foreign losses of $183 million, of which approximately $137 million carries over indefinitely and $46 million
expires from 2029 - 2036. We also have $153 million of federal alternative minimum tax credits which do not expire; and
95
approximately $21 million of foreign tax credits, which will expire from 2017 - 2023. Use of a portion of our U.S. federal
carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the
separate return limitation rules of Internal Revenue Service regulations. If certain substantial changes in our ownership
occur, there would be an annual limitation on the amount of carryforwards that could be utilized.
Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not
that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the
tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax
benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a
greater than 50% likelihood of being realized upon ultimate resolution.
A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows (in millions):
Balance at beginning of period
Additions based on current year tax positions
Additions based on prior year tax positions
Reductions based on prior year tax positions
Reductions based on settlements with taxing authority
Reductions due to lapse in statute of limitations
Balance at end of period
$
Year Ended December 31,
2016
2015
2014
$
148
$
189
$
3
7
(1)
(26)
(9)
122
$
4
—
(6)
(25)
(14)
148
$
209
12
—
(3)
(24)
(5)
189
We recognize interest and/or penalties related to income tax matters in income tax expense. We recognized tax expense
of $2 million and a benefit of $4 million and $1 million at December 31, 2016, 2015, and 2014, respectively. As of
December 31, 2016, 2015, and 2014, we had $28 million, $24 million and $28 million, respectively, of accrued interest. We
had no accrued penalties as of December 31, 2016 and $2 million in accrued penalties as of both December 31, 2015 and
2014. All of the $122 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future
periods. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will increase by
approximately $2 million during the next year to approximately $124 million, primarily due to additions for state filing
positions taken in prior years.
We are subject to taxation, and have tax years open to examination for the periods 2011-2015 in the U.S., 2002-2015 in
various states and 2007-2015 in various foreign jurisdictions.
6. Property, Plant and Equipment, net
Classes and Depreciation
As of December 31, 2016 and 2015, our property, plant and equipment, net consisted of the following (in millions):
Pipelines (Natural gas, liquids, crude oil and CO2)
Equipment (Natural gas, liquids, crude oil, CO2, and terminals)
Other(a)
Accumulated depreciation, depletion and amortization
Land and land rights-of-way
Construction work in process
Property, plant and equipment, net
_______
(a) Includes buildings, computer and communication equipment, vessels, linefill and other.
96
December 31,
2016
2015
$
19,341
$
23,298
4,780
(12,306)
35,113
1,431
2,161
19,855
22,979
4,719
(10,851)
36,702
1,450
2,395
$
38,705
$
40,547
As of December 31, 2016 and 2015, property, plant and equipment, net included $12,900 million and $16,089 million,
respectively, of assets which were regulated by either the FERC or the NEB. Depreciation, depletion, and amortization expense
charged against property, plant and equipment was $1,970 million, $2,059 million, and $1,862 million for the years ended
December 31, 2016, 2015, and 2014, respectively.
Asset Retirement Obligations
As of December 31, 2016 and 2015, we recognized asset retirement obligations in the aggregate amount of $193 million
and $215 million, respectively, of which $9 million were classified as current for each respective period. The majority of our
asset retirement obligations are associated with our CO2 business segment, where we are required to plug and abandon oil and
gas wells that have been removed from service and to remove the surface wellhead equipment and compressors.
7. Investments
Our investments primarily consist of equity investments where we hold significant influence over investee actions and for
which we apply the equity method of accounting. As of December 31, 2016 and 2015, our investments consisted of the
following (in millions):
Citrus Corporation
SNG
Ruby
Gulf LNG Holdings Group, LLC
NGPL Holdings LLC
Plantation Pipe Line Company
EagleHawk
MEP
Red Cedar Gathering Company
Watco Companies, LLC
Double Eagle Pipeline LLC
FEP
Liberty Pipeline Group LLC
Bear Creek Storage
Sierrita Gas Pipeline LLC
Utopia Holding LLC
Fort Union Gas Gathering L.L.C.
Parkway Pipeline LLC
All others
Total equity investments
Bond investments
Total investments
December 31,
2016
2015
$
1,709
$
1,505
798
485
475
333
329
328
191
180
151
101
75
61
57
55
25
—
169
7,027
—
$
7,027
$
1,719
—
1,093
516
153
327
348
713
185
201
158
116
79
—
60
—
50
131
183
6,032
8
6,040
As shown in the table above, our significant equity investments, as of December 31, 2016 consisted of the following:
• Citrus Corporation—We own a 50% interest in Citrus Corporation, the sole owner of Florida Gas Transmission
Company, L.L.C. (Florida Gas). Florida Gas transports natural gas to cogeneration facilities, electric utilities,
independent power producers, municipal generators, and local distribution companies through a 5,300-mile natural gas
pipeline. Energy Transfer Partners L.P. operates Florida Gas and owns the remaining 50% interest in Citrus;
•
SNG—Effective September 1, 2016, we operate SNG and own a 50% interest in SNG; and Evergreen Enterprise
Holdings, LLC, a subsidiary of Southern Company, owns the remaining 50% interest.
97
• Ruby—We operate Ruby and own the common interest in Ruby, the sole owner of the Ruby Pipeline natural gas
transmission system. Veresen Inc. owns the remaining interest in Ruby in the form of a convertible preferred interest.
If Veresen converted its preferred interest into common interest, we and Veresen would each own a 50% common
interest in Ruby;
• Gulf LNG Holdings Group, LLC—We operate Gulf LNG Holdings Group, LLC and own a 50% interest in Gulf LNG
Holdings Group, LLC, the owner of a LNG receiving, storage and regasification terminal near Pascagoula,
Mississippi, as well as pipeline facilities to deliver vaporized natural gas into third party pipelines for delivery into
various markets around the country. The remaining 50% interest is owned by a variety of investment entities
including subsidiaries of GE Financial Services and The Blackstone Group L.P.;
• NGPL Holdings LLC— We operate NGPL Holdings LLC and own a 50% interest in NGPL Holdings LLC, the
indirect owner of NGPL and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural
gas pipeline and storage system. The remaining 50% interest is owned by Brookfield;
•
Plantation—We operate Plantation and own a 51.17% interest in Plantation, the sole owner of the Plantation refined
petroleum products pipeline system. A subsidiary of Exxon Mobil Corporation owns the remaining interest. Each
investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain
corporate actions that are considered substantive participating rights; therefore, we do not control Plantation, and
account for the investment under the equity method;
• BHP Billiton Petroleum (Eagle Ford) LLC, (EagleHawk)—We own a 25% interest in EagleHawk, the sole owner of
natural gas and condensate gathering systems serving the producers of the Eagle Ford shale formation. A subsidiary of
BHP Billiton Petroleum operates EagleHawk and owns the remaining 75% ownership interest;
• MEP—We operate MEP and own a 50% interest in MEP, the sole owner of the Midcontinent Express natural gas
pipeline system. The remaining 50% ownership interest is owned by subsidiaries of Energy Transfer Partners L.P.;
• Red Cedar Gathering Company—We own a 49% interest in Red Cedar Gathering Company, the sole owner of the Red
Cedar natural gas gathering, compression and treating system. The Southern Ute Indian Tribe owns the remaining
51% interest and serves as operator of Red Cedar;
• Watco Companies, LLC—We hold a preferred and common equity investment in Watco Companies, LLC, the largest
privately held short line railroad company in the U.S. We own 100,000 Class A and 50,000 Class B preferred shares
and pursuant to the terms of the investment, receive priority, cumulative cash and stock distributions from the
preferred shares at a rate of 3.25% and 3.00% per quarter, respectively, and participate partially in additional profit
distributions at a rate equal to 0.4%. Neither class holds any voting powers, but do provide us certain approval rights,
including the right to appoint one of the members to Watco’s board of managers. In addition to the senior interests, we
also hold approximately 13,000 common equity units, which represents a 3.4% common ownership that is accounted
for under the equity method of accounting;
• Double Eagle Pipeline LLC - We own a 50% equity interest in Double Eagle Pipeline LLC. The remaining 50%
interest is owned by Magellan Midstream Partners;
•
FEP —We own a 50% interest in FEP, the sole owner of the Fayetteville Express natural gas pipeline system. Energy
Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of FEP;
• Liberty Pipeline Group, LLC (Liberty) —We own a 50% interest in Liberty. ETC NGL Transport, LLC, a subsidiary
of Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of Liberty;
• Bear Creek Storage—We own a 50% interest in Bear Creek through TGP, one of our wholly owned subsidiaries. SNG
owns the remaining 50% interest;
•
Sierrita Gas Pipeline LLC — We operate Sierrita Gas Pipeline LLC and own a 35% equity interest in the Sierrita Gas
Pipeline LLC. MGI Enterprises U.S. LLC, a subsidiary of PEMEX, owns 35%; and MIT Pipeline Investment
Americas, Inc., a subsidiary of Mitsui & Co., Ltd, owns 30%;
• Utopia Holding L.L.C. — We operate Utopia Holding L.L.C. and own a 50% interest in Utopia Holding L.L.C. after
the sale of 50% of our interest to Riverstone Investment Group LLC on June 28, 2016;
•
Fort Union Gas Gathering LLC—We own a 37.04% equity interest in the Fort Union Gas Gathering LLC. Crestone
Powder River LLC, a subsidiary of ONEOK Partners L.P., owns 37.04%; Powder River Midstream, LLC owns
11.11%; and Western Gas Wyoming, LLC owns the remaining 14.81%. Western Gas Resources, Inc. serves as
operator of Fort Union Gas Gathering LLC;
98
•
Parkway Pipeline LLC —Prior to the sale of our interest in Parkway, we operated and owned a 50% interest in
Parkway Pipeline LLC, the sole owner of the Parkway Pipeline refined petroleum products pipeline system. Valero
Energy Corp. owns the remaining 50% interest;
• Cortez Pipeline Company—We operate the Cortez carbon dioxide pipeline system, and as of December 31, 2016, we
owned a 50% interest in, the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system.
Our earnings (losses) from equity investments were as follows (in millions):
Year Ended December 31,
2016
2015
2014
$
102
$
Citrus Corporation
SNG
FEP
Gulf LNG Holdings Group, LLC
MEP
Plantation Pipe Line Company
Watco Companies, LLC
Red Cedar Gathering Company
Cortez Pipeline Company(a)
Ruby
Parkway Pipeline LLC
NGPL Holdings LLC
Liberty Pipeline Group LLC
EagleHawk
Sierrita Gas Pipeline LLC
Double Eagle Pipeline LLC
Bear Creek Storage
Fort Union Gas Gathering L.L.C.(b)
All others
58
51
48
40
37
25
24
24
15
14
12
11
10
7
5
2
1
11
497
(59)
$
$
96
—
55
49
45
29
16
26
(3)
18
5
—
9
24
9
3
—
16
17
97
—
55
48
45
29
13
33
25
15
8
—
6
(7)
3
(1)
—
16
21
$
414
(51)
406
(45)
Total earnings from equity investments
$
Amortization of excess costs
_______
(a) 2016 and 2015 amounts include $9 million and $26 million, respectively, representing our share of a non-cash impairment charge (pre-
tax) recorded by Cortez Pipeline Company.
(b) 2016 amount includes non-cash impairment charges of $7 million (pre-tax) related to our investment.
Summarized combined financial information for our significant equity investments (listed or described above) is reported
below (in millions; amounts represent 100% of investee financial information):
Income Statement
Revenues
Costs and expenses
Net income
Year Ended December 31,
2015
2014
2016
$
$
4,084
3,056
1,028
$
$
3,857
3,408
449
$
$
3,829
3,063
766
99
Balance Sheet
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Partners’/owners’ equity
8. Goodwill
December 31,
2016
2015
$
892
$
22,170
3,532
9,187
10,343
811
19,745
1,009
11,227
8,320
Changes in the amounts of our goodwill for each of the years ended December 31, 2016 and 2015 are summarized by reporting unit
as follows (in millions):
Natural
Gas
Pipelines
Regulated
Natural
Gas
Pipelines
Non-
Regulated
CO2
Products
Pipelines
Products
Pipelines
Terminals Terminals
Kinder
Morgan
Canada
Total
Historical Goodwill
$
17,527
$
5,719
$
1,528
$
1,908
$
221
$
1,573
$
591
$ 29,067
Accumulated
impairment losses
December 31, 2014
Acquisitions(a)
Currency translation
Impairment
(1,643)
15,884
—
—
—
December 31, 2015
15,884
Currency translation
Divestitures(b)
—
(1,635)
(447)
5,272
93
—
(1,150)
4,215
—
—
—
1,528
—
—
—
1,528
—
—
(1,197)
711
217
—
—
928
—
—
(70)
151
—
—
—
151
—
—
December 31, 2016
$
14,249
$
4,215
$
1,528
$
928
$
151
$
(679)
894
11
—
—
905
—
(9)
896
$
(377)
214
—
(35)
—
179
6
—
185
(4,413)
24,654
321
(35)
(1,150)
23,790
6
(1,644)
$ 22,152
_______
(a) 2015 includes $93 million and $217 million, respectively, related to the February 2015 acquisition of Hiland by Natural Gas Pipelines Non-
Regulated and Products Pipelines, and $7 million related to the February 2015 acquisition of Vopak terminal assets by Terminals, all of which are
discussed in Note 3.
(b) 2016 includes $1,635 million related to the sale of a 50% interest in our SNG natural gas pipeline system by Natural Gas Pipelines Regulated to
Southern Company and $9 million related to certain terminal divestitures.
Refer to Note 2 “Summary of Significant Accounting Policies—Goodwill” for a description of our accounting for goodwill and
Note 4 for further discussion regarding impairments.
We determine the fair value of each reporting unit as of May 31 of each year based primarily on a market approach utilizing
enterprise value to estimated EBITDA multiplies of comparable companies. The value of each reporting unit is determined on a stand-
alone basis from the perspective of a market participant representing the price estimated to be received in a sale of the reporting unit in
an orderly transaction between market participants at the measurement date. As of May 31, 2016, with the exception of our Natural Gas
Pipelines Non-Regulated reporting unit, each of our reporting units indicated a fair value in excess of their respective carrying values.
The amount of excess fair value over the carrying value ranged from approximately 9% for our Natural Gas Pipelines Regulated
reporting unit to 80% for our Products Pipelines Terminals as of May 31, 2016. The results of our Step 2 analysis for our Natural Gas
Pipelines Non-Regulated reporting unit did not indicate an impairment of goodwill and we did not identify any triggers for further
impairment analysis during the remainder of the year.
Due to the effect of commodity prices on market conditions that impacted the energy sector, during the fourth quarter 2015, we
conducted an interim test of the recoverability of goodwill as of December 31, 2015, and concluded that the goodwill of our Natural Gas
Pipelines - Non-Regulated reporting unit was impaired by $1.15 billion.
For our Natural Gas Pipelines Non-Regulated and our CO2 reporting units, our May 31, 2016 annual test and our December 31,
2015 interim test included a discounted cash flow analysis (income approach) to evaluate the fair value of these reporting units to
100
provide additional indication of fair value based on the present value of cash flows these reporting units are expected to generate in the
future. We weighted the market and income approaches for these reporting units to arrive at an estimated fair value of these respective
reporting units giving more weighting on the income approach and less on the market approach as we believed the values indicated
using the income approach are more representative of the value that could be received from a market participant.
The fair value estimates of our reporting unit fair value, and in arriving at the fourth quarter 2015 impairment amount, were based
on Level 3 inputs of the fair value hierarchy as discussed in Note 4.
A continued period of volatile commodity prices could result in further deterioration of market multiples, comparable sales
transactions prices, weighted average costs of capital, and our cash flow estimates. A significant unfavorable change to any one or
combination of these factors would result in a change to the reporting unit fair values discussed above potentially resulting in additional
impairments of long-lived assets, equity method investments, and/or goodwill. Such non-cash impairments could have a significant
effect on our results of operations.
9. Debt
We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated
with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying
consolidated statements of income.
The following table provides detail on the principal amount of our outstanding debt balances. The table amounts exclude
all debt fair value adjustments, including debt discounts, premiums and issuance costs (in millions):
KMI
Unsecured term loan facility, variable rate, due January 26, 2019(a)
Senior notes 1.50% through 8.25%, due 2016 through 2098(b)(c)
Credit facility expiring November 26, 2019
Commercial paper borrowings
KMP
Senior notes, 2.65% through 9.00%, due 2016 through 2044(c)
TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(a)(c)
EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c)
Copano senior notes, 7.125%, due April 1, 2021(c)(d)
CIG senior notes, 4.15% through 6.85%, due 2026 through 2037(c)(e)
SNG notes, 4.40% through 8.00%, due 2017 through 2032(c)(f)
Other Subsidiary Borrowings (as obligor)
Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(a)(c)
Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022(c)(g)
EPC Building, LLC, promissory note, 3.967%, due 2016 through 2035
Trust I preferred securities, 4.75%, due March 31, 2028(h)
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(i)
Other miscellaneous debt(j)
December 31,
2016
2015
$
1,000
13,236
—
—
19,485
1,540
1,115
—
475
—
$
—
13,346
—
—
19,985
1,790
1,115
332
100
1,211
786
225
433
221
100
285
38,901
2,696
$ 36,205
1,636
974
443
221
100
300
41,553
821
$ 40,732
Total debt – KMI and Subsidiaries
Less: Current portion of debt(a)(f)(k)
Total long-term debt – KMI and Subsidiaries(l)
_______
(a) On January 26, 2016, we entered into a $1 billion three-year unsecured term loan facility with a variable interest rate, which is
determined in the same manner as interest on our revolving credit facility borrowings. In January 2016, we repaid $850 million of
maturing 5.70% senior notes, and in February 2016, we repaid $250 million of maturing 8.00% senior notes primarily using proceeds
from the three-year term loan. Since we refinanced a portion of the maturing debt with proceeds from long-term debt, we classified $1
billion of the maturing debt within “Long-term debt” on our consolidated balance sheet as of December 31, 2015.
(b) Amounts include senior notes that are denominated in Euros and have been converted and are respectively reported above at the
December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro and the December 31, 2015 exchange rate of 1.0862 U.S. dollars per
Euro. For the year ended December 31, 2016, our debt decreased by $43 million as a result of the change in the exchange rate of U.S
dollars per Euro. The decrease in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-
currency swaps reflected in “Deferred charges and other assets” and “ Other long-term liabilities and deferred credits” on our
consolidated balance sheets. At the time of issuance, we entered into cross-currency swap agreements associated with these senior notes,
effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 14 “Risk Management—Foreign Currency Risk
Management”).
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(c) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the
redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these
include limitations on the incurrence of liens and limitations on sale-leaseback transactions.
(d) On September 30, 2016, we repaid the $332 million principal amount of 7.125% senior notes due 2021, plus accrued interest. We
recognized a $28.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated
statements of income for the year ended December 31, 2016 consisting of an $11.8 million premium on the debt repaid and a $40.1
million gain from the write-off of unamortized purchase accounting associated with the extinguished debt. Copano continues to be a
subsidiary guarantor under a cross guarantee agreement (see Note 19).
(e) On August 16, 2016, CIG completed a private offering of $375 million in principal amount of 4.15% senior notes due August 15, 2026.
The net proceeds of $372 million received from the offering were used to reduce debt incurred as the result of the repayment of CIG’s
senior notes that matured in 2015 and for general corporate purposes.
(f) Due to the September 1, 2016 sale of a 50% interest in SNG, we no longer consolidate SNG’s accounts in our consolidated financial
statements. As of the transaction date, SNG had $1,211 million of debt outstanding (including a current portion of $500 million).
(g) On October 1, 2016, a portion of the proceeds from the sale of a 50% interest in SNG was used to repay the $749 million principal
amount of Hiland’s 7.25% senior notes due 2020, plus accrued interest. We recognized a $17.3 million gain from the early
extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended
December 31, 2016 consisting of a $27.1 million premium on the debt repaid and a $44.4 million gain from the write-off of unamortized
purchase accounting associated with the extinguished debt.
(h) Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2016, had 4.4 million of 4.75% trust convertible
preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred
securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income
is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and
unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to
obtain funds from our subsidiaries by distribution, dividend or loan. The Trust I Preferred Securities are non-voting (except in limited
circumstances), pay quarterly distributions at an annual rate of 4.75%, carry a liquidation value of $50 per security plus accrued and
unpaid distributions and are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the
following mixed consideration: (i) 0.7197 of a share of our Class P common stock; (ii) $25.18 in cash without interest; and (iii) 1.100
warrants to purchase a share of our Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time.
Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the Trust I
Preferred Securities into debt and equity components and as of December 31, 2016, the outstanding balance of $221 million (of which
$111 million was classified as current) was bifurcated between debt ($199 million) and equity ($22 million). During the years ended
December 31, 2016 and 2015, 200 and 1,176,015, respectively, of Trust I Preferred Securities had been converted into (i) 143 and
846,369 shares of our Class P common stock; (ii) approximately $5,000 and $30 million in cash; and (iii) 220 and 1,293,615 in warrants,
respectively.
(i) As of December 31, 2016 and 2015, KMGP had outstanding, 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating
Rate Term Cumulative Preferred Stock due 2057. Since August 18, 2012, dividends on the preferred stock accumulate at a floating rate
of the 3-month LIBOR plus 3.8975% and are payable quarterly in arrears, when and if declared by KMGP’s board of directors, on
February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights
over a commencement of or filing of voluntary bankruptcy by KMP or its SFPP or Calnev subsidiaries.
In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG’s joint
venture partner in WYCO funded 50% of the construction costs. Upon project completion, the advances were converted into a financing
obligation to WYCO. As of December 31, 2016, the principal amounts of the Totem and High Plains financing obligations were $71
million and $92 million, respectively, which will be paid in monthly installments through 2039 based on the initial lease term. The
interest rate on these obligations is 15.5%, payable on a monthly basis.
(j)
(k) Amounts include outstanding credit facility and commercial paper borrowings and other debt maturing within 12 months. See “—
Maturities of Debt” below.
(l) Excludes our “Debt fair value adjustments” which, as of December 31, 2016 and 2015, increased our combined debt balances by $1,149
million and $1,674 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and
purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for
hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further
information about our debt fair value adjustments, see —“Debt Fair Value Adjustments” below.
We and substantially all of our wholly owned domestic subsidiaries are a party to a cross guarantee agreement whereby
each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each
other party to the agreement. Also, see Note 19.
Credit Facilities and Restrictive Covenants
On January 26, 2016, we increased the capacity of our revolving credit agreement, initially entered into during 2014, from
$4.0 billion to $5.0 billion. The other terms of our revolving credit agreement remain the same. We also maintain a $4.0 billion
commercial paper program through the private placement of short-term notes. The notes mature up to 270 days from the date
of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less
a discount representing an interest factor or if interest bearing, at par. Borrowings under our revolving credit facility can be
102
used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings
under our commercial paper program reduce the borrowings allowed under our credit facility.
Our credit facility borrowings bear interest at either (i) LIBOR plus an applicable margin ranging from 1.125% to 2.000%
per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; and (3)
LIBOR Rate for a one month eurodollar loan, plus 1%, plus, in each case, an applicable margin ranging from 0.125% to 1.00%
per annum based on our credit rating. As of December 31, 2016, we were in compliance with all required financial covenants.
Our credit facility included the following restrictive covenants as of December 31, 2016:
•
•
•
•
•
total debt divided by earnings before interest, income taxes, depreciation and amortization may not exceed:
• 6.50: 1.00, for the period ended on or prior to December 31, 2017; or
• 6.25: 1.00, for the period ended after December 31, 2017 and on or prior to December 31, 2018; or
• 6.00: 1.00, for the period ended after December 31, 2018;
certain limitations on indebtedness, including payments and amendments;
certain limitations on entering into mergers, consolidations, sales of assets and investments;
limitations on granting liens; and
prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such
dividend.
As of December 31, 2016, we had no borrowings outstanding under our five-year $5.0 billion revolving credit facility, no
borrowings outstanding under our $4.0 billion commercial paper program and $160 million in letters of credit. Our availability
under our revolving credit facility as of December 31, 2016 was $4,840 million.
Current Portion of Debt
The primary components of our current portion of debt include the following significant series of long-term notes:
As of December 31, 2016
$600 million 6.00% notes due February 2017
$300 million 7.50% notes due April 2017
$355 million 5.95% notes due April 2017
$786 million 7.00% notes due June 2017
$500 million 2.00% notes due December 2017
As of December 31, 2015
$500 million 3.50% notes due March 2016
103
Long-term Debt Issuances, Repayments and Other Significant Changes in Debt
Following are significant long-term debt issuances, repayments and other significant changes made during 2016 and 2015:
2016
2015
Issuances
$1.0 billion unsecured term loan facility due 2019
$800 million 5.05% notes due 2046
$375 million 4.15% notes due 2026
$815 million 1.50% notes due 2022(a)
$543 million 2.25% notes due 2027(a)
Repayments
$850 million 5.70% notes due 2016
$300 million 5.625% notes due 2015
$500 million 3.50% notes due 2016
$250 million 8.00% notes due 2016
$250 million 5.15% notes due 2015
$340 million 6.80% notes due 2015
$67 million 8.25% notes due 2016
$375 million 4.10% notes due 2015
$332 million 7.125% notes due 2021
$749 million 7.25% notes due 2020
Other significant changes
$1,211 million reduction due to the
deconsolidation of SNG, including a current
portion of $500 million (see Note 3)
$1,413 million assumption of senior notes
and other borrowings due to the Hiland
acquisition of which $368 million was
immediately paid down after closing (see
Note 3)(b)
_______
(a) Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0862 U.S.
dollars per Euro. We entered into cross-currency swap agreements associated with these senior notes (see Note 14—“Risk Management
—Foreign Currency Risk Management”).
(b) As of the February 13, 2015 Hiland acquisition date, we assumed (i) $975 million in principal amount of senior notes (which were
valued at $1,043 million as of the acquisition date) and (ii) $368 million of other borrowings that were immediately repaid after closing,
primarily consisting of borrowings outstanding under a revolving credit facility. The senior notes are subject to our cross guarantee
agreement discussed in Note 19.
Maturities of Debt
The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2016,
are summarized as follows (in millions):
Year
2017
2018
2019
2020
2021
Thereafter
Total
Debt Fair Value Adjustments
$
Total
2,696
2,328
3,820
2,204
2,422
25,431
$
38,901
The carrying value adjustment to debt securities whose fair value is being hedged is included within “Debt fair value
adjustments” on our accompanying consolidated balance sheets. “Debt fair value adjustments” also include unamortized debt
discount/premiums, purchase accounting debt fair value adjustments, unamortized portion of proceeds received from the early
termination of interest rate swap agreements, and debt issuance costs. As of December 31, 2016, the weighted-average
amortization period of the unamortized premium from the termination of interest rate swaps was approximately 16 years. The
104
following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets (in
millions):
Debt Fair Value Adjustments
Purchase accounting debt fair value adjustments
Carrying value adjustment to hedged debt
Unamortized portion of proceeds received from the early termination of
interest rate swap agreements
Unamortized debt discount/premiums
Unamortized debt issuance costs
Total debt fair value adjustments
Interest Rates, Interest Rate Swaps and Contingent Debt
December 31,
2016
2015
$
$
$
806
220
342
(80)
(139)
1,149
$
1,135
380
397
(86)
(152)
1,674
The weighted average interest rate on all of our borrowings was 4.95% during 2016 and 4.92% during 2015. Information
on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13
“Commitments and Contingent Liabilities—Contingent Debt”).
10. Share-based Compensation and Employee Benefits
Share-based Compensation
Class P Shares
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors
We have a Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors, in which
our eligible non-employee directors participate. The plan recognizes that the compensation paid to each eligible non-employee
director is fixed by our board, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of
receiving some or all of the cash compensation, each eligible non-employee director may elect to receive shares of Class P
common stock. Each election will be generally at or around the first board meeting in January of each calendar year and will
be effective for the entire calendar year. An eligible director may make a new election each calendar year. The total number of
shares of Class P common stock authorized under the plan is 250,000. During 2016, 2015 and 2014, we made restricted Class
P common stock grants to our non-employee directors of 31,880, 9,580 and 6,210, respectively. These grants were valued at
time of issuance at $400,000, $401,000 and $220,000, respectively. All of the restricted stock awards made to non-employee
directors vest during a six-month period.
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan
The Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan is an equity awards plan available to eligible
employees. The following table sets forth a summary of activity and related balances of our restricted stock awards excluding
that issued to non-employee directors (in millions, except share and per share amounts):
Year Ended
December 31, 2016
Year Ended
December 31, 2015
Year Ended
December 31, 2014
Weighted
Average
Grant Date
Fair Value
Shares
Weighted
Average
Grant Date
Fair Value
Weighted
Average
Grant Date
Fair Value
Shares
Shares
Outstanding at beginning of period
7,645,105
$
Granted
Vested
Forfeited
2,816,599
(1,226,652)
(196,915)
Outstanding at end of period
9,038,137
$
37.91
21.36
38.53
35.74
32.72
7,373,294
$
1,488,467
(817,797)
(398,859)
7,645,105
$
37.63
38.20
35.66
38.51
37.91
6,382,885
$
1,694,668
(460,032)
(244,227)
7,373,294
$
37.38
36.01
28.84
36.39
37.63
105
The intrinsic value of restricted stock awards vested during the years ended December 31, 2016, 2015 and 2014 was $25
million, $31 million and $17 million, respectively. Restricted stock awards made to employees have vesting periods ranging
from 1 year with variable vesting dates to 10 years. Following is a summary of the future vesting of our outstanding restricted
stock awards:
Year
2017
2018
2019
2020
2021
Thereafter
Total Outstanding
Vesting of Restricted
Shares
1,476,832
2,352,443
4,358,728
539,790
199,850
110,494
9,038,137
The related compensation costs less estimated forfeitures is generally recognized ratably over the vesting period of the
restricted stock awards. Upon vesting, the grants will be paid in our Class P common shares.
During 2016, 2015 and 2014, we recorded $66 million, $52 million and $51 million, respectively, in expense related to
restricted stock awards and capitalized approximately $9 million, $15 million and $6 million, respectively. At December 31,
2016 and 2015, unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $133
million and $154 million, respectively.
Pension and Other Postretirement Benefit Plans
Savings Plan
We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for
most of the plan participants. Certain plan participants’ contributions and Company contributions are based on collective
bargaining agreements. The total expense for our savings plan was approximately $48 million, $46 million, and $42 million for
the years ended December 31, 2016, 2015 and 2014, respectively.
Pension Plans
Our U.S. pension plan is a defined benefit plan that covers substantially all of our U.S. employees and provides benefits
under a cash balance formula. A participant in the cash balance plan accrues benefits through contribution credits based on a
combination of age and years of service, times eligible compensation. Interest is also credited to the participant’s plan account.
A participant becomes fully vested in the plan after three years, and may take a lump sum distribution upon termination of
employment or retirement. Certain collectively bargained and grandfathered employees continue to accrue benefits through
career pay or final pay formulas.
Two of our subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partner of Trans
Mountain Pipeline L.P.), are sponsors of pension plans for eligible Canadian and Trans Mountain pipeline employees. The
plans include registered defined benefit pension plans, supplemental unfunded arrangements (which provide pension benefits in
excess of statutory limits) and defined contributory plans. Benefits under the defined benefit components accrue through career
pay or final pay formulas. The net periodic benefit costs, contributions and liability amounts associated with our Canadian
plans are not material to our consolidated income statements or balance sheets; however, we began to include the activity and
balances associated with our Canadian plans (including our Canadian OPEB plans discussed below) in the following
disclosures on a prospective basis beginning in 2016. The associated net periodic benefit costs for these combined Canadian
plans of $12 million and $10 million for the years ended December 31, 2015 and 2014, respectively, were reported separately
in prior years.
Other Postretirement Benefit Plans
We and certain of our U.S. subsidiaries provide other postretirement benefits (OPEB), including medical benefits for
closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life
insurance benefits for retired employees. Our Canadian subsidiaries also provide OPEB benefits to current and future retirees
and their dependents. Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar
106
caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits. Effective
January 1, 2014, the U.S. plans were amended to provide a fixed subsidy to post-age 65 Medicare eligible participants to
purchase coverage through a retiree Medicare exchange.
Additionally, our subsidiary SFPP has incurred certain liabilities for postretirement benefits to certain current and former
employees, their covered dependents, and their beneficiaries. However, the net periodic benefit costs, contributions and liability
amounts associated with the SFPP postretirement benefit plan are not material to our consolidated income statements or balance
sheets.
Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and
OPEB plans as of and for each of the years ended December 31, 2016 and 2015 (in millions):
Pension Benefits
OPEB
2016
2015
2016
2015
Change in benefit obligation:
Benefit obligation at beginning of period
$
2,654
$
2,804
$
509
$
Service cost
Interest cost
Actuarial loss (gain)
Benefits paid
Participant contributions
Medicare Part D subsidy receipts
Exchange rate changes
Other(a)
Benefit obligation at end of period
Change in plan assets:
Fair value of plan assets at beginning of period
Actual return (loss) on plan assets
Employer contributions
Participant contributions
Medicare Part D subsidy receipts
Benefits paid
Exchange rate changes
Other(a)
36
89
127
(180)
3
—
4
151
2,884
2,050
157
8
3
—
(180)
3
119
33
99
(109)
(173)
—
—
—
—
2,654
2,377
(204)
50
—
—
(173)
—
—
1
16
(42)
(41)
2
1
1
26
473
325
29
16
2
1
(41)
—
—
Fair value of plan assets at end of period
Funded status - net liability at December 31,
2,160
(724) $
2,050
(604) $
$
332
(141) $
624
—
21
(101)
(39)
2
2
—
—
509
389
(45)
16
2
2
(39)
—
—
325
(184)
_______
(a) 2016 amounts represent December 31, 2015 balances associated with our Canadian pension and OPEB plans and Plantation Pipeline
OPEB plan for prospective inclusion in these disclosures, which associated net periodic benefit costs were reported separately in prior
years.
Components of Funded Status. The following table details the amounts recognized in our balance sheet at December 31,
2016 and 2015 related to our pension and OPEB plans (in millions):
Non-current benefit asset(a)
Current benefit liability
Non-current benefit liability(a)
Funded status - net liability at December 31,
_______
$
$
107
Pension Benefits
OPEB
2016
2015
2016
2015
— $
—
(724)
(724) $
— $
—
(604)
(604) $
$
153
(16)
(278)
(141) $
139
(16)
(307)
(184)
(a) 2016 OPEB amount includes $29 million of non-current benefit assets and $12 million of non-current benefit liabilities related to plans
we sponsor which are associated with employee services provided to unconsolidated joint ventures, and for which we have recorded an
offsetting related party deferred charge/credit.
Components of Accumulated Other Comprehensive (Loss) Income. The following table details the amounts of pre-tax
accumulated other comprehensive (loss) income at December 31, 2016 and 2015 related to our pension and OPEB plans which
are included on our accompanying consolidated balance sheets, including the portion attributable to our noncontrolling
interests, (in millions):
Pension Benefits
OPEB
2016
2015
2016
2015
Unrecognized net actuarial (loss) gain
$
Unrecognized prior service (cost) credit
Accumulated other comprehensive (loss) income
$
(682) $
(5)
(687) $
(558) $
(4)
(562) $
69
18
87
$
$
23
19
42
We anticipate that approximately $44 million of pre-tax accumulated other comprehensive loss will be recognized as part
of our net periodic benefit cost in 2017, including approximately $45 million of unrecognized net actuarial loss and
approximately $1 million of unrecognized prior service credit.
Our accumulated benefit obligation for our pension plans was $2,834 million and $2,615 million at December 31, 2016
and 2015, respectively.
Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit
obligations exceeded the fair value of plan assets, was $415 million and $444 million at December 31, 2016 and 2015,
respectively. The fair value of these plans’ assets was approximately $121 million at both December 31, 2016 and 2015.
Plan Assets. The investment policies and strategies are established by the Fiduciary Committee for the assets of each of
the U.S. pension and OPEB plans and by the Pension Committee for the assets of the Canadian pension plans (the
“Committees”), which are responsible for investment decisions and management oversight of the plans. The stated philosophy
of each of the Committees is to manage these assets in a manner consistent with the purpose for which the plans were
established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management
program are to (1) meet or exceed plan actuarial earnings assumptions over the long term and (2) provide a reasonable return
on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying
benefit and expense obligations when due. In seeking to meet these objectives, the Committees recognize that prudent
investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order
to reduce portfolio risk and volatility, the Committees have each adopted a strategy of using multiple asset classes.
As of December 31, 2016, the allowable range for asset allocations in effect for our U.S. pension plan were 34% to 59%
equity, 37% to 57% fixed income, 0% to 5% cash, 0% to 2% alternative investments and 0% to 10% company securities (KMI
Class P common stock). As of December 31, 2016, the allowable range for asset allocations in effect for our U.S. retiree
medical and retiree life insurance plans were 15% to 55% equity, 15% to 47% fixed income, 0% to 20% cash and 13% to 39%
master limited partnerships. As of December 31, 2016, the allowable range for asset allocations in effect for our Canadian
pension plans were 0% to 55% equity and 45% to 100% fixed income.
Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used
for assets measured at fair value.
• Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included
in this level are cash, equities, exchange traded mutual funds and master limited partnerships. These investments are
valued at the closing price reported on the active market on which the individual securities are traded.
• Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in
active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed
income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair
value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a
compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are
exchange-traded through clearinghouses and are valued based on these prices.
• Level 3 assets’ fair values are calculated using valuation techniques that require inputs that are both significant to the
fair value measurement and are unobservable, or are similar to Level 2 assets. Included in this level are guaranteed
108
insurance contracts and immediate participation guarantee contracts. These contracts are valued at contract value,
which approximates fair value.
•
Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as reported by the
issuers are determined based on the fair value of the underlying securities as of the valuation date and include
common/collective trust funds, private investment funds, limited partnerships, and fixed income trusts. These
amounts are not categorized within the fair value hierarchy described above, but are separately identified in the
following tables.
Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and
categorized by fair value measurement used at December 31, 2016 and 2015 (in millions):
Pension Assets
2016
2015
Level 1 Level 2 Level 3
Total
Level 1 Level 2 Level 3
Total
$ — $ — $
10
$
$ — $ — $
10
—
197
283
—
—
—
100
—
—
428
—
(2)
$
490
$
526
$
Measured within fair value hierarchy
Cash
$
Short-term investment funds
Mutual funds(a)
Equities(b)
Fixed income securities
Immediate participation guarantee
contract
Derivatives
Subtotal
Measured at NAV(c)
Common/collective trusts(d)
Private investment funds(e)
Private limited partnerships(f)
Subtotal
Total plan assets fair value
—
—
—
—
16
—
16
15
—
70
271
—
—
—
100
197
283
428
16
(2)
110
—
—
449
—
(14)
1,032
$
356
$
545
$
829
290
9
1,128
$ 2,160
—
—
—
—
15
—
15
15
110
70
271
449
15
(14)
916
775
347
12
1,134
$ 2,050
_______
(a) For 2016 and 2015, this category includes mutual funds which are invested in equity.
(b) Plan assets include $126 million and $91 million of KMI Class P common stock for 2016 and 2015, respectively.
(c) Plan assets for which fair value was measured using NAV as a practical expedient.
(d) Common/collective trust funds were invested in approximately 39% fixed income and 61% equity in 2016 and 45% fixed income and
55% equity in 2015.
(e) Private investment funds were invested in approximately 54% fixed income and 46% equity in 2016 and 46% fixed income and 54%
equity in 2015.
(f) Private limited partnerships were invested in real estate, venture and buyout funds for 2016 and 2015.
109
OPEB Assets
2016
2015
Level 1 Level 2 Level 3
Total
Level 1 Level 2 Level 3
Total
Measured within fair value hierarchy
Short-term investment funds
$ — $
11
57
—
1
$
69
$
Equities
Master limited partnerships
Guaranteed insurance contracts
Mutual funds
Subtotal
Measured at NAV(a)
Common/collective trusts(b)
Fixed income trusts
Limited partnerships(c)
Subtotal
Total plan assets fair value
15
—
—
—
—
15
$ — $
—
—
47
—
47
$
15
11
57
47
1
$ — $
8
51
—
1
131
$
60
$
16
—
—
—
—
16
$ — $
—
—
49
—
49
$
68
64
69
201
$ 332
$
16
8
51
49
1
125
71
58
71
200
325
_______
(a) Plan assets for which fair value was measured using NAV as a practical expedient.
(b) Common/collective trust funds which are invested in approximately 72% equity and 28% fixed income securities for 2016 and 67%
equity and 33% fixed income securities for 2015.
(c) For 2016 and 2015, limited partnerships were invested in global equity securities.
The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended
December 31, 2016 and 2015 (in millions):
2016
Insurance contracts
2015
Insurance contracts
2016
Insurance contracts
2015
Insurance contracts
Balance at
Beginning of
Period
Transfers In
(Out)
Pension Assets
Realized and
Unrealized
Gains
(Losses), net
Purchases
(Sales), net
Balance at
End of
Period
$
$
15
$
— $
1
$
— $
16
15
$
— $
— $
— $
15
Balance at
Beginning of
Period
Transfers In
(Out)
OPEB Assets
Realized and
Unrealized
Gains
(Losses), net
Purchases
(Sales), net
Balance at
End of
Period
$
$
49
$
— $
(2) $
— $
51
$
— $
(1) $
(1) $
47
49
Changes in the underlying value of Level 3 assets due to the effect of changes of fair value were immaterial for the years
ended December 31, 2016 and 2015.
110
Expected Payment of Future Benefits and Employer Contributions. As of December 31, 2016, we expect to make the
following benefit payments under our plans (in millions):
Fiscal year
2017
2018
2019
2020
2021
2022 - 2026
Pension
Benefits
OPEB(a)
$
$
235
237
232
231
220
1,016
39
38
39
37
37
168
_______
(a) Includes a reduction of approximately $3 million in each of the years 2017 - 2021 and approximately $16 million in aggregate for 2022 -
2026 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
In 2017, we expect to contribute approximately $22 million to our U.S. pension plan and $7 million, net of anticipated
subsidies, to our U.S. OPEB plans. In 2017, we expect to contribute approximately $8 million to our Canadian pension plans
and $1 million to our Canadian OPEB plan.
Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates
and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit
obligation and net benefit costs of our pension and OPEB plans for 2016, 2015 and 2014:
Assumptions related to benefit obligations:
Discount rate
Rate of compensation increase
Assumptions related to benefit costs:
Discount rate for benefit obligations
Pension Benefits
2016
2015
2014
2016
OPEB
2015
2014
3.83% 4.05% 3.66%
3.69% 3.91% 3.56%
3.52% 3.50% 4.50%
n/a
n/a
n/a
4.05% 3.66% 4.45%
3.91% 3.56% 4.34%
Discount rate for interest on benefit obligations
3.24% 3.66% 4.45%
3.18% 3.56% 4.34%
Discount rate for service cost
4.15% 3.66% 4.45%
4.36% 3.56% 4.34%
Discount rate for interest on service cost
3.50% 3.66% 4.45%
4.17% 3.56% 4.34%
Expected return on plan assets(a)
Rate of compensation increase
7.31% 7.50% 7.50%
7.07% 7.08% 7.43%
3.51% 4.50% 3.50%
n/a
n/a
n/a
_______
(a) The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For
the OPEB assets subject to unrelated business income taxes (UBIT), we utilize an after-tax expected return on plan assets to determine
our benefit costs, which is based on a UBIT rate of 21% for 2016, 2015 and 2014.
For years prior to 2016, we selected 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. Effective January 1, 2016, we changed our estimate of the service and interest cost components of
net periodic benefit cost (credit) for our pension and other postretirement benefit plans. The new estimate utilizes a full yield
curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the
determination of the benefit obligation to their underlying projected cash flows. The new estimate provides a more precise
measurement of service and interest costs by improving the correlation between projected benefit cash flows and their
corresponding spot rates. The change did not affect the measurement of our pension and postretirement benefit obligations and
it was accounted for as a change in accounting estimate, which was applied prospectively. The expected long-term rates of
return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the
investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the
portfolio is invested and the target weightings of each asset class.
Actuarial estimates for our OPEB plans assumed a weighted-average annual rate of increase in the per capita cost of
covered health care benefits of 9.30%, gradually decreasing to 4.54% by the year 2038. Assumed health care cost trends have a
111
significant effect on the amounts reported for OPEB plans. A one-percentage point change in assumed health care cost trends
would have the following effects as of December 31, 2016 and 2015 (in millions):
One-percentage point increase:
Aggregate of service cost and interest cost
Accumulated postretirement benefit obligation
One-percentage point decrease:
Aggregate of service cost and interest cost
Accumulated postretirement benefit obligation
2016
2015
$
$
$
1
27
(1) $
(23)
2
31
(1)
(27)
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years
ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income
related to our pension and OPEB plans are as follows (in millions):
Components of net benefit cost:
Service cost
Interest cost
Expected return on assets
Amortization of prior service cost (credit)
Amortization of net actuarial loss (gain)
Net benefit (credit) cost(a)
Other changes in plan assets and benefit
obligations recognized in other
comprehensive (income) loss:
Net loss (gain) arising during period
Prior service cost (credit) arising during period
Amortization or settlement recognition of net
actuarial loss
Amortization of prior service credit
Exchange rate changes
Total recognized in total other comprehensive
(income) loss
Total recognized in net benefit cost (credit)
and other comprehensive (income) loss
Pension Benefits
2016
2015
2014
2016
OPEB
2015
2014
$
36
89
(151)
1
35
10
116
—
(34)
—
1
83
$
33
$
21
$
1
$
— $
99
(172)
—
5
(35)
267
—
(5)
—
—
112
(171)
—
—
(38)
285
—
—
—
—
16
(19)
(3)
—
(5)
(48)
—
—
1
—
21
(23)
(3)
1
(4)
(49)
—
(1)
1
—
262
285
(47)
(49)
$
93
$
227
$
247
$
(52) $
(53) $
—
25
(24)
(2)
(1)
(2)
10
—
—
1
—
11
9
_______
(a) 2016 OPEB amount includes $4 million of net benefit credits related to plans that we sponsor that are associated with employee services
provided to unconsolidated joint ventures. We charge or refund these costs or credits associated with these plans to the joint venture as
an offset to our net benefit cost or credit and receive our proportionate share of these costs or credits through our share of the equity
investee’s earnings.
Multiemployer Plans
We participate in several multi-employer pension plans for the benefit of employees who are union members. We do not
administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits
include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their
dependents’ health care costs. Amounts charged to expense for these plans were approximately $8 million, $10 million and $13
million for the years ended December 31, 2016, 2015 and 2014, respectively. We consider the overall multi-employer pension
plan liability exposure to be minimal in relation to the value of its total consolidated assets and net income.
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11. Stockholders’ Equity
Common Equity
As of December 31, 2016, our common equity consisted of our Class P common stock.
During the years 2014 through 2015, as authorized by our board of directors under various repurchase programs, we
repurchased shares and warrants. As of December 31, 2016, we had $90 million of availability to repurchase warrants. During
the years ended December 31, 2015 and 2014, we paid a total of $12 million and $98 million, respectively, for the repurchase
of warrants. During the year ended December 31, 2014, we repurchased $94 million of our Class P shares.
On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the
managers party thereto, as sales agents and/or principals, shares of our Class P common stock having an aggregate offering of
up to $5.0 billion from time to time during the term of this agreement. During the year ended December 31, 2015, we issued
and sold 102,614,508 shares of our Class P common stock pursuant to the equity distribution agreement resulting in net
proceeds of $3.9 billion.
Common Dividends
Holders of our common stock participate in any dividend declared by our board of directors, subject to the rights of the
holders of any outstanding preferred stock. The following table provides information about our per share dividends:
Per common share cash dividend declared for the period
$
Per common share cash dividend paid in the period
Year Ended December 31,
2016
2015
2014
0.50
0.50
$
1.605
$
1.93
1.74
1.70
On January 18, 2017, our board of directors declared a cash dividend of $0.125 per common share for the quarterly period
ended December 31, 2016, which is payable on February 15, 2017 to shareholders of record as of February 1, 2017.
Warrants
Each of our warrants entitles the holder to purchase one share of our common stock for an exercise price of $40 per share,
payable in cash or by cashless exercise, at any time until May 25, 2017. The table below sets forth the changes in our
outstanding warrants:
Beginning balance
Warrants issued with conversions of EP Trust I Preferred securities(a)
Warrants exercised
Warrants repurchased and canceled
Ending balance
_______
(a) See Note 9.
Mandatory Convertible Preferred Stock
2016
Warrants
2015
2014
293,263,797
298,135,976
347,933,107
—
—
—
293,263,797
1,293,615
(71,268)
(6,094,526)
293,263,797
4,315
(18,040)
(49,783,406)
298,135,976
On October 30, 2015, we completed an offering of 32,000,000 depositary shares, each of which represents a 1/20th interest
in a share of our 1,600,000 shares of 9.75% Series A mandatory convertible preferred stock, with a liquidating preference of
$1,000 per share (equal to a $50 liquidation preference per depositary share). Net proceeds, after underwriting discount and
expenses, from the depositary share offering were approximately $1,541 million. The proceeds from the offering were used to
repay borrowings under our revolving credit facility and commercial paper debt and for general corporate purposes.
Unless converted earlier at the option of the holders, on or around October 26, 2018, each share of convertible preferred
stock will automatically convert into between 30.8800 and 36.2840 shares of our common stock (and, correspondingly, each
113
depositary share will convert into between 1.5440 and 1.8142 shares of our common stock), subject to customary anti-dilution
adjustments. The conversion range depends on the volume-weighted average price of our common stock over a 20 trading day
averaging period immediately prior to that date (Applicable Market Value). If the Applicable Market Value for our common
stock is greater than $32.38 or less than $27.56, the conversion rate per preferred stock will be 30.8800 or 36.2840,
respectively. If the Applicable Market Value is between $32.38 and $27.56, the conversion rate per preferred stock will be
between 30.8800 and 36.2840.
Preferred Dividends
Dividends on our mandatory convertible preferred stock are payable on a cumulative basis when, as and if declared by our
board of directors (or an authorized committee thereof) at an annual rate of 9.75% of the liquidation preference of $1,000 per
share on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and including,
October 26, 2018. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any
combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless
full cumulative dividends have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for
all prior dividend periods, no dividends may be declared or paid on common stock.
On October 19, 2016, our board of directors declared a cash dividend of $24.375000 per share of our mandatory
convertible preferred stock (equivalent of $1.218750 per depositary share) for the period from and including October 26, 2016
through and including January 25, 2017, which was paid on January 26, 2017 to mandatory convertible preferred shareholders
of record as of January 11, 2017.
Noncontrolling Interests
Contributions
Prior to the completion of the Merger Transactions on November 26, 2014, contributions from our noncontrolling interests
consisted primarily of equity issuances to the public of common units or shares by KMP, EPB and KMR. Each of these
subsidiaries had an equity distribution agreement in place which allowed the subsidiary to sell its equity interests from time to
time through a designated sales agent. The equity distribution agreement provided the subsidiary with the right, but not the
obligation to offer and sell its equity units or shares, at prices to be determined by market conditions. For the period from
January 1, 2014 to November 26, 2014, KMP, EPB and KMR made equity issuances of 30 million units or shares, resulting in
net proceeds of $1,695 million. These equity issuances had the associated effects of increasing our (i) noncontrolling interests
by $1,640 million; (ii) accumulated deferred income taxes by $19 million; and (iii) additional paid-in capital by $36 million.
Distributions
The following table provides information about distributions from our noncontrolling interests (in millions except per unit
and i-unit distribution amounts):
Year Ended December 31, 2014
KMP(a)
Per unit cash distribution declared for the period
Per unit cash distribution paid in the period
Cash distributions paid in the period to the public
EPB(a)
Per unit cash distribution declared for the period
Per unit cash distribution paid in the period
Cash distributions paid in the period to the public
KMR(a)(b)
$
$
$
$
$
$
4.17
5.53
1,654
1.95
2.60
347
Share distributions paid in the period to the public
7,794,183
_______
(a) As a result of the Merger Transactions, no distribution was declared starting with the fourth quarter of 2014.
(b) KMR’s distributions were paid in the form of additional shares or fractions thereof calculated by dividing the KMP cash distribution per
common unit by the average of the market closing prices of a KMR share determined for a ten-trading day period ending on the trading
day immediately prior to the ex-dividend date for the shares. Represents share distributions made in the period to noncontrolling interests
and excludes 1,127,712 of shares distributed in 2014 on KMR shares we directly and indirectly owned.
114
12. Related Party Transactions
Affiliate Balances
The following tables summarize our affiliate balance sheet balances and income statement activity (in millions):
December 31,
2016
2015
$
$
$
$
$
$
$
37
—
10
47
6
28
9
161
29
233
$
2016
Year Ended December 31,
2015
2014
$
$
$
$
$
$
71
71
142
38
75
$
$
$
72
71
143
60
55
25
36
—
61
6
22
10
167
—
205
29
86
115
74
57
Balance sheet location
Accounts receivable, net
Other current assets
Deferred charges and other assets
Current portion of debt
Accounts payable
Other current liabilities
Long-term debt
Other long-term liabilities and deferred credits
Income statement location
Revenues
Services
Product sales and other
Operating Costs, Expenses and Other
Costs of sales
Other operating expenses
Notes Receivable
Plantation
In March 2016, we received the final principal payment of $35 million for our proportionate share of a note receivable due
from Plantation. We own a 51.17% equity interest in Plantation and the $35 million note receivable balance for our
proportionate share of the note was included within “Other current assets” on our accompanying consolidated balance sheet as
of December 31, 2015.
Subsequent Event
MEP Loan Agreement
On February 3, 2017 we renewed our $40 million loan agreement for an additional one-year term with MEP, our 50%-
owned equity investee. The loan agreement allows us, at our sole option, to make loans from time to time to MEP to fund its
working capital needs and for other LLC purposes. Borrowings under the loan agreement bear interest at a rate of one month
LIBOR plus 1.50%, and all borrowings can be prepaid before maturity without penalty or premium. As of both December 31,
2016 and 2015 there was no amount outstanding pursuant to this loan agreement.
115
13. Commitments and Contingent Liabilities
Leases and Rights-of-Way Obligations
The table below depicts future gross minimum rental commitments under our operating leases and rights-of-way
obligations as of December 31, 2016 (in millions):
Year
2017
2018
2019
2020
2021
Thereafter
Total minimum payments
Commitment
$
$
106
94
86
75
61
342
764
The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to
forty-one years. Total lease and rental expenses were $138 million, $143 million and $114 million for the years ended
December 31, 2016, 2015 and 2014, respectively. The amount of capital leases included within “Property, plant and equipment,
net” in our accompanying consolidated balance sheets as of December 31, 2016 and 2015 is not material to our consolidated
balance sheets.
Contingent Debt
Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain
types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee
is remote.
As of December 31, 2016 and 2015, our contingent debt obligations, as well as our obligations with respect to related
letters of credit, totaled $1,179 million and $1,202 million, respectively. Both December 31, 2016 and 2015 amounts are
primarily represented by our proportional share of the debt obligations of two equity investees. Under such guarantees we are
severally liable for our percentage ownership share of these equity investees’ debt issued in the event of their non-performance.
Also included in our contingent debt obligations is a guarantee of the debt obligations of our 50%-owned investee, Cortez
Pipeline Company. We are severally liable for 50% (our percentage ownership share) of the Cortez Pipeline Company debt
which includes a $50 million credit facility and $100 million in bonds. In addition, we are liable for 100% of the debt issued by
one of Cortez Pipeline Company’s subsidiaries in the event of their non-performance which has a $100 million credit facility
and $120 million private placement note to fund an expansion project.
Guarantees and Indemnifications
We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance
guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under,
or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party
will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically
provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not
limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.
While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification
obligation, there are also circumstances where the amount and duration are unlimited. Currently, we are not subject to any
material requirements to perform under quantifiable arrangements, and we expect future requirements to perform under
quantifiable arrangements will be immaterial. We are unable to estimate a maximum exposure for our guarantee and
indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these
exposures.
See Note 17 “Litigation, Environmental and Other Contingencies” for a description of matters that we have identified as
contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or
indemnification agreements.
116
Commitment for Jones Act Trade Fleet Expansion
Under an August 2015 definitive construction agreement with Philly Tankers LLC, we are expected to have four more
Jones Act tankers delivered by the end of 2017. Our obligation for payments due under the terms of this agreement total $383
million in 2017, of which, approximately $195 million relates to work not yet performed as of December 31, 2016.
14. Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas,
NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt
obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce
our exposure to certain of these risks. In addition, prior to May 2016, we had power forward and swap contracts related to
legacy operations of acquired businesses.
Energy Commodity Price Risk Management
As of December 31, 2016, we had the following outstanding commodity forward contracts to hedge our forecasted energy
commodity purchases and sales:
Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price
Crude oil basis
Natural gas fixed price
Natural gas basis
Derivatives not designated as hedging contracts
Crude oil fixed price
Crude oil basis
Natural gas fixed price
Natural gas basis
NGL and other fixed price
(19.7) MMBbl
(1.3) MMBbl
(38.4) Bcf
(19.3) Bcf
(1.7) MMBbl
(0.1) MMBbl
(5.2) Bcf
(1.4) Bcf
(5.0) MMBbl
As of December 31, 2016, the maximum length of time over which we have hedged, for accounting purposes, our
exposure to the variability in future cash flows associated with energy commodity price risk is through December 2020.
Interest Rate Risk Management
As of December 31, 2016, we had a combined notional principal amount of $9,775 million of fixed-to-variable interest
rate swap agreements, all of which were designated as fair value hedges. As of December 31, 2015, we had a combined
notional principal amount of $11,000 million of fixed-to-variable interest rate swap agreements, of which $9,700 million were
designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain
series of senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread and have termination
dates that correspond to the maturity dates of the related series of senior notes. As of December 31, 2016, the maximum length
of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk
is through March 15, 2035.
Foreign Currency Risk Management
In connection with the issuance of our Euro denominated senior notes in March 2015 (see Note 9), we entered into $1,358
million of cross-currency swap agreements to manage the related foreign currency risk by effectively converting all of the
fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar
denominated debt at fixed rates equivalent to approximately 3.79% and 4.67% for the 7-year and 12-year senior notes,
respectively. These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap
agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior
notes.
117
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated
balance sheets (in millions):
Fair Value of Derivative Contracts
Location
Fair value of derivative contracts/
(Other current liabilities)
Deferred charges and other assets/
(Other long-term liabilities and
deferred credits)
Fair value of derivative contracts/
(Other current liabilities)
Deferred charges and other assets/
(Other long-term liabilities and
deferred credits)
Fair value of derivative contracts/
(Other current liabilities)
Deferred charges and other assets/
(Other long-term liabilities and
deferred credits)
Derivatives designated as
hedging contracts
Natural gas and crude derivative
contracts
Subtotal
Interest rate swap agreements
Subtotal
Cross-currency swap agreements
Subtotal
Total
Derivatives not designated as
hedging contracts
Natural gas, crude, NGL and other
Fair value of derivative contracts/
derivative contracts
(Other current liabilities)
Deferred charges and other assets/
(Other long-term liabilities and
deferred credits)
Fair value of derivative contracts/
(Other current liabilities)
Deferred charges and other assets/
(Other long-term liabilities and
deferred credits)
Fair value of derivative contracts/
(Other current liabilities)
Subtotal
Interest rate swap agreements
Subtotal
Power derivative contracts
Subtotal
Total
Total derivatives
Asset derivatives
December 31,
2015
2016
Fair value
Liability derivatives
December 31,
2015
2016
Fair value
$
101
$
359
$
(57) $
(13)
70
171
94
206
300
—
—
—
471
3
—
3
—
—
—
—
—
3
244
603
111
273
384
—
—
—
987
35
—
35
1
—
1
1
1
37
(24)
(81)
—
(57)
(57)
(7)
(24)
(31)
(169)
—
(13)
—
(9)
(9)
(6)
(46)
(52)
(74)
(29)
(1)
(1)
(30)
—
—
—
—
—
(30)
(199) $
—
(1)
(11)
(5)
(16)
(17)
(17)
(34)
(108)
$
474
$ 1,024
$
118
Effect of Derivative Contracts on the Income Statement
The following tables summarize the impact of our derivative contracts on our accompanying consolidated statements of
income (in millions):
Derivatives in fair value hedging relationships
Location
Interest rate swap agreements
Hedged fixed rate debt
Interest, net
Interest, net
$
$
Gain/(loss) recognized in income on
derivatives and related hedged item
Year Ended December 31,
2016
2015
2014
(180) $
25
$
207
160
$
(33) $
(204)
Derivatives in
cash flow
hedging
relationships
Energy
commodity
derivative
contracts
Gain/(loss)
recognized in OCI
on derivative
(effective portion)(a)
Year Ended
December 31,
2016
2015
2014
$ (115) $ 201
$ 424
Location
Revenues—
Natural gas
sales
Revenues—
Product sales
and other
Costs of sales
Gain/(loss)
recognized in
income on derivative
(ineffective portion
and amount
excluded from
effectiveness testing)
Year Ended
December 31,
2016
2015
2014
$ — $ — $ —
Gain/(loss)
reclassified from
Accumulated OCI
into income
(effective portion)(b)
Year Ended
December 31,
2016
2015
2014
$ 15
$ 54
$ (1)
Location
Revenues—
Natural gas
sales
Revenues—
Product sales
and other
148
(17)
236
(15)
26
4 Costs of sales
(12)
—
Interest rate
swap
agreements(c)
Cross-currency
swap
(2)
(4)
(15)
Interest, net
(3)
(3)
(4)
Interest, net
—
13
(33) — Other, net
Total
$ (104) $ 164
$ 409 Total
(27) —
$ 272
$ 116
— Other, net
$ 25 Total
—
$ (12) $
_______
(a) We expect to reclassify an approximate $8 million gain associated with cash flow hedge price risk management activities included in our
accumulated other comprehensive loss balances as of December 31, 2016 into earnings during the next twelve months (when the
associated forecasted transactions are also expected to occur), however, actual amounts reclassified into earnings could vary materially
as a result of changes in market prices.
(b) Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and
purchases actually occurred).
(c) Amounts represent our share of an equity investee’s accumulated other comprehensive loss.
119
2
—
—
—
2
11
—
—
—
$ 11
Derivatives not designated as
accounting hedges
Location
Energy commodity derivative contracts
Revenues—Natural gas sales
Revenues—Product sales and other
Costs of sales
Other (income) expense, net
Interest rate swap agreements
Interest, net
Total(a)
Gain/(loss) recognized in income on
derivatives
Year Ended December 31,
2016
2015
2014
$
$
(10) $
(26)
3
—
63
30
$
17
$
176
(2)
—
(15)
176
$
(7)
20
—
(2)
—
11
________
(a) For the years ended December 31, 2016 and 2015, includes an approximate gain of $73 million and $31 million, respectively, associated
with natural gas, crude and NGL derivative contract settlements.
Credit Risks
In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may
include posting letters of credit or placing cash in margin accounts. As of December 31, 2016 and 2015, we had $0 million and
$2 million, respectively, of outstanding letters of credit supporting our commodity price risk management program. As of
December 31, 2016, we had cash margins of $37 million posted by us with our counterparties as collateral and no amounts
posted by our counterparties as collateral. As of December 31, 2015, we had no cash margins posted by us as collateral and
cash margins of $37 million posted by our counterparties as collateral. We also use industry standard commercial agreements
which allow for the netting of exposures associated with transactions executed under a single commercial agreement.
Additionally, we generally utilize netting agreements to offset credit exposure across multiple commercial agreements with a
single counterparty.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the
posting of additional collateral upon a decrease in our credit rating. As of December 31, 2016, based on our current mark to
market positions and posted collateral, we estimate that if our credit rating were downgraded one notch we would be required
to post $10 million of additional collateral and no additional collateral beyond this $10 million if we were downgraded two
notches.
120
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but
excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our
consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-
controlling interests are summarized as follows (in millions):
Net
unrealized
gains/(losses)
on cash flow
hedge
derivatives
Foreign
currency
translation
adjustments
Pension and
other
postretirement
liability
adjustments
Total
Accumulated
other
comprehensive
loss
Balance as of December 31, 2013
$
(3) $
2
$
(23) $
Other comprehensive gain (loss) before
reclassifications
Gains reclassified from accumulated other
comprehensive loss
Impact of Merger Transactions (See Note 1)
Net current-period other comprehensive income (loss)
Balance as of December 31, 2014
Other comprehensive gain (loss) before
reclassifications
Gains reclassified from accumulated other
comprehensive loss
Net current-period other comprehensive loss
Balance as of December 31, 2015
Other comprehensive (loss) gain before
reclassifications
Gains reclassified from accumulated other
comprehensive loss
Net current-period other comprehensive (loss) income
254
(22)
98
330
327
164
(272)
(108)
219
(104)
(116)
(220)
Balance as of December 31, 2016
$
(1) $
15. Fair Value of Financial Instruments
(68)
—
(42)
(110)
(108)
(214)
—
(214)
(322)
34
—
34
(288) $
(212)
(1)
—
(213)
(236)
(122)
—
(122)
(358)
(14)
—
(14)
(372) $
(24)
(26)
(23)
56
7
(17)
(172)
(272)
(444)
(461)
(84)
(116)
(200)
(661)
The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our
assessment of the availability of observable market data and the significance of non-observable data used to determine fair
value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the
fair value measurement in its entirety.
The three broad levels of inputs defined by the fair value hierarchy are as follows:
• Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity
has the ability to access at the measurement date;
• Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability,
either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be
observable for substantially the full term of the asset or liability; and
• Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own
assumptions about the assumptions that market participants would use in pricing the asset or liability, and are
developed based on the best information available in the circumstances (which might include the reporting entity’s
own data).
121
Fair Value of Derivative Contracts
The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii)
interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the
Codification (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our
accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
Balance sheet asset fair value
measurements by level
Level 1 Level 2 Level 3
Gross
amount
Contracts
available
for netting
Cash
collateral
held(b)
Net
amount
As of December 31, 2016
Energy commodity derivative contracts(a) $
6
$
Interest rate swap agreements
$ — $
168
300
$ — $
$ — $
As of December 31, 2015
Energy commodity derivative contracts(a) $
48
$
Interest rate swap agreements
$ — $
589
385
$
2
$
$ — $
174
300
639
385
$
$
$
$
(43) $
(18) $
(12) $
(8) $
— $
— $
(37) $
— $
131
282
590
377
Balance sheet liability
fair value measurements by level
Level 1 Level 2 Level 3
Gross
amount
Contracts
available
for netting
Collateral
posted(c)
Net
amount
As of December 31, 2016
Energy commodity derivative contracts(a) $
(29) $
Interest rate swap agreements
Cross-currency swap agreements
As of December 31, 2015
$ — $
$ — $
(82) $ — $
(57) $ — $
(31) $ — $
(111) $
(57) $
(31) $
Energy commodity derivative contracts(a) $
(4) $
Interest rate swap agreements
Cross-currency swap agreements
$ — $
$ — $
(17) $
(10) $
(25) $ — $
(52) $ — $
(31) $
(25) $
(52) $
43
18
$
$
— $
12
8
$
$
— $
37
$
— $
— $
— $
— $
— $
(31)
(39)
(31)
(19)
(17)
(52)
_______
(a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and options and NGL
swaps. Level 3 consists primarily of power derivative contracts.
(b) Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported
within “Other current liabilities” on our accompanying consolidated balance sheets.
(c) Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported
within “Restricted Deposits” on our accompanying consolidated balance sheets.
The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts (in
millions):
Significant unobservable inputs (Level 3)
Derivatives-net asset (liability)
Beginning of period
Total gains or (losses) included in earnings
Settlements
End of period
The amount of total gains or (losses) for the period included in earnings attributable to the
change in unrealized gains or (losses) relating to assets held at the reporting date
122
Year Ended December 31,
2016
2015
$
$
$
(15) $
(9)
24
— $
— $
(61)
(13)
59
(15)
—
As of December 31, 2015, our Level 3 derivative assets and liabilities consisted primarily of power derivative contracts
(which expired in April 2016), where a significant portion of fair value is calculated from underlying market data that is not
readily observable. The derived values use industry standard methodologies that may consider the historical relationships
among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The
use of these inputs results in management’s best estimate of fair value and management does not expect materially different
valuation results were we to use different input amounts within reasonable ranges.
Fair Value of Debt
The carrying value and estimated fair value of our outstanding debt balances is disclosed below (in millions):
December 31, 2016
December 31, 2015
Carrying
value
Estimated
fair value
Carrying
value
Estimated
fair value
Total debt
$
40,050
$
41,015
$
43,227
$
37,481
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31,
2016 and 2015.
16. Reportable Segments
Our reportable business segments are:
• Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and
storage systems; (ii) natural gas and crude oil gathering systems and natural gas processing and treating facilities; (iii)
NGL fractionation facilities and transportation systems; and (iv) LNG facilities;
• 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 located throughout the U.S. and
portions of Canada that transload and store refined petroleum products, crude oil, chemicals, and ethanol and bulk
products, including coal, petroleum coke, fertilizer, steel and ores and (ii) Jones Act tankers;
•
Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate
pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, crude oil and condensate
to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline
transmix facilities; and
• Kinder Morgan Canada—the ownership and operation of the Trans Mountain pipeline system that transports crude oil
and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British
Columbia, Canada and the state of Washington, plus the Jet Fuel aviation turbine fuel pipeline that serves the
Vancouver (Canada) International Airport.
We evaluate performance principally based on each segment’s EBDA, which excludes general and administrative
expenses, interest expense, net, and income tax expense. Our reportable segments are strategic business units that offer
different products and services, and they are structured based on how our chief operating decision makers organize their
operations for optimal performance and resource allocation. Each segment is managed separately because each segment
involves different products and marketing strategies.
Segment results for the years ended December 31, 2015 and 2014 have been retrospectively adjusted to reflect the
elimination of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now
presented within the Corporate non-segment activities in reconciling to the consolidated totals in the respective segment
reporting tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not
associated with our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition,
the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries
123
as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interest
income and income tax expense previously allocated to our business segments is now included in “Interest expense, net” and
“Income tax expense” for all periods presented in the following tables.
We consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment
performance for our reporting segments. We account for intersegment sales at market prices, while we account for asset
transfers at either market value or, in some instances, book value.
During 2016, 2015 and 2014, we did not have revenues from any single external customer that exceeded 10% of our
consolidated revenues.
Financial information by segment follows (in millions):
Revenues
Natural Gas Pipelines
Revenues from external customers
Intersegment revenues
CO2
Terminals
Revenues from external customers
Intersegment revenues
Products Pipelines
Revenues from external customers
Intersegment revenues
Kinder Morgan Canada
Corporate and intersegment eliminations(a)
Total consolidated revenues
Operating expenses(b)
Natural Gas Pipelines
CO2
Terminals
Products Pipelines
Kinder Morgan Canada
Corporate and intersegment eliminations
Total consolidated operating expenses
Year Ended December 31,
2016
2015
2014
$
7,998
$
8,704
$
10,153
7
1,221
1,921
1
1,631
18
253
8
21
1,699
1,878
1
1,828
3
260
9
15
1,960
1,717
1
2,068
—
291
21
$
13,058
$
14,403
$
16,226
Year Ended December 31,
2016
2015
2014
$
4,393
$
4,738
$
399
768
573
87
2
432
836
772
87
26
$
6,222
$
6,891
$
6,241
494
746
1,258
106
8
8,853
124
Other expense (income)(c)
Natural Gas Pipelines
CO2
Terminals
Products Pipelines
Kinder Morgan Canada
Corporate
Year Ended December 31,
2016
2015
2014
$
199
$
1,269
$
19
99
76
—
(7)
386
606
190
2
(1)
—
5
243
29
(3)
—
1
Total consolidated other expense (income)
$
$
2,066
$
275
DD&A
Natural Gas Pipelines
CO2
Terminals
Products Pipelines
Kinder Morgan Canada
Corporate
Year Ended December 31,
2016
2015
2014
$
1,041
$
1,046
$
446
435
221
44
22
556
433
206
46
22
897
570
337
166
51
19
Total consolidated DD&A
$
2,209
$
2,309
$
2,040
Year Ended December 31,
2016
2015
2014
$
$
$
$
(269) $
22
19
56
—
(172) $
$
285
(5)
17
36
—
333
$
Year Ended December 31,
2016
2015
2014
19
$
24
$
4
2
15
4
44
$
8
4
8
(1)
43
$
279
26
18
37
1
361
24
12
(1)
15
30
80
Earnings from equity investments and amortization of excess cost of equity
investments, including loss on impairments
Natural Gas Pipelines
CO2
Terminals
Products Pipelines
Corporate
Total consolidated equity earnings
Other, net-income (expense)
Natural Gas Pipelines
Terminals
Products Pipelines
Kinder Morgan Canada
Corporate
Total consolidated other, net-income (expense)
125
Segment EBDA(d)
Natural Gas Pipelines
CO2
Terminals
Products Pipelines
Kinder Morgan Canada
Total segment EBDA
DD&A
Amortization of excess cost of equity investments
General and administrative expenses
Interest expense, net
Corporate(a)
Income tax expense
Total consolidated net income
$
Year Ended December 31,
2016
2015
2014
$
3,211
$
3,067
$
827
1,078
1,067
181
6,364
(2,209)
(59)
(669)
(1,806)
17
(917)
721
$
658
878
1,106
182
5,891
(2,309)
(51)
(690)
(2,051)
(18)
(564)
208
$
4,264
1,248
973
856
200
7,541
(2,040)
(45)
(610)
(1,798)
43
(648)
2,443
Capital expenditures
Natural Gas Pipelines
CO2
Terminals
Products Pipelines
Kinder Morgan Canada
Corporate
Total consolidated capital expenditures
Investments at December 31
Natural Gas Pipelines
Terminals
Products Pipelines
Kinder Morgan Canada
Corporate
Year Ended December 31,
2016
2015
2014
$
1,227
$
1,642
$
276
983
244
124
28
725
847
524
142
16
935
792
1,049
680
156
5
$
$
2,882
$
3,896
$
3,617
2016
2015
6,185
$
5,080
252
566
20
4
306
641
10
3
Total consolidated investments
$
7,027
$
6,040
126
Assets at December 31
Natural Gas Pipelines
CO2
Terminals
Products Pipelines
Kinder Morgan Canada
Corporate assets(e)
Assets held for sale
2016
2015
$
50,428
$
53,704
4,065
9,725
8,329
1,572
6,108
78
4,706
9,083
8,464
1,434
6,694
19
Total consolidated assets $
80,305
$
84,104
_______
(a) Includes a management fee for services we perform as operator of an equity investee.
(b) Includes natural gas purchases and other costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(c) Includes loss on impairment of goodwill, loss on impairments and divestitures, net and other (income) expense, net.
(d) Includes revenues, earnings from equity investments, other, net, less operating expenses, and other (income) expense, net, loss on
impairment of goodwill, and loss on impairments and divestitures, net and loss on impairments and divestitures of equity investments,
net.
(e) Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, certain prepaid assets and deferred
charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in
Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy
operations) not allocated to the reportable segments.
We do not attribute interest and debt expense to any of our reportable business segments.
Following is geographic information regarding the revenues and long-lived assets of our business segments (in millions):
Revenues from external customers
U.S.
Canada
Mexico
Total consolidated revenues from external customers
Long-term assets, excluding goodwill and other intangibles
U.S.
Canada
Mexico
Total consolidated long-lived assets
17. Litigation, Environmental and Other Contingencies
Year Ended December 31,
2016
2015
2014
12,459
$
13,797
$
15,605
483
116
479
127
437
184
13,058
$
14,403
$
16,226
December 31,
2016
2015
2014
49,125
$
51,679
$
2,399
82
2,193
67
49,992
2,268
81
51,606
$
53,939
$
52,341
$
$
$
$
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of
our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be
given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate
resolution of such items will not have a material adverse impact on our business, financial position, results of operations or
dividends to our shareholders. We believe we have meritorious defenses to the matters to which we are a party and intend to
vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an
undiscounted liability for such contingencies based on our best estimate using information available at that time. If the
estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low
127
end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management,
we conclude the matter should otherwise be disclosed.
Federal Energy Regulatory Commission Proceedings
SFPP
The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the
complaints and protests of various shippers the most recent of which was filed in late 2015 with the FERC (docketed at
OR16-6) challenging SFPP’s filed East Line rates. In general, these complaints and protests allege the rates and tariffs charged
by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have
challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate
increases. If the shippers prevail on their arguments or claims, they are entitled to seek reparations (which may reach back up
to two years prior to the filing date of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce
its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal
courts. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the
appropriate level of return and income tax allowance SFPP may include in its rates. On March 22, 2016, the D.C. Circuit
issued a decision in United Airlines, Inc. v. FERC remanding to FERC for further consideration of two issues: (1) the
appropriate data to be used to determine the return on equity for SFPP in the underlying docket, and (2) the just and reasonable
return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. With
respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking
approximately $40 million in annual rate reductions and approximately $190 million in refunds. Management believes SFPP
has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and
protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP
estimates that applying the principles of FERC precedent, as applicable, to pending SFPP cases would result in rate reductions
and refunds substantially lower than those sought by the shippers.
EPNG
The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010
rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC
generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it will apply its findings in
Opinion 517-A to the same issues in the 2010 rate case. EPNG has sought federal appellate review of Opinion 517-A and oral
argument is scheduled for February 15, 2017. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A)
on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law
Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent
with the terms of Opinions 517-A and 528-A. EPNG and two intervenors sought rehearing of certain aspects of the decision,
and the judicial review sought by certain intervenors has been delayed until the FERC issues an order on rehearing. All refund
obligations related to the 2008 rate case were satisfied during calendar year 2015. With respect to the 2010 rate case, EPNG
believes it has an appropriate reserve related to the findings in Opinions 517-A and 528-A.
NGPL and WIC
On January 19, 2017, NGPL and WIC were notified by the FERC of rate proceedings against them pursuant to section 5 of
the Natural Gas Act (the “Orders”). Each respective proceeding will set the matter for hearing and determine whether NGPL’s
and WIC’s current rates remain just and reasonable. A proceeding under section 5 of the Natural Gas Act is prospective in
nature such that a change in rates charged to customers, if any, would likely only occur after the FERC has issued a final order.
Unless a settlement is reached sooner, an initial Administrative Law Judge decision is anticipated in late February, 2018, with a
final FERC decision anticipated by the third quarter, 2018. We do not believe that the ultimate resolution of these proceedings
will have a material adverse impact on our results of operations or cash flows from operations.
Other Commercial Matters
Union Pacific Railroad Company Easements & Related Litigation
SFPP and Union Pacific Railroad Company (UPRR) are engaged in a proceeding to determine the extent, if any, to which
the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to
existing contractual arrangements for the ten-year period beginning January 1, 2004 (Union Pacific Railroad Company v. Santa
Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of
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the State of California for the County of Los Angeles, filed July 28, 2004). In September 2011, the trial judge determined that
the annual rent payable as of January 1, 2004 was $14 million, subject to annual consumer price index increases. SFPP
appealed the judgment.
By notice dated October 25, 2013, UPRR demanded the payment of $22.3 million in rent for the first year of the next ten-
year period beginning January 1, 2014, which SFPP rejected.
On November 5, 2014, the Court of Appeals issued an opinion which reversed the judgment, including the award of
prejudgment interest, and remanded the matter to the trial court for a determination of UPRR’s property interest in its right-of-
way, including whether UPRR has sufficient interest to grant SFPP’s easements. UPRR filed a petition for review to the
California Supreme Court which was denied. The trial court has not set a date for the retrial.
After the above-referenced decision by the California Court of Appeals which held that UPRR does not own the subsurface
rights to grant certain easements and may not be able to collect rent from those easements, a purported class action lawsuit was
filed in 2015 in the U.S. District Court for the Southern District of California by private landowners in California who claim to
be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP. Substantially similar follow-on
lawsuits were filed and are pending in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which
are brought purportedly as class actions on behalf of all landowners who own land in fee adjacent to and underlying the railroad
easement under which the SFPP pipeline is located in those respective states, assert claims against UPRR, SFPP, KMGP, and
Kinder Morgan Operating L.P. “D” for declaratory judgment, trespass, ejectment, quiet title, unjust enrichment, accounting, and
alleged unlawful business acts and practices arising from defendants’ alleged improper use or occupation of subsurface real
property. SFPP views these cases as primarily a dispute between UPRR and the plaintiffs. UPRR purported to grant SFPP a
network of subsurface pipeline easements along UPRR’s railroad right-of-way. SFPP relied on the validity of those easements
and paid rent to UPRR for the value of those easements. We believe we have recorded a right-of-way liability sufficient to
cover our potential obligation, if any, for back rent.
SFPP and UPRR have engaged in multiple disputes over the circumstances under which SFPP must pay for relocations of
its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In 2006, following a bench trial
regarding the circumstances under which SFPP must pay for relocations, the judge determined that SFPP must pay for any
relocations resulting from any legitimate business purpose of the UPRR. The decision was affirmed on appeal. In addition,
UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way
Association (AREMA) standards in determining when relocations are necessary and in completing relocations. Each party has
sought declaratory relief with respect to its positions regarding the application of these standards with respect to relocations. In
2011, a jury verdict was reached that SFPP was obligated to comply with AREMA standards in connection with a railroad
project in Beaumont Hills, California. In 2014, the trial court entered judgment against SFPP, consistent with the jury’s verdict.
On June 29, 2015, the parties entered into a confidential settlement of all of the claims relating to the project in Beaumont Hills
and the case was dismissed.
Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult
to quantify the effects of the outcome of these cases on SFPP. Even if SFPP is successful in advancing its positions, significant
relocations for which SFPP must nonetheless bear the cost (i.e., for railroad purposes, with the standards in the federal Pipeline
Safety Act applying) could have an adverse effect on our financial position, results of operations, cash flows, and our
dividends to our shareholders. These effects could be even greater in the event SFPP is unsuccessful in one or more of these
lawsuits.
Gulf LNG Facility Arbitration
On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Disagreement and
Disputed Statements and a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that
entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that is not
scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy
company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA seeks declaratory and monetary relief
based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas
market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii)
activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG
Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the
agreement. As set forth in the terminal use agreement, disputes are meant to be resolved by final and binding arbitration. A
three-member arbitration panel conducted an arbitration hearing in January 2017. We expect the arbitration panel will issue its
decision within approximately six months. Eni USA has indicated that it will continue to pay the amounts claimed to be due
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pending resolution of the dispute. The successful assertion by Eni USA of its claim to terminate or amend its payment
obligations under the agreement prior to the expiration of its initial term could have an adverse effect on the business, financial
position, results of operations, or cash flows of GLNG and distributions to KMI, a 50% shareholder of GLNG. We view the
demand for arbitration to be without merit, and we intend to contest it vigorously.
Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al.
On October 16, 2013, Plains Gas Solutions, LLC (Plains) filed a petition in the 151st Judicial District Court for Harris
County, Texas (Case No. 62528) against TGP, Kinetica Partners, LLC and two other Kinetica entities. The suit arose from the
sale by TGP of the Cameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleged that
defendants breached a straddle agreement requiring that gas on the Cameron System be committed to Plains’ Grand Chenier
gas-processing facility, that requisite daily volume reports were not provided, that TGP improperly assigned its obligations
under the straddle agreement to Kinetica, and that defendants interfered with Plains’ contracts with producers. The petition
alleged damages of at least $100 million. Under the Amended and Restated Purchase and Sale Agreement with Kinetica,
Kinetica is obligated to defend and indemnify TGP in connection with the gas commitment and reporting claims. After
agreeing initially to defend and indemnify TGP against such claims, Kinetica withdrew its defense, disputed its indemnity
obligation, and settled with Plains. On January 20, 2017, Plains and TGP agreed to release and dismiss their claims and causes
of action in the lawsuit with prejudice.
Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al.
In December 2011 (Brinckerhoff I), March 2012, (Brinckerhoff II), May 2013 (Brinckerhoff III) and June 2014
(Brinckerhoff IV), derivative lawsuits were filed in Delaware Chancery Court against El Paso Corporation, El Paso Pipeline GP
Company, L.L.C., the general partner of EPB, and the directors of the general partner at the time of the relevant transactions.
EPB was named in these lawsuits as a “Nominal Defendant.” The lawsuits arise from the March 2010, November 2010, May
2012 and June 2011 drop-down transactions involving EPB’s purchase of SLNG, Elba Express, CPG and interests in SNG and
CIG. The lawsuits allege various conflicts of interest and that the consideration paid by EPB was excessive. Brinckerhoff I
and II were consolidated into one proceeding. Motions to dismiss were filed in Brinckerhoff III and Brinckerhoff IV, and such
motions remain pending. On June 12, 2014, defendants’ motion for summary judgment was granted in Brinckerhoff I,
dismissing the case in its entirety. Defendants’ motion for summary judgment in Brinckerhoff II was granted in part, dismissing
certain claims and allowing the matter to go to trial in late 2014 on the remaining claims. On April 20, 2015, the Court issued a
post-trial memorandum opinion (Memorandum Opinion) in Brinckerhoff II entering judgment in favor of all of the defendants
other than the general partner of EPB, but finding the general partner liable for breach of contract in connection with EPB’s
purchase of 49% interests in Elba and SLNG and a 15% interest in SNG in a $1.13 billion drop-down transaction that closed on
November 19, 2010 (Fall Dropdown), prior to our acquisition of El Paso Corporation in 2012. In its Memorandum Opinion,
the Court determined that EPB suffered damages of $171 million from the Fall Dropdown, which the Court determined to be
the amount that EPB overpaid for Elba. We believe the claim is derivative in nature and was extinguished by our acquisition on
November 26, 2014, pursuant to a merger agreement, of all of the outstanding common units of EPB that we did not already
own. On December 2, 2015, the Court denied our motion to dismiss the remaining claims in Brinckerhoff II based upon our
acquisition of all of the outstanding common units of EPB, and held that damages should be calculated by considering the
unaffiliated unitholders’ ownership percentage as of the effective date of the merger. Based on this ruling, the Court entered
judgment on February 4, 2016 in the amount of $100.2 million plus interest at the legal rate for the period from November 15,
2010 until the date of payment, if any payment is ultimately required. We filed an appeal to the Delaware Supreme Court and
Brinckerhoff filed a cross-appeal challenging the dismissal of Brinckerhoff I. On December 20, 2016, the Delaware Supreme
Court issued an opinion reversing the trial court’s December 2, 2015 decision, finding that the claims were derivative in nature
and that Brinckerhoff lost standing to continue both the appeal and cross-appeal when the merger closed. Because its holding
terminates the litigation, the Supreme Court did not reach the other issues raised by the parties. On January 5, 2017, the
Supreme Court issued a mandate to the trial court reversing the February 4, 2016 judgment in its entirety. On January 30,
2017, the trial court dismissed the case. We continue to believe the transactions at issue were appropriate and in the best
interests of EPB. We believe the remaining lawsuits (Brinckerhoff III and IV) should be dismissed on the same grounds,
among others, as Brinckerhoff I and II and we intend to continue to defend such lawsuits vigorously.
Price Reporting Litigation
Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso
Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired
to manipulate the price of natural gas by providing false price information to industry trade publications that published gas
indices. Several of the cases have been settled or dismissed. The remaining cases, which are pending in Nevada federal court,
were dismissed, but the dismissal was reversed by the 9th Circuit Court of Appeals. The U.S. Supreme Court affirmed the 9th
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Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the Nevada federal court for
further consideration and trial, if necessary, of numerous remaining issues. On May 24, 2016, the Court granted a motion for
summary judgment dismissing a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in
damages has been alleged. That ruling has been appealed to the 9th Circuit Court of Appeals. Tentative settlements have been
reached in class actions originally filed in Kansas and Missouri, which settlements are subject to court approval. In the
remaining case, a Wisconsin class action, approximately $300 million in damages have been alleged against all defendants.
There remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of
damages, if any, which may be allocated to us in the remaining lawsuits and therefore, our legal exposure, if any, and costs are
not currently determinable.
Kinder Morgan, Inc. Corporate Reorganization Litigation
Certain unitholders of KMP and EPB filed five putative class action lawsuits in the Court of Chancery of the State of
Delaware in connection with our November 26, 2014 acquisition, pursuant to three separate merger agreements, of all of the
outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we did not already own. The
lawsuits were consolidated under the caption In re Kinder Morgan, Inc. Corporate Reorganization Litigation (Consolidated
Case No. 10093-VCL). On December 12, 2014, the plaintiffs filed a Verified Second Consolidated Amended Class Action
Complaint, which purported to assert claims on behalf of both the former EPB unitholders and the former KMP unitholders.
The EPB plaintiff alleged that (i) El Paso Pipeline GP Company, L.L.C. (EPGP), the general partner of EPB, and the directors
of EPGP breached duties under the EPB partnership agreement, including the implied covenant of good faith and fair dealing,
by entering into the EPB Transaction; (ii) EPB, E Merger Sub LLC, KMI and individual defendants aided and abetted such
breaches; and (iii) EPB, E Merger Sub LLC, KMI, and individual defendants tortiously interfered with the EPB partnership
agreement by causing EPGP to breach its duties under the EPB partnership agreement.
The KMP plaintiffs alleged that (i) KMR, KMGP, and individual defendants breached duties under the KMP partnership
agreement, including the implied duty of good faith and fair dealing, by entering into the KMP Transaction and by failing to
adequately disclose material facts related to the transaction; (ii) KMI aided and abetted such breach; and (iii) KMI, KMP,
KMR, P Merger Sub LLC, and individual defendants tortiously interfered with the rights of the plaintiffs and the putative class
under the KMP partnership agreement by causing KMGP to breach its duties under the KMP partnership agreement. The
complaint sought declaratory relief that the transactions were unlawful and unenforceable, reformation, rescission, rescissory or
compensatory damages, interest, and attorneys’ and experts’ fees and costs. On December 30, 2014, the defendants moved to
dismiss the complaint. On April 2, 2015, the EPB plaintiff and the defendants submitted a stipulation and proposed order of
dismissal, agreeing to dismiss all claims brought by the EPB plaintiff with prejudice as to the EPB lead plaintiff and without
prejudice to all other members of the putative EPB class. The Court entered such order on April 2, 2015.
On August 24, 2015, the Court issued an order granting the defendants’ motion to dismiss the remaining counts of the
complaint for failure to state a claim. On September 21, 2015, plaintiffs filed a notice of appeal to the Supreme Court of the
State of Delaware, captioned Haynes Family Trust et al. v. Kinder Morgan G.P., Inc. et al. (Case No. 515). On March 10, 2016,
the Delaware Supreme Court affirmed the dismissal of all claims on appeal and this matter is now concluded.
Pipeline Integrity and Releases
From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may
cause explosions, fire, and 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.
General
As of December 31, 2016 and 2015, our total reserve for legal matters was $407 million and $463 million, respectively.
The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline
segments and certain corporate matters.
Environmental Matters
We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular,
CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners
and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a
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liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and
local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial
compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline,
terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and
liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and
enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from
our operations, could result in substantial costs and liabilities to us.
We are currently involved in several governmental proceedings involving alleged violations of environmental and safety
regulations, including alleged violations of the Risk Management Program and leak detection and repair requirements of the
Clean Air Act. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate.
These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties, individually or in
the aggregate, will be material. We are also currently involved in several governmental proceedings involving groundwater and
soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to
address the costs associated with the cleanup.
In addition, we are involved with and have been identified as a potentially responsible party in several federal and state
superfund sites. Environmental reserves have been established for those sites where our contribution is probable and
reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have
occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas and CO2.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
In December 2000, the EPA issued General Notice letters to potentially responsible parties including GATX Terminals
Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an
industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a
Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette
Group (LWG), of which KMLT is a non-voting member and pays a minimal fee to be part of the group. The LWG agreed to
conduct the remedial investigation and feasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland
Harbor site. After a dispute with the EPA concerning certain provision of the FS, the parties agreed that the EPA would
complete the FS and that the LWG may dispute the FS within 14 days of the publication of the proposed remedy for cleanup.
EPA issued the FS and the Proposed Plan on June 8, 2016. The EPA’s Proposed Plan included a combination of dredging,
capping, and enhanced natural recovery. Comments on the FS and the Proposed Plan were submitted by the LWG and on our
own behalf on September 7, 2016. On January 6, 2017, the EPA issued its Record of Decision (ROD) for the final cleanup
plan. The final remedy is more stringent than the remedy proposed in the EPA’s Proposed Plan. The estimated cost has
increased from approximately $750 million to approximately $1.1 billion and active cleanup is now expected to take as long as
13 years to complete. KMLT and 90 other parties are involved in a non-judicial allocation process to determine each party’s
respective share of the cleanup costs. We are participating in the allocation process on behalf of KMLT and KMBT in
connection with their current or former ownership or operation of four facilities located in Portland Harbor. Our share of
responsibility for Portland Harbor Superfund Site costs will not be determined until the ongoing non-judicial allocation process
is concluded in several years or a lawsuit is filed that results in a judicial decision allocating responsibility. Until the allocation
process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the
proposed remedy and cleanup of the site.
Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court,
Arizona
The Roosevelt Irrigation District sued KMGP, KMEP and others under CERCLA for alleged contamination of the water
purveyor’s wells. The First Amended Complaint sought $175 million in damages from approximately 70 defendants. On
August 6, 2013 plaintiffs filed their Second Amended Complaint seeking monetary damages in unspecified amounts and
reducing the number of defendants to 26 including KMEP and SFPP. The claims now presented against KMEP and SFPP are
related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on
water wells owned by the plaintiffs and located in the vicinity of the Terminal. We have filed an answer, general denial, and
affirmative defenses in response to the Second Amended Complaint and fact discovery is proceeding.
Mission Valley Terminal Lawsuit
In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of
California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting
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from hydrocarbon and methyl tertiary butyl ether (MTBE) impacted soils and groundwater beneath the City’s stadium property
in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court
of California, San Diego County and was removed in 2007 to the U.S. District Court, Southern District of California (Case No.
07CV1883WCAB). The City disclosed in discovery that it was seeking approximately $170 million in damages for alleged
lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the
property. Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of
other claims that increased its claim for damages to approximately $365 million.
On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ summary adjudication motions. The
Court tentatively granted our partial motions for summary judgment on the City’s claims for water and real estate damages and
the State’s claims for violations of California Business and Professions Code § 17200, tentatively denied the City’s motion for
summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary
judgment on such claims. On January 25, 2013, the Court rendered judgment in favor of all defendants on all claims asserted
by the City.
On February 20, 2013, the City of San Diego filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit.
On May 21, 2015, the Court of Appeals issued a memorandum decision which affirmed the District Court’s summary judgment
in our favor with respect to the City’s claim under California Safe Drinking Water and Toxic Enforcement Act, but reversed
both the District Court’s summary judgment decision in our favor on the City’s remaining claims and the District Court’s
decision to exclude the City’s expert testimony. The Court of Appeals issued a mandate returning the case to the U.S. District
Court.
On June 17, 2016, the parties entered into a settlement resolving all claims related to the historical contamination at the
City’s stadium property. The settlement provides for a $20 million payment to the City, a waiver and release by the City of all
claims which were asserted or could have been asserted in the litigation, and an agreement by defendants to indemnify the City
for additional, incremental costs, if any, incurred by the City in the redevelopment of the stadium property or the development
of groundwater beneath the stadium property, that would not have been incurred but for the historical releases from the Mission
Valley Terminal. By Order dated June 17, 2016, the District Court granted dismissal of the litigation.
This site remains under the regulatory oversight and order of the California Regional Water Quality Control Board
(RWQCB). SFPP completed the soil and groundwater remediation at the City of San Diego’s stadium property site and
conducted quarterly sampling and monitoring through 2015 as part of the compliance evaluation required by the RWQCB. The
RWQCB issued a notice of no further action with respect to the stadium property site on May 4, 2016. SFPP’s remediation
effort is now focused on its adjacent Mission Valley Terminal site.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty uranium mines in
the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in
response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support
the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying
EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a potentially
responsible party within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order
on Consent and Scope of Work pursuant to which EPNG is conducting a radiological assessment of the surface of the mines.
On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona (Case No. 3:14-08165-
DGC) seeking cost recovery and contribution from the applicable federal government agencies toward the cost of
environmental activities associated with the mines, given the pervasive control of such federal agencies over all aspects of the
nuclear weapons program. Defendants filed an answer and counterclaims seeking contribution and recovery of response costs
allegedly incurred by the federal agencies in investigating uranium impacts on the Navajo Reservation. The counterclaim of
defendant EPA has been settled, and no viable claims for reimbursement by the other defendants are known to exist.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, Essex, Hudson, Bergen and Passaic Counties, New
Jersey
EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso
Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic
River Study Area Superfund Site (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC
Polymers and EPEC Oil Trust may be potentially responsible parties (PRPs) under CERCLA based on prior ownership and/or
operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into
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two Administrative Orders on Consent (AOCs) which obligate them to investigate and characterize contamination at the Site.
They are also part of a joint defense group (JDG) of approximately 70 cooperating parties which have entered into AOCs and
are directing and funding the work required by the EPA. Under the first AOC, draft remedial investigation and feasibility
studies (RI/FS) of the Site were submitted to the EPA in 2015, and comments from the EPA remain pending. Under the second
AOC, the JDG members conducted a CERCLA removal action at the Passaic River Mile 10.9, and the group is currently
conducting EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of
compliance with the AOCs.
On April 11, 2014, the EPA announced the issuance of its Focused Feasibility Study (FFS) for the lower eight miles of the
Passaic River Study Area, and its proposed plan for remedial alternatives to address the dioxin sediment contamination from
the mouth of Newark Bay to River Mile 8.3. The EPA estimates the cost for the alternatives will range from $365 million to
$3.2 billion. The EPA’s preferred alternative would involve dredging the river bank-to-bank and installing an engineered cap at
an estimated cost of $1.7 billion. On March 4, 2016, the EPA issued its ROD for the lower 8.3 miles of the Passaic River Study
area. The final cleanup plan in the ROD is substantially similar to the EPA’s preferred alternative announced on April 11, 2014.
On October 5, 2016, the EPA entered into an AOC with one member of the PRP group requiring such member to spend $165
million to perform engineering and design work necessary to begin the cleanup of the lower 8.3 miles of the Passaic River. The
design work is expected to take four years to complete and the cleanup is expected to take six years to complete.
In addition to the AOC with one member of the PRP group described above, the EPA has notified over 80 other PRPs,
including EPEC Polymers and EPEC Oil Trust (the Notice), that the EPA intends to pursue additional agreements with other
“major PRPs” and initiate negotiations over cash buyouts with parties whom the EPA does not consider “major PRPs.” The
Notice creates significant uncertainty as to the implementation and associated costs of the remedy set forth in the FFS and
ROD, and provides no guidance as to the EPA’s definition of a “major PRP” or the potential amount or range of cash buyouts.
There is also uncertainty as to the impact of the RI/FS that the CPG is currently preparing for portions of the Site. The draft RI/
FS was submitted by the CPG earlier in 2015 and proposes a different remedy than the FFS announced by the EPA. Therefore,
the scope of potential EPA claims for the lower eight miles of the Passaic River is not reasonably estimable at this time.
Southeast Louisiana Flood Protection Litigation
On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (SLFPA) filed
a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP,
SNG and approximately 100 other energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial
operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased
storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The SLFPA asserts claims for
negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks
unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the
alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land
bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13,
2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On February 13, 2015, the Court
granted defendants’ motion to dismiss the suit for failure to state a claim, and issued an order dismissing the SLFPA’s claims
with prejudice. The SLFPA filed a notice of appeal on February 20, 2015. The U.S. Court of Appeals for the Fifth Circuit
heard oral argument on February 29, 2016 and we await the Court’s decision.
Plaquemines Parish Louisiana Coastal Zone Litigation
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for
Plaquemines Parish, Louisiana (Docket No. 60-999) against TGP and 17 other energy companies, alleging that defendants’ oil
and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas
fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish,
including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of
state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal
Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish
seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the
allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. In
connection with this suit, TGP has made two tenders for defense and indemnity: (1) to Anadarko, as successor to the entity that
purchased TGP’s oil and gas assets in Bastian Bay, and (2) to Kinetica, which purchased TGP’s pipeline assets in Bastian Bay
in 2013. Anadarko has accepted TGP’s tender (limited to oil and gas assets), and Kinetica rejected TGP’s tender. TGP
responded to Kinetica by reasserting TGP’s demand for defense and indemnity and reserving its rights. On November 12,
2015, the Plaquemines Parish Council adopted a resolution directing its legal counsel in all its Coastal Zone cases to take all
134
actions necessary to cause the dismissal of all such cases. On April 14, 2016, following interventions in the suit by the
Louisiana Department of Natural Resources and Attorney General, the Parish Council passed a resolution rescinding its
November 12, 2015 resolution that had directed its counsel to dismiss the suit. We intend to continue to vigorously defend the
suit.
Vermilion Parish Louisiana Coastal Zone Litigation
On July 28, 2016, the District Attorney for the 15th Judicial District of Louisiana, purporting to act on behalf of Vermilion
Parish and the State of Louisiana, filed suit in the state district court for Vermilion Parish, Louisiana against TGP and 52 other
energy companies, alleging that the defendants’ oil and gas and transportation operations associated with the development of
several fields in Vermilion Parish (Operational Areas) were conducted in violation of the Coastal Zone Management Act. The
suit alleges such operations caused substantial damage to the coastal waters and nearby lands (Coastal Zone) of Vermilion
Parish, resulting in the release of pollutants and contaminants into the environment, improper discharge of oil field wastes, the
improper use of waste pits and failure to close such pits, and the dredging of canals, which resulted in degradation of the
Operational Areas, including erosion of marshes and degradation of terrestrial and aquatic life therein. As a result of such
alleged violations of the Coastal Zone Management Act, the suit seeks a judgment against the defendants awarding all
appropriate damages, the payment of costs to clear, revegetate, detoxify and otherwise restore the Vermilion Parish Coastal
Zone, actual restoration of the affected Coastal Zone to its original condition, and reasonable costs and attorney fees. On
September 2, 2016, the case was removed to the United States District Court for the Western District of Louisiana. On
September 20, 2016, the plaintiffs filed a motion to remand the case back to the state district court. A hearing on this motion
has been continued until a decision has been reached by the U.S. Court of Appeals for the Fifth Circuit in the Southeast
Louisiana Flood Protection Litigation discussed above.
Vintage Assets, Inc. Coastal Erosion Litigation
On December 18, 2015, Vintage Assets, Inc. filed a petition in the 25th Judicial District Court for Plaquemines Parish,
Louisiana alleging that its 5,000 acre property is composed of coastal wetlands, and that SNG, TGP, and certain other
defendants failed to maintain pipeline canals and banks, causing widening of the canals, land loss, and damage to the ecology
and hydrology of the marsh, in breach of right of way agreements, prudent operating practices, and Louisiana law. The suit
also claims that defendants’ alleged failure to maintain pipeline canals and banks constitutes negligence and has resulted in
encroachment of the canals, constituting trespass. The suit seeks in excess of $80 million in money damages, including
recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and
projected reconstruction cost of replacing or restoring wetlands. The suit was removed to the U.S. District Court for the
Eastern District of Louisiana. The SNG assets at issue were sold to Highpoint Gas Transmission, LLC in 2011, which was
subsequently purchased by American Midstream Partners, LP. In response to SNG’s demand for defense and indemnity,
American Midstream Partners agreed to pay 50% of joint defense costs and expenses, with a percentage of indemnity to be
determined upon final resolution of the suit. On October 20, 2016, plaintiffs filed an amended complaint naming Highpoint
Gas Transmission, LLC as an additional defendant. A non-jury trial is scheduled to begin on September 11, 2017 and we intend
to vigorously defend the suit.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set
forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our
business, financial position, results of operations or cash flows. As of December 31, 2016 and 2015, we have accrued a total
reserve for environmental liabilities in the amount of $302 million and $284 million, respectively. In addition, as of
December 31, 2016 and 2015, we have recorded a receivable of $13 million for expected cost recoveries that have been
deemed probable.
18. Recent Accounting Pronouncements
Accounting Standards Updates
Topic 606
On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” followed by a series of
related accounting standard updates (collectively referred to as “Topic 606”). Topic 606 is designed to create greater revenue
recognition and disclosure comparability in financial statements. The provisions of Topic 606 include a five-step process by
which an entity will determine revenue recognition, depicting the transfer of goods or services to customers in amounts
135
reflecting the payment to which an entity expects to be entitled in exchange for those goods or services. Topic 606 requires
certain disclosures about contracts with customers and provides more comprehensive guidance for transactions such as service
revenue, contract modifications, and multiple-element arrangements.
We are in the process of comparing our current revenue recognition policies to the requirements of Topic 606 for each of
our revenue categories. While we have not identified any material differences in the amount and timing of revenue recognition
for the categories we have reviewed to date, our evaluation is not complete and we have not concluded on the overall impacts
of adopting Topic 606. Topic 606 will require that our revenue recognition policy disclosure include further detail regarding
our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our
contracts with customers. Topic 606 will also require disclosure of significant changes in contract asset and contract liability
balances period to period and the amount of the transaction price allocated to performance obligations that are unsatisfied (or
partially unsatisfied) as of the end of the reporting period, as applicable. We will adopt Topic 606 effective January 1, 2018.
Topic 606 provides for adoption either retrospectively to each prior reporting period presented or as a cumulative-effect
adjustment as of the date of adoption. We plan to make a determination as to our method of adoption once we more fully
complete our evaluation of the impacts of the standard on our revenue recognition and we are better able to evaluate the cost-
benefit of each method.
ASU No. 2014-15
On August 27, 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to
Continue as a Going Concern.” This ASU provides guidance about management’s responsibility to evaluate whether there is
substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures if
management concludes that substantial doubt exists or that its plans alleviate substantial doubt that was raised. We adopted
ASU 2014-15 for the year ended December 31, 2016 with no impact to our financial statements.
ASU No. 2015-02
On February 18, 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810) - Amendments to the Consolidated
Analysis.” This ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether
they should consolidate certain legal entities. We adopted ASU No. 2015-02 effective January 1, 2016 with no impact to our
financial statements.
ASU No. 2015-11
On July 22, 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory.”
This ASU requires entities to subsequently measure inventory at the lower of cost and net realizable value, and defines net
realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of
completion, disposal, and transportation. ASU No. 2015-11 was effective January 1, 2017. We do not expect the effect of ASU
No. 2015-11 to have a material impact on our financial statements.
ASU No. 2016-02
On February 25, 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” This ASU requires that lessees will be
required to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all
leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users
information on the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 will be effective for us as
of January 1, 2019. We are currently reviewing the effect of ASU No. 2016-02.
ASU No. 2016-05
On March 10, 2016, the FASB issued ASU 2016-05, “Derivatives and Hedging (Topic 815): Effect of Derivative Contract
Novations on Existing Hedge Accounting Relationships.” This ASU clarifies that for the purposes of applying the guidance in
Topic 815, a change in the counterparty to a derivative instrument that has been designated as the hedging instrument in an
existing hedging relationship would not, in and of itself, be considered a termination of the derivative instrument. We adopted
ASU 2016-05 in the first quarter of 2016 with no material impact to our financial statements.
136
ASU No. 2016-09
On March 30, 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation (Topic 718).” This ASU was
issued as part of the FASB’s simplification initiative and affects all entities that issue share-based payment awards to their
employees. This ASU covers accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as
classification in the statement of cash flows. ASU No. 2016-09 was effective January 1, 2017. We do not expect the effect of
ASU No. 2016-09 to have a material impact on our financial statements.
ASU No. 2016-13
On June 16, 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of
Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in
place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. ASU No.
2016-13 will be effective for us as of January 1, 2020. We are currently reviewing the effect of ASU No. 2016-13.
ASU No. 2016-15
On August 26, 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts
and Cash Payments (Topic 230).” This ASU is intended to reduce the diversity in practice around how certain transactions are
classified within the statement of cash flows. We adopted ASU No. 2016-15 in the third quarter of 2016 with no material
impact to our financial statements.
ASU No. 2016-18
On November 17, 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a
consensus of the FASB Emerging Issues Task Force).” This ASU requires the statement of cash flows to explain the change
during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash
equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with
cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statement of cash
flows. ASU No. 2016-18 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to
our financial statements.
ASU No. 2017-04
On January 26, 2017, the FASB issued ASU 2017-04, “ASU 2017-04 Simplifying the Test for Goodwill Impairment (Topic
350)” to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which
requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s
carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us
as of January 1, 2020. We are currently reviewing the effect of this ASU to our financial statements.
19. Guarantee of Securities of Subsidiaries
KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of
KMI’s wholly owned domestic subsidiaries, are parties to a cross guarantee agreement whereby each party to the agreement
unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement.
Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary
issuer and other subsidiaries are all guarantors of each series of public debt. As a result of the cross guarantee agreement, a
holder of any of the guaranteed public debt securities issued by KMI or KMP are in the same position with respect to the net
assets, income and cash flows of KMI and the Subsidiary Issuer and Guarantors. The only amounts that are not available to the
holders of each of the guaranteed public debt securities to satisfy the repayment of such securities are the net assets, income
and cash flows of the Subsidiary Non-Guarantors.
In lieu of providing separate financial statements for subsidiary issuer and guarantor, we have included the accompanying
condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X. We have presented each of the
parent and subsidiary issuer in separate columns in this single set of condensed consolidating financial statements.
On September 30, 2016, Copano (previously reflected as a Subsidiary Issuer and Guarantor) repaid the $332 million
principal amount of its 7.125% senior notes due 2021. Copano continues to be a subsidiary guarantor under the cross guarantee
137
agreement mentioned above. For all periods presented, financial statement balances and activities for Copano are now
reflected within the Subsidiary Guarantor column, and the Subsidiary Issuer and Guarantor-Copano column has been
eliminated.
On September 1, 2016, we sold a 50% equity interest in SNG (see further details discussed in Note 3, “Acquisitions and
Divestitures”). Subsequent to the transaction, we deconsolidated SNG and now account for our equity interest in SNG as an
equity investment. Our wholly owned subsidiary which holds our interest in SNG is reflected within the Subsidiary Guarantors
column of these condensed consolidating financial statements.
Excluding fair value adjustments, as of December 31, 2016, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-
KMP, and Subsidiary Guarantors had $14,235 million, $19,485 million, and $4,191 million of Guaranteed Notes outstanding,
respectively. Included in the Subsidiary Guarantors debt balance as presented in the accompanying December 31,
2016 condensed consolidating balance sheets are approximately $169 million of capitalized lease debt that is not subject to the
cross guarantee agreement.
The accounts within the Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Guarantors and
Subsidiary Non-Guarantors are presented using the equity method of accounting for investments in subsidiaries, including
subsidiaries that are guarantors and non-guarantors, for purposes of these condensed consolidating financial statements only.
These intercompany investments and related activity eliminate in consolidation and are presented separately in the
accompanying condensed consolidating balance sheets and statements of income and cash flows.
A significant amount of each Issuers’ income and cash flow is generated by its respective subsidiaries. As a result, the
funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it
receives from its respective subsidiaries. We utilize a centralized cash pooling program among our majority-owned and
consolidated subsidiaries, including the Subsidiary Issuers and Guarantors and Subsidiary Non-Guarantors. The following
Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash
collection and payments made on behalf of our subsidiaries, as cash activities.
138
Condensed Consolidating Statements of Income and Comprehensive Income
for the Year Ended December 31, 2016
(In Millions)
Parent
Issuer and
Guarantor
34
$
Subsidiary
Issuer and
Guarantor -
KMP
Subsidiary
Guarantors
11,572
— $
Subsidiary
Non-
Guarantors
1,511
$
Consolidating
Adjustments
$
(59) $
Consolidated
KMI
Total Revenues
Operating Costs, Expenses and Other
Costs of sales
Depreciation, depletion and amortization
Other operating expenses
Total Operating Costs, Expenses and Other
Operating (Loss) Income
Other Income (Expense)
Earnings from consolidated subsidiaries
Losses from equity investments
Interest, net
Amortization of excess cost of equity investments and other,
net
Income Before Income Taxes
Income Tax Expense
Net Income
Net Income Attributable to Noncontrolling Interests
Net Income Attributable to Controlling Interests
Preferred Stock Dividends
Net Income Available to Common Stockholders
Net Income
Total other comprehensive (loss) income
Comprehensive income
Comprehensive income attributable to noncontrolling
interests
Comprehensive income attributable to controlling interests
$
$
$
$
$
$
—
18
725
743
(709)
2,948
—
(696)
—
1,543
(835)
708
—
708
(156)
552
708
(200)
508
—
—
—
(36)
(36)
36
2,826
—
90
—
2,952
3,245
1,872
2,390
7,507
4,065
245
(113)
(1,149)
(20)
3,028
(5)
(33)
2,947
—
2,947
—
2,947
2,947
(341)
2,606
—
$
$
2,995
—
2,995
—
2,995
2,995
(352)
2,643
—
$
$
266
319
746
1,331
180
59
—
(51)
5
193
(44)
149
—
149
—
149
149
55
204
—
$
$
(13)
—
(46)
(59)
—
(6,078)
—
—
—
—
(6,078)
(13)
(6,091)
—
(6,091) $
(6,078) $
638
(5,440)
(13)
(6,078)
1,638
13,058
3,498
2,209
3,779
9,486
3,572
—
(113)
(1,806)
(15)
(917)
721
(13)
708
(156)
552
721
(200)
521
(13)
508
508
$
2,606
$
2,643
$
204
$
(5,453) $
139
Condensed Consolidating Statements of Income and Comprehensive Income
for the Year Ended December 31, 2015
(In Millions)
Total Revenues
Operating Costs, Expenses and Other
Costs of sales
Depreciation, depletion and amortization
Other operating expenses
Total Operating Costs, Expenses and Other
Operating (Loss) Income
Other Income (Expense)
Earnings (losses) from consolidated subsidiaries
Earnings from equity investments
Interest, net
Amortization of excess cost of equity investments and other,
net
Income Before Income Taxes
Income Tax Expense
Net Income (Loss)
Net Loss Attributable to Noncontrolling Interests
Net Income (Loss) Attributable to Controlling Interests
Preferred Stock Dividends
Net Income (Loss) Available to Common Stockholders
Net Income (Loss)
Total other comprehensive loss
Comprehensive (loss) income
Comprehensive loss attributable to noncontrolling interests
Comprehensive (loss) income attributable to controlling
interests
Consolidating
Adjustments
$
(49) $
Consolidated
KMI
Parent
Issuer and
Guarantor
37
$
Subsidiary
Issuer and
Guarantor -
KMP
$
— $
Subsidiary
Guarantors
12,840
—
22
71
93
—
—
38
38
3,747
1,929
4,714
10,390
(56)
(38)
2,450
1,430
—
(686)
—
688
(435)
253
—
1,643
—
23
1
118
384
(1,345)
(17)
1,629
1,590
(4)
(6)
1,625
—
1,584
—
Subsidiary
Non-
Guarantors
1,575
$
367
358
759
1,484
91
(30)
—
(43)
8
26
(119)
(93)
—
1
—
(50)
(49)
—
(3,161)
—
—
—
(3,161)
—
(3,161)
45
$
253
(26) $
1,625
$
— $
1,584
$
— $
(93) $
— $
(3,116) $
— $
$
$
$
$
227
253
(444)
(191)
—
$
$
1,625
1,625
(460)
1,165
—
$
$
1,584
1,584
(325)
1,259
—
(93) $
(3,116) $
(93) $
(326)
(419)
(3,161) $
1,111
(2,050)
—
45
$
(191) $
1,165
$
1,259
$
(419) $
(2,005) $
(191)
140
14,403
4,115
2,309
5,532
11,956
2,447
—
384
(2,051)
(8)
772
(564)
208
45
253
(26)
227
208
(444)
(236)
45
Condensed Consolidating Statements of Income and Comprehensive Income
for the Year Ended December 31, 2014
(In Millions)
Parent
Issuer and
Guarantor
36
$
Subsidiary
Issuer and
Guarantor -
KMP
Subsidiary
Guarantors
14,575
— $
Subsidiary
Non-
Guarantors
1,621
$
Consolidating
Adjustments
$
(6) $
Consolidated
KMI
Total Revenues
Operating Costs, Expenses and Other
Costs of sales
Depreciation, depletion and amortization
Other operating expenses
Total Operating Costs, Expenses and Other
Operating (Loss) Income
Other Income (Expense)
Earnings from consolidated subsidiaries
Earnings (losses) from equity investments
Interest, net
Amortization of excess cost of equity investments and other,
net
Income Before Income Taxes
Income Tax Expense
Net Income
Net Income Attributable to Noncontrolling Interests
Net Income Attributable to Controlling Interests
Net Income
Total other comprehensive (loss) income
Comprehensive income
Comprehensive income attributable to noncontrolling
interests
Comprehensive income attributable to controlling interests
$
$
$
$
$
$
—
21
30
51
(15)
2,080
—
(513)
—
1,552
(278)
1,274
(248)
1,026
1,274
(24)
1,250
(273)
16,226
6,278
2,040
3,460
11,778
4,448
—
406
(1,798)
35
3,091
(648)
2,443
(1,417)
1,026
2,443
20
2,463
(1,486)
977
—
—
5
5
(5)
3,977
—
(111)
—
5,738
1,686
2,972
10,396
4,179
443
407
(1,084)
(13)
3,861
3,932
(7)
3,854
(211)
3,643
3,854
275
4,129
(203)
$
$
(71)
3,861
—
3,861
3,861
288
4,149
—
$
$
498
333
501
1,332
289
1,120
(1)
(90)
48
1,366
(292)
1,074
—
1,074
1,074
(168)
906
42
—
(48)
(6)
—
(7,620)
—
—
—
(7,620)
—
$
$
(7,620)
(958)
(8,578) $
(7,620) $
(351)
(7,971)
—
(1,010)
977
$
3,926
$
4,149
$
906
$
(8,981) $
141
Condensed Consolidating Balance Sheets as of December 31, 2016
(In Millions)
Parent
Issuer and
Guarantor
Subsidiary
Issuer and
Guarantor -
KMP
Subsidiary
Guarantors
Subsidiary
Non-
Guarantors
Consolidating
Adjustments
Consolidated
KMI
ASSETS
Cash and cash equivalents
Other current assets - affiliates
All other current assets
Property, plant and equipment, net
Investments
Investments in subsidiaries
Goodwill
Notes receivable from affiliates
Deferred income taxes
Other non-current assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt
Other current liabilities - affiliates
All other current liabilities
Long-term debt
Notes payable to affiliates
Deferred income taxes
Other long-term liabilities and deferred credits
Total liabilities
Stockholders’ equity
Total KMI equity
Noncontrolling interests
Total stockholders’ equity
Total liabilities and stockholders’ equity
9
13,207
1,935
30,795
6,236
4,307
5,167
1,132
—
4,455
67,243
687
4,197
2,016
4,095
20,520
681
821
33,017
34,226
—
34,226
67,243
$
$
$
$
205
655
205
7,668
124
4,028
3,174
412
—
107
16,578
123
553
422
674
1,167
1,614
517
5,070
$
(1) $
(21,600)
(3)
—
—
(64,663)
—
(23,668)
(2,295)
—
$
(112,230) $
$
— $
(21,600)
(4)
—
(23,668)
(2,295)
—
(47,567)
11,508
—
11,508
16,578
$
(65,034)
371
(64,663)
(112,230) $
684
—
2,545
38,705
7,027
—
22,152
—
4,352
4,840
80,305
2,696
—
3,228
37,354
—
—
2,225
45,503
34,431
371
34,802
80,305
$
$
$
$
471
5,739
269
242
665
26,907
13,789
516
6,647
72
55,317
1,286
3,551
432
13,308
1,533
—
776
20,886
34,431
—
34,431
55,317
$
— $
1,999
139
—
2
29,421
22
21,608
—
206
53,397
600
13,299
362
19,277
448
—
111
34,097
19,300
—
19,300
53,397
$
$
$
$
$
$
142
Condensed Consolidating Balance Sheets as of December 31, 2015
(In Millions)
Parent
Issuer and
Guarantor
Subsidiary
Issuer and
Guarantor -
KMP
Subsidiary
Guarantors
Subsidiary
Non-
Guarantors
Consolidating
Adjustments
Consolidated
KMI
ASSETS
Cash and cash equivalents
Other current assets - affiliates
All other current assets
Property, plant and equipment, net
Investments
Investments in subsidiaries
Goodwill
Notes receivable from affiliates
Deferred income taxes
Other non-current assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt
Other current liabilities - affiliates
All other current liabilities
Long-term debt
Notes payable to affiliates
Deferred income taxes
All other long-term liabilities and deferred credits
Total liabilities
Stockholders’ equity
Total KMI equity
Noncontrolling interests
Total stockholders’ equity
$
$
$
123
2,233
126
252
16
27,401
15,089
850
7,501
215
53,806
67
1,328
321
13,845
2,404
—
722
18,687
35,119
—
35,119
$
— $
$
$
$
$
1,600
119
—
2
28,038
22
21,319
—
307
51,407
500
8,682
458
20,053
448
—
193
30,334
21,073
—
21,073
$
$
$
12
9,410
2,161
33,032
5,906
3,493
5,508
2,092
—
4,951
66,565
132
3,210
1,992
7,825
20,462
596
909
35,126
31,439
—
31,439
142
688
195
7,263
116
3,320
3,171
358
—
107
15,360
122
711
527
683
1,305
1,582
406
5,336
10,024
—
10,024
$
(48) $
(13,931)
(6)
—
—
(62,252)
—
(24,619)
(2,178)
—
$
(103,034) $
$
— $
(13,931)
(54)
—
(24,619)
(2,178)
—
(40,782)
(62,536)
284
(62,252)
229
—
2,595
40,547
6,040
—
23,790
—
5,323
5,580
84,104
821
—
3,244
42,406
—
—
2,230
48,701
35,119
284
35,403
Total liabilities and stockholders’ equity
$
53,806
$
51,407
$
66,565
$
15,360
$
(103,034) $
84,104
143
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2016
(In Millions)
Subsidiary
Issuer and
Guarantor -
KMP
Parent
Issuer and
Guarantor
$
(3,989) $
Subsidiary
Guarantors
11,641
$
Subsidiary
Non-
Guarantors
885
$
Consolidating
Adjustments
$
(8,730) $
Consolidated
KMI
Net cash (used in) provided by operating activities
Cash flows from investing activities
Acquisitions of assets and investments, net of cash acquired
Capital expenditures
Proceeds from sale of equity interests in subsidiaries, net
Sales of property, plant and equipment, investments and other net assets, net of
removal costs
Contributions to investments
Distributions from equity investments in excess of cumulative earnings
Funding to affiliates
Other, net
Net cash used in investing activities
Cash flows from financing activities
Issuances of debt
Payments of debt
Debt issue costs
Cash dividends - common shares
Cash dividends - preferred shares
Funding from affiliates
Contributions from parents
Contributions from noncontrolling interests
Distributions to parents
Distributions to noncontrolling interests
Net cash provided by (used in) financing activities
(2)
(27)
—
6
(343)
2,417
(2,820)
—
(769)
8,255
(7,322)
(16)
(1,118)
(154)
5,461
—
—
—
—
5,106
4,980
—
—
—
—
—
298
(535)
(73)
(310)
—
(500)
—
—
—
1,116
—
—
(5,286)
—
(4,670)
(331)
(2,258)
1,401
326
(54)
190
(5,062)
39
(5,749)
374
(2,227)
(2)
—
—
1,959
117
—
(6,116)
—
(5,895)
Effect of exchange rate changes on cash and cash equivalents
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
—
348
123
471
$
$
—
—
—
— $
—
(3)
12
9
$
144
—
(597)
—
(2)
(11)
—
(727)
(10)
(1,347)
—
(11)
(1)
—
—
608
—
—
(73)
—
523
2
63
142
205
—
—
—
—
—
(2,674)
9,144
—
6,470
—
—
—
—
—
(9,144)
(117)
117
11,475
(24)
2,307
—
47
(48)
(1) $
$
4,787
(333)
(2,882)
1,401
330
(408)
231
—
(44)
(1,705)
8,629
(10,060)
(19)
(1,118)
(154)
—
—
117
—
(24)
(2,629)
2
455
229
684
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2015
(In Millions)
Subsidiary
Issuer and
Guarantor -
KMP
Parent
Issuer and
Guarantor
$
(4,218) $
Subsidiary
Guarantors
11,039
$
Subsidiary
Non-
Guarantors
347
$
Consolidating
Adjustments
$
(8,689) $
Consolidated
KMI
Net cash (used in) provided by operating activities
Cash flows from investing activities
Acquisitions of assets and investments
Capital expenditures
Sales of property, plant and equipment, investments and other net assets, net of
removal costs
Contributions to investments
Distributions from equity investments in excess of cumulative earnings
Investment in KMP
Funding to affiliates
Other, net
Net cash used in investing activities
Cash flows from financing activities
Issuances of debt
Payments of debt
Debt issue costs
Issuances of common shares
Issuance of mandatory convertible preferred stock
Cash dividends - common shares
Repurchases of shares and warrants
Merger Transactions costs
Funding from affiliates
Contributions from parents
Contributions from noncontrolling interests
Distributions to parents
Distributions to noncontrolling interests
Other, net
Net cash provided by financing activities
(1,843)
(10)
—
(21)
2,653
(159)
(3,204)
—
(2,584)
14,316
(14,048)
(24)
3,870
1,541
(4,224)
(12)
(2)
5,502
—
—
—
—
2
6,921
Effect of exchange rate changes on cash and cash equivalents
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
—
119
4
123
$
$
145
6,824
—
—
—
—
—
—
(8,388)
24
(8,364)
—
(675)
—
—
—
—
—
—
6,989
156
—
(4,944)
—
(1)
1,525
—
(15)
15
— $
(236)
(3,555)
39
(70)
143
—
(7,980)
16
(11,643)
—
(383)
—
—
—
—
—
—
7,112
3
—
(6,133)
—
—
599
—
(5)
17
12
$
—
(331)
—
(10)
—
—
(779)
58
(1,062)
—
(10)
—
—
—
—
—
—
748
16
—
(166)
—
—
588
(10)
(137)
279
142
—
—
—
5
(2,568)
159
20,351
—
17,947
—
—
—
—
—
—
—
—
(20,351)
(175)
11
11,243
(34)
—
(9,306)
—
(48)
—
(48) $
$
5,303
(2,079)
(3,896)
39
(96)
228
—
—
98
(5,706)
14,316
(15,116)
(24)
3,870
1,541
(4,224)
(12)
(2)
—
—
11
—
(34)
1
327
(10)
(86)
315
229
Condensed Consolidating Statements of Cash Flows for the Year Ended December 31, 2014
(In Millions)
Parent
Issuer and
Guarantor
1,419
$
Subsidiary
Issuer and
Guarantor -
KMP
$
3,810
Subsidiary
Guarantors
6,059
$
Subsidiary
Non-
Guarantors
641
$
Consolidating
Adjustments
$
(7,462) $
Consolidated
KMI
Net cash provided by operating activities
Cash flows from investing activities
Acquisitions of assets and investments
Capital expenditures
Sales of property, plant and equipment, investments, and other net assets, net
of removal costs
Contributions to investments
Distributions from equity investments in excess of cumulative earnings
Investment in KMP
Drop down assets to KMP
Funding to affiliates
Other, net
Net cash used in investing activities
Cash flows from financing activities
Issuances of debt
Payments of debt
Debt issue costs
Cash dividends - common shares
Repurchases of shares and warrants
Cash consideration of Merger Transactions
Merger Transactions costs
Funding from affiliates
Contributions from parents
Contributions from noncontrolling interests
Distributions to parents
Distributions to noncontrolling interests
Other, net
Net cash provided by financing activities
—
(1)
—
—
93
(550)
875
(1,949)
—
(1,532)
10,594
(5,479)
(74)
(1,760)
(192)
(3,937)
(74)
956
—
—
—
—
—
34
—
—
—
(189)
440
—
(875)
(6,644)
27
(7,241)
13,979
(12,171)
(15)
—
—
—
—
4,129
1,912
—
(4,475)
—
(1)
3,358
(1,370)
(2,911)
(9)
(389)
183
—
—
(3,826)
29
(8,293)
—
(142)
—
—
—
—
—
7,241
533
—
(5,398)
—
(2)
2,232
Effect of exchange rate changes on cash and cash equivalents
Net decrease in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
—
(79)
83
4
$
$
—
(73)
88
15
$
1
(1)
18
17
$
146
(18)
(705)
14
—
—
—
—
(784)
(60)
(1,553)
—
(9)
—
—
—
—
—
877
64
—
(138)
—
—
794
(12)
(130)
409
279
—
—
—
189
(534)
550
—
13,203
1
13,409
—
—
—
—
—
—
—
(13,203)
(2,509)
1,767
10,011
(2,013)
—
(5,947)
—
—
—
— $
$
4,467
(1,388)
(3,617)
5
(389)
182
—
—
—
(3)
(5,210)
24,573
(17,801)
(89)
(1,760)
(192)
(3,937)
(74)
—
—
1,767
—
(2,013)
(3)
471
(11)
(283)
598
315
Supplemental Selected Quarterly Financial Data (Unaudited)
2016
Revenues
Operating Income
Net Income (Loss)
Net Income (Loss) Attributable to
Kinder Morgan, Inc.
Net Income (Loss) Available to
Common Stockholders
Basic and Diluted Earnings (Loss) Per
Common Share
2015
Revenues
Operating Income (Loss)
Net Income (Loss)
Net Income (Loss) Attributable to
Kinder Morgan, Inc.
Net Income (Loss) Available to
Common Stockholders
Basic and Diluted Earnings (Loss) Per
Common Share
Quarters Ended
March 31
June 30
September 30
December 31
(In millions, except per share amounts)
$
3,195
$
3,144
$
3,330
$
3,389
816
314
315
276
0.12
940
375
372
333
0.15
882
(183)
(188)
(227)
(0.10)
$
3,597
$
3,463
$
3,707
$
1,078
419
429
429
0.20
892
342
333
333
0.15
721
183
186
186
0.08
934
215
209
170
0.08
3,636
(244)
(736)
(695)
(721)
(0.32)
Item 16. Form 10-K Summary.
Not Applicable.
147
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly authorized.
SIGNATURES
KINDER MORGAN, INC.
Registrant
By: /s/ Kimberly A. Dang
Kimberly A. Dang
Vice President and Chief Financial Officer
(principal financial and accounting officer)
Date: February 10, 2017
148
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons in the capacities and on the dates indicated.
Signature
Title
Date
/s/ KIMBERLY A. DANG
Kimberly A. Dang
/s/ STEVEN J. KEAN
Steven J. Kean
/s/ RICHARD D. KINDER
Richard D. Kinder
/s/ TED A. GARDNER
Ted A. Gardner
/s/ ANTHONY W. HALL, JR.
Anthony W. Hall, Jr.
/s/ GARY L. HULTQUIST
Gary L. Hultquist
/s/ RONALD L. KUEHN, JR.
Ronald L. Kuehn, Jr.
/s/ DEBORAH A. MACDONALD
Deborah A. Macdonald
/s/ MICHAEL C. MORGAN
Michael C. Morgan
/s/ ARTHUR C. REICHSTETTER
Arthur C. Reichstetter
/s/ FAYEZ SAROFIM
Fayez Sarofim
/s/ C. PARK SHAPER
C. Park Shaper
/s/ WILLIAM A. SMITH
William A. Smith
/s/ JOEL V. STAFF
Joel V. Staff
/s/ ROBERT F. VAGT
Robert F. Vagt
/s/ PERRY M. WAUGHTAL
Perry M. Waughtal
Vice President and Chief Financial
Officer (principal financial officer and
principal accounting officer); Director
February 10, 2017
President and Chief Executive Officer
(principal executive officer); Director
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
February 10, 2017
Executive Chairman
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
149
Exhibit 10.16
CROSS GUARANTEE AGREEMENT
This CROSS GUARANTEE AGREEMENT is dated as of November 26, 2014 (as amended, restated,
supplemented or otherwise modified from time to time, this “Agreement”), by each of the signatories listed
on the signature pages hereto and each of the other entities that becomes a party hereto pursuant to Section
19 (the “Guarantors” and individually, a “Guarantor”), for the benefit of the Guaranteed Parties (as defined
below).
W I T N E S S E T H:
WHEREAS, Kinder Morgan, Inc., a Delaware corporation (“KMI”), and certain of its direct and
indirect Subsidiaries have outstanding senior, unsecured Indebtedness and may from time to time issue
additional senior, unsecured Indebtedness;
WHEREAS, each Guarantor, other than KMI, is a direct or indirect Subsidiary of KMI;
WHEREAS, each Guarantor desires to provide the guarantee set forth herein with respect to the
Indebtedness of such Guarantors that constitutes the Guaranteed Obligations; and
WHEREAS, each Guarantor acknowledges that it will derive substantial direct and indirect benefit
from the making of the guarantees hereby;
NOW, THEREFORE, in consideration of the premises, the Guarantors hereby agree with each other
for the benefit of the Guaranteed Parties as follows:
1.
Defined Terms.
(a)
As used in this Agreement, the following terms have the meanings specified below:
“Agreement” has the meaning provided in the preamble hereto.
“Bankruptcy Code” means Title 11 of the United States Code, as now or hereafter in effect,
or any successor thereto.
“Capital Stock” means, with respect to any Person, any and all shares, interests, rights to
purchase, warrants, options, participations or other equivalents (however designated) of such Person’s equity,
including (i) all common stock and preferred stock, any limited or general partnership interest and any limited
liability company member interest, (ii) beneficial interests in trusts, and (iii) any other interest or participation
that confers upon a Person the right to receive a share of the profits and losses of, or distribution of assets
of, the issuing Person.
“CFC” means a Person that is a “controlled foreign corporation” within the meaning of
Section 957 of the Internal Revenue Code of 1986, as amended.
“Commodity Exchange Act” means the Commodity Exchange Act (7 U.S.C. § 1 et seq.),
as amended from time to time, and any successor statute.
“Consolidated Assets” means, at the date of any determination thereof, the total assets of
KMI and its Subsidiaries as set forth on a consolidated balance sheet of KMI and its Subsidiaries for their
most recently completed fiscal quarter, prepared in accordance with GAAP.
“Consolidated Tangible Assets” means, at the date of any determination thereof,
Consolidated Assets after deducting therefrom the value, net of any applicable reserves and accumulated
Exhibit 10.16
amortization, of all goodwill, trade names, trademarks, patents and other like intangible assets, all as set
forth, or on a pro forma basis would be set forth, on a consolidated balance sheet of KMI and its Subsidiaries
for their most recently completed fiscal quarter, prepared in accordance with GAAP.
“Domestic Subsidiary” means any Subsidiary of KMI organized under the laws of any
jurisdiction within the United States.
“Excluded Subsidiary” means (i) any Subsidiary that is not a Wholly-owned Domestic
Operating Subsidiary, (ii) any Domestic Subsidiary that is a Subsidiary of a CFC or any Domestic Subsidiary
(including a disregarded entity for U.S. federal income tax purposes) substantially all of whose assets (held
directly or through Subsidiaries) consist of Capital Stock of one or more CFCs or Indebtedness of such CFCs,
(iii) any Immaterial Subsidiary, (iv) any Subsidiary listed on Schedule III, (v) each of Calnev Pipe Line LLC,
SFPP, L.P., Kinder Morgan G.P., Inc. and EPEC Realty, Inc. and each of its Subsidiaries, (vi) any other
Subsidiary that is not a Guarantor under the Revolving Credit Agreement Guarantee, (vii) any not-for-profit
Subsidiary, (viii) any Subsidiary that is prohibited by a Requirement of Law from guaranteeing the Guaranteed
Obligations, and (ix) any Subsidiary acquired by KMI or its Subsidiaries after the date of this Agreement to
the extent, and so long as, the financing documentation governing any existing Indebtedness of such
Subsidiary that survives such acquisition prohibits such Subsidiary from guaranteeing the Guaranteed
Obligations; provided, that notwithstanding the foregoing, any Subsidiary that is party to the Revolving
Credit Agreement Guarantee or that Guarantees any senior notes or senior debt securities issued by KMI
(other than pursuant to this Agreement) shall not constitute an Excluded Subsidiary for so long as such
Guarantee is in effect.
“Excluded Swap Obligation” means, with respect to any Guarantor, any Swap Obligation
if, and to the extent that, all or a portion of the Guarantee of such Guarantor of such Swap Obligation (or
any Guarantee thereof) is or becomes illegal under the Commodity Exchange Act or any rule, regulation or
order of the Commodity Futures Trading Commission (or the application or official interpretation of any
thereof) by virtue of such Guarantor’s failure for any reason to constitute an “eligible contract participant”
as defined in the Commodity Exchange Act and the regulations thereunder at the time the Guarantee of such
Guarantor becomes effective with respect to such Swap Obligation. If a Swap Obligation arises under a
master agreement governing more than one swap, such exclusion shall apply only to the portion of such
Swap Obligation that is attributable to swaps for which such Guarantee is or becomes illegal.
“GAAP” means generally accepted accounting principles in the United States of America
from time to time, including as set forth in the opinions, statements and pronouncements of the Accounting
Principles Board of the American Institute of Certified Public Accountants and the Financial Accounting
Standards Board.
“Governmental Authority” means the government of the United States of America or any
other nation, or of any political subdivision thereof, whether state or local, and any agency, authority,
instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial,
taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra
national bodies such as the European Union or the European Central Bank).
“Guarantee” of or by any Person (the “guarantor”) means any obligation, contingent or
otherwise, of the guarantor guaranteeing or having the economic effect of guaranteeing any Indebtedness or
other obligation of any other Person (the “primary obligor”) in any manner, whether directly or indirectly,
and including any obligation of the guarantor, direct or indirect, (i) to purchase or pay (or advance or supply
funds for the purchase or payment of) such Indebtedness or other obligation or to purchase (or to advance
or supply funds for the purchase of) any security for the payment thereof, (ii) to purchase or lease property,
securities or services for the purpose of assuring the owner of such Indebtedness
2
Exhibit 10.16
or other obligation of the payment thereof, (iii) to maintain working capital, equity capital or any other
financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay
such Indebtedness or other obligation or (iv) as an account party in respect of any letter of credit or letter of
guaranty issued to support such Indebtedness or obligation; provided that the term Guarantee shall not include
endorsements for collection or deposit in the ordinary course of business.
“Guarantee Termination Date” has the meaning set forth in Section 2(d).
“Guaranteed Obligations” means the Indebtedness set forth on Schedule I hereto, as such
schedule may be amended from time to time in accordance with the terms of this Agreement; provided that
the term “Guaranteed Obligations” shall exclude any Excluded Swap Obligations.
“Guaranteed Parties” means, collectively, (i) in the case of Guaranteed Obligations that are
governed by trust indentures, the holders (as that term is defined in the applicable trust indenture) of such
Guaranteed Obligations, (ii) in the case of Guaranteed Obligations that are governed by loan agreements,
credit agreements, or similar agreements, the lenders providing such loans or credit, and (iii) in the case of
Guaranteed Obligations with respect to Hedging Agreements, the counterparties under such agreements.
“Guarantor” has the meaning provided in the preamble hereto. Schedule II hereto, as such
schedule may be amended from time to time in accordance with the terms of this Agreement, sets forth the
name of each Guarantor.
“Hedging Agreement” means a financial instrument, agreement or security which hedges
or is used to hedge or manage the risk associated with a change in interest rates, foreign currency exchange
rates or commodity prices (but excluding any purchase, swap, derivative contract or similar agreement
relating to power, electricity or any related commodity product).
“Immaterial Subsidiary” means any Subsidiary that is not a Material Subsidiary.
“Indebtedness” means, collectively, (i) any senior, unsecured obligation created or assumed
by any Person for borrowed money, including all obligations of such Person evidenced by bonds, debentures,
notes or similar instruments (other than surety, performance and guaranty bonds), and (ii) all payment
obligations of any Person with respect to obligations under Hedging Agreements.
“Investment Grade Rating” means a rating equal to or higher than Baa3 by Moody’s and
BBB- by S&P; provided, however, that if (i) either of Moody’s or S&P changes its rating system, such ratings
shall be the equivalent ratings after such changes or (ii) Moody’s or S&P shall not make a rating of a
Guaranteed Obligation publicly available, the references above to Moody’s or S&P or both of them, as the
case may be, shall be to a nationally recognized U.S. rating agency or agencies, as the case may be, selected
by KMI and the references to the ratings categories above shall be to the corresponding rating categories of
such rating agency or rating agencies, as the case may be.
“Issuer” means the issuer, borrower, or other applicable primary obligor of a Guaranteed
Obligation.
“KMI” has the meaning provided in the recitals hereto.
“Lien” means, with respect to any asset (i) any mortgage, deed of trust, lien, pledge,
hypothecation, encumbrance, charge or security interest in, on or of such asset, and (ii) the interest of a
vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any
financing lease having substantially the same economic effect as any of the foregoing) relating to such asset.
3
Exhibit 10.16
“Material Subsidiary” means, as at any date of determination, any Subsidiary of KMI whose
total tangible assets (for purposes of the below, when combined with the tangible assets of such Subsidiary’s
Subsidiaries, after eliminating intercompany obligations) as at such date of determination are greater than
or equal to 5% of Consolidated Tangible Assets as of the last day of the fiscal quarter most recently ended
for which financial statements of KMI have been filed with the SEC.
“Moody’s” means Moody’s Investors Service, Inc. and its successors.
“Operating Subsidiary” means any operating company that is a Subsidiary of KMI.
“Person” means any natural person, corporation, limited liability company, trust, joint
venture, association, company, partnership, Governmental Authority or other entity.
“Qualified ECP Guarantor” means, in respect of any Swap Obligation, each Guarantor that
has total assets exceeding $10,000,000 at the time the relevant Guarantee becomes effective with respect to
such Swap Obligation or such other person as constitutes an “eligible contract participant” under the
Commodity Exchange Act or any regulations promulgated thereunder and can cause another person to qualify
as an “eligible contract participant” at such time by entering into a keepwell under Section 1a(18)(A)(v)(II)
of the Commodity Exchange Act.
“Rating Agencies” means Moody’s and S&P; provided that, if at the relevant time neither
Moody’s nor S&P shall be rating the relevant Guaranteed Obligation, then “Rating Agencies” shall mean
another nationally recognized rating service that rates such Guaranteed Obligation.
“Rating Date” means the date immediately prior to the earlier of (i) the occurrence of a
Release Event and (ii) public notice of the intention to effect a Release Event.
“Rating Decline” means, with respect to a Guaranteed Obligation, the occurrence of the
following on, or within 90 days after, the date of the occurrence of a Release Event or of public notice of
the intention to effect a Release Event (which period may be extended so long as the rating of such Guaranteed
Obligation is under publicly announced consideration for possible downgrade by either of the Rating
Agencies): (i) in the event such Guaranteed Obligation is assigned an Investment Grade Rating by both
Rating Agencies on the Rating Date, the rating of such Guaranteed Obligation by one or both of the Rating
Agencies shall be below an Investment Grade Rating; or (ii) in the event such Guaranteed Obligation is rated
below an Investment Grade Rating by either of the Rating Agencies on the Rating Date, any such below-
Investment Grade Rating of such Guaranteed Obligation shall be decreased by one or more gradations
(including gradations within rating categories as well as between rating categories).
“Release Event” has the meaning set forth in Section 6(b).
“Requirement of Law” means any law, statute, code, ordinance, order, determination, rule,
regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other
directive or requirement (whether or not having the force of law), including environmental laws, energy
regulations and occupational, safety and health standards or controls, of any Governmental Authority.
4
Exhibit 10.16
“Revolving Credit Agreement” means the Revolving Credit Agreement, dated as of
September 19, 2014, among KMI, the lenders party thereto and Barclays Bank PLC, as administrative agent,
as such credit agreement may be amended, modified, supplemented or restated from time to time, or refunded,
refinanced, restructured, replaced, renewed, repaid or extended from time to time (whether with the original
agents and lenders or other agents or lenders or trustee or otherwise, and whether provided under the original
credit agreement or other credit agreements or note indentures or otherwise), including, without limitation,
increasing the amount of available borrowings or other Indebtedness thereunder.
“Revolving Credit Agreement Guarantee” means the Guarantee Agreement, dated as of
November 26, 2014, made by the Subsidiaries of KMI party thereto in favor of Barclays Bank PLC, as
administrative agent, for the benefit of the lenders and the issuing banks under the Revolving Credit
Agreement, as such guarantee agreement may be amended, modified, supplemented or restated from time
to time, and as it may be replaced or renewed from time to time in connection with any amendment,
modification, supplement, restatement, refunding, refinancing, restructuring, replacement, renewal,
repayment, or extension of any Revolving Credit Agreement from time to time.
“S&P” means Standard & Poor’s Rating Services, a division of The McGraw-Hill
Companies, Inc., and its successors.
“SEC” means the United States Securities and Exchange Commission.
“Subsidiary” means, with respect to any Person (the “parent”) at any date, any corporation,
limited liability company, partnership, association or other entity the accounts of which would be consolidated
with those of the parent in the parent’s consolidated financial statements if such financial statements were
prepared in accordance with GAAP as of such date, as well as any other corporation, limited liability company,
partnership, association or other entity (a) of which securities or other ownership interests representing more
than 50% of the equity or more than 50% of the ordinary voting power or, in the case of a partnership, more
than 50% of the general partner interests are, as of such date, owned, controlled or held, or (b) that is, as of
such date, otherwise controlled, by the parent or one or more Subsidiaries of the parent or by the parent and
one or more Subsidiaries of the parent. Unless the context otherwise clearly requires, references in this
Agreement to a “Subsidiary” or the “Subsidiaries” refer to a Subsidiary or the Subsidiaries of KMI.
Notwithstanding the foregoing, Plantation Pipe Line Company, a Delaware and Virginia corporation, shall
not be a Subsidiary of KMI until such time as its assets and liabilities, profit or loss and cash flow are required
under GAAP to be consolidated with those of KMI.
“Swap Obligation” means, with respect to any Guarantor, any obligation to pay or perform
under any agreement, contract or transaction that constitutes a “swap” within the meaning of Section 1a(47)
of the Commodity Exchange Act.
“Wholly-owned Domestic Operating Subsidiary” means any Wholly-owned Subsidiary that
constitutes (i) a Domestic Subsidiary and (ii) an Operating Subsidiary.
“Wholly-owned Subsidiary” means a Subsidiary of which all issued and outstanding Capital
Stock (excluding in the case of a corporation, directors’ qualifying shares) is directly or indirectly owned by
KMI.
(b)
The words “hereof”, “herein” and “hereunder” and words of similar import when
used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this
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Exhibit 10.16
Agreement, and Section references are to Sections of this Agreement unless otherwise specified. The words
“include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”.
(c)
The meanings given to terms defined herein shall be equally applicable to both the
singular and plural forms of such terms.
2.
Guarantee.
(a)
Subject to the provisions of Section 2(b), each of the Guarantors hereby, jointly and
severally, unconditionally and irrevocably, guarantees, as primary obligor and not merely as surety, for the
benefit of the Guaranteed Parties, the prompt and complete payment when due (whether at the stated maturity,
by acceleration or otherwise) of the Guaranteed Obligations; provided that each Guarantor shall be released
from its respective guarantee obligations under this Agreement as provided in Section 6(b). Upon the failure
of an Issuer to punctually pay any Guaranteed Obligation, each Guarantor shall, upon written demand by
the applicable Guaranteed Party to such Guarantor, pay or cause to be paid such amounts.
(b)
Anything herein to the contrary notwithstanding, the maximum liability of each
Guarantor hereunder shall in no event exceed the amount that can be guaranteed by such Guarantor under
the Bankruptcy Code or any applicable laws relating to fraudulent conveyances, fraudulent transfers or the
insolvency of debtors after giving full effect to the liability under this Agreement and its related contribution
rights set forth in this Section 2, but before taking into account any liabilities under any other Guarantees.
(c)
Each Guarantor agrees that the Guaranteed Obligations may at any time and from
time to time exceed the amount of the liability of such Guarantor hereunder (as a result of the limitations set
forth in Section 2(b) or elsewhere in this Agreement) without impairing this Agreement or affecting the rights
and remedies of any Guaranteed Party hereunder.
(d)
No payment or payments made by any Issuer, any of the Guarantors, any other
guarantor or any other Person or received or collected by any Guaranteed Party from any Issuer, any of the
Guarantors, any other guarantor or any other Person by virtue of any action or proceeding or any set-off or
appropriation or application at any time or from time to time in reduction of or in payment of any Guaranteed
Obligation shall be deemed to modify, reduce, release or otherwise affect the liability of any Guarantor
hereunder, which shall, notwithstanding any such payment or payments, other than payments made by such
Guarantor in respect of such Guaranteed Obligation or payments received or collected from such Guarantor
in respect of such Guaranteed Obligation, remain liable for the Guaranteed Obligations up to the maximum
liability of such Guarantor hereunder until all Guaranteed Obligations (other than any contingent indemnity
obligations not then due and any letters of credit that remain outstanding which have been fully cash
collateralized or otherwise back-stopped to the reasonable satisfaction of the applicable issuing bank) shall
have been discharged by payment in full or shall have been deemed paid and discharged by defeasance
pursuant to the terms of the instruments governing such Guaranteed Obligations (the “Guarantee Termination
Date”).
(e)
If and to the extent required in order for the obligations of any Guarantor hereunder
to be enforceable under applicable federal, state and other laws relating to the insolvency of debtors, the
maximum liability of such Guarantor hereunder shall be limited to the greatest amount which can lawfully
be guaranteed by such Guarantor under such laws, after giving effect to any rights of contribution,
reimbursement and subrogation arising hereunder. Each Guarantor acknowledges and agrees
6
Exhibit 10.16
that, to the extent not prohibited by applicable law, (i) such Guarantor (as opposed to its creditors,
representatives of creditors or bankruptcy trustee, including such Guarantor in its capacity as debtor in
possession exercising any powers of a bankruptcy trustee) has no personal right under such laws to reduce,
or request any judicial relief that has the effect of reducing, the amount of its liability under this Agreement,
(ii) such Guarantor (as opposed to its creditors, representatives of creditors or bankruptcy trustee, including
such Guarantor in its capacity as debtor in possession exercising any powers of a bankruptcy trustee) has no
personal right to enforce the limitation set forth in this Section 2(e) or to reduce, or request judicial relief
reducing, the amount of its liability under this Agreement, and (iii) the limitation set forth in this Section 2
(e) may be enforced only to the extent required under such laws in order for the obligations of such Guarantor
under this Agreement to be enforceable under such laws and only by or for the benefit of a creditor,
representative of creditors or bankruptcy trustee of such Guarantor or other Person entitled, under such laws,
to enforce the provisions hereof.
3.
Right of Contribution. Each Guarantor hereby agrees that to the extent that a Guarantor
shall have paid more than its proportionate share of any payment made hereunder (including by way of set-
off rights being exercised against it), such Guarantor shall be entitled to seek and receive contribution from
and against any other Guarantor hereunder who has not paid its proportionate share of such payment as set
forth in this Section 3. To the extent that any Guarantor shall be required hereunder to pay any portion of
any Guaranteed Obligation guaranteed hereunder exceeding the greater of (a) the amount of the value actually
received by such Guarantor and its Subsidiaries from such Guaranteed Obligation and (b) the amount such
Guarantor would otherwise have paid if such Guarantor had paid the aggregate amount of such Guaranteed
Obligation guaranteed hereunder (excluding the amount thereof repaid by the Issuer of such Guaranteed
Obligation) in the same proportion as such Guarantor’s net worth on the date enforcement is sought hereunder
bears to the aggregate net worth of all the Guarantors on such date, then such Guarantor shall be reimbursed
by such other Guarantors for the amount of such excess, pro rata, based on the respective net worth of such
other Guarantors on such date; provided that any Guarantor’s right of reimbursement shall be subject to the
terms and conditions of Section 5 hereof. For purposes of determining the net worth of any Guarantor in
connection with the foregoing, all Guarantees of such Guarantor other than pursuant to this Agreement will
be deemed to be enforceable and payable after its obligations pursuant to this Agreement. The provisions
of this Section 3 shall in no respect limit the obligations and liabilities of any Guarantor to the Guaranteed
Parties, and each Guarantor shall remain liable to the Guaranteed Parties for the full amount guaranteed by
such Guarantor hereunder.
4.
No Right of Set-off. No Guaranteed Party shall have, as a result of this Agreement, any
right of set-off against any amount owing by such Guaranteed Party to or for the credit or the account of a
Guarantor.
5.
No Subrogation. Notwithstanding any payment or payments made by any of the Guarantors
hereunder, no Guarantor shall be entitled to be subrogated to any of the rights (or if subrogated by operation
of law, such Guarantor hereby waives such rights to the extent permitted by applicable law) of any Guaranteed
Party against any Issuer or any other Guarantor or any collateral security or guarantee or right of offset held
by any Guaranteed Party for the payment of any Guaranteed Obligation, nor shall any Guarantor seek or be
entitled to seek any contribution or reimbursement from any Issuer or any other Guarantor in respect of
payments made by such Guarantor hereunder, until the Guarantee Termination Date. If any amount shall
be paid to any Guarantor on account of such subrogation, contribution or reimbursement rights at any time
prior to the Guarantee Termination Date, such amount shall be held by such Guarantor in trust for the
applicable Guaranteed Parties, segregated from other funds of such Guarantor, and shall, forthwith upon
receipt by such Guarantor, be turned over to the applicable Guaranteed Parties in the exact form received
by such Guarantor (duly indorsed by such
7
Exhibit 10.16
Guarantor to the applicable Guaranteed Parties if required), to be applied against the applicable Guaranteed
Obligation, whether due or to become due.
6.
Amendments, etc. with Respect to the Guaranteed Obligations; Waiver of Rights; Release.
(a)
Each Guarantor shall remain obligated hereunder notwithstanding that, without any
reservation of rights against any Guarantor and without notice to or further assent by any Guarantor, (i) any
demand for payment of any Guaranteed Obligation made by any Guaranteed Party may be rescinded by such
party and any Guaranteed Obligation continued, (ii) a Guaranteed Obligation, or the liability of any other
party upon or for any part thereof, or any collateral security or guarantee therefor or right of offset with
respect thereto, may, from time to time, in whole or in part, be renewed, extended, amended, modified,
accelerated, compromised, waived, allowed to lapse, surrendered or released by any Guaranteed Party,
(iii) the instruments governing any Guaranteed Obligation may be amended, modified, supplemented or
terminated, in whole or in part, and (iv) any collateral security, guarantee or right of offset at any time held
by any Guaranteed Party for the payment of any Guaranteed Obligation may be sold, exchanged, waived,
allowed to lapse, surrendered or released. No Guaranteed Party shall have any obligation to protect, secure,
perfect or insure any Lien at any time held by it as security for the Guaranteed Obligations or for this
Agreement or any property subject thereto. When making any demand hereunder against any Guarantor, a
Guaranteed Party may, but shall be under no obligation to, make a similar demand on the Issuer of the
applicable Guaranteed Obligation or any other Guarantor or any other person, and any failure by a Guaranteed
Party to make any such demand or to collect any payments from such Issuer or any other Guarantor or any
other person or any release of such Issuer or any other Guarantor or any other person shall not relieve any
Guarantor in respect of which a demand or collection is not made or any Guarantor not so released of its
several obligations or liabilities hereunder, and shall not impair or affect the rights and remedies, express or
implied, or as a matter of law, of any Guaranteed Party against any Guarantor. For the purposes hereof
“demand” shall include the commencement and continuance of any legal proceedings.
(b)
A Guarantor shall be automatically released from its guarantee hereunder upon
release of such Guarantor from the Revolving Credit Agreement Guarantee, including upon consummation
of any transaction resulting in such Guarantor ceasing to constitute a Subsidiary or upon any Guarantor
becoming an Excluded Subsidiary (such transaction or event, a “Release Event”).
(c)
Upon the occurrence of a Release Event, each Guaranteed Obligation for which
such released Guarantor was the Issuer shall be automatically released from the provisions of this Agreement
and shall cease to constitute a Guaranteed Obligation hereunder; provided that in the case of any Guaranteed
Obligation that has been assigned an Investment Grade Rating by the Rating Agencies, such Guaranteed
Obligation shall be so released, effective as of the 91st day after the occurrence of the Release Event, if and
only if a Rating Decline with respect to such Guaranteed Obligation does not occur.
7.
Guarantee Absolute and Unconditional.
(a)
Each Guarantor waives any and all notice of the creation, contraction, incurrence,
renewal, extension, amendment, waiver or accrual of any of the Guaranteed Obligations, and notice of or
proof of reliance by any Guaranteed Party upon this Agreement or acceptance of this Agreement. To the
fullest extent permitted by applicable law, each Guarantor waives diligence, promptness, presentment, protest
and notice of protest, demand for payment or performance, notice of default or nonpayment, notice of
acceptance and any other notice in respect of the Guaranteed Obligations or any part of them, and any defense
arising by reason of any disability or other defense of any Issuer or any of the Guarantors
8
Exhibit 10.16
with respect to the Guaranteed Obligations. Each Guarantor understands and agrees that this Agreement
shall be construed as a continuing, absolute and unconditional guarantee of payment without regard to (i) the
validity, regularity or enforceability of any of the Guaranteed Obligations, the indenture, loan agreement,
note or other instrument evidencing or governing any of the Guaranteed Obligations or any collateral security
therefor or guarantee or right of offset with respect thereto at any time or from time to time held by any
Guaranteed Party, (ii) any defense, set-off or counterclaim (other than a defense of payment or performance)
that may at any time be available to or be asserted by any Issuer against any Guaranteed Party or (iii) any
other circumstance whatsoever (with or without notice to or knowledge of any Issuer or such Guarantor)
that constitutes, or might be construed to constitute, an equitable or legal discharge of any Issuer for any of
the Guaranteed Obligations, or of such Guarantor under this Agreement, in bankruptcy or in any other
instance. When pursuing its rights and remedies hereunder against any Guarantor, any Guaranteed Party
may, but shall be under no obligation to, pursue such rights and remedies as it may have against the Issuer
or any other Person or against any collateral security or guarantee for the Guaranteed Obligations or any
right of offset with respect thereto, and any failure by any Guaranteed Party to pursue such other rights or
remedies or to collect any payments from the Issuer or any such other Person or to realize upon any such
collateral security or guarantee or to exercise any such right of offset, or any release of the Issuer or any such
other Person or any such collateral security, guarantee or right of offset, shall not relieve such Guarantor of
any liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or
available as a matter of law, of the other Guaranteed Parties against such Guarantor.
(b)
This Agreement shall remain in full force and effect and be binding in accordance
with and to the extent of its terms upon each Guarantor and the successors and assigns thereof and shall
inure to the benefit of the Guaranteed Parties and their respective successors, indorsees, transferees and
assigns until the Guarantee Termination Date.
8.
Reinstatement. This Agreement shall continue to be effective, or be reinstated, as the case
may be, if at any time payment, or any part thereof, of any of the Guaranteed Obligations is rescinded or
must otherwise be restored or returned by any Guaranteed Party upon the insolvency, bankruptcy, dissolution,
liquidation or reorganization of any Issuer or any Guarantor, or upon or as a result of the appointment of a
receiver, intervenor or conservator of, or trustee or similar officer for, any Issuer or any Guarantor or any
substantial part of its property, or otherwise, all as though such payments had not been made.
9.
Payments. Each Guarantor hereby guarantees that payments hereunder will be paid to the
applicable Guaranteed Parties without set-off or counterclaim in dollars.
10.
Representations and Warranties. Each Guarantor hereby represents and warrants to each
Guaranteed Party that the following representations and warranties are true and correct in all material respects
as of the date of this Agreement or as of the date such Guarantor became a party to this Agreement, as
applicable:
(a)
such Guarantor (i) is a corporation, partnership or limited liability company duly
organized or formed, validly existing and in good standing under the laws of the state of its incorporation,
organization or formation, (ii) has all requisite corporate, partnership, limited liability company or other
power and all material governmental licenses, authorizations, consents and approvals required to carry on
its business as now conducted and (iii) is duly qualified to do business and is in good standing in every
jurisdiction in which the failure to be so qualified would have a material adverse effect on its ability to
perform its obligations under this Agreement;
9
Exhibit 10.16
(b)
such Guarantor has all requisite corporate (or other organizational) power and
authority to execute and deliver and to perform its obligations under this Agreement, and all such actions
have been duly authorized by all necessary proceedings on its behalf;
(c)
this Agreement has been duly and validly executed and delivered by or on behalf
of such Guarantor and constitutes the valid and legally binding agreement of such Guarantor, enforceable
against such Guarantor in accordance with its terms, except (i) as may be limited by bankruptcy, insolvency,
reorganization, moratorium, fraudulent transfer, fraudulent conveyance or other similar laws relating to or
affecting the enforcement of creditors’ rights generally, and by general principles of equity (including
principles of good faith, reasonableness, materiality and fair dealing) which may, among other things, limit
the right to obtain equitable remedies (regardless of whether considered in a proceeding in equity or at law)
and (ii) as to the enforceability of provisions for indemnification for violation of applicable securities laws,
limitations thereon arising as a matter of law or public policy;
(d)
no authorization, consent, approval, license or exemption of or registration,
declaration or filing with any Governmental Authority is necessary for the valid execution and delivery of,
or the performance by such Guarantor of its obligations hereunder, except those that have been obtained and
such matters relating to performance as would ordinarily be done in the ordinary course of business after
the date of this Agreement or as of the date such Guarantor became a party to this Agreement, as applicable;
and
(e)
neither the execution and delivery of, nor the performance by such Guarantor of its
obligations under, this Agreement will (i) breach or violate any applicable Requirement of Law, (ii) result
in any breach or violation of any of the terms, covenants, conditions or provisions of, or constitute a default
under, or result in the creation or imposition of (or the obligation to create or impose) any Lien upon any of
its property or assets (other than Liens created or contemplated by this Agreement) pursuant to the terms of,
any indenture, mortgage, deed of trust, agreement or other instrument to which it or any of its Subsidiaries
is party or by which any of its properties or assets, or those of any of its Subsidiaries is bound or to which
it is subject, except for breaches, violations and defaults under clauses (i) and (ii) that neither individually
nor in the aggregate could reasonably be expected to result in a material adverse effect on its ability to perform
its obligations under this Agreement, or (iii) violate any provision of the organizational documents of such
Guarantor.
11.
Rights of Guaranteed Parties. Each Guarantor acknowledges and agrees that any changes
in the identity of the Persons from time to time comprising the Guaranteed Parties gives rise to an equivalent
change in the Guaranteed Parties, without any further act. Upon such an occurrence, the persons then
comprising the Guaranteed Parties are vested with the rights, remedies and discretions of the Guaranteed
Parties under this Agreement.
12.
Notices.
(a)
All notices, requests, demands and other communications to any Guarantor pursuant
hereto shall be in writing and mailed, telecopied or delivered to such Guarantor in care of KMI, 1001 Louisiana
Street, Suite 1000, Houston, Texas 77002, Attention: Treasurer, Telecopy: (713) 445-8302.
(b)
KMI will provide a copy of this Agreement, including the most recently amended
schedules and supplements hereto, to any Guaranteed Party upon written request to the address set forth in
Section 12(a); provided, however, that KMI’s obligations under this Section 12(b) shall be deemed satisfied
if KMI has filed a copy of this Agreement, including the most recently amended schedules and
10
Exhibit 10.16
supplements hereto, with the SEC within three months preceding the date on which KMI receives such
written request.
13.
Counterparts. This Agreement may be executed by one or more of the parties to this
Agreement on any number of separate counterparts (including by facsimile or other electronic transmission),
and all of said counterparts taken together shall be deemed to constitute one and the same instrument. A set
of the copies of this Agreement signed by all the parties shall be lodged with KMI.
14.
Severability. Any provision of this Agreement that is prohibited or unenforceable in any
jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability
without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any
jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. The parties
hereto shall endeavor in good-faith negotiations to replace the invalid, illegal or unenforceable provisions
with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal
or unenforceable provisions.
15.
Integration. This Agreement represents the agreement of each Guarantor with respect to
the subject matter hereof, and there are no promises, undertakings, representations or warranties by any
Guaranteed Party relative to the subject matter hereof not expressly set forth or referred to herein.
16.
Amendments; No Waiver; Cumulative Remedies.
(a)
None of the terms or provisions of this Agreement may be waived, amended,
supplemented or otherwise modified except by a written instrument executed by the affected Guarantors and
KMI.
(b)
The Guarantors may amend or supplement this Agreement by a written instrument
executed by all Guarantors:
(i)
to cure any ambiguity, defect or inconsistency;
(ii)
to reflect a change in the Guarantors or the Guaranteed Obligations made in
accordance with this Agreement;
(iii)
to make any change that would provide any additional rights or benefits to the
Guaranteed Parties or that would not adversely affect the legal rights hereunder of any
Guaranteed Party in any material respect; or
(iv)
to conform this Agreement to any change made to the Revolving Credit
Agreement or to the Revolving Credit Agreement Guarantee.
Except as set forth in this clause (b) or otherwise provided herein, the Guarantors may not amend, supplement
or otherwise modify this Agreement prior to the Guarantee Termination Date without the prior written consent
of the holders of the majority of the outstanding principal amount of the Guaranteed Obligations (excluding
obligations with respect to Hedging Agreements). Notwithstanding the foregoing, in the case of an
amendment that would reasonably be expected to adversely, materially and disproportionately affect
Guaranteed Parties with Guaranteed Obligations existing under Hedging Agreements relative to the other
Guaranteed Parties, the foregoing exclusion of obligations with respect to Hedging Agreements shall not
apply, and the outstanding principal amount attributable to each such Guaranteed Party’s Guaranteed
Obligations shall be deemed to be equal to the termination payment that
11
Exhibit 10.16
would be due to such Guaranteed Party as if the valuation date were an “Early Termination Date” under and
calculated in accordance with each applicable Hedging Agreement.
(c)
No Guaranteed Party shall by any act, delay, indulgence, omission or otherwise be
deemed to have waived any right or remedy hereunder or to have acquiesced in any breach of any of the
terms and conditions hereof. No failure to exercise, nor any delay in exercising, on the part of any Guaranteed
Party, any right, power or privilege hereunder shall operate as a waiver thereof. No single or partial exercise
of any right, power or privilege hereunder shall preclude any other or further exercise thereof or the exercise
of any other right, power or privilege. A waiver by a Guaranteed Party of any right or remedy hereunder on
any one occasion shall not be construed as a bar to any right or remedy that such Guaranteed Party would
otherwise have on any future occasion.
(d)
The rights, remedies, powers and privileges herein provided are cumulative, may
be exercised singly or concurrently and are not exclusive of any other rights or remedies provided by law.
17.
Section Headings. The Section headings used in this Agreement are for convenience of
reference only and are not to affect the construction hereof or be taken into consideration in the interpretation
hereof.
18.
Successors and Assigns. This Agreement shall be binding upon the successors and assigns
of each Guarantor and shall inure to the benefit of the Guaranteed Parties and their respective successors
and permitted assigns, except that no Guarantor may assign, transfer or delegate any of its rights or obligations
under this Agreement except pursuant to a transaction permitted by the Revolving Credit Agreement and in
connection with a corresponding assignment under the Revolving Credit Agreement Guarantee.
19.
Additional Guarantors.
(a)
KMI shall cause each Subsidiary (other than any Excluded Subsidiary) formed or
otherwise purchased or acquired after the date of this Agreement (including each Subsidiary that ceases to
constitute an Excluded Subsidiary after the date of this Agreement) to execute a supplement to this Agreement
and become a Guarantor within 45 days of the occurrence of the applicable event specified in this Section
19(a).
(b)
Each Subsidiary of KMI that becomes, at the request of KMI, or that is required
pursuant to Section 19(a) to become, a party to this Agreement shall become a Guarantor, with the same
force and effect as if originally named as a Guarantor herein, for all purposes of this Agreement upon execution
and delivery by such Subsidiary of a written supplement substantially in the form of Annex A hereto. The
execution and delivery of any instrument adding an additional Guarantor as a party to this Agreement shall
not require the consent of any other Guarantor hereunder. The rights and obligations of each Guarantor
hereunder shall remain in full force and effect notwithstanding the addition of any new Guarantor as a party
to this Agreement.
20.
Additional Guaranteed Obligations. Any Indebtedness issued by a Guarantor or for which
a Guarantor otherwise becomes obligated after the date of this Agreement shall become a Guaranteed
Obligation upon the execution by all Guarantors of a notation of guarantee substantially in the form of Annex
B hereto, which shall be affixed to the instrument or instruments evidencing such Indebtedness. Each such
notation of guarantee shall be signed on behalf of each Guarantor by a duly authorized officer prior to the
authentication or issuance of such Indebtedness.
12
Exhibit 10.16
21.
GOVERNING LAW.
THIS AGREEMENT AND THE RIGHTS AND
OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND
CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF
NEW YORK.
22.
Keepwell. Each Qualified ECP Guarantor hereby jointly and severally absolutely,
unconditionally and irrevocably undertakes to provide such funds or other support as may be needed from
time to time by each other Guarantor to honor all of its obligations under this Agreement in respect of Swap
Obligations (provided, however, that each Qualified ECP Guarantor shall only be liable under this Section
22 for the maximum amount of such liability that can be hereby incurred without rendering its obligations
under this Section 22, or otherwise under this Agreement, voidable under applicable law relating to fraudulent
conveyance or fraudulent transfer, and not for any greater amount). The obligations of each Qualified ECP
Guarantor under this Section shall remain in full force and effect until the Guarantee Termination Date. Each
Qualified ECP Guarantor intends that this Section 22 constitute, and this Section 22 shall be deemed to
constitute, a “keepwell, support, or other agreement” for the benefit of each other Guarantor for all purposes
of Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.
[Signature pages follow]
13
IN WITNESS WHEREOF, each of the undersigned has caused this Agreement to be duly executed and
delivered by its duly authorized officer or other representative as of the day and year first above written.
Exhibit 10.16
KINDER MORGAN, INC.
By:
/s/ Anthony B. Ashley
Name: Anthony B. Ashley
Title: Treasurer
AGNES B CRANE, LLC
AMERICAN PETROLEUM TANKERS II LLC
AMERICAN PETROLEUM TANKERS III LLC
AMERICAN PETROLEUM TANKERS IV LLC
AMERICAN PETROLEUM TANKERS LLC
AMERICAN PETROLEUM TANKERS PARENT LLC
AMERICAN PETROLEUM TANKERS V LLC
AMERICAN PETROLEUM TANKERS VI LLC
AMERICAN PETROLEUM TANKERS VII LLC
APT FLORIDA LLC
APT INTERMEDIATE HOLDCO LLC
APT NEW INTERMEDIATE HOLDCO LLC
APT PENNSYLVANIA LLC
APT SUNSHINE STATE LLC
AUDREY TUG LLC
BEAR CREEK STORAGE COMPANY, L.L.C.
BETTY LOU LLC
CAMINO REAL GATHERING COMPANY, L.L.C.
CANTERA GAS COMPANY LLC
CDE PIPELINE LLC
CENTRAL FLORIDA PIPELINE LLC
CHEYENNE PLAINS GAS PIPELINE COMPANY, L.L.C.
CIG GAS STORAGE COMPANY LLC
CIG PIPELINE SERVICES COMPANY, L.L.C.
CIMMARRON GATHERING LLC
COLORADO INTERSTATE GAS COMPANY, L.L.C.
COLORADO INTERSTATE ISSUING CORPORATION
COPANO DOUBLE EAGLE LLC
COPANO ENERGY FINANCE CORPORATION
COPANO ENERGY, L.L.C.
COPANO ENERGY SERVICES/UPPER GULF COAST LLC
COPANO FIELD SERVICES GP, L.L.C.
COPANO FIELD SERVICES/NORTH TEXAS, L.L.C.
COPANO FIELD SERVICES/SOUTH TEXAS LLC
COPANO FIELD SERVICES/UPPER GULF COAST LLC
COPANO LIBERTY, LLC
COPANO NGL SERVICES (MARKHAM), L.L.C.
COPANO NGL SERVICES LLC
COPANO PIPELINES GROUP, L.L.C.
[Signature Page to Cross Guarantee]
Exhibit 10.16
COPANO PIPELINES/NORTH TEXAS, L.L.C.
COPANO PIPELINES/ROCKY MOUNTAINS, LLC
COPANO PIPELINES/SOUTH TEXAS LLC
COPANO PIPELINES/UPPER GULF COAST LLC
COPANO PROCESSING LLC
COPANO RISK MANAGEMENT LLC
COPANO/WEBB-DUVAL PIPELINE LLC
CPNO SERVICES LLC
DAKOTA BULK TERMINAL, INC.
DELTA TERMINAL SERVICES LLC
EAGLE FORD GATHERING LLC
EL PASO CHEYENNE HOLDINGS, L.L.C.
EL PASO CITRUS HOLDINGS, INC.
EL PASO CNG COMPANY, L.L.C.
EL PASO ENERGY SERVICE COMPANY, L.L.C.
EL PASO LLC
EL PASO MIDSTREAM GROUP LLC
EL PASO NATURAL GAS COMPANY, L.L.C.
EL PASO NORIC INVESTMENTS III, L.L.C.
EL PASO PIPELINE CORPORATION
EL PASO PIPELINE GP COMPANY, L.L.C.
EL PASO PIPELINE HOLDING COMPANY, L.L.C.
EL PASO PIPELINE LP HOLDINGS, L.L.C.
EL PASO PIPELINE PARTNERS, L.P.
By El Paso Pipeline GP Company, L.L.C., its general partner
EL PASO PIPELINE PARTNERS OPERATING COMPANY, L.L.C.
EL PASO RUBY HOLDING COMPANY, L.L.C.
EL PASO TENNESSEE PIPELINE CO., L.L.C.
ELBA EXPRESS COMPANY, L.L.C.
ELIZABETH RIVER TERMINALS LLC
EMORY B CRANE, LLC
EPBGP CONTRACTING SERVICES LLC
EP ENERGY HOLDING COMPANY
EP RUBY LLC
EPTP ISSUING CORPORATION
FERNANDINA MARINE CONSTRUCTION MANAGEMENT LLC
FRANK L. CRANE, LLC
GENERAL STEVEDORES GP, LLC
GENERAL STEVEDORES HOLDINGS LLC
GLOBAL AMERICAN TERMINALS LLC
HAMPSHIRE LLC
HARRAH MIDSTREAM LLC
HBM ENVIRONMENTAL, INC.
ICPT, L.L.C
J.R. NICHOLLS LLC
JAVELINA TUG LLC
JEANNIE BREWER LLC
JV TANKER CHARTERER LLC
KINDER MORGAN (DELAWARE), INC.
KINDER MORGAN 2-MILE LLC
KINDER MORGAN ADMINISTRATIVE SERVICES TAMPA LLC
KINDER MORGAN ALTAMONT LLC
[Signature Page to Cross Guarantee]
Exhibit 10.16
KINDER MORGAN AMORY LLC
KINDER MORGAN ARROW TERMINALS HOLDINGS, INC.
KINDER MORGAN ARROW TERMINALS, L.P.
By Kinder Morgan River Terminals, LLC, its general partner
KINDER MORGAN BALTIMORE TRANSLOAD TERMINAL LLC
KINDER MORGAN BATTLEGROUND OIL LLC
KINDER MORGAN BORDER PIPELINE LLC
KINDER MORGAN BULK TERMINALS, INC.
KINDER MORGAN CARBON DIOXIDE TRANSPORTATION
COMPANY
KINDER MORGAN CO2 COMPANY, L.P.
By Kinder Morgan G.P., Inc., its general partner
KINDER MORGAN COCHIN LLC
KINDER MORGAN COLUMBUS LLC
KINDER MORGAN COMMERCIAL SERVICES LLC
KINDER MORGAN CRUDE & CONDENSATE LLC
KINDER MORGAN CRUDE OIL PIPELINES LLC
KINDER MORGAN CRUDE TO RAIL LLC
KINDER MORGAN CUSHING LLC
KINDER MORGAN DALLAS FORT WORTH RAIL TERMINAL LLC
KINDER MORGAN ENDEAVOR LLC
KINDER MORGAN ENERGY PARTNERS, L.P.
By Kinder Morgan G.P., Inc., its general partner
KINDER MORGAN EP MIDSTREAM LLC
KINDER MORGAN FINANCE COMPANY LLC
KINDER MORGAN FLEETING LLC
KINDER MORGAN FREEDOM PIPELINE LLC
KINDER MORGAN KEYSTONE GAS STORAGE LLC
KINDER MORGAN KMAP LLC
KINDER MORGAN LAS VEGAS LLC
KINDER MORGAN LINDEN TRANSLOAD TERMINAL LLC
KINDER MORGAN LIQUIDS TERMINALS LLC
KINDER MORGAN LIQUIDS TERMINALS ST. GABRIEL LLC
KINDER MORGAN MARINE SERVICES LLC
KINDER MORGAN MATERIALS SERVICES, LLC
KINDER MORGAN MID ATLANTIC MARINE SERVICES LLC
KINDER MORGAN NATGAS O&M LLC
KINDER MORGAN NORTH TEXAS PIPELINE LLC
KINDER MORGAN OPERATING L.P. “A”
By Kinder Morgan G.P., Inc., its general partner
KINDER MORGAN OPERATING L.P. “B”
By Kinder Morgan G.P., Inc., its general partner
KINDER MORGAN OPERATING L.P. “C”
By Kinder Morgan G.P., Inc., its general partner
KINDER MORGAN OPERATING L.P. “D”
By Kinder Morgan G.P., Inc., its general partner
KINDER MORGAN PECOS LLC
KINDER MORGAN PECOS VALLEY LLC
KINDER MORGAN PETCOKE GP LLC
[Signature Page to Cross Guarantee]
Exhibit 10.16
KINDER MORGAN PETCOKE, L.P.
By Kinder Morgan Petcoke GP LLC, its general partner
KINDER MORGAN PETCOKE LP LLC
KINDER MORGAN PETROLEUM TANKERS LLC
KINDER MORGAN PIPELINE LLC
KINDER MORGAN PIPELINES (USA) INC.
KINDER MORGAN PORT MANATEE TERMINAL LLC
KINDER MORGAN PORT SUTTON TERMINAL LLC
KINDER MORGAN PORT TERMINALS USA LLC
KINDER MORGAN PRODUCTION COMPANY LLC
KINDER MORGAN RAIL SERVICES LLC
KINDER MORGAN RESOURCES II LLC
KINDER MORGAN RESOURCES III LLC
KINDER MORGAN RESOURCES LLC
KINDER MORGAN RIVER TERMINALS LLC
KINDER MORGAN SERVICES LLC
KINDER MORGAN SEVEN OAKS LLC
KINDER MORGAN SOUTHEAST TERMINALS LLC
KINDER MORGAN TANK STORAGE TERMINALS LLC
KINDER MORGAN TEJAS PIPELINE LLC
KINDER MORGAN TERMINALS, INC.
KINDER MORGAN TEXAS PIPELINE LLC
KINDER MORGAN TEXAS TERMINALS, L.P.
By General Stevedores GP, LLC, its general partner
KINDER MORGAN TRANSMIX COMPANY, LLC
KINDER MORGAN TREATING LP
By KM Treating GP LLC, its general partner
KINDER MORGAN URBAN RENEWAL, L.L.C.
KINDER MORGAN UTICA LLC
KINDER MORGAN VIRGINIA LIQUIDS TERMINALS LLC
KINDER MORGAN WINK PIPELINE LLC
KINDERHAWK FIELD SERVICES LLC
KM CRANE LLC
KM DECATUR, INC.
KM EAGLE GATHERING LLC
KM GATHERING LLC
KM KASKASKIA DOCK LLC
KM LIQUIDS TERMINALS LLC
KM NORTH CAHOKIA LAND LLC
KM NORTH CAHOKIA SPECIAL PROJECT LLC
KM NORTH CAHOKIA TERMINAL PROJECT LLC
KM SHIP CHANNEL SERVICES LLC
KM TREATING GP LLC
KM TREATING PRODUCTION LLC
KMBT LLC
KMGP CONTRACTING SERVICES LLC
KMGP SERVICES COMPANY, INC.
KN TELECOMMUNICATIONS, INC.
KNIGHT POWER COMPANY LLC
LOMITA RAIL TERMINAL LLC
MILWAUKEE BULK TERMINALS LLC
MJR OPERATING LLC
MOJAVE PIPELINE COMPANY, L.L.C.
MOJAVE PIPELINE OPERATING COMPANY, L.L.C.
MR. BENNETT LLC
[Signature Page to Cross Guarantee]
Exhibit 10.16
MR. VANCE LLC
NASSAU TERMINALS LLC
NGPL HOLDCO INC.
NS 307 HOLDINGS INC.
PADDY RYAN CRANE, LLC
PALMETTO PRODUCTS PIPE LINE LLC
PI 2 PELICAN STATE LLC
PINNEY DOCK & TRANSPORT LLC
QUEEN CITY TERMINALS LLC
RAHWAY RIVER LAND LLC
RAZORBACK TUG LLC
RCI HOLDINGS, INC.
RIVER TERMINALS PROPERTIES GP LLC
RIVER TERMINAL PROPERTIES, L.P.
By River Terminals Properties GP LLC, its general partner
SCISSORTAIL ENERGY, LLC
SNG PIPELINE SERVICES COMPANY, L.L.C.
SOUTHERN GULF LNG COMPANY, L.L.C.
SOUTHERN LIQUEFACTION COMPANY LLC
SOUTHERN LNG COMPANY, L.L.C.
SOUTHERN NATURAL GAS COMPANY, L.L.C.
SOUTHERN NATURAL ISSUING CORPORATION
SOUTHTEX TREATERS LLC
SOUTHWEST FLORIDA PIPELINE LLC
SRT VESSELS LLC
STEVEDORE HOLDINGS, L.P.
By Kinder Morgan Petcoke GP LLC, its general partner
TAJON HOLDINGS, INC.
TEJAS GAS, LLC
TEJAS NATURAL GAS, LLC
TENNESSEE GAS PIPELINE COMPANY, L.L.C.
TENNESSEE GAS PIPELINE ISSUING CORPORATION
TEXAN TUG LLC
TGP PIPELINE SERVICES COMPANY, L.L.C.
TRANS MOUNTAIN PIPELINE (PUGET SOUND) LLC
TRANSCOLORADO GAS TRANSMISSION COMPANY LLC
TRANSLOAD SERVICES, LLC
UTICA MARCELLUS TEXAS PIPELINE LLC
WESTERN PLANT SERVICES, INC.
WYOMING INTERSTATE COMPANY, L.L.C.
By:
/s/ Anthony B. Ashley
Anthony Ashley
Vice President
[Signature Page to Cross Guarantee]
Exhibit 10.16
ANNEX A TO
THE CROSS GUARANTEE AGREEMENT
SUPPLEMENT NO. [ ] dated as of [ ] to the CROSS GUARANTEE AGREEMENT dated as of
[ ] (the “Agreement”), among each of the Guarantors listed on the signature pages thereto and each of the
other entities that becomes a party thereto pursuant to Section 19 of the Agreement (each such entity individually, a
“Guarantor” and, collectively, the “Guarantors”). Unless otherwise defined herein, terms defined in the Agreement
and used herein shall have the meanings given to them in the Agreement.
A.
The Guarantors consist of Kinder Morgan, Inc., a Delaware corporation (“KMI”), and certain of its
direct and indirect Subsidiaries, and the Guarantors have entered into the Agreement in order to provide guarantees of
certain of the Guarantors’ senior, unsecured Indebtedness outstanding from time to time.
B.
Section 19 of the Agreement provides that additional Subsidiaries may become Guarantors under the
Agreement by execution and delivery of an instrument in the form of this Supplement. Each undersigned Subsidiary
(each a “New Guarantor”) is executing this Supplement at the request of KMI or in accordance with the requirements
of the Agreement to become a Guarantor under the Agreement.
Accordingly, each New Guarantor agrees as follows:
SECTION 1.
In accordance with Section 19 of the Agreement, each New Guarantor by its signature below
becomes a Guarantor under the Agreement with the same force and effect as if originally named therein as a Guarantor
and each New Guarantor hereby (a) agrees to all the terms and provisions of the Agreement applicable to it as a
Guarantor thereunder and (b) represents and warrants that the representations and warranties made by it as a Guarantor
thereunder are true and correct on and as of the date hereof. Each reference to a Guarantor in the Agreement shall be
deemed to include each New Guarantor. The Agreement is hereby incorporated herein by reference.
SECTION 2. Each New Guarantor represents and warrants to the Guaranteed Parties that this Supplement
has been duly authorized, executed and delivered by it and constitutes its legal, valid and binding obligation, enforceable
against it in accordance with its terms.
SECTION 3. This Supplement may be executed by one or more of the parties to this Supplement on any
number of separate counterparts (including by facsimile or other electronic transmission), and all of said counterparts
taken together shall be deemed to constitute one and the same instrument. A set of the copies of this Supplement signed
by all the parties shall be lodged with KMI. This Supplement shall become effective as to each New Guarantor when
KMI shall have received a counterpart of this Supplement that bears the signature of such New Guarantor.
SECTION 4. Except as expressly supplemented hereby, the Agreement shall remain in full force and
effect.
SECTION 5. THIS SUPPLEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES
HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE
WITH, THE LAW OF THE STATE OF NEW YORK.
Exhibit 10.16
SECTION 6. Any provision of this Supplement that is prohibited or unenforceable in any jurisdiction shall,
as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the
remaining provisions hereof and in the Agreement, and any such prohibition or unenforceability in any jurisdiction
shall not invalidate or render unenforceable such provision in any other jurisdiction. The parties hereto shall endeavor
in good-faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic
effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions.
SECTION 7. All notices, requests and demands pursuant hereto shall be made in accordance with Section
12 of the Agreement. All communications and notices hereunder to each New Guarantor shall be given to it in care
of KMI at the address set forth in Section 12 of the Agreement.
[Signature Pages Follow]
IN WITNESS WHEREOF, each New Guarantor has duly executed this Supplement to the Agreement as of
the day and year first above written.
Exhibit 10.16
_________________________________
as Guarantor
By:______________________________
Name:
Title:
Exhibit 10.16
ANNEX B TO
THE CROSS GUARANTEE AGREEMENT
FORM OF NOTATION OF GUARANTEE
Subject to the limitations set forth in the Cross Guarantee Agreement, dated as of [•] (the “Guarantee
Agreement”), the undersigned Guarantors hereby certify that this [Indebtedness] constitutes a Guaranteed Obligation,
entitled to all the rights as such set forth in the Guarantee Agreement. The Guarantors may be released from their
guarantees upon the terms and subject to the conditions provided in the Guarantee Agreement. Capitalized terms used
but not defined in this notation of guarantee have the meanings assigned such terms in the Guarantee Agreement, a
copy of which will be provided to [a holder of this instrument] upon request to [Issuer].
Schedule I of the Guarantee Agreement is hereby deemed to be automatically updated to include this
[Indebtedness] thereon as a Guaranteed Obligation.
[GUARANTORS],
as Guarantor
By:
______________________________
Name:
Title:
Exhibit 10.16
SCHEDULE I
Guaranteed Obligations
Current as of: December 31, 2016
Issuer
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Indebtedness
7.00% bonds
2.00% notes
6.00% notes
7.00% bonds (Sonat)
7.25% bonds
3.05% notes
6.50% bonds
5.00% notes
1.500% notes
5.625% notes
4.30% notes
6.70% bonds (Coastal)
2.250% notes
6.67% debentures
7.25% debentures
6.95% bonds (Coastal)
8.05% bonds
7.80% bonds
7.75% bonds
5.30% notes
7.75% bonds (Coastal)
6.40% notes
7.42% bonds (Coastal)
5.55% notes
5.050% notes
7.45% debentures
6.00% bonds
5.95% bonds
9.00% bonds
2.65% bonds
6.85% bonds
5.30% bonds
5.80% bonds
3.50% bonds
4.15% bonds
3.95% bonds
3.45% bonds
3.50% bonds
4.15% bonds
4.25% bonds
7.40% bonds
7.75% bonds
7.30% bonds
5.80% bonds
6.50% bonds
6.95% bonds
Maturity
June 15, 2017
December 1, 2017
January 15, 2018
February 1, 2018
June 1, 2018
December 1, 2019
September 15, 2020
February 15, 2021
March 16, 2022
November 15, 2023
June 1, 2025
February 15, 2027
March 16, 2027
November 1, 2027
March 1, 2028
June 1, 2028
October 15, 2030
August 1, 2031
January 15, 2032
December 1, 2034
October 15, 2035
January 5, 2036
February 15, 2037
June 1, 2045
February 15, 2046
March 1, 2098
February 1, 2017
February 15, 2018
February 1, 2019
February 1, 2019
February 15, 2020
September 15, 2020
March 1, 2021
March 1, 2021
March 1, 2022
September 1, 2022
February 15, 2023
September 1, 2023
February 1, 2024
September 1, 2024
March 15, 2031
March 15, 2032
August 15, 2033
March 15, 2035
February 1, 2037
January 15, 2038
Exhibit 10.16
Schedule I
(Guaranteed Obligations)
Current as of: December 31, 2016
Issuer
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.(1)
Kinder Morgan Energy Partners, L.P.(1)
Kinder Morgan Energy Partners, L.P.(1)
Kinder Morgan Energy Partners, L.P.(1)
Kinder Morgan Energy Partners, L.P.(1)
Tennessee Gas Pipeline Company, L.L.C.
Tennessee Gas Pipeline Company, L.L.C.
Tennessee Gas Pipeline Company, L.L.C.
Tennessee Gas Pipeline Company, L.L.C.
Tennessee Gas Pipeline Company, L.L.C.
El Paso Natural Gas Company, L.L.C.
El Paso Natural Gas Company, L.L.C.
El Paso Natural Gas Company, L.L.C.
El Paso Natural Gas Company, L.L.C.
Colorado Interstate Gas Company, L.L.C.
Colorado Interstate Gas Company, L.L.C.
El Paso Tennessee Pipeline Co. L.L.C.
Other
Other
Hiland Partners Holdings LLC and
Hiland Partners Finance Corp.
_________________________________________________
Indebtedness
6.50% bonds
6.55% bonds
6.375% bonds
5.625% bonds
5.00% bonds
5.00% bonds
5.50% bonds
5.40% bonds
6.50% bonds
5.00% bonds
4.30% bonds
7.50% bonds
4.70% bonds
7.50% bonds
7.00% bonds
7.00% bonds
8.375% bonds
7.625% bonds
5.95% bonds
8.625% bonds
7.50% bonds
8.375% bonds
4.15% notes
6.85% bonds
7.25% bonds
KM LQT IRBs-Stolt floating rate bonds
Cora industrial revenue bonds
5.50% notes
Maturity
September 1, 2039
September 15, 2040
March 1, 2041
September 1, 2041
August 15, 2042
March 1, 2043
March 1, 2044
September 1, 2044
April 1, 2020
October 1, 2021
May 1, 2024
November 15, 2040
November 1, 2042
April 1, 2017
March 15, 2027
October 15, 2028
June 15, 2032
April 1, 2037
April 15, 2017
January 15, 2022
November 15, 2026
June 15, 2032
August 15, 2026
June 15, 2037
December 15, 2025
January 15, 2018
April 1, 2024
May 15, 2022
(1) The original issuer, El Paso Pipeline Partners, L.P. merged with and into Kinder Morgan Energy
Partners, L.P. effective January 1, 2015.
2
Hedging Agreements1
Issuer
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Kinder Morgan, Inc.
Exhibit 10.16
Schedule I
(Guaranteed Obligations)
Current as of: December 31, 2016
Guaranteed Party
Bank of America, N.A.
BNP Paribas
Citibank, N.A.
J. Aron & Company
SunTrust Bank
Barclays Bank PLC
Bank of Tokyo-Mitsubishi, Ltd., New York
Branch
Date
August 29, 2001
September 15, 2016
March 14, 2002
December 23, 2011
August 29, 2001
November 26, 2014
November 26, 2014
Canadian Imperial Bank of Commerce
November 26, 2014
Compass Bank
Credit Agricole Corporate and Investment
Bank
Credit Suisse International
Deutsche Bank AG
ING Capital Markets LLC
JPMorgan Chase Bank, N.A.
Mizuho Capital Markets Corporation
Royal Bank of Canada
The Bank of Nova Scotia
The Royal Bank of Scotland PLC
Societe Generale
UBS AG
Wells Fargo Bank, N.A.
March 24, 2015
November 26, 2014
November 26, 2014
November 26, 2014
November 26, 2014
February 19, 2015
November 26, 2014
November 26, 2014
November 26, 2014
November 26, 2014
November 26, 2014
November 26, 2014
November 26, 2014
April 14, 1999
November 23, 2004
November 18, 2003
August 4, 2011
March 14, 2002
June 20, 2014
May 14, 2010
April 2, 2009
Kinder Morgan Energy Partners, L.P.
Bank of America, N.A.
Kinder Morgan Energy Partners, L.P.
Bank of Tokyo-Mitsubishi, Ltd., New York
Branch
Kinder Morgan Energy Partners, L.P.
Barclays Bank PLC
Kinder Morgan Energy Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Canadian Imperial Bank of Commerce
Citibank, N.A.
Kinder Morgan Energy Partners, L.P.
Credit Agricole Corporate and Investment
Bank
Kinder Morgan Energy Partners, L.P.
Credit Suisse International
Kinder Morgan Energy Partners, L.P.
Deutsche Bank AG
Kinder Morgan Energy Partners, L.P.
_________________________________________________
ING Capital Markets LLC
September 21, 2011
1 Guaranteed Obligations with respect to Hedging Agreements include International Swaps and
Derivatives Association Master Agreements (“ISDAs”) and all transactions entered into pursuant to
any ISDA listed on this Schedule I.
3
Exhibit 10.16
Schedule I
(Guaranteed Obligations)
Current as of: December 31, 2016
Hedging Agreements1
Issuer
Kinder Morgan Energy Partners, L.P.
Guaranteed Party
J. Aron & Company
Kinder Morgan Energy Partners, L.P.
JPMorgan Chase Bank
Kinder Morgan Energy Partners, L.P.
Mizuho Capital Markets Corporation
Kinder Morgan Energy Partners, L.P.
Morgan Stanley Capital Services Inc.
Kinder Morgan Energy Partners, L.P.
Royal Bank of Canada
Kinder Morgan Energy Partners, L.P.
The Royal Bank of Scotland PLC
Kinder Morgan Energy Partners, L.P.
The Bank of Nova Scotia
Kinder Morgan Energy Partners, L.P.
Societe Generale
Kinder Morgan Energy Partners, L.P.
SunTrust Bank
Kinder Morgan Energy Partners, L.P.
UBS AG
Kinder Morgan Energy Partners, L.P.
Wells Fargo Bank, N.A.
Kinder Morgan Texas Pipeline LLC
Barclays Bank PLC
Kinder Morgan Texas Pipeline LLC
BNP Paribas
Date
November 11, 2004
August 29, 2001
July 11, 2014
March 10, 2010
March 12, 2009
March 20, 2009
August 14, 2003
July 18, 2014
March 14, 2002
February 23, 2011
July 31, 2007
January 10, 2003
March 2, 2005
Kinder Morgan Texas Pipeline LLC
Canadian Imperial Bank of Commerce
December 18, 2006
Kinder Morgan Texas Pipeline LLC
Citibank, N.A.
Kinder Morgan Texas Pipeline LLC
Credit Suisse International
Kinder Morgan Texas Pipeline LLC
Deutsche Bank AG
Kinder Morgan Texas Pipeline LLC
Kinder Morgan Production LLC
ING Capital Markets LLC
J. Aron & Company
Kinder Morgan Texas Pipeline LLC
J. Aron & Company
Kinder Morgan Texas Pipeline LLC
JPMorgan Chase Bank, N.A.
Kinder Morgan Texas Pipeline LLC
Macquarie Bank Limited
Kinder Morgan Texas Pipeline LLC
Merrill Lynch Commodities, Inc.
Kinder Morgan Texas Pipeline LLC
Morgan Stanley Capital Group Inc.
Kinder Morgan Texas Pipeline LLC
Natixis
Kinder Morgan Texas Pipeline LLC
Phillips 66 Company
Kinder Morgan Texas Pipeline LLC
Royal Bank of Canada
Kinder Morgan Texas Pipeline LLC
The Bank of Nova Scotia
Kinder Morgan Texas Pipeline LLC
Shell Trading (US) Company
Kinder Morgan Texas Pipeline LLC
Societe Generale
Kinder Morgan Texas Pipeline LLC
Wells Fargo Bank, N.A.
Copano Risk Management, LLC
Citibank, N.A.
Copano Risk Management, LLC
J. Aron & Company
February 22, 2005
August 31, 2012
June 13, 2007
April 17, 2014
June 12, 2006
June 8, 2000
September 7, 2006
September 20, 2010
October 24, 2001
January 15, 2004
June 13, 2011
March 30, 2015
May 6, 2009
May 8, 2014
November 14, 2011
January 14, 2003
June 1, 2013
July 21, 2008
December 12, 2005
Copano Risk Management, LLC
Morgan Stanley Capital Group Inc.
May 4, 2007
Copano Risk Management, LLC
_________________________________________________
Wells Fargo Bank, N.A.
October 19, 2007
1 Guaranteed Obligations with respect to Hedging Agreements include International Swaps and
Derivatives Association Master Agreements (“ISDAs”) and all transactions entered into pursuant to
any ISDA listed on this Schedule I.
4
Exhibit 10.16
SCHEDULE II
Guarantors
Current as of: December 31, 2016
Agnes B Crane, LLC
American Petroleum Tankers II LLC
American Petroleum Tankers III LLC
American Petroleum Tankers IV LLC
American Petroleum Tankers LLC
American Petroleum Tankers Parent LLC
American Petroleum Tankers V LLC
American Petroleum Tankers VI LLC
American Petroleum Tankers VII LLC
American Petroleum Tankers VIII LLC
American Petroleum Tankers IX LLC
American Petroleum Tankers X LLC
American Petroleum Tankers XI LLC
APT Florida LLC
APT Intermediate Holdco LLC
APT New Intermediate Holdco LLC
APT Pennsylvania LLC
APT Sunshine State LLC
Audrey Tug LLC
Betty Lou LLC
Camino Real Gathering Company, L.L.C.
Cantera Gas Company LLC
CDE Pipeline LLC
Central Florida Pipeline LLC
Cheyenne Plains Gas Pipeline Company, L.L.C.
CIG Gas Storage Company LLC
CIG Pipeline Services Company, L.L.C.
Colorado Interstate Gas Company, L.L.C.
Colorado Interstate Issuing Corporation
Copano Double Eagle LLC
Copano Energy Finance Corporation
Copano Energy Services/Upper Gulf Coast LLC
Copano Energy, L.L.C.
Copano Field Services GP, L.L.C.
Copano Field Services/North Texas, L.L.C.
Copano Field Services/South Texas LLC
Copano Field Services/Upper Gulf Coast LLC
Copano Liberty, LLC
Copano NGL Services (Markham), L.L.C.
Copano NGL Services LLC
Copano Pipelines Group, L.L.C.
Copano Pipelines/North Texas, L.L.C.
Copano Pipelines/Rocky Mountains, LLC
Copano Pipelines/South Texas LLC
Copano Pipelines/Upper Gulf Coast LLC
Copano Processing LLC
Copano Risk Management LLC
Copano/Webb-Duval Pipeline LLC
CPNO Services LLC
Dakota Bulk Terminal, Inc.
Delta Terminal Services LLC
Eagle Ford Gathering LLC
El Paso Cheyenne Holdings, L.L.C.
El Paso Citrus Holdings, Inc.
El Paso CNG Company, L.L.C.
El Paso Energy Service Company, L.L.C.
El Paso LLC
El Paso Midstream Group LLC
El Paso Natural Gas Company, L.L.C.
El Paso Noric Investments III, L.L.C.
El Paso Ruby Holding Company, L.L.C.
El Paso Tennessee Pipeline Co., L.L.C.
Elba Express Company, L.L.C.
Elba Liquefaction Company, L.L.C.
Elizabeth River Terminals LLC
Emory B Crane, LLC
EP Ruby LLC
EPBGP Contracting Services LLC
EPTP Issuing Corporation
Fernandina Marine Construction Management
LLC
Frank L. Crane, LLC
General Stevedores GP, LLC
General Stevedores Holdings LLC
Glenpool West Gathering LLC
Global American Terminals LLC
Hampshire LLC
Harrah Midstream LLC
HBM Environmental, Inc.
Hiland Crude, LLC
Hiland Partners Finance Corp.
Hiland Partners Holdings LLC
ICPT, L.L.C
Independent Trading & Transportation
Company I, L.L.C.
J.R. Nicholls LLC
Javelina Tug LLC
Jeannie Brewer LLC
JV Tanker Charterer LLC
Kinder Morgan 2-Mile LLC
Kinder Morgan Administrative Services Tampa LLC
Kinder Morgan Altamont LLC
Exhibit 10.16
Schedule II
(Guarantors)
Current as of: December 31, 2016
Kinder Morgan Amory LLC
Kinder Morgan Arrow Terminals Holdings, Inc.
Kinder Morgan Arrow Terminals, L.P.
Kinder Morgan Baltimore Transload Terminal
LLC
Kinder Morgan Battleground Oil LLC
Kinder Morgan Border Pipeline LLC
Kinder Morgan Bulk Terminals LLC
Kinder Morgan Carbon Dioxide Transportation
Company
Kinder Morgan CO2 Company, L.P.
Kinder Morgan Cochin LLC
Kinder Morgan Columbus LLC
Kinder Morgan Commercial Services LLC
Kinder Morgan Contracting Services LLC
Kinder Morgan Crude & Condensate LLC
Kinder Morgan Crude Oil Pipelines LLC
Kinder Morgan Crude to Rail LLC
Kinder Morgan Cushing LLC
Kinder Morgan Dallas Fort Worth Rail Terminal
LLC
Kinder Morgan Endeavor LLC
Kinder Morgan Energy Partners, L.P.
Kinder Morgan EP Midstream LLC
Kinder Morgan Finance Company LLC
Kinder Morgan Fleeting LLC
Kinder Morgan Freedom Pipeline LLC
Kinder Morgan Galena Park West LLC
Kinder Morgan, Inc.
Kinder Morgan Keystone Gas Storage LLC
Kinder Morgan KMAP LLC
Kinder Morgan Las Vegas LLC
Kinder Morgan Linden Transload Terminal LLC
Kinder Morgan Liquids Terminals LLC
Kinder Morgan Liquids Terminals St. Gabriel LLC
Kinder Morgan Louisiana Pipeline Holding LLC
Kinder Morgan Louisiana Pipeline LLC
Kinder Morgan Marine Services LLC
Kinder Morgan Materials Services, LLC
Kinder Morgan Mid Atlantic Marine Services LLC
Kinder Morgan NatGas O&M LLC
Kinder Morgan NGL LLC
Kinder Morgan NGPL Holdings LLC
Kinder Morgan North Texas Pipeline LLC
Kinder Morgan Operating L.P. “A”
Kinder Morgan Operating L.P. “B”
Kinder Morgan Operating L.P. “C”
Kinder Morgan Operating L.P. “D”
Kinder Morgan Pecos LLC
Kinder Morgan Pecos Valley LLC
Kinder Morgan Petcoke GP LLC
Kinder Morgan Petcoke LP LLC
Kinder Morgan Petcoke, L.P.
Kinder Morgan Petroleum Tankers LLC
Kinder Morgan Pipeline LLC
Kinder Morgan Port Manatee Terminal LLC
Kinder Morgan Port Sutton Terminal LLC
Kinder Morgan Port Terminals USA LLC
Kinder Morgan Production Company LLC
Kinder Morgan Rail Services LLC
Kinder Morgan Resources II LLC
Kinder Morgan Resources III LLC
Kinder Morgan Resources LLC
Kinder Morgan River Terminals LLC
Kinder Morgan Seven Oaks LLC
Kinder Morgan SNG Operator LLC
Kinder Morgan Southeast Terminals LLC
Kinder Morgan Scurry Connector LLC
Kinder Morgan Tank Storage Terminals LLC
Kinder Morgan Tejas Pipeline LLC
Kinder Morgan Terminals, Inc.
Kinder Morgan Terminals Wilmington LLC
Kinder Morgan Texas Pipeline LLC
Kinder Morgan Texas Terminals, L.P.
Kinder Morgan Transmix Company, LLC
Kinder Morgan Treating LP
Kinder Morgan Urban Renewal, L.L.C.
Kinder Morgan Utica LLC
Kinder Morgan Virginia Liquids Terminals LLC
Kinder Morgan Wink Pipeline LLC
KinderHawk Field Services LLC
KM Crane LLC
KM Decatur, Inc.
KM Eagle Gathering LLC
KM Gathering LLC
KM Kaskaskia Dock LLC
KM Liquids Terminals LLC
KM North Cahokia Land LLC
KM North Cahokia Special Project LLC
KM North Cahokia Terminal Project LLC
KM Ship Channel Services LLC
KM Treating GP LLC
KM Treating Production LLC
KMBT LLC
KMGP Services Company, Inc.
KN Telecommunications, Inc.
Knight Power Company LLC
Lomita Rail Terminal LLC
Milwaukee Bulk Terminals LLC
MJR Operating LLC
2
Exhibit 10.16
Schedule II
(Guarantors)
Current as of: December 31, 2016
Mojave Pipeline Company, L.L.C.
Mojave Pipeline Operating Company, L.L.C.
Mr. Bennett LLC
Mr. Vance LLC
Nassau Terminals LLC
Paddy Ryan Crane, LLC
Palmetto Products Pipe Line LLC
PI 2 Pelican State LLC
Pinney Dock & Transport LLC
Queen City Terminals LLC
Rahway River Land LLC
Razorback Tug LLC
RCI Holdings, Inc.
River Terminals Properties GP LLC
River Terminal Properties, L.P.
ScissorTail Energy, LLC
SNG Pipeline Services Company, L.L.C.
Southern Gulf LNG Company, L.L.C.
Southern Liquefaction Company LLC
Southern LNG Company, L.L.C.
Southern Oklahoma Gathering LLC
SouthTex Treaters LLC
Southwest Florida Pipeline LLC
SRT Vessels LLC
Stevedore Holdings, L.P.
Tajon Holdings, Inc.
Tejas Gas, LLC
Tejas Natural Gas, LLC
Tennessee Gas Pipeline Company, L.L.C.
Tennessee Gas Pipeline Issuing Corporation
Texan Tug LLC
TGP Pipeline Services Company, L.L.C.
Trans Mountain Pipeline (Puget Sound) LLC
TransColorado Gas Transmission Company LLC
Transload Services, LLC
Utica Marcellus Texas Pipeline LLC
Western Plant Services, Inc.
Wyoming Interstate Company, L.L.C.
3
Exhibit 10.16
SCHEDULE III
Excluded Subsidiaries
ANR Real Estate Corporation
Coastal Eagle Point Oil Company
Coastal Oil New England, Inc.
Colton Processing Facility
Coscol Petroleum Corporation
El Paso CGP Company, L.L.C.
El Paso Energy Capital Trust I
El Paso Energy E.S.T. Company
El Paso Energy International Company
El Paso Marketing Company, L.L.C.
El Paso Merchant Energy North America Company, L.L.C.
El Paso Merchant Energy-Petroleum Company
El Paso Reata Energy Company, L.L.C.
El Paso Remediation Company
El Paso Services Holding Company
EPEC Corporation
EPEC Oil Company Liquidating Trust
EPEC Polymers, Inc.
EPED Holding Company
KN Capital Trust I
KN Capital Trust III
Mesquite Investors, L.L.C.
Note: The Excluded Subsidiaries listed on this Schedule III may also be Excluded Subsidiaries pursuant to other
exceptions set forth in the definition of “Excluded Subsidiary”.
EXHIBIT 12.1 - STATEMENT RE: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
KINDER MORGAN, INC. AND SUBSIDIARIES
(Dollars in millions except ratio amounts)
Exhibit 12.1
Earnings:
Pre-tax income before adjustment for net income attributable to
noncontrolling interests and earnings from equity investments
(including amortization of excess cost of equity investments) per
statements of income
Add:
Fixed charges
Amortization of capitalized interest
Distributed income of equity investees
Less:
Interest capitalized from continuing operations
Noncontrolling interest in pre-tax income of subsidiaries with no
fixed charges
Income as adjusted
Fixed charges:
Interest and debt expense, net per statements of income (includes
amortization of debt discount, premium, and debt issuance costs);
also excludes gain on early extinguishment of debt and includes
capitalized interest
Add:
Portion of rents representative of the interest factor
Fixed charges
2016
Year Ended December 31,
2013
2014
2015
2012
$ 1,200
$
439
$ 2,730
$ 3,150
$ 1,213
1,977
13
431
2,174
9
391
1,921
5
381
1,785
6
398
1,486
5
311
(77)
(71)
(75)
(52)
(27)
(11)
$ 3,533
(4)
$ 2,938
(377)
$ 4,585
(390)
$ 4,897
17
$ 3,005
$ 1,931
$ 2,126
$ 1,882
$ 1,742
$ 1,454
46
$ 1,977
48
$ 2,174
39
$ 1,921
43
$ 1,785
32
$ 1,486
Ratio of earnings to fixed charges
1.79
1.35
2.39
2.74
2.02
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
6048935 Canada Inc.
Agnes B Crane, LLC
Agua del Cajon (Cayman) Company
American Petroleum Tankers II LLC
American Petroleum Tankers III LLC
American Petroleum Tankers IV LLC
American Petroleum Tankers IX LLC
American Petroleum Tankers LLC
American Petroleum Tankers Parent LLC
American Petroleum Tankers V LLC
American Petroleum Tankers VI LLC
American Petroleum Tankers VII LLC
American Petroleum Tankers VIII LLC
American Petroleum Tankers X LLC
American Petroleum Tankers XI LLC
ANR Advance Holdings, Inc.
ANR Real Estate Corporation
APT Florida LLC
APT Intermediate Holdco LLC
APT New Intermediate Holdco LLC
APT Pennsylvania LLC
APT Sunshine State LLC
Aquamarine Power Holdings, L.L.C.
Ascension Holding Company, L.L.C.
Audrey Tug LLC
Base Line Terminal East Limited Partnership
Battleground Oil Specialty Terminal Company LLC
Bear Creek Storage Company, L.L.C.
Berkshire Feedline Acquisition Limited Partnership
Betty Lou LLC
BHP Billiton Petroleum (Eagle Ford Gathering) LLC
Bighorn Gas Gathering, L.L.C.
Calnev Pipe Line LLC
Camino Real Gathering Company, L.L.C.
Cantera Gas Company LLC
CDE Pipeline LLC
Cedar Cove Midstream LLC
Central Florida Pipeline LLC
Cheyenne Plains Gas Pipeline Company, L.L.C.
CIG Gas Storage Company LLC
Place of Incorporation
Canada
Louisiana
Cayman Islands
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Canada - Limited Partnership
Delaware
Louisiana
Massachusetts
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
CIG Pipeline Services Company, L.L.C.
Citrus Energy Services, Inc.
Citrus LLC
Cliffside Helium, LLC
Cliffside Refiners, L.P.
Coastal Eagle Point Oil Company
Coastal Energy Resources Ltd.
Coastal Oil New England, Inc.
Coastal Wartsila Petroleum Private Limited
Colbourne Insurance Company Limited
Colorado Interstate Gas Company, L.L.C.
Colorado Interstate Issuing Corporation
Colton Processing Facility
Copano Double Eagle LLC
Copano Energy Finance Corporation
Copano Energy L.L.C.
Copano Energy Services/Upper Gulf Coast LLC
Copano Field Services GP, L.L.C.
Copano Field Services/North Texas, L.L.C.
Copano Field Services/South Texas LLC
Copano Field Services/Upper Gulf Coast LLC
Copano Liberty, LLC
Copano NGL Services (Markham), L.L.C.
Copano NGL Services LLC
Copano Pipelines Group, L.L.C.
Copano Pipelines/North Texas, L.L.C.
Copano Pipelines/Rocky Mountains, LLC
Copano Pipelines/South Texas LLC
Copano Pipelines/Upper Gulf Coast LLC
Copano Processing LLC
Copano Risk Management LLC
Copano/Webb-Duval Pipeline LLC
Cortez Capital Corporation
Cortez Expansion Capital Corporation
Cortez Pipeline Company
Coscol Petroleum Corporation
Cottonwood Creek, Inc.
Coyote Gas Treating Limited Liability Company
CPNO Services LLC
Cross Country Development L.L.C.
Place of Incorporation
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Mauritius
Massachusetts
India
United Kingdom
Delaware
Delaware
California
Delaware
Delaware
Delaware
Texas
Delaware
Delaware
Texas
Texas
Delaware
Delaware
Texas
Delaware
Delaware
Delaware
Texas
Texas
Texas
Texas
Delaware
Delaware
Delaware
Texas
Delaware
Oklahoma
Colorado
Texas
Delaware
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
Cypress Interstate Pipeline LLC
Dakota Bulk Terminal, Inc.
Deeprock Development, LLC
Deeprock North, LLC
Delta Terminal Services LLC
Double Eagle Pipeline LLC
Eagle Ford Gathering LLC
El Paso Amazonas Energia Ltda.
El Paso CGP Company, L.L.C.
El Paso Cheyenne Holdings, L.L.C.
El Paso Citrus Holdings, Inc.
El Paso CNG Company, L.L.C.
El Paso Energia do Brasil Ltda.
El Paso Energy Argentina Service Company
El Paso Energy Capital Trust I
El Paso Energy E.S.T. Company
El Paso Energy International Company
El Paso Energy Marketing de Mexico, S. de R.L. de C.V.
El Paso Energy Service Company, L.L.C.
El Paso LLC
El Paso Marketing Company, L.L.C.
El Paso Merchant Energy North America Company, L.L.C.
El Paso Merchant Energy-Petroleum Company
El Paso Mexico Holding B.V.
El Paso Midstream Group LLC
El Paso Natural Gas Company, L.L.C.
El Paso Neuquen Holding Company
El Paso Noric Investments III, L.L.C.
El Paso Reata Energy Company, L.L.C.
El Paso Remediation Company
El Paso Rio Negro Energia Ltda.
El Paso Ruby Holding Company, L.L.C.
El Paso Services Holding Company
El Paso Tennessee Pipeline Co., L.L.C.
Elba Express Company, L.L.C.
Elba Liquefaction Company, L.L.C.
Elizabeth River Terminals LLC
Emory B Crane, LLC
Endeavor Gathering LLC
EP Ruby LLC
Place of Incorporation
Delaware
Wisconsin
Delaware
Delaware
Delaware
Delaware
Delaware
Brazil
Delaware
Delaware
Delaware
Delaware
Brazil
Delaware
Delaware
Delaware
Delaware
Mexico
Delaware
Delaware
Delaware
Delaware
Delaware
Netherlands
Delaware
Delaware
Cayman Islands
Delaware
Delaware
Delaware
Brazil
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Louisiana
Delaware
Delaware
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
EPBGP Contracting Services LLC
EPC Building LLC
EPC Property Holdings, Inc.
EPEC Corporation
EPEC Oil Company Liquidating Trust
EPEC Polymers, Inc.
EPEC Realty, Inc.
EPED B Company
EPED Holding Company
EPTP Issuing Corporation
Express GP Holdings Ltd.
Fayetteville Express Pipeline LLC
Fernandina Marine Construction Management LLC
Fife Power
Florida Gas Transmission Company, LLC
Fort Union Gas Gathering, L.L.C.
Frank L Crane, LLC
GEBF, L.L.C.
General Stevedores GP, LLC
General Stevedores Holdings LLC
GLE Channel Improvement, LLC
Glenpool West Gathering LLC
Global American Terminals LLC
Greens Bayou Fleeting, LLC
Greens Port CBR, LLC
Guilford County Terminal Company, LLC
Gulf LNG Energy (Port), LLC
Gulf LNG Energy, LLC
Gulf LNG Holdings Group, LLC
Gulf LNG Liquefaction Company, LLC
Gulf LNG Pipeline, LLC
Hampshire LLC
Harrah Midstream LLC
HBM Environmental, Inc.
Hiland Crude, LLC
Hiland Partners Finance Corp.
Hiland Partners Holdings LLC
Horizon Pipeline Company, L.L.C.
I.M.T. Land Corp.
ICPT, L.L.C.
Place of Incorporation
Delaware
Delaware
Delaware
Delaware
Delaware Law
Delaware
Delaware
Cayman Islands
Delaware
Delaware
Canada (Alberta)
Delaware
Delaware
Scotland
Delaware
Delaware
Louisiana
Louisiana
Texas
Delaware
Delaware
Delaware
Delaware
Texas
Delaware
North Carolina
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Louisiana
Oklahoma
Delaware
Delaware
Delaware
Louisiana
Louisiana
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
Independent Trading & Transportation Company I, L.L.C.
Interenergy Company
International Marine Terminals Partnership
J.R. Nicholls LLC
Javelina Tug LLC
Jeannie Brewer LLC
Johnston County Terminal, LLC
JV Tanker Charterer LLC
Kellogg Terminal, LLC
Kinder Morgan 2-Mile LLC
Kinder Morgan Administrative Services Tampa LLC
Kinder Morgan Altamont LLC
Kinder Morgan Amory LLC
Kinder Morgan Arrow Terminals Holdings, Inc.
Kinder Morgan Arrow Terminals, L.P.
Kinder Morgan Baltimore Transload Terminal LLC
Kinder Morgan Battleground Oil LLC
Kinder Morgan Border Pipeline LLC
Kinder Morgan Bulk Terminals LLC
Kinder Morgan Canada Company
Kinder Morgan Canada Inc.
Kinder Morgan Canada Terminals Limited Partnership
Kinder Morgan Carbon Dioxide Transportation Company
Kinder Morgan CO2 Company, L.P.
Kinder Morgan Cochin LLC
Kinder Morgan Cochin ULC
Kinder Morgan Columbus LLC
Kinder Morgan Commercial Services LLC
Kinder Morgan Contracting Services LLC
Kinder Morgan Crude & Condensate LLC
Kinder Morgan Crude Oil Pipelines LLC
Kinder Morgan Crude to Rail LLC
Kinder Morgan Cushing LLC
Kinder Morgan Dallas Fort Worth Rail Terminal LLC
Kinder Morgan Endeavor LLC
Kinder Morgan Energy Partners, L.P.
Kinder Morgan EP Midstream LLC
Kinder Morgan Finance Company LLC
Kinder Morgan Fleeting LLC
Kinder Morgan Foundation
Place of Incorporation
Oklahoma
Cayman Islands
Louisiana
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Mississippi
Delaware
Delaware
Delaware
Delaware
Delaware
Louisiana
Canada (Nova Scotia)
Canada (Alberta)
Canada
Delaware
Texas
Delaware
Canada (Nova Scotia)
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Colorado
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
Kinder Morgan Freedom Pipeline LLC
Kinder Morgan G.P., Inc.
Kinder Morgan Galena Park West LLC
Kinder Morgan Gas Natural de Mexico, S. de R.L. de C.V.
Kinder Morgan Heartland ULC
Kinder Morgan Illinois Pipeline LLC
Kinder Morgan IMT Holdco LLC
Kinder Morgan Keystone Gas Storage LLC
Kinder Morgan KMAP LLC
Kinder Morgan Las Vegas LLC
Kinder Morgan Linden Transload Terminal LLC
Kinder Morgan Liquids Terminals LLC
Kinder Morgan Liquids Terminals St. Gabriel LLC
Kinder Morgan Louisiana Pipeline Holding LLC
Kinder Morgan Louisiana Pipeline LLC
Kinder Morgan Marine Services LLC
Kinder Morgan Materials Services, LLC
Kinder Morgan Mexico LLC
Kinder Morgan Mid Atlantic Marine Services LLC
Kinder Morgan NatGas O & M LLC
Kinder Morgan NGL LLC
Kinder Morgan NGPL Holdings LLC
Kinder Morgan North Texas Pipeline LLC
Kinder Morgan Operating L.P. "A"
Kinder Morgan Operating L.P. "B"
Kinder Morgan Operating L.P. "C"
Kinder Morgan Operating L.P. "D"
Kinder Morgan Pecos LLC
Kinder Morgan Pecos Valley LLC
Kinder Morgan Petcoke GP LLC
Kinder Morgan Petcoke LP LLC
Kinder Morgan Petcoke, L.P.
Kinder Morgan Petroleum Tankers LLC
Kinder Morgan Pipeline LLC
Kinder Morgan Pipeline Servicios de Mexico S. de R.L. de C.V.
Kinder Morgan Port Manatee Terminal LLC
Kinder Morgan Port Sutton Terminal LLC
Kinder Morgan Port Terminals USA LLC
Kinder Morgan Production Company LLC
Kinder Morgan Rail Services LLC
Place of Incorporation
Delaware
Delaware
Delaware
Mexico
Canada (Alberta)
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Mexico
Delaware
Delaware
Delaware
Delaware
Delaware
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
Kinder Morgan Resources II LLC
Kinder Morgan Resources III LLC
Kinder Morgan Resources LLC
Kinder Morgan River Terminals LLC
Kinder Morgan Scurry Connector LLC
Kinder Morgan Seven Oaks LLC
Kinder Morgan SNG Operator LLC
Kinder Morgan Southeast Terminals LLC
Kinder Morgan Tank Storage Terminals LLC
Kinder Morgan Tejas Pipeline GP LLC
Kinder Morgan Tejas Pipeline LLC
Kinder Morgan Terminals Wilmington LLC
Kinder Morgan Terminals, Inc.
Kinder Morgan Texas Pipeline LLC
Kinder Morgan Texas Terminals, L.P.
Kinder Morgan TrailStone Energy Marketing Ventures LLC
Kinder Morgan Transmix Company, LLC
Kinder Morgan Treating LP
Kinder Morgan Urban Renewal II, LLC
Kinder Morgan Urban Renewal, L.L.C.
Kinder Morgan Utica LLC
Kinder Morgan Utopia Holdco LLC
Kinder Morgan Utopia LLC
Kinder Morgan Utopia Ltd.
Kinder Morgan Virginia Liquids Terminals LLC
Kinder Morgan Wink Pipeline LLC
KinderHawk Field Services LLC
KM Canada Edmonton North Rail Terminal Limited Partnership
KM Canada Marine Terminal Limited Partnership
KM Canada North 40 Limited Partnership
KM Canada Rail Holdings GP Limited
KM Canada South Rail Terminal Limited Partnership
KM Canada Terminals ULC
KM Crane LLC
KM Crude by Rail Canada Corp.
KM Decatur, Inc.
KM Eagle Gathering LLC
KM Express Limited
KM Gathering LLC
KM Insurance Texas Inc.
Place of Incorporation
Delaware
Delaware
Delaware
Tennessee
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
New Jersey
New Jersey
Delaware
Delaware
Delaware
Canada (Alberta)
Delaware
Delaware
Delaware
Canada - Limited Partnership
Canada - Limited Partnership
Canada - Limited Partnership
Canada (Alberta)
Canada - Limited Partnership
Canada (Alberta)
Maryland
Canada (Alberta)
Alabama
Delaware
Canada (Alberta)
Delaware
Texas
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
KM Kaskaskia Dock LLC
KM Liquids Terminals LLC
KM North Cahokia Land LLC
KM North Cahokia Special Project LLC
KM North Cahokia Terminal Project LLC
KM Phoenix Holdings LLC
KM Ship Channel Services LLC
KM Treating GP LLC
KM Treating Production LLC
KMBT LLC
KMGP Services Company, Inc.
KN Telecommunications, Inc.
Knight Power Company LLC
KW Express Canada GP Limited
KW Express, LLC
Liberty Pipeline Group, LLC
Lomita Rail Terminal LLC
Mesquite Investors, L.L.C.
Midco LLC
Midcontinent Express Pipeline LLC
Mid-Ship Group LLC
Mid-Ship Oil Brokers LLC
Milwaukee Bulk Terminals LLC
MJR Operating LLC
Mojave Pipeline Company, L.L.C.
Mojave Pipeline Operating Company, L.L.C.
Mr. Bennett LLC
Mr. Vance LLC
Nassau Terminals LLC
Natural Gas Pipeline Company of America LLC
NGPL Finance LLC
NGPL Holdings LLC
NGPL Intermediate Holdings LLC
NGPL PipeCo LLC
North Cahokia Industrial, LLC
North Cahokia Real Estate, LLC
North Cahokia Terminal, LLC
North Denton Pipeline, L.L.C.
Paddy Ryan Crane, LLC
Palmetto Products Pipe Line LLC
Place of Incorporation
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Colorado
Delaware
Canada Limited Partnership
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Wisconsin
Maryland
Delaware
Texas
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Texas
Louisiana
Delaware
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
PI 2 Pelican State LLC
Pinney Dock & Transport LLC
Plantation Pipe Line Company
Plantation Services LLC
Queen City Terminals LLC
Rahway River Land LLC
Razorback Tug LLC
RCI Holdings, Inc.
Red Cedar Gathering Company
Reno Pipeline, L.L.C.
River Terminals Properties GP LLC
River Terminals Properties L.P.
Ruby Investment Company, L.L.C.
Ruby Pipeline Holding Company, L.L.C.
Ruby Pipeline, L.L.C.
ScissorTail Energy, LLC
SFPP, L.P.
Sierrita Gas Pipeline LLC
SNG Pipeline Services Company, L.L.C.
Sonoran Pipeline LLC
Southern Dome, LLC
Southern Gulf LNG Company, L.L.C.
Southern Liquefaction Company LLC
Southern LNG Company, L.L.C.
Southern Natural Gas Company, L.L.C.
Southern Natural Issuing Corporation
Southern Oklahoma Gathering LLC
SouthTex Treaters LLC
Southwest Florida Pipeline LLC
SRT Vessels LLC
Stevedore Holdings, L.P.
Tajon Holdings, Inc.
Tejas Gas, LLC
Tejas Natural Gas, LLC
Tennessee Gas Pipeline Company, L.L.C.
Tennessee Gas Pipeline Issuing Corporation
Texan Tug LLC
TGP Pipeline Services Company, L.L.C.
The Pecos Carbon Dioxide Pipeline Company
Trans Mountain (Jet Fuel) Inc.
Place of Incorporation
Delaware
Delaware
Delaware and Virginia
Delaware
Delaware
Delaware
Delaware
Louisiana
Colorado
Texas
Delaware
Tennessee
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Texas
Canada (British Columbia)
Kinder Morgan, Inc.
Subsidiaries of the Registrant as of December 31, 2016
Exhibit 21.1
Entity Name
Trans Mountain Pipeline (Puget Sound) LLC
Trans Mountain Pipeline L.P.
Trans Mountain Pipeline ULC
TransColorado Gas Transmission Company LLC
Transload Services, LLC
Transport USA, Inc.
Utica Marcellus Texas Pipeline LLC
Webb/Duval Gatherers
Western Plant Services, Inc.
WYCO Development LLC
Wyoming Interstate Company, L.L.C.
Young Gas Storage Company, Ltd.
Place of Incorporation
Delaware
Canada - Limited Partnership
Canada (Alberta)
Delaware
Illinois
Pennsylvania
Delaware
Texas
California
Colorado
Delaware
Colorado
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on (i) Form S-3 (Nos. 333-200421 and
333-207599), (ii) Form S-3, converted from Form S-4 (No. 333-177895), and (iii) Form S-8 (Nos. 333-172170, 333-172582,
333-172584, 333-172606, 333-181782 and 333-205430) of Kinder Morgan, Inc. of our report dated February 10, 2017 relating
to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
Exhibit 23.1
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 10, 2017
KINDER MORGAN, INC. AND SUBSIDIARIES
CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934,
AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 31.1
I, Steven J. Kean, certify that:
1.
I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in
all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to
be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles in the United States;
c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during
the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial
reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons
performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and
report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant's internal control over financial reporting.
Date: February 10, 2017
/s/ Steven J. Kean
Steven J. Kean
President and Chief Executive Officer
Exhibit 31.2
KINDER MORGAN, INC. AND SUBSIDIARIES
CERTIFICATION PURSUANT TO RULE 13A-14(A) OR 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934,
AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Kimberly A. Dang, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Kinder Morgan, Inc.;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
b.
c.
d.
designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles in the United States;
evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a.
b.
all significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: February 10, 2017
/s/ Kimberly A. Dang
Kimberly A. Dang
Vice President and Chief Financial Officer
Exhibit 32.1
KINDER MORGAN, INC. AND SUBSIDIARIES
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report on Form 10-K of Kinder Morgan, Inc. (the "Company") for the yearly period ended
December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned,
in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934;
and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results
of operations of the Company.
Date: February 10, 2017
/s/ Steven J. Kean
Steven J. Kean
President and Chief Executive Officer
Exhibit 32.2
KINDER MORGAN, INC.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906
OF THE
SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report on Form 10-K of Kinder Morgan, Inc. (the "Company") for the yearly period ended
December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned,
in the capacity and on the date indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934;
and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results
of operations of the Company.
Date: February 10, 2017
/s/ Kimberly A. Dang
Kimberly A. Dang
Vice President and Chief Financial Officer
KINDER MORGAN, INC. AND SUBSIDIARIES
EXHIBIT 95.1 – MINE SAFETY DISCLOSURES
Exhibit 95.1
This exhibit contains 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. The following table provides information about citations,
orders and notices issued under the Federal Mine Safety and Health Act of 1977 (the "Mine Act") by the federal Mine Safety
and Health Administration ("MSHA") for our mines during the year ended December 31, 2016.
Mine or Operating Name/
MSHA Identification
Number
Section 104
S&S
Citations
(#)
Section
104(b)
Orders
(#)
Section 104
(d) Citations
and Orders
(#)
Section 110(b)
(2) Violations
(#)
Section
107(a)
Orders
(#)
Total Dollar
Value of MSHA
Assessments
Proposed
($)
Total
Number of
Mining
Related
Fatalities
(#)
Received
Notice of
Pattern of
Violations
Under
Section 104
(e)
(yes/no)
Received
Notice of
Potential
to Have
Pattern
under
Section
104(e)
(yes/no)
Legal
Actions
Pending
as of
Last Day
of Period
(#)
Legal
Actions
Initiated
During
Period
(#)
Legal
Actions
Resolved
During
Period
(#)
1103225 Cahokia
1518234
Grand Rivers
____________
—
1
—
—
—
—
—
—
—
—
$
$
100
921
—
—
No
No
No
No
—
—
1
2
1
2
The dollar value represents the total dollar value of all MSHA citations issued and assessed at this time for the two MSHA regulated
terminals noted above. The value includes S&S and non-S&S citations issued during the calendar year 2016.
The MSHA citations, orders and assessments reflected above are those initially issued or proposed by MSHA. They do not
reflect subsequent changes in the level of severity of a citation or order or the value of an assessment that may occur as a result
of proceedings conducted in accordance with MSHA rules.
• Cahokia Terminal, Mine ID# 1103225
Non S&S Citation #9031875, issued 2/1/2016. Assessment amount $100.
• Grand Rivers Terminal, Mine ID# 1518234
S&S Citation #9047305, issued 3/15/2016. Assessment amount $807, settled at $650.
Non S&S Citation #9049366, issued 8/22/2016. Assessment amount $114.
As of December 31, 2016, there were no pending legal actions before the Federal Mine Safety and Health Review Commission
involving any of our mines other than actions filed under the following docket numbers (all of which are contests of citations or
orders under Section 104 of the Mine Act):
During the year ended December 31, 2016, the following legal actions before the Federal Mine Safety and Health Review
Commission involving our mines were resolved:
• Cahokia Terminal, Mine ID# 1103225
Non S&S Citation #9031875 in the amount $100. Payment to MSHA was remitted on 3/21/2016 and this
matter is closed with the agency.
• Grand Rivers Terminal, Mine ID#1518234
Docket 2016-382 Citation #9047305
Negotiated settlement for S&S citation in the amount of $650. Payment to MSHA was remitted on 11/9/2016
and this matter is closed with the agency.
Docket 2016-382 non S&S Citation #9049366 in the amount of $114. Payment to MSHA was remitted on
11/9/2016 and this matter is closed with the agency.