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EX-95.1 - EXHIBIT 95.1 - KINDER MORGAN, INC.kmi-03312017ex951.htm
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EX-31.2 - EXHIBIT 31.2 - KINDER MORGAN, INC.kmi-03312017ex312.htm
EX-31.1 - EXHIBIT 31.1 - KINDER MORGAN, INC.kmi-03312017ex311.htm
EX-10.1 - EXHIBIT 10.1 - KINDER MORGAN, INC.kmi-03312017ex101.htm
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
 
F O R M   10-Q
 
þ  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended March 31, 2017
 
or
 
o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _____to_____
 
Commission file number: 001-35081
image0a30a03.gif

KINDER MORGAN, INC.
(Exact name of registrant as specified in its charter)
 
Delaware
80-0682103
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)

1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant’s telephone number, including area code: 713-369-9000
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o Emerging Growth Company o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o No þ
 
As of April 20, 2017, the registrant had 2,232,442,396 Class P shares outstanding.




KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS

 
 
Page
Number
 
 
 
 
 
 
 
 
 
Consolidated Statements of Income - Three Months Ended March 31, 2017 and 2016
 
 
Consolidated Balance Sheets - March 31, 2017 and December 31, 2016
 
Consolidated Statements of Cash Flows - Three Months Ended March 31, 2017 and 2016
 
Consolidated Statements of Stockholders’ Equity - Three Months Ended March 31, 2017 and 2016
 
 
 
 
 Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
Liquidity and Capital Resources
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

1


KINDER MORGAN, INC. AND SUBSIDIARIES
GLOSSARY

Company Abbreviations

CIG
=
Colorado Interstate Gas Company, L.L.C.
KMI
=
Kinder Morgan, Inc. and its majority-owned and/or
Copano
=
Copano Energy, L.L.C.
 
 
controlled subsidiaries
CPG
=
Cheyenne Plains Gas Pipeline Company, L.L.C.
KMP
=
Kinder Morgan Energy Partners, L.P. and its
Elba Express
=
Elba Express Company, L.L.C.
 
 
majority-owned and controlled subsidiaries
EPB
=
El Paso Pipeline Partners, L.P. and its majority-
KMR
=
Kinder Morgan Management, LLC
 
 
owned and controlled subsidiaries
SFPP
=
SFPP, L.P.
EPNG
=
El Paso Natural Gas Company, L.L.C.
SLNG
=
Southern LNG Company, L.L.C.
Hiland
=
Hiland Partners, LP
SNG
=
Southern Natural Gas Company, L.L.C.
KMEP
=
Kinder Morgan Energy Partners, L.P.
TGP
=
Tennessee Gas Pipeline Company, L.L.C.
KMGP
=
Kinder Morgan G.P., Inc.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
EPA
=
United States Environmental Protection Agency
BBtu
=
billion British Thermal Units
FASB
=
Financial Accounting Standards Board
Bcf
=
billion cubic feet
FERC
=
Federal Energy Regulatory Commission
CERCLA
=
Comprehensive Environmental Response,
GAAP
=
United States Generally Accepted Accounting
 
 
Compensation and Liability Act
 
 
Principles
CO2
=
carbon dioxide or our CO2 business segment
LLC
=
limited liability company
DCF
=
distributable cash flow
MBbl
=
thousand barrels
DD&A
=
depreciation, depletion and amortization
MMBbl
=
million barrels
EBDA
=
earnings before depreciation, depletion and
NGL
=
natural gas liquids
 
 
amortization expenses, including amortization of
OTC
=
over-the-counter
 
 
excess cost of equity investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.




2


Information Regarding Forward-Looking Statements

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

See “Information Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016 (2016 Form 10-K) for a more detailed description of factors that may affect the forward-looking statements. You should keep these risk factors in mind when considering forward-looking statements. These risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Because of these risks and uncertainties, you should not place undue reliance on any forward-looking statement. We plan to provide updates to projections included in this report when we believe previously disclosed projections no longer have a reasonable basis.


3


PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions, Except Per Share Amounts)
(Unaudited)
 
 
Three Months Ended March 31,
 
 
2017
 
2016
Revenues
 
 
 
 
Natural gas sales
 
$
809

 
$
543

Services
 
1,977

 
2,114

Product sales and other
 
638

 
538

Total Revenues
 
3,424

 
3,195

 
 
 
 
 
Operating Costs, Expenses and Other
 
 

 
 

Costs of sales
 
1,081

 
731

Operations and maintenance
 
513

 
565

Depreciation, depletion and amortization
 
558

 
551

General and administrative
 
181

 
190

Taxes, other than income taxes
 
104

 
108

Loss on impairments and divestitures, net
 
6

 
235

Other expense (income), net
 
1

 
(1
)
Total Operating Costs, Expenses and Other
 
2,444

 
2,379

 
 
 
 
 
Operating Income
 
980

 
816

 
 
 
 
 
Other Income (Expense)
 
 

 
 

Earnings from equity investments
 
175

 
100

Loss on impairments and divestitures of equity investments, net
 

 
(6
)
Amortization of excess cost of equity investments
 
(15
)
 
(14
)
Interest, net
 
(465
)
 
(441
)
Other, net
 
16

 
13

Total Other Expense
 
(289
)
 
(348
)
 
 
 
 
 
Income Before Income Taxes
 
691

 
468

 
 
 
 
 
Income Tax Expense
 
(246
)
 
(154
)
 
 
 
 
 
Net Income
 
445

 
314

 
 
 
 
 
Net (Income) Loss Attributable to Noncontrolling Interests
 
(5
)
 
1

 
 
 
 
 
Net Income Attributable to Kinder Morgan, Inc.
 
440

 
315

 
 
 
 
 
Preferred Stock Dividends
 
(39
)
 
(39
)
 
 
 
 
 
Net Income Available to Common Stockholders
 
$
401

 
$
276

 
 
 
 
 
Class P Shares
 
 
 
 
Basic Earnings Per Common Share
 
$
0.18

 
$
0.12

 
 
 
 
 
Basic Weighted Average Common Shares Outstanding
 
2,230

 
2,229

 
 
 
 
 
Diluted Earnings Per Common Share
 
$
0.18

 
$
0.12

 
 
 
 
 
Diluted Weighted Average Common Shares Outstanding
 
2,230

 
2,229

 
 
 
 
 
Dividends Per Common Share Declared for the Period
 
$
0.125

 
$
0.125


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

4


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Millions)
(Unaudited)
 
Three Months Ended March 31,
 
2017
 
2016
 
 
 
 
Net income
$
445

 
$
314

Other comprehensive income (loss), net of tax
 
 
 
Change in fair value of hedge derivatives (net of tax expense of $(39) and $(43), respectively)
70

 
73

Reclassification of change in fair value of derivatives to net income (net of tax benefit of $12 and $64, respectively)
(21
)
 
(108
)
Foreign currency translation adjustments (net of tax expense of $(7) and $(45), respectively)
13

 
78

Benefit plan adjustments (net of tax expense of $(5) and $(3), respectively)
6

 
4

Total other comprehensive income
68

 
47

 
 
 
 
Comprehensive income
513

 
361

Comprehensive (income) loss attributable to noncontrolling interests
(5
)
 
1

Comprehensive income attributable to Kinder Morgan, Inc.
$
508

 
$
362


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

5


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Millions, Except Share and Per Share Amounts)
 
March 31, 2017
 
December 31, 2016
 
(Unaudited)
 
 
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
396

 
$
684

Restricted deposits
90

 
103

Accounts receivable, net
1,263

 
1,370

Fair value of derivative contracts
213

 
198

Inventories
380

 
357

Income tax receivable
177

 
180

Other current assets
156

 
337

Total current assets
2,675

 
3,229

 
 
 
 
Property, plant and equipment, net
39,023

 
38,705

Investments
7,136

 
7,027

Goodwill
22,154

 
22,152

Other intangibles, net
3,263

 
3,318

Deferred income taxes
4,064

 
4,352

Deferred charges and other assets
1,478

 
1,522

Total Assets
$
79,793

 
$
80,305

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current Liabilities
 

 
 

Current portion of debt
$
3,928

 
$
2,696

Accounts payable
1,214

 
1,257

Accrued interest
444

 
625

Accrued contingencies
264

 
261

Other current liabilities
839

 
1,085

Total current liabilities
6,689

 
5,924

Long-term liabilities and deferred credits
 

 
 

Long-term debt
 

 
 

Outstanding
34,285

 
36,105

Preferred interest in general partner of KMP
100

 
100

Debt fair value adjustments
1,079

 
1,149

Total long-term debt
35,464

 
37,354

Other long-term liabilities and deferred credits
2,635

 
2,225

Total long-term liabilities and deferred credits
38,099

 
39,579

Total Liabilities
44,788

 
45,503

Commitments and contingencies (Notes 3 and 9)


 


Stockholders’ Equity
 

 
 

Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,230,149,554 and 2,230,102,384 shares, respectively, issued and outstanding
22

 
22

Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference, 1,600,000 shares issued and outstanding

 

Additional paid-in capital
41,756

 
41,739

Retained deficit
(6,540
)
 
(6,669
)
Accumulated other comprehensive loss
(593
)
 
(661
)
Total Kinder Morgan, Inc.’s stockholders’ equity
34,645

 
34,431

Noncontrolling interests
360

 
371

Total Stockholders’ Equity
35,005

 
34,802

Total Liabilities and Stockholders’ Equity
$
79,793

 
$
80,305


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

6


KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
(Unaudited)
 
Three Months Ended March 31,
 
2017
 
2016
Cash Flows From Operating Activities
 
 
 
Net income
$
445

 
$
314

Adjustments to reconcile net income to net cash provided by operating activities
 
 
 

Depreciation, depletion and amortization
558

 
551

Deferred income taxes
244

 
179

Amortization of excess cost of equity investments
15

 
14

Change in fair market value of derivative contracts
(6
)
 
(30
)
Loss on impairments and divestitures, net
6

 
235

Loss on impairments and divestitures of equity investments, net

 
6

Earnings from equity investments
(175
)
 
(100
)
Distributions from equity investment earnings
102

 
91

Changes in components of working capital, net of the effects of acquisitions and dispositions
 
 
 
Accounts receivable, net
105

 
116

Inventories
(35
)
 
46

Other current assets
10

 
14

Accounts payable
(35
)
 
(172
)
Accrued interest, net of interest rate swaps
(165
)
 
(159
)
Accrued contingencies and other current liabilities
(146
)
 
(23
)
Rate reparations, refunds and other litigation reserve adjustments

 
31

Other, net
(37
)
 
(63
)
Net Cash Provided by Operating Activities
886

 
1,050

 
 
 
 
Cash Flows From Investing Activities
 
 
 
Acquisitions of assets and investments, net of cash acquired
(4
)
 
(330
)
Capital expenditures
(664
)
 
(811
)
Sales of property, plant and equipment, and other net assets, net of removal costs
71

 
(6
)
Contributions to investments
(191
)
 
(44
)
Distributions from equity investments in excess of cumulative earnings
138

 
43

Other, net
13

 
4

Net Cash Used in Investing Activities
(637
)
 
(1,144
)
 
 
 
 
Cash Flows From Financing Activities
 
 
 
Issuances of debt
1,517

 
4,610

Payments of debt
(2,122
)
 
(4,336
)
Debt issue costs
(1
)
 
(6
)
Cash dividends - common shares
(280
)
 
(279
)
Cash dividends - preferred shares
(39
)
 
(37
)
Contributions from investment partner
391

 

Contributions from noncontrolling interests
6

 
87

Distributions to noncontrolling interests
(9
)
 
(4
)
Other, net
(1
)
 

Net Cash (Used in) Provided by Financing Activities
(538
)
 
35

 
 
 
 
Effect of Exchange Rate Changes on Cash and Cash Equivalents
1

 
5

 
 
 
 
Net decrease in Cash and Cash Equivalents
(288
)
 
(54
)
Cash and Cash Equivalents, beginning of period
684

 
229

Cash and Cash Equivalents, end of period
$
396

 
$
175

 
Non-cash Investing and Financing Activities
 
 
 
Assets acquired by the assumption or incurrence of liabilities
$

 
$
43

 
 
 
 
Supplemental Disclosures of Cash Flow Information
 
 
 
Cash paid during the period for interest (net of capitalized interest)
$
643

 
$
659

Cash refund during the period for income taxes, net
(2
)
 
(2
)

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

7


KINDER MORGAN, INC. AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In Millions)
(Unaudited)
 
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
Balance at December 31, 2016
2,230

 
$
22

 
2

 
$

 
$
41,739

 
$
(6,669
)
 
$
(661
)
 
$
34,431

 
$
371

 
$
34,802

Restricted shares
 
 
 
 
 
 
 
 
18

 
 
 
 
 
18

 
 
 
18

Net income
 
 
 
 
 
 
 
 
 
 
440

 
 
 
440

 
5

 
445

Distributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
(9
)
 
(9
)
Contributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
6

 
6

Preferred stock dividends
 
 
 
 
 
 
 
 
 
 
(39
)
 
 
 
(39
)
 
 
 
(39
)
Common stock dividends
 
 
 
 
 
 
 
 
 
 
(280
)
 
 
 
(280
)
 
 
 
(280
)
Impact of adoption of ASU 2016-09 (See Note 8)
 
 
 
 
 
 
 
 
 
 
8

 
 
 
8

 
 
 
8

Other
 
 
 
 
 
 
 
 
(1
)
 
 
 
 
 
(1
)
 
(13
)
 
(14
)
Other comprehensive income
 
 
 
 
 
 
 
 
 
 
 
 
68

 
68

 

 
68

Balance at March 31, 2017
2,230

 
$
22

 
2

 
$

 
$
41,756

 
$
(6,540
)
 
$
(593
)
 
$
34,645

 
$
360

 
$
35,005


 
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
Balance at December 31, 2015
2,229

 
$
22

 
2

 
$

 
$
41,661

 
$
(6,103
)
 
$
(461
)
 
$
35,119

 
$
284

 
$
35,403

Restricted shares
 
 
 
 
 
 
 
 
17

 
 
 
 
 
17

 
 
 
17

Net income
 
 
 
 
 
 
 
 
 
 
315

 
 
 
315

 
(1
)
 
314

Distributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
(4
)
 
(4
)
Contributions
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
87

 
87

Preferred stock dividends
 
 
 
 
 
 
 
 
 
 
(39
)
 
 
 
(39
)
 
 
 
(39
)
Common stock dividends
 
 
 
 
 
 
 
 
 
 
(279
)
 
 
 
(279
)
 
 
 
(279
)
Other comprehensive income
 
 
 
 
 
 
 
 
 
 
 
 
47

 
47

 
 
 
47

Balance at March 31, 2016
2,229

 
$
22

 
2

 
$

 
$
41,678

 
$
(6,106
)
 
$
(414
)
 
$
35,180

 
$
366

 
$
35,546



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

8


KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.  General
 
Organization

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.

Basis of Presentation
 
General

Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the United States Securities and Exchange Commission (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.

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair presentation of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2016 Form 10-K.

Impairments and Losses on Divestitures

During the three months ended March 31, 2017 and 2016, we recorded non-cash pre-tax losses on impairments and divestitures netting to $6 million and $235 million, respectively. The three months ended March 31, 2017 and 2016 included net losses of $6 million and $11 million on miscellaneous asset disposals. The three months ended March 31, 2016 also included $191 million of project write-offs across our Natural Gas Pipelines, CO2, and Products Pipelines business segments, along with $20 million of impairments related to certain coal facilities in our Terminals business segment and a $13 million loss related to the sale of a Transmix facility in our Products Pipelines business segment.

These impairments were driven by market conditions that existed at the time and 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 impairments. 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 assets, including some 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 be not fully recoverable.


9


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.

The following table sets forth the allocation of net income available to shareholders of Class P shares and participating securities (in millions):
 
Three Months Ended March 31,

2017
 
2016
Class P shares
$
399

 
$
275

Participating securities:
 
 
 
   Restricted stock awards(a)
2

 
1

Net Income Available to Common Stockholders
$
401

 
$
276

________
(a)
As of March 31, 2017, there were approximately 9 million 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):
 
Three Months Ended March 31,
 
2017
 
2016
Unvested restricted stock awards
9

 
8

Warrants to purchase our Class P shares(a)
293

 
293

Convertible trust preferred securities
8

 
8

Mandatory convertible preferred stock(b)
58

 
58

_______
(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.

2.  Divestiture
 
Sale of Interest in Elba Liquefaction Company L.L.C. (ELC)

Effective February 28, 2017, we sold a 49% partnership interest in ELC to investment funds managed by EIG Global Energy Partners (EIG). We continue to own a 51% controlling interest in and operate ELC. Under the terms of ELC’s limited liability company agreement, we are responsible for placing in service and operating certain supply pipelines and terminal facilities that support the operations of ELC and which are wholly owned by us. In certain limited circumstances which are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account. We have, as a result of these contingencies, reflected the $391 million of total contributions from EIG, consisting of $387 million of proceeds from the sale and $4 million as an additional contribution for March 2017 capital expenditures, as a deferred credit within “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of March 31, 2017. EIG is not entitled to any specified return on its capital. Once these contingencies expire, EIG’s capital account will be reflected as noncontrolling interest on our balance sheet.
3. 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.

10



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):
 
March 31, 2017
 
December 31, 2016
Unsecured term loan facility, variable rate, due January 26, 2019
$
1,000

 
$
1,000

Senior notes, 1.50% through 8.05%, due 2017 through 2098(a)
13,253

 
13,236

Credit facility due November 26, 2019

 

Commercial paper borrowings

 

KMP senior notes, 2.65% through 9.00%, due 2017 through 2044(b)
18,885

 
19,485

TGP senior notes, 7.00% through 8.375%, due 2017 through 2037
1,540

 
1,540

EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032
1,115

 
1,115

CIG senior notes, 4.15% and 6.85%, due 2026 and 2037
475

 
475

Kinder Morgan Finance Company, LLC, senior notes, 6.00% and 6.40%, due 2018 and 2036
786

 
786

Hiland Partners Holdings LLC, senior note, 5.50%, due 2022
225

 
225

EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035
430

 
433

Trust I preferred securities, 4.75%, due March 31, 2028
221

 
221

KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock
100

 
100

Other miscellaneous debt
283

 
285

Total debt – KMI and Subsidiaries
38,313

 
38,901

Less: Current portion of debt(c)
3,928

 
2,696

Total long-term debt – KMI and Subsidiaries(d)
$
34,385

 
$
36,205

_______
(a)
Amount includes senior notes that are denominated in Euros and have been converted to U.S. dollars and are respectively reported above at the March 31, 2017 exchange rate of 1.0652 U.S. dollars per Euro and the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro. For the three months ended March 31, 2017, our debt balance increased by $17 million as a result of the change in the exchange rate of U.S. dollars per Euro. The increase 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 5 “Risk Management—Foreign Currency Risk Management”).
(b)
In February 2017, we repaid $600 million of maturing 6.00% senior notes.
(c)
Amounts include outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months (see “—Current Portion of Debt” below).
(d)
Excludes our “Debt fair value adjustments” which, as of March 31, 2017 and December 31, 2016, increased our combined debt balances by $1,079 million and $1,149 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.

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 11.

Credit Facilities
 
As of March 31, 2017, we had $4,881 million available under our $5.0 billion revolving credit agreement, which is net of $119 million in letters of credit. Borrowings 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 reduce the borrowings allowed under our credit facility.


11


Current Portion of Debt
Our current portion of debt as of March 31, 2017, primarily includes the following significant series of long-term notes maturing within the next 12 months:
$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
$750 million 6.00% notes due January 2018
$82 million 7.00% notes due February 2018
$975 million 5.95% notes due February 2018
 
Subsequent Event—Debt Repayments

In April 2017, we repaid $300 million of maturing 7.50% TGP senior notes and $355 million of maturing 5.95% EPNG senior notes listed above in current portion of debt as of March 31, 2017.
4.  Stockholders’ Equity
 
Common Equity
 
As of March 31, 2017, our common equity consisted of our Class P common stock. For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2016 Form 10-K.

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. Our per share dividends declared for and paid in the periods ended March 31, 2017 and 2016 were $0.125 per share. On April 19, 2017, our board of directors declared a cash dividend of $0.125 per common share for the quarterly period ended March 31, 2017, which is payable on May 15, 2017 to common shareholders of record as of May 1, 2017.

Mandatory Convertible Preferred Stock

We have issued and outstanding 1,600,000 shares of 9.750% Series A mandatory convertible preferred stock, with a liquidating preference of $1,000 per share. For additional information regarding our mandatory convertible preferred stock, see Note 11 to our consolidated financial statements included in our 2016 Form 10-K.

Preferred Dividends

On January 18, 2017, our board of directors declared a cash dividend of $24.375 per share of our mandatory convertible preferred stock (equivalent of $1.21875 per depositary share) for the period from and including January 26, 2017 through and including April 25, 2017, which is payable on April 26, 2017 to mandatory convertible preferred shareholders of record as of April 11, 2017.

5.  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 some of these risks. In addition, prior to May 2016, we had power forward and swap contracts related to legacy operations of acquired businesses.


12


Energy Commodity Price Risk Management
 
As of March 31, 2017, 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
(19.4
)
 
MMBbl
Crude oil basis
(3.3
)
 
MMBbl
Natural gas fixed price
(50.3
)
 
Bcf
Natural gas basis
(21.1
)
 
Bcf
Derivatives not designated as hedging contracts
 

 
 
Crude oil fixed price
(1.3
)
 
MMBbl
Crude oil basis
(0.5
)
 
MMBbl
Natural gas fixed price
1.5

 
Bcf
Natural gas basis
2.2

 
Bcf
NGL and other fixed price
(5.8
)
 
MMBbl

As of March 31, 2017, 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 2021.

Interest Rate Risk Management

 As of March 31, 2017 and December 31, 2016, we had a combined notional principal amount of $9,575 million and $9,775 million, respectively, of fixed-to-variable interest rate swap agreements, all of which 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 London Interbank Offered Rate plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of March 31, 2017, 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

As of March 31, 2017, we had a notional principal amount of $1,358 million of cross-currency swap agreements to manage the foreign currency risk related to our Euro denominated senior notes 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. 

13



Fair Value of Derivative Contracts
 
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions):
Fair Value of Derivative Contracts
 
 
 
 
Asset derivatives
 
Liability derivatives
 
 
 
 
March 31,
2017
 
December 31,
2016
 
March 31,
2017
 
December 31,
2016
 
 
Location
 
Fair value
 
Fair value
Derivatives designated as hedging contracts
 
 
 
 
 
 
 
 
 
 
Natural gas and crude derivative contracts
 
Fair value of derivative contracts/(Other current liabilities)
 
$
119

 
$
101

 
$
(22
)
 
$
(57
)
 
 
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
 
81

 
70

 
(7
)
 
(24
)
Subtotal
 
 
 
200

 
171

 
(29
)
 
(81
)
Interest rate swap agreements
 
Fair value of derivative contracts/(Other current liabilities)
 
86

 
94

 

 

 
 
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
 
175

 
206

 
(57
)
 
(57
)
Subtotal
 
 
 
261

 
300

 
(57
)
 
(57
)
Cross-currency swap agreements
 
Fair value of derivative contracts/(Other current liabilities)
 

 

 
(30
)
 
(7
)
 
 
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
 
7

 

 
(5
)
 
(24
)
Subtotal
 
 
 
7

 

 
(35
)
 
(31
)
Total
 
 
 
468

 
471

 
(121
)
 
(169
)
 
 
 
 
 
 
 
 
 
 
 
Derivatives not designated as hedging contracts
 
 
 
 

 
 
 
 

 
 
Natural gas, crude, NGL and other derivative contracts
 
Fair value of derivative contracts/(Other current liabilities)
 
8

 
3

 
(10
)
 
(29
)
 
 
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
 

 

 
(1
)
 
(1
)
Subtotal
 
 
 
8

 
3

 
(11
)
 
(30
)
Total
 
 
 
8

 
3

 
(11
)
 
(30
)
Total derivatives
 
 
 
$
476

 
$
474

 
$
(132
)
 
$
(199
)



14


Effect of Derivative Contracts on the Income Statement
 
The following tables summarize the impact of our derivative contracts in our accompanying consolidated statements of income (in millions): 
Derivatives in fair value hedging relationships
 
Location
 
Gain/(loss) recognized in income
on derivatives and related hedged item
 
 
 
 
Three Months Ended March 31,
 
 
 
 
2017
 
2016
 
 
 
 
 
 
 
Interest rate swap agreements
 
Interest, net
 
$
(39
)
 
$
280

 
 
 
 
 
 
 
Hedged fixed rate debt
 
Interest, net
 
$
36

 
$
(284
)

Derivatives in cash flow hedging relationships
 
Gain/(loss)
recognized in OCI on derivative (effective portion)(a)
 
Location
 
Gain/(loss) reclassified from Accumulated OCI
into income (effective portion)(b)
 
Location
 
Gain/(loss)
recognized in income
on derivative
(ineffective portion
and amount
excluded from
effectiveness testing)
 
 
Three Months Ended March 31,
 
 
 
Three Months Ended March 31,
 
 
 
Three Months Ended March 31,
 
 
2017
 
2016
 
 
 
2017
 
2016
 
 
 
2017
 
2016
Energy commodity
 derivative contracts
 
$
68

 
$
27

 
Revenues—Natural
 gas sales
 
$
2

 
$
21

 
Revenues—Natural
 gas sales
 
$

 
$

 
 
 
 
 
 
Revenues—Product
 sales and other
 
6

 
57

 
Revenues—Product
 sales and other
 
3

 
1

 
 
 
 
 
 
Costs of sales
 
3

 
(10
)
 
Costs of sales
 

 

Interest rate swap
 agreements(c)
 

 
(4
)
 
Interest, net
 

 
(1
)
 
Interest, net
 

 

Cross-currency swap
 
2

 
50

 
Other, net
 
10

 
41

 
Other, net
 

 

Total
 
$
70

 
$
73

 
Total
 
$
21

 
$
108

 
Total
 
$
3

 
$
1

_____
(a)
We expect to reclassify an approximate $25 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of March 31, 2017 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.
Derivatives not designated as accounting hedges
 
Location
 
Gain/(loss) recognized in income on derivatives
 
 
 
 
Three Months Ended March 31,
 
 
 
 
2017
 
2016
Energy commodity derivative contracts
 
Revenues—Natural gas sales
 
$
6

 
$
6

 
 
Revenues—Product sales and other
 
12

 
(2
)
 
 
Costs of sales
 

 
(5
)
Interest rate swap agreements
 
Interest, net
 

 
53

Total(a)
 
 
 
$
18

 
$
52

_______
(a) The three months ended March 31, 2017 and 2016 include approximate gains of $12 million and $19 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.


15


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 March 31, 2017 and December 31, 2016, we had no outstanding letters of credit supporting our commodity price risk management program. As of March 31, 2017 and December 31, 2016, we had cash margins of $26 million and $37 million, respectively, posted by us with our counterparties as collateral and no amounts posted by our counterparties as collateral. The balance at March 31, 2017, consisted of initial margin requirements of $15 million and variation margin requirements of $11 million. 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 master 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 March 31, 2017, based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches we would not be required to post additional collateral.

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, 2016
$
(1
)
 
$
(288
)
 
$
(372
)
 
$
(661
)
Other comprehensive gain before reclassifications
70

 
13

 
6

 
89

Gains reclassified from accumulated other comprehensive loss
(21
)
 

 

 
(21
)
Net current-period other comprehensive income
49

 
13

 
6

 
68

Balance as of March 31, 2017
$
48

 
$
(275
)
 
$
(366
)
 
$
(593
)

 
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, 2015
$
219

 
$
(322
)
 
$
(358
)
 
$
(461
)
Other comprehensive gain before reclassifications
73

 
78

 
4

 
155

Gains reclassified from accumulated other comprehensive loss
(108
)
 

 

 
(108
)
Net current-period other comprehensive (loss) income
(35
)
 
78

 
4

 
47

Balance as of March 31, 2016
$
184

 
$
(244
)
 
$
(354
)
 
$
(414
)

6.  Fair Value
 
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.

16



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).
 
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
 
 
 
Net amount
 
Level 1
 
Level 2
 
Level 3
 
Gross amount
 
Contracts available for netting
 
Cash collateral held
As of March 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
Energy commodity derivative contracts(a)
$
3

 
$
205

 
$

 
$
208

 
$
(19
)
 
$

 
$
189

Interest rate swap agreements

 
261

 

 
261

 
(26
)
 

 
235

Cross-currency swap agreements

 
7

 

 
7

 
(7
)
 

 

As of December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
Energy commodity derivative contracts(a)
$
6

 
$
168

 
$

 
$
174

 
$
(43
)
 
$

 
$
131

Interest rate swap agreements

 
300

 

 
300

 
(18
)
 

 
282


 
Balance sheet liability
fair value measurements by level
 
 
 
Net amount
 
Level 1
 
Level 2
 
Level 3
 
Gross amount
 
Contracts available for netting
 
Collateral posted(b)
As of March 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
Energy commodity derivative contracts(a)
$
(13
)
 
$
(27
)
 
$

 
$
(40
)
 
$
19

 
$
11

 
$
(10
)
Interest rate swap agreements

 
(57
)
 

 
(57
)
 
26

 

 
(31
)
Cross-currency swap agreements

 
(35
)
 

 
(35
)
 
7

 

 
(28
)
As of December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
Energy commodity derivative contracts(a)
$
(29
)
 
$
(82
)
 
$

 
$
(111
)
 
$
43

 
$
37

 
$
(31
)
Interest rate swap agreements

 
(57
)
 

 
(57
)
 
18

 

 
(39
)
Cross-currency swap agreements

 
(31
)
 

 
(31
)
 

 

 
(31
)
_______
(a)
Level 1 consists primarily of New York Mercantile Exchange natural gas futures.  Level 2 consists primarily of OTC West Texas Intermediate swaps and options.  
(b)
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. Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.


17


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)
 
Three Months Ended March 31,
 
2017
 
2016
Derivatives-net asset (liability)
 
 
 
Beginning of Period
$

 
$
(15
)
Total gains or (losses) included in earnings

 
(6
)
Settlements

 
19

End of Period
$

 
$
(2
)
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
$

 
$
1


As of March 31, 2016, 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 would not expect materially different valuation results were we to use different input amounts within reasonable ranges.

Fair Value of Financial Instruments
 
The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions): 
 
March 31, 2017
 
December 31, 2016
 
Carrying
value
 
Estimated
fair value
 
Carrying
value
 
Estimated
fair value
Total debt
$
39,392

 
$
40,467

 
$
40,050

 
$
41,015

 
We used Level 2 input values to measure the estimated fair value of our outstanding debt balances as of both March 31, 2017 and December 31, 2016.

7.  Reportable Segments
Segment results for the three months ended March 31, 2016 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.

18


Financial information by segment follows (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Revenues
 
 
 
Natural Gas Pipelines
 
 
 
    Revenues from external customers
$
2,168

 
$
1,970

    Intersegment revenues
3

 
1

CO2
303

 
302

Terminals
487

 
465

Products Pipelines
 
 
 
    Revenues from external customers
398

 
391

    Intersegment revenues
4

 
5

Kinder Morgan Canada
59

 
59

Corporate and intersegment eliminations(a)
2

 
2

Total consolidated revenues
$
3,424

 
$
3,195

 
Three Months Ended March 31,
 
2017
 
2016
Segment EBDA(b)
 
 
 
Natural Gas Pipelines
$
1,055

 
$
994

CO2
218

 
187

Terminals
307

 
260

Products Pipelines
287

 
177

Kinder Morgan Canada
43

 
46

Total Segment EBDA
1,910

 
1,664

DD&A
(558
)
 
(551
)
Amortization of excess cost of equity investments
(15
)
 
(14
)
General and administrative and corporate charges
(181
)
 
(190
)
Interest expense, net
(465
)
 
(441
)
Income tax expense
(246
)
 
(154
)
Total consolidated net income
$
445

 
$
314

 
March 31, 2017
 
December 31, 2016
Assets
 
 
 
Natural Gas Pipelines
$
50,418

 
$
50,428

CO2
4,104

 
4,065

Terminals
9,809

 
9,725

Products Pipelines
8,353

 
8,329

Kinder Morgan Canada
1,638

 
1,572

Corporate assets(c)
5,469

 
6,108

Assets held for sale
2

 
78

Total consolidated assets
$
79,793

 
$
80,305

_______
(a)
Includes a management fee for services we perform as operator of an equity investee.
(b)
Includes revenues, earnings from equity investments, other, net, less operating expenses, and other (income) expense, net, loss on impairments and divestitures, net and loss on impairments and divestitures of equity investments, net.
(c)
Includes cash and cash equivalents, margin and restricted deposits, 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.


19


8.  Income Taxes
 
Income tax expense included in our accompanying consolidated statements of income were as follows (in millions, except percentages): 
 
Three Months Ended March 31,
 
2017
 
2016
Income tax expense
$
246

 
$
154

Effective tax rate
35.6
%
 
32.9
%

The effective tax rate for the three months ended March 31, 2017 is slightly higher than the statutory federal rate of 35% primarily due to state and foreign income taxes, partially offset by dividend-received deductions from our investment in Florida Gas Transmission Company (Citrus) and Plantation Pipe Line.

The effective tax rate for the three months ended March 31, 2016 is lower than the statutory federal rate of 35% primarily due to dividend-received deductions from our investment in Citrus and adjustments to our income tax reserve for uncertain tax positions, partially offset by state and foreign income taxes.

Adoption of ASU 2016-09“Compensation - Stock Compensation (Topic 718)”

The tax impact of ASU 2016-09, which was adopted and effective January 1, 2017, resulted in $8 million of deferred tax assets being recorded through a cumulative-effect adjustment to our retained deficit. The previously unrecorded deferred tax asset is related to net operating loss carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Post-adoption the excess tax benefits or deficiencies are recognized for income tax purposes in the period in which they occur through the income statement.

9.  Litigation, Environmental and Other Contingencies
 
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 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 $200 million in refunds. Management believes SFPP

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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 arguments were held on February 15, 2017. On February 21, 2017, the reviewing court delayed the case until FERC rules on the rehearing requests pending in the 2010 Rate Case. 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 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 is expected to retry the 2004 rental dispute in April, 2018. Until the 2004 rental dispute is resolved, the parties have stayed the proceeding to establish rent for the rental term beginning in 2014.

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

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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. On April 19, 2017, the federal district court in Arizona denied plaintiffs’ motion for class certification. 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 four months. Eni USA has indicated that it will continue to pay the amounts claimed to be due 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 will continue to contest it vigorously.

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 arose 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 alleged 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. 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

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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. 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. 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. After the filing of an agreed stipulation and order of dismissal, the remaining lawsuits (Brinckerhoff III and IV) were dismissed by the Chancery Court on March 2, 2017, thereby successfully terminating all remaining litigation involving the drop down transactions.

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 district court, were dismissed, but the dismissal was reversed by the 9th Circuit Court of Appeals. The U.S. Supreme Court affirmed the 9th Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the Nevada federal district court for further consideration and trial, if necessary, of numerous remaining issues. On May 24, 2016, the district 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 in which approximately $300 million in damages has been alleged against all defendants, the district court denied plaintiff’s motion for class certification. Plaintiff has petitioned the 9th Circuit Court of Appeals for an interlocutory review of this ruling. 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.

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 March 31, 2017 and December 31, 2016, our total reserve for legal matters was $413 million and $407 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline segments.

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 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.

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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