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 84,300 miles of pipelines and 157 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, crude oil, diesel fuel, chemicals, metals and petroleum coke.
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 U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. In compliance with 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 statement 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 2018 Form 10-K.
The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.
For a discussion of Accounting Standards Updates (ASU) we adopted on January 1, 2019 and 2018, see Notes 4, 5 and 10.
Goodwill
We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six 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; and (vi) Terminals. The evaluation of goodwill for impairment involves a two-step test.
The results of our May 31, 2019 annual step 1 impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. A future period of volatile commodity prices could result in a deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital and our cash flow estimates. Changes to any one or combination of these factors would result in a change to the reporting unit fair values discussed above, which could lead to future impairment charges. Such potential impairment could have a material effect on our results of operations.
The fair value estimates used in step 1 of the goodwill test are based on Level 3 inputs of the fair value hierarchy. The level 3 inputs include valuation estimates using industry standard market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions prices, weighted average costs of capital, 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. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit.
Earnings per Share
We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares 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 restricted stock or restricted stock units issued to employees and non-employee directors 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 September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Net Income Available to Common Stockholders
|
$
|
506
|
|
|
$
|
693
|
|
|
$
|
1,580
|
|
|
$
|
998
|
|
Participating securities:
|
|
|
|
|
|
|
|
Less: Net Income allocated to restricted stock awards(a)
|
(3
|
)
|
|
(4
|
)
|
|
(9
|
)
|
|
(5
|
)
|
Net Income Allocated to Class P Stockholders
|
$
|
503
|
|
|
$
|
689
|
|
|
$
|
1,571
|
|
|
$
|
993
|
|
|
|
|
|
|
|
|
|
Basic Weighted Average Common Shares Outstanding
|
2,264
|
|
|
2,205
|
|
|
2,263
|
|
|
2,205
|
|
Basic Earnings Per Common Share
|
$
|
0.22
|
|
|
$
|
0.31
|
|
|
$
|
0.69
|
|
|
$
|
0.45
|
|
________
|
|
(a)
|
As of September 30, 2019, there were approximately 12 million restricted stock awards outstanding.
|
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 September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Unvested restricted stock awards
|
13
|
|
|
13
|
|
|
13
|
|
|
11
|
|
Convertible trust preferred securities
|
3
|
|
|
3
|
|
|
3
|
|
|
3
|
|
Mandatory convertible preferred stock(a)
|
—
|
|
|
58
|
|
|
—
|
|
|
58
|
|
_______
|
|
(a)
|
The holder of each convertible preferred share participated in our earnings by receiving preferred stock dividends through the mandatory conversion date of October 26, 2018, at which time our convertible preferred shares were converted to common shares.
|
2. Divestitures
Pending Sale of U.S. Portion of Cochin Pipeline and KML
On August 21, 2019, we announced an agreement to sell the U.S. portion of the Cochin Pipeline to Pembina Pipeline Corporation (Pembina) for $1.546 billion in cash. Also, KML announced that it reached an agreement with Pembina under which Pembina has agreed to acquire all of the outstanding common equity of KML, including our 70% interest, subject to the terms of the arrangement agreement between KML and Pembina. Subject to and upon closing, KML shareholders will receive 0.3068 shares of Pembina common stock for each share of KML common stock whereby we will receive approximately 25 million shares of Pembina common stock, with a pre-tax value of approximately $927 million as of September 30, 2019, for our 70% interest in KML. The closing of the two transactions are cross-conditioned upon each other, subject to KML’s shareholder and applicable regulatory approvals.
Sale of Trans Mountain Pipeline System and Its Expansion Project
On August 31, 2018, KML completed the sale of the TMPL, the TMEP, Puget Sound pipeline system and Kinder Morgan Canada Inc., the Canadian employer of our staff that operate the business, which were indirectly acquired by the Government of Canada through Trans Mountain Corporation (a subsidiary of the Canada Development Investment Corporation) for net cash consideration of C$4.43 billion (U.S.$3.4 billion), net of working capital adjustments (TMPL Sale). We recognized a pre-tax
gain from the TMPL Sale of $622 million within “(Gain) loss on divestitures and impairments, net” in our accompanying consolidated statements of income during both the three and nine months ended September 30, 2018. During the first quarter of 2019, KML settled an additional C$37 million (U.S.$28 million) of working capital adjustments, which amount is included in the accompanying consolidated statements of cash flows within “Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments” for the nine months ended September 30, 2019 and which we had substantially accrued for as of December 31, 2018.
On January 3, 2019, KML distributed the net proceeds from the TMPL Sale to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70% portion of the net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used to repay our outstanding commercial paper borrowings of $0.4 billion, and in February 2019, to pay down approximately $1.3 billion of maturing long-term debt.
3. Debt
The following table provides information 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):
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
Current portion of debt
|
|
|
|
$500 million, 364-day credit facility due November 15, 2019
|
$
|
—
|
|
|
$
|
—
|
|
$4 billion credit facility due November 16, 2023
|
—
|
|
|
—
|
|
Commercial paper notes(a)
|
532
|
|
|
433
|
|
KML C$500 million credit facility, due August 31, 2022(b)(c)
|
34
|
|
|
—
|
|
Current portion of senior notes
|
|
|
|
9.00%, due February 2019
|
—
|
|
|
500
|
|
2.65%, due February 2019
|
—
|
|
|
800
|
|
3.05%, due December 2019
|
1,500
|
|
|
1,500
|
|
6.85%, due February 2020
|
700
|
|
|
—
|
|
6.50%, due April 2020
|
535
|
|
|
—
|
|
5.30%, due September 2020
|
600
|
|
|
—
|
|
6.50%, due September 2020
|
349
|
|
|
—
|
|
Trust I preferred securities, 4.75%, due March 2028
|
111
|
|
|
111
|
|
Current portion of other debt
|
45
|
|
|
44
|
|
Total current portion of debt
|
4,406
|
|
|
3,388
|
|
|
|
|
|
Long-term debt (excluding current portion)
|
|
|
|
Senior notes
|
30,124
|
|
|
32,380
|
|
EPC Building, LLC, promissory note, 3.967%, due 2018 through 2035
|
385
|
|
|
395
|
|
Kinder Morgan G.P. Inc., $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d)
|
100
|
|
|
100
|
|
Trust I preferred securities, 4.75%, due March 2028
|
110
|
|
|
110
|
|
Other
|
230
|
|
|
220
|
|
Total long-term debt
|
30,949
|
|
|
33,205
|
|
Total debt(e)
|
$
|
35,355
|
|
|
$
|
36,593
|
|
_______
|
|
(a)
|
Weighted average interest rates on borrowings outstanding as of September 30, 2019 and December 31, 2018 were 2.47% and 3.10%, respectively.
|
|
|
(b)
|
Weighted average interest rate on borrowings outstanding as of September 30, 2019 was 3.41%.
|
|
|
(c)
|
Borrowings under the KML $500 million credit facility are denominated in C$ and are presented above in U.S. dollars. At September 30, 2019, the exchange rate was 0.7551 U.S. dollars per C$. See “—Credit Facilities—KML” below.
|
|
|
(d)
|
On July 17, 2019, we entered into a guarantee agreement for the payment obligations to the holders of these securities.
|
|
|
(e)
|
Excludes our “Debt fair value adjustments” which, as of September 30, 2019 and December 31, 2018, increased our total debt balances by $1,162 million and $731 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 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. For more information, see Note 13.
Credit Facilities
KMI
As of September 30, 2019, we had no borrowings outstanding under our $4.5 billion credit facilities (in the aggregate), $532 million outstanding under our commercial paper program and $84 million in letters of credit. Our availability under the credit facilities as of September 30, 2019 was $3,884 million. As of September 30, 2019, we were in compliance with all required covenants.
KML
As of September 30, 2019, KML had C$45 million (U.S.$34 million) of borrowings outstanding under its 4-year, C$500 million unsecured revolving credit facility, due August 31, 2022, with C$452 million (U.S.$341 million) available after further reducing the C$500 million (U.S.$378 million) capacity for C$3 million (U.S.$3 million) in letters of credit. As of September 30, 2019, KML was in compliance with all required covenants. As of December 31, 2018, KML had no borrowings outstanding under its credit facility.
4. Stockholders’ Equity
Common Equity
As of September 30, 2019, 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 2018 Form 10-K.
On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the nine months ended September 30, 2019, we settled repurchases of approximately 0.1 million of our Class P shares for approximately $2 million. Since December 2017, in total, we have repurchased approximately 29 million of our Class P shares under the program at an average price of approximately $18.18 per share for approximately $525 million.
KMI Common Stock Dividends
Holders of our common stock participate in common stock dividends 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Per common share cash dividend declared for the period
|
$
|
0.25
|
|
|
$
|
0.20
|
|
|
$
|
0.75
|
|
|
$
|
0.60
|
|
Per common share cash dividend paid in the period
|
$
|
0.25
|
|
|
$
|
0.20
|
|
|
$
|
0.70
|
|
|
$
|
0.525
|
|
On October 16, 2019, our board of directors declared a cash dividend of $0.25 per common share for the quarterly period ended September 30, 2019, which is payable on November 15, 2019 to common shareholders of record as of the close of business on October 31, 2019.
Noncontrolling Interests
KML
On August 21, 2019, KML announced that it reached an agreement with Pembina under which Pembina has agreed to acquire all the outstanding common and preferred equity of KML, including our 70% interest. See Note 2 for more information.
Distributions
KML has a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. For additional information regarding our KML distributions, see Note 11 to our consolidated financial statements included in our 2018 Form 10-K.
During the three and nine months ended September 30, 2019, KML paid dividends to the public on its restricted voting shares of $4 million and $13 million, respectively, and on its Series 1 and Series 3 Preferred Shares of $5 million and $16 million, respectively.
On January 3, 2019, KML distributed approximately $0.9 billion of the net proceeds from the TMPL Sale to its restricted voting shareholders as a return of capital.
Adoption of Accounting Pronouncements
On January 1, 2018, we adopted ASU No. 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets.” This ASU clarifies the scope and application of ASC 610-20 on contracts for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU also clarifies that the derecognition of all businesses is in the scope of ASC 810 and defines an “in substance nonfinancial asset.” We utilized the modified retrospective method to adopt the provisions of this ASU, which required us to apply the new standard to (i) all new contracts entered into after January 1, 2018, and (ii) to contracts that were not completed contracts as of January 1, 2018 through a cumulative adjustment to our “Retained deficit” balance. The cumulative effect of our adoption of this ASU was a $66 million, net of income taxes, adjustment to our beginning “Retained deficit” balance as presented in our consolidated statement of stockholders’ equity for the nine months ended September 30, 2018. This ASU also required us to classify EIG’s cumulative contribution to ELC as mezzanine equity, which we have included as “Redeemable noncontrolling interest” on our consolidated balance sheets as of September 30, 2019 and December 31, 2018, as EIG has the right to redeem their interests for cash under certain conditions.
On January 1, 2018, we adopted ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” Our accounting policy for the release of stranded tax effects in accumulated other comprehensive income is on an aggregate portfolio basis. This ASU permits companies to reclassify the income tax effects of the 2017 Tax Reform on items within accumulated other comprehensive income to retained earnings. The FASB refers to these amounts as “stranded tax effects.” Only the stranded tax effects resulting from the 2017 Tax Reform are eligible for reclassification. Our adoption of this ASU resulted in a $109 million reclassification adjustment of stranded income tax effects from “Accumulated other comprehensive loss” to “Retained deficit” on our consolidated statement of stockholders’ equity for the nine months ended September 30, 2018.
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 and net investments in foreign operations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.
On January 1, 2019, we adopted ASU No. 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The ASU better aligns an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. We applied ASU No. 2017-12 using a modified retrospective approach for cash flow and fair value hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. Our adoption of ASU No. 2017-12 did not have a material impact on our consolidated financial statements.
Energy Commodity Price Risk Management
As of September 30, 2019, 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 instruments
|
|
|
|
Crude oil fixed price
|
(20.0
|
)
|
|
MMBbl
|
Crude oil basis
|
(8.8
|
)
|
|
MMBbl
|
Natural gas fixed price
|
(46.5
|
)
|
|
Bcf
|
Natural gas basis
|
(36.0
|
)
|
|
Bcf
|
NGL fixed price
|
(0.9
|
)
|
|
MMBbl
|
Derivatives not designated as hedging instruments
|
|
|
|
|
Crude oil fixed price
|
(0.8
|
)
|
|
MMBbl
|
Crude oil basis
|
(5.0
|
)
|
|
MMBbl
|
Natural gas fixed price
|
(8.3
|
)
|
|
Bcf
|
Natural gas basis
|
(18.2
|
)
|
|
Bcf
|
NGL fixed price
|
(2.2
|
)
|
|
MMBbl
|
As of September 30, 2019, 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 2023.
Interest Rate Risk Management
As of September 30, 2019 and December 31, 2018, we had a combined notional principal amount of $10,225 million and $10,575 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 the London Interbank Offered Rate (LIBOR) plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of September 30, 2019, the principal amount of hedged senior notes consisted of $2,600 million included in “Current portion of debt” and $7,625 million included in “Long-term debt” on our accompanying consolidated balance sheets. As of September 30, 2019, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of debt due to interest rate risk is through March 15, 2035.
During the nine months ended September 30, 2019, we entered into a floating-to-fixed interest rate swap agreement with a notional principal amount of $250 million, which was designated as a cash flow hedge. This agreement effectively converts the interest expense associated with certain variable rate debt issuances from floating rates to fixed rates. As of September 30, 2019, the maximum length of time over which we have hedged a portion of our exposure to the variability in future interest payments is through January 15, 2023.
Foreign Currency Risk Management
As of both September 30, 2019 and December 31, 2018, we had a combined 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 critical terms of the cross-currency swap agreements correspond to the related hedged senior notes.
During the year ended December 31, 2018, we entered into foreign currency swap agreements with a combined notional principal amount of C$2,450 million (U.S.$1,888 million). These swaps resulted in our selling fixed C$ and receiving fixed U.S.$, effectively hedging the foreign currency risk associated with a substantial portion of our share of the TMPL Sale proceeds which were held in Canadian dollar denominated accounts until KML’s board of directors and shareholder-approved distribution of the proceeds was made on January 3, 2019. At such time, our share of the TMPL Sale proceeds were then transferred into a U.S. dollar denominated account, our exposure to foreign currency risk was eliminated, and our foreign currency swaps were settled. These foreign currency swaps were accounted for as net investment hedges as the foreign currency risk was related to our investment in Canadian dollar denominated foreign operations, and the critical risks of the forward contracts coincided with those of the net investment. As a result, the change in fair value of the foreign currency swaps
while outstanding were reflected in the “Foreign currency translation adjustments” section of “Other comprehensive income (loss), net of tax” on our consolidated statements of comprehensive income.
Impact of Derivative Contracts on Our Consolidated Financial Statements
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
|
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
|
|
|
September 30,
2019
|
|
December 31,
2018
|
|
September 30,
2019
|
|
December 31,
2018
|
|
|
Location
|
|
Fair value
|
|
Fair value
|
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
$
|
73
|
|
|
$
|
135
|
|
|
$
|
(35
|
)
|
|
$
|
(45
|
)
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
47
|
|
|
64
|
|
|
(1
|
)
|
|
—
|
|
Subtotal
|
|
|
|
120
|
|
|
199
|
|
|
(36
|
)
|
|
(45
|
)
|
Interest rate contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
53
|
|
|
12
|
|
|
(2
|
)
|
|
(37
|
)
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
421
|
|
|
121
|
|
|
(2
|
)
|
|
(78
|
)
|
Subtotal
|
|
|
|
474
|
|
|
133
|
|
|
(4
|
)
|
|
(115
|
)
|
Foreign currency contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
—
|
|
|
91
|
|
|
(14
|
)
|
|
(6
|
)
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
20
|
|
|
106
|
|
|
—
|
|
|
—
|
|
Subtotal
|
|
|
|
20
|
|
|
197
|
|
|
(14
|
)
|
|
(6
|
)
|
Total
|
|
|
|
614
|
|
|
529
|
|
|
(54
|
)
|
|
(166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
18
|
|
|
22
|
|
|
(4
|
)
|
|
(5
|
)
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
Total
|
|
|
|
19
|
|
|
22
|
|
|
(5
|
)
|
|
(5
|
)
|
Total derivatives
|
|
|
|
$
|
633
|
|
|
$
|
551
|
|
|
$
|
(59
|
)
|
|
$
|
(171
|
)
|
The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of income and comprehensive income (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in fair value hedging relationships
|
|
Location
|
|
Gain/(loss) recognized in income
on derivative and related hedged item
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
Interest, net
|
|
$
|
117
|
|
|
$
|
(72
|
)
|
|
$
|
453
|
|
|
$
|
(326
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Hedged fixed rate debt(a)
|
|
Interest, net
|
|
$
|
(119
|
)
|
|
$
|
70
|
|
|
$
|
(468
|
)
|
|
$
|
315
|
|
_______
|
|
(a)
|
As of September 30, 2019, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $475 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in cash flow hedging relationships
|
|
Gain/(loss)
recognized in OCI on derivative(a)
|
|
Location
|
|
Gain/(loss) reclassified from Accumulated OCI
into income(b)
|
|
|
Three Months Ended September 30,
|
|
|
|
Three Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
|
|
2019
|
|
2018
|
Energy commodity derivative contracts
|
|
$
|
96
|
|
|
$
|
(109
|
)
|
|
Revenues—Natural
gas sales
|
|
$
|
11
|
|
|
$
|
(4
|
)
|
|
|
|
|
|
|
Revenues—Product
sales and other
|
|
(2
|
)
|
|
(3
|
)
|
|
|
|
|
|
|
Costs of sales
|
|
(3
|
)
|
|
2
|
|
Interest rate contracts
|
|
(1
|
)
|
|
—
|
|
|
Earnings from equity investments(c)
|
|
—
|
|
|
—
|
|
Foreign currency contracts
|
|
(69
|
)
|
|
(4
|
)
|
|
Other, net
|
|
(59
|
)
|
|
(10
|
)
|
Total
|
|
$
|
26
|
|
|
$
|
(113
|
)
|
|
Total
|
|
$
|
(53
|
)
|
|
$
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in cash flow hedging relationships
|
|
Gain/(loss)
recognized in OCI on derivative(a)
|
|
Location
|
|
Gain/(loss) reclassified from Accumulated OCI
into income(b)
|
|
|
Nine Months Ended September 30,
|
|
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
|
|
2019
|
|
2018
|
Energy commodity derivative contracts
|
|
$
|
(74
|
)
|
|
$
|
(160
|
)
|
|
Revenues—Natural
gas sales
|
|
$
|
16
|
|
|
$
|
(9
|
)
|
|
|
|
|
|
|
Revenues—Product
sales and other
|
|
(1
|
)
|
|
(40
|
)
|
|
|
|
|
|
|
Costs of sales
|
|
8
|
|
|
3
|
|
Interest rate contracts
|
|
(2
|
)
|
|
3
|
|
|
Earnings from equity investments(c)
|
|
2
|
|
|
(5
|
)
|
Foreign currency contracts
|
|
(95
|
)
|
|
(15
|
)
|
|
Other, net
|
|
(71
|
)
|
|
(50
|
)
|
Total
|
|
$
|
(171
|
)
|
|
$
|
(172
|
)
|
|
Total
|
|
$
|
(46
|
)
|
|
$
|
(101
|
)
|
_______
|
|
(a)
|
We expect to reclassify an approximate $69 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2019 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
|
|
|
(b)
|
During the nine months ended September 30, 2019, we recognized a $12 million gain associated with a write-down of hedged inventory. During the nine months ended September 30, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring. All other 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 income (loss).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in net investment hedging relationships
|
|
Gain/(loss)
recognized in OCI on derivative
|
|
Location
|
|
Gain/(loss) reclassified from Accumulated OCI
into income(a)
|
|
|
Three Months Ended September 30,
|
|
|
|
Three Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
|
|
2019
|
|
2018
|
Foreign currency contracts
|
|
$
|
—
|
|
|
$
|
(14
|
)
|
|
(Gain) loss on divestitures and impairments, net
|
|
$
|
—
|
|
|
$
|
26
|
|
Total
|
|
$
|
—
|
|
|
$
|
(14
|
)
|
|
Total
|
|
$
|
—
|
|
|
$
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in net investment hedging relationships
|
|
Gain/(loss)
recognized in OCI on derivative
|
|
Location
|
|
Gain/(loss) reclassified from Accumulated OCI
into income(a)
|
|
|
Nine Months Ended September 30,
|
|
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
|
|
2019
|
|
2018
|
Foreign currency contracts
|
|
$
|
(8
|
)
|
|
$
|
(14
|
)
|
|
(Gain) loss on divestitures and impairments, net
|
|
$
|
—
|
|
|
$
|
26
|
|
Total
|
|
$
|
(8
|
)
|
|
$
|
(14
|
)
|
|
Total
|
|
$
|
—
|
|
|
$
|
26
|
|
_______
|
|
(a)
|
During the three and nine months ended September 30, 2018, we recognized a $26 million gain as a result of the TMPL Sale. See Note 2.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|
Location
|
|
Gain/(loss) recognized in income on derivative
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Energy commodity derivative contracts
|
|
Revenues—Natural gas sales
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
26
|
|
|
$
|
2
|
|
|
|
Revenues—Product sales and other
|
|
11
|
|
|
(65
|
)
|
|
10
|
|
|
(111
|
)
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
1
|
|
|
|
Earnings from equity investments(b)
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
Total(a)
|
|
|
|
$
|
12
|
|
|
$
|
(65
|
)
|
|
$
|
35
|
|
|
$
|
(108
|
)
|
_______
|
|
(a)
|
The three and nine months ended September 30, 2019 include approximate losses of $4 million and $2 million, respectively, and the three and nine months ended September 30, 2018 include approximate losses of $14 million and $11 million, respectively. These losses were associated with natural gas, crude and NGL derivative contract settlements.
|
(b) Amounts represent our share of an equity investee’s income (loss).
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 September 30, 2019 and December 31, 2018, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2019 and December 31, 2018, we had cash margins of $19 million and $16 million, respectively, posted by our counterparties with us as collateral and reported within “Other Current Liabilities” on our accompanying consolidated balance sheets. The balance at September 30, 2019 represents the net of our initial margin requirements of $15 million, offset by counterparty variation margin requirements of $34 million. We also use industry standard commercial agreements that 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 September 30, 2019, 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, 2018
|
$
|
164
|
|
|
$
|
(91
|
)
|
|
$
|
(403
|
)
|
|
$
|
(330
|
)
|
Other comprehensive (loss) gain before reclassifications
|
(132
|
)
|
|
20
|
|
|
23
|
|
|
(89
|
)
|
Loss reclassified from accumulated other comprehensive loss
|
35
|
|
|
—
|
|
|
—
|
|
|
35
|
|
Net current-period change in accumulated other comprehensive (loss) income
|
(97
|
)
|
|
20
|
|
|
23
|
|
|
(54
|
)
|
Balance as of September 30, 2019
|
$
|
67
|
|
|
$
|
(71
|
)
|
|
$
|
(380
|
)
|
|
$
|
(384
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2017
|
$
|
(27
|
)
|
|
$
|
(189
|
)
|
|
$
|
(325
|
)
|
|
$
|
(541
|
)
|
Other comprehensive (loss) gain before reclassifications
|
(133
|
)
|
|
(51
|
)
|
|
16
|
|
|
(168
|
)
|
Losses reclassified from accumulated other comprehensive loss
|
78
|
|
|
223
|
|
|
22
|
|
|
323
|
|
Impact of adoption of ASU 2018-02 (Note 4)
|
(4
|
)
|
|
(36
|
)
|
|
(69
|
)
|
|
(109
|
)
|
Net current-period change in accumulated other comprehensive (loss) income
|
(59
|
)
|
|
136
|
|
|
(31
|
)
|
|
46
|
|
Balance as of September 30, 2018
|
$
|
(86
|
)
|
|
$
|
(53
|
)
|
|
$
|
(356
|
)
|
|
$
|
(495
|
)
|
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.
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 ASC (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(b)
|
As of September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
23
|
|
|
$
|
116
|
|
|
$
|
—
|
|
|
$
|
139
|
|
|
$
|
(19
|
)
|
|
$
|
(34
|
)
|
|
$
|
86
|
|
Interest rate contracts
|
—
|
|
|
474
|
|
|
—
|
|
|
474
|
|
|
(1
|
)
|
|
—
|
|
|
473
|
|
Foreign currency contracts
|
—
|
|
|
20
|
|
|
—
|
|
|
20
|
|
|
(14
|
)
|
|
—
|
|
|
6
|
|
As of December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
28
|
|
|
$
|
193
|
|
|
$
|
—
|
|
|
$
|
221
|
|
|
$
|
(39
|
)
|
|
$
|
(25
|
)
|
|
$
|
157
|
|
Interest rate contracts
|
—
|
|
|
133
|
|
|
—
|
|
|
133
|
|
|
(7
|
)
|
|
—
|
|
|
126
|
|
Foreign currency contracts
|
—
|
|
|
197
|
|
|
—
|
|
|
197
|
|
|
(6
|
)
|
|
—
|
|
|
191
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet liability
fair value measurements by level
|
|
|
|
Net amount
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross amount
|
|
Contracts available for netting
|
|
Cash collateral posted(b)
|
As of September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
(2
|
)
|
|
$
|
(39
|
)
|
|
$
|
—
|
|
|
$
|
(41
|
)
|
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
(22
|
)
|
Interest rate contracts
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
|
1
|
|
|
—
|
|
|
(3
|
)
|
Foreign currency contracts
|
—
|
|
|
(14
|
)
|
|
—
|
|
|
(14
|
)
|
|
14
|
|
|
—
|
|
|
—
|
|
As of December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
(11
|
)
|
|
$
|
(39
|
)
|
|
$
|
—
|
|
|
$
|
(50
|
)
|
|
$
|
39
|
|
|
$
|
—
|
|
|
$
|
(11
|
)
|
Interest rate contracts
|
—
|
|
|
(115
|
)
|
|
—
|
|
|
(115
|
)
|
|
7
|
|
|
—
|
|
|
(108
|
)
|
Foreign currency contracts
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
|
6
|
|
|
—
|
|
|
—
|
|
_______
|
|
(a)
|
Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.
|
|
|
(b)
|
Any cash collateral paid or received is reflected in this table, but only to the extent that such cash collateral 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.
|
Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
Carrying
value
|
|
Estimated
fair value
|
|
Carrying
value
|
|
Estimated
fair value
|
Total debt
|
$
|
36,517
|
|
|
$
|
40,056
|
|
|
$
|
37,324
|
|
|
$
|
37,469
|
|
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2019 and December 31, 2018.
7. Revenue Recognition
Disaggregation of Revenues
The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2019
|
|
|
Natural Gas Pipelines
|
|
Products Pipelines
|
|
Terminals
|
|
CO2
|
|
Corporate and Eliminations
|
|
Total
|
Revenues from contracts with customers(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm services(b)
|
|
$
|
882
|
|
|
$
|
89
|
|
|
$
|
256
|
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
|
$
|
1,227
|
|
Fee-based services
|
|
182
|
|
|
265
|
|
|
132
|
|
|
14
|
|
|
—
|
|
|
593
|
|
Total services revenues
|
|
1,064
|
|
|
354
|
|
|
388
|
|
|
15
|
|
|
(1
|
)
|
|
1,820
|
|
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
618
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
617
|
|
Product sales
|
|
162
|
|
|
84
|
|
|
9
|
|
|
268
|
|
|
(7
|
)
|
|
516
|
|
Total sales revenues
|
|
780
|
|
|
84
|
|
|
9
|
|
|
268
|
|
|
(8
|
)
|
|
1,133
|
|
Total revenues from contracts with customers
|
|
1,844
|
|
|
438
|
|
|
397
|
|
|
283
|
|
|
(9
|
)
|
|
2,953
|
|
Other revenues(c)
|
|
90
|
|
|
46
|
|
|
111
|
|
|
15
|
|
|
(1
|
)
|
|
261
|
|
Total revenues
|
|
$
|
1,934
|
|
|
$
|
484
|
|
|
$
|
508
|
|
|
$
|
298
|
|
|
$
|
(10
|
)
|
|
$
|
3,214
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
|
Natural Gas Pipelines
|
|
Products Pipelines
|
|
Terminals
|
|
CO2
|
|
Kinder Morgan Canada(d)
|
|
Corporate and Eliminations
|
|
Total
|
Revenues from contracts with customers(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm services(b)
|
|
$
|
819
|
|
|
$
|
95
|
|
|
$
|
232
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,146
|
|
Fee-based services
|
|
174
|
|
|
246
|
|
|
163
|
|
|
17
|
|
|
41
|
|
|
—
|
|
|
641
|
|
Total services revenues
|
|
993
|
|
|
341
|
|
|
395
|
|
|
17
|
|
|
41
|
|
|
—
|
|
|
1,787
|
|
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
806
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
803
|
|
Product sales
|
|
358
|
|
|
94
|
|
|
9
|
|
|
313
|
|
|
—
|
|
|
(11
|
)
|
|
763
|
|
Total sales revenues
|
|
1,164
|
|
|
94
|
|
|
9
|
|
|
313
|
|
|
—
|
|
|
(14
|
)
|
|
1,566
|
|
Total revenues from contracts with customers
|
|
2,157
|
|
|
435
|
|
|
404
|
|
|
330
|
|
|
41
|
|
|
(14
|
)
|
|
3,353
|
|
Other revenues(c)
|
|
35
|
|
|
40
|
|
|
100
|
|
|
(14
|
)
|
|
3
|
|
|
—
|
|
|
164
|
|
Total revenues
|
|
$
|
2,192
|
|
|
$
|
475
|
|
|
$
|
504
|
|
|
$
|
316
|
|
|
$
|
44
|
|
|
$
|
(14
|
)
|
|
$
|
3,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2019
|
|
|
Natural Gas Pipelines
|
|
Products Pipelines
|
|
Terminals
|
|
CO2
|
|
Corporate and Eliminations
|
|
Total
|
Revenues from contracts with customers(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm services(b)
|
|
$
|
2,701
|
|
|
$
|
253
|
|
|
$
|
785
|
|
|
$
|
1
|
|
|
$
|
(3
|
)
|
|
$
|
3,737
|
|
Fee-based services
|
|
561
|
|
|
752
|
|
|
398
|
|
|
45
|
|
|
—
|
|
|
1,756
|
|
Total services revenues
|
|
3,262
|
|
|
1,005
|
|
|
1,183
|
|
|
46
|
|
|
(3
|
)
|
|
5,493
|
|
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
1,979
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(7
|
)
|
|
1,973
|
|
Product sales
|
|
599
|
|
|
211
|
|
|
16
|
|
|
827
|
|
|
(23
|
)
|
|
1,630
|
|
Total sales revenues
|
|
2,578
|
|
|
211
|
|
|
16
|
|
|
828
|
|
|
(30
|
)
|
|
3,603
|
|
Total revenues from contracts with customers
|
|
5,840
|
|
|
1,216
|
|
|
1,199
|
|
|
874
|
|
|
(33
|
)
|
|
9,096
|
|
Other revenues(c)
|
|
263
|
|
|
134
|
|
|
325
|
|
|
39
|
|
|
—
|
|
|
761
|
|
Total revenues
|
|
$
|
6,103
|
|
|
$
|
1,350
|
|
|
$
|
1,524
|
|
|
$
|
913
|
|
|
$
|
(33
|
)
|
|
$
|
9,857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
|
|
Natural Gas Pipelines
|
|
Products Pipelines
|
|
Terminals
|
|
CO2
|
|
Kinder Morgan Canada(d)
|
|
Corporate and Eliminations
|
|
Total
|
Revenues from contracts with customers(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm services(b)
|
|
$
|
2,490
|
|
|
$
|
286
|
|
|
$
|
751
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
3,526
|
|
Fee-based services
|
|
500
|
|
|
706
|
|
|
460
|
|
|
50
|
|
|
167
|
|
|
—
|
|
|
1,883
|
|
Total services revenues
|
|
2,990
|
|
|
992
|
|
|
1,211
|
|
|
51
|
|
|
167
|
|
|
(2
|
)
|
|
5,409
|
|
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
2,370
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(6
|
)
|
|
2,365
|
|
Product sales
|
|
904
|
|
|
310
|
|
|
16
|
|
|
948
|
|
|
—
|
|
|
(28
|
)
|
|
2,150
|
|
Total sales revenues
|
|
3,274
|
|
|
310
|
|
|
16
|
|
|
949
|
|
|
—
|
|
|
(34
|
)
|
|
4,515
|
|
Total revenues from contracts with customers
|
|
6,264
|
|
|
1,302
|
|
|
1,227
|
|
|
1,000
|
|
|
167
|
|
|
(36
|
)
|
|
9,924
|
|
Other revenues(c)
|
|
161
|
|
|
118
|
|
|
287
|
|
|
(130
|
)
|
|
3
|
|
|
—
|
|
|
439
|
|
Total revenues
|
|
$
|
6,425
|
|
|
$
|
1,420
|
|
|
$
|
1,514
|
|
|
$
|
870
|
|
|
$
|
170
|
|
|
$
|
(36
|
)
|
|
$
|
10,363
|
|
_______
|
|
(a)
|
Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c) below).
|
|
|
(b)
|
Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.
|
|
|
(c)
|
Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 and primarily include leases and derivatives. See Notes 5 and 10 for additional information related to our derivative contracts and lessor contracts, respectively.
|
|
|
(d)
|
On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment does not have results of operations on a prospective basis (see Note 2).
|
Contract Balances
Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections.
The following table presents the activity in our contract assets and liabilities (in millions):
|
|
|
|
|
|
Nine Months Ended September 30, 2019
|
Contract Assets
|
|
Balance at December 31, 2018(a)
|
$
|
24
|
|
Additions
|
77
|
|
Transfer to Accounts receivable
|
(27
|
)
|
Other
|
(1
|
)
|
Balance at September 30, 2019(b)
|
$
|
73
|
|
Contract Liabilities
|
|
Balance at December 31, 2018(c)
|
$
|
292
|
|
Additions
|
305
|
|
Transfer to Revenues
|
(285
|
)
|
Other(d)
|
(15
|
)
|
Balance at September 30, 2019(e)
|
$
|
297
|
|
_______
|
|
(a)
|
Includes current and non-current balances of $14 million and $10 million, respectively.
|
|
|
(b)
|
Includes current and non-current balances of $63 million and $10 million, respectively.
|
|
|
(c)
|
Includes current and non-current balances of $80 million and $212 million, respectively.
|
|
|
(d)
|
Includes foreign currency translation adjustments.
|
|
|
(e)
|
Includes current and non-current balances of $74 million and $223 million, respectively.
|
Revenue Allocated to Remaining Performance Obligations
The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of September 30, 2019 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions):
|
|
|
|
|
|
Year
|
|
Estimated Revenue
|
Three months ended December 31, 2019
|
|
$
|
1,290
|
|
2020
|
|
4,631
|
|
2021
|
|
3,961
|
|
2022
|
|
3,346
|
|
2023
|
|
2,771
|
|
Thereafter
|
|
15,834
|
|
Total
|
|
$
|
31,833
|
|
Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude remaining performance obligations for (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which we recognize revenue at the amount for which we have the right to invoice for services performed.
8. Reportable Segments
For segment reporting purposes, effective January 1, 2019, certain assets were transferred among our business segments. As a result, individual segment results for the three and nine months ended September 30, 2018 and balances as of December 31, 2018 have been reclassified to conform to the current presentation in the following tables.
Financial information by segment follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Revenues
|
|
|
|
|
|
|
|
Natural Gas Pipelines
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
1,925
|
|
|
$
|
2,180
|
|
|
$
|
6,073
|
|
|
$
|
6,391
|
|
Intersegment revenues
|
9
|
|
|
12
|
|
|
30
|
|
|
34
|
|
Products Pipelines
|
484
|
|
|
475
|
|
|
1,350
|
|
|
1,420
|
|
Terminals
|
|
|
|
|
|
|
|
Revenues from external customers
|
507
|
|
|
503
|
|
|
1,521
|
|
|
1,512
|
|
Intersegment revenues
|
1
|
|
|
1
|
|
|
3
|
|
|
2
|
|
CO2
|
298
|
|
|
316
|
|
|
913
|
|
|
870
|
|
Kinder Morgan Canada(a)
|
—
|
|
|
44
|
|
|
—
|
|
|
170
|
|
Corporate and intersegment eliminations
|
(10
|
)
|
|
(14
|
)
|
|
(33
|
)
|
|
(36
|
)
|
Total consolidated revenues(b)
|
$
|
3,214
|
|
|
$
|
3,517
|
|
|
$
|
9,857
|
|
|
$
|
10,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Segment EBDA(c)
|
|
|
|
|
|
|
|
Natural Gas Pipelines
|
$
|
1,092
|
|
|
$
|
930
|
|
|
$
|
3,383
|
|
|
$
|
2,368
|
|
Products Pipelines
|
325
|
|
|
325
|
|
|
908
|
|
|
912
|
|
Terminals
|
295
|
|
|
301
|
|
|
884
|
|
|
872
|
|
CO2
|
164
|
|
|
205
|
|
|
558
|
|
|
561
|
|
Kinder Morgan Canada(a)
|
—
|
|
|
654
|
|
|
(2
|
)
|
|
746
|
|
Total Segment EBDA(d)
|
1,876
|
|
|
2,415
|
|
|
5,731
|
|
|
5,459
|
|
DD&A
|
(578
|
)
|
|
(569
|
)
|
|
(1,750
|
)
|
|
(1,710
|
)
|
Amortization of excess cost of equity investments
|
(21
|
)
|
|
(21
|
)
|
|
(61
|
)
|
|
(77
|
)
|
General and administrative and corporate charges
|
(162
|
)
|
|
(151
|
)
|
|
(478
|
)
|
|
(485
|
)
|
Interest, net
|
(447
|
)
|
|
(473
|
)
|
|
(1,359
|
)
|
|
(1,456
|
)
|
Income tax expense
|
(151
|
)
|
|
(196
|
)
|
|
(471
|
)
|
|
(314
|
)
|
Total consolidated net income
|
$
|
517
|
|
|
$
|
1,005
|
|
|
$
|
1,612
|
|
|
$
|
1,417
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
Assets
|
|
|
|
Natural Gas Pipelines
|
$
|
51,164
|
|
|
$
|
50,261
|
|
Products Pipelines
|
9,501
|
|
|
9,598
|
|
Terminals
|
9,903
|
|
|
9,415
|
|
CO2
|
3,757
|
|
|
3,928
|
|
Corporate assets(e)
|
2,606
|
|
|
5,664
|
|
Total consolidated assets(f)
|
$
|
76,931
|
|
|
$
|
78,866
|
|
_______
|
|
(a)
|
On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment does not have results of operations on a prospective basis (see Note 2).
|
|
|
(b)
|
Revenues previously reported (before reclassifications) for the three months ended September 30, 2018 were $2,227 million, $432 million, $502 million and $(4) million and for the nine months ended September 30, 2018 were $6,559 million, $1,273 million, $1,508 million and $(17) million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, and the Corporate and intersegment eliminations, respectively.
|
|
|
(c)
|
Includes revenues, earnings from equity investments, other, net, less operating expenses, (gain) loss on divestitures and impairments, net, and other income, net.
|
|
|
(d)
|
Segment EBDA previously reported (before reclassifications) for the three months ended September 30, 2018 were $976 million, $279 million and $301 million and for the nine months ended September 30, 2018 were $2,425 million, $857 million and $870 million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, respectively.
|
|
|
(e)
|
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 activity) not allocated to our reportable segments.
|
|
|
(f)
|
Assets previously reported as of December 31, 2018 were $51,562 million, $8,429 million and $9,283 million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, respectively. The reclassification included a transfer of $450 million of goodwill from the Natural Gas Pipelines Non-Regulated reporting unit to the Products Pipelines reporting unit.
|
9. Income Taxes
Income tax expense included in our accompanying consolidated statements of income are as follows (in millions, except percentages):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Income tax expense
|
$
|
151
|
|
|
$
|
196
|
|
|
$
|
471
|
|
|
$
|
314
|
|
Effective tax rate
|
22.6
|
%
|
|
16.3
|
%
|
|
22.6
|
%
|
|
18.1
|
%
|
The effective tax rate for the three and nine months ended September 30, 2019 is higher than the statutory federal rate of 21% primarily due to state and foreign income taxes, partially offset by dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings LLC (NGPL) and Plantation Pipe Line Company (Plantation).
The effective tax rate for the three and nine months ended September 30, 2018 is lower than the statutory federal rate of 21% primarily due to the lower Canadian capital gains tax rate applicable to the TMPL Sale, dividend-received deductions from our investments in Citrus, Plantation and NGPL, and a reduction of our income tax reserve for uncertain tax positions as a result of the settlement of income tax audits. These reductions are partially offset by state income taxes.
10. Leases
Effective January 1, 2019, we adopted ASU No. 2016-02, “Leases (Topic 842)” and the series of related Accounting Standards Updates that followed (collectively referred to as “Topic 842”). The most significant changes under the new guidance include clarification of the definition of a lease, and the requirements for lessees to recognize a ROU asset and a lease liability for all qualifying leases with terms longer than twelve months in the consolidated balance sheet. In addition, under Topic 842, additional disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.
We elected the practical expedient available to us under ASU 2018-11 “Leases: Targeted Improvements” which allows us to apply the transition provision for Topic 842 at our adoption date instead of at the earliest comparative period presented in our financial statements. Therefore, we recognized and measured leases existing at January 1, 2019 but without retrospective application. In addition, we elected the optional practical expedient permitted under the transition guidance related to land easements which allows us to carry forward our historical accounting treatment for land easements on existing agreements upon adoption. We also elected all other available practical expedients except the hindsight practical expedient.
The impact of Topic 842 on our consolidated balance sheet beginning January 1, 2019 was through the recognition of ROU assets and lease liabilities for operating leases, while our accounting for finance leases remained substantially unchanged. Our finance leases were immaterial prior to the adoption of Topic 842, and no change was made to the classification for these leases. Amounts recognized at January 1, 2019 for operating leases were as follows (in millions):
|
|
|
|
|
|
January 1, 2019
|
ROU assets
|
$
|
696
|
|
Short-term lease liability
|
52
|
|
Long-term lease liability
|
644
|
|
No impact was recorded to the income statement or beginning retained earnings for Topic 842.
Lessee
We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 34 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
Beginning January 1, 2019, operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Operating leases in effect prior to January 1, 2019 were recognized at the present value of the remaining payments on the remaining lease term as of January 1, 2019. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, were reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately, while for the remainder of our agreements we have elected the practical expedient to account for lease and non-lease components as a single lease component. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, are reassessed when agreements are modified.
Following are components of our lease cost (in millions):
|
|
|
|
|
|
Nine Months Ended September 30, 2019
|
Operating leases
|
$
|
107
|
|
Short-term and variable leases
|
58
|
|
Total lease cost(a)
|
$
|
165
|
|
_______
|
|
(a)
|
Includes $29 million of capitalized lease costs.
|
Other information related to our operating leases are as follows (in millions, except lease term and discount rate):
|
|
|
|
|
|
Nine Months Ended September 30, 2019
|
Operating cash flows from operating leases
|
$
|
(136
|
)
|
Investing cash flows from operating leases
|
(29
|
)
|
ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion
|
70
|
|
Amortization of ROU assets
|
52
|
|
|
|
Weighted average remaining lease term
|
16.31 years
|
|
Weighted average discount rate
|
5.87
|
%
|
Amounts recognized in the accompanying consolidated balance sheet are as follows (in millions):
|
|
|
|
|
|
Lease Activity
|
Balance sheet location
|
September 30, 2019
|
ROU assets
|
Deferred charges and other assets
|
$
|
714
|
|
Short-term lease liability
|
Other current liabilities
|
53
|
|
Long-term lease liability
|
Other long-term liabilities and deferred credits
|
661
|
|
Finance lease assets
|
Property, plant and equipment, net
|
2
|
|
Finance lease liabilities
|
Long-term debt—Outstanding
|
2
|
|
Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of September 30, 2019 are as follows (in millions):
|
|
|
|
|
Three months ended December 31, 2019
|
$
|
26
|
|
2020
|
90
|
|
2021
|
81
|
|
2022
|
74
|
|
2023
|
67
|
|
Thereafter
|
825
|
|
Total lease payments(a)
|
1,163
|
|
Less: Interest
|
(449
|
)
|
Present value of lease liabilities
|
$
|
714
|
|
_______
|
|
(a)
|
Amount excludes future minimum rights-of-way obligations (ROW) as they do not constitute a lease obligation. The amounts in our future minimum ROW obligations as presented in the table below have not materially changed since December 31, 2018.
|
Undiscounted future gross minimum operating lease payments and ROW obligations as of December 31, 2018 are as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Leases
|
|
ROW
|
|
Total(a)
|
2019
|
$
|
90
|
|
|
$
|
25
|
|
|
$
|
115
|
|
2020
|
75
|
|
|
25
|
|
|
100
|
|
2021
|
70
|
|
|
25
|
|
|
95
|
|
2022
|
65
|
|
|
26
|
|
|
91
|
|
2023
|
59
|
|
|
25
|
|
|
84
|
|
Thereafter
|
771
|
|
|
88
|
|
|
859
|
|
Total payments
|
$
|
1,130
|
|
|
$
|
214
|
|
|
$
|
1,344
|
|
_______
|
|
(a)
|
This table has been revised from the previously reported December 31, 2018 future gross minimum rental commitments under our operating leases and ROW obligations table in our 2018 Form 10-K to (i) separately present lease and ROW obligations and (ii) to correct amounts previously reported to include an additional $482 million of undiscounted future lease payments, primarily in the “Thereafter” amount associated with the 2018 extension of KML’s, Edmonton South tank lease through December 2038.
|
Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.
Lessor
Our assets that we lease to others under operating leases consists primarily of specific facilities where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating and gas equipment and pipelines with separate control locations. Our leases have remaining lease terms of one to 32 years, some of which have options to extend the lease for up to an additional 25 years, and some of which may include options to terminate the lease within one year. We determine if an arrangement is a lease at inception or upon modification. None of our leases allow the lessee to purchase the leased asset.
Lease income for the three and nine months ended September 30, 2019 totaled $226 million and $660 million, respectively, including a significant amount of variable lease payments that is excluded from the following disclosure as the amounts cannot be reasonably estimated for future periods.
Future minimum operating lease payments to be received based on contractual agreements are as follows (in millions):
|
|
|
|
|
|
September 30, 2019
|
2019 (three months ended December 31, 2019)
|
$
|
98
|
|
2020
|
370
|
|
2021
|
344
|
|
2022
|
329
|
|
2023
|
299
|
|
Thereafter
|
3,699
|
|
Total
|
$
|
5,139
|
|
Options for a lessee to renew the agreement are not included as part of future minimum operating lease revenues. We elected the practical expedient available to us to not separate lease and non-lease components under these agreements. Any modification of a lease will result in a reevaluation of the lease classification.
11. Litigation and Environmental
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.
FERC Proceedings
FERC Rulemaking on Tax Cuts and Jobs Act for Jurisdictional Natural Gas Pipelines
In July 2018, the FERC issued an order requiring an informational filing by interstate natural gas pipelines on a new Form 501-G, evaluating the impact of the 2017 Tax Reform and the Revised Tax Policy on tax allowances for the pipelines. KMI and certain of its pipeline affiliates successfully worked with their shippers to achieve settlements without the need for litigation or any additional intervention by the FERC. The FERC has approved settlements filed by EPNG, SNG, TGP, Young Gas Storage, and Bear Creek Storage Company, L.L.C. and terminated all of our remaining 501-G proceedings without taking further action. Accordingly, our 501-G exposure has been resolved.
FERC Inquiry Regarding the Commission’s Policy for Determining Return on Equity
On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI seeks comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Comments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC and there is no deadline or requirement for the FERC to take action on this matter.
SFPP
The tariffs and rates charged by SFPP are subject to a number of ongoing shipper-initiated proceedings at the FERC. These include IS08-390, filed in June 2008, in which various shippers are challenging SFPP’s West Line rates (currently on appeal to the D.C. Circuit Court); IS09-437, filed in July 2009, in which various shippers are challenging SFPP’s East Line rates (currently before the FERC on rehearing); OR11-13/16/18, filed in June 2011, in which various shippers are seeking to challenge SFPP’s North Line, Oregon Line, and West Line rates (not yet been set for hearing by the FERC); OR14-35/36, filed in June 2014, in which various shippers are challenging SFPP’s index increases in 2012 and 2013 (dismissed by the FERC, but remanded back to the FERC from the D.C. Circuit for further consideration); OR16-6, filed in December 2015, in which
various shippers are challenging SFPP’s East line rates (pending before the FERC for an order on the initial decision); and OR19-21, filed beginning in April 2019, in which various shippers are challenging SFPP’s index increases in 2018 (currently pending before the FERC for an order on the complaints). 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. 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. 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.
Per order of the FERC, in May 2019 SFPP paid refunds to shippers in the IS08-390 proceeding based on the denial of an income tax allowance. With respect to the various SFPP related complaints and protest proceedings at the FERC (including IS08-390), we estimate that the shippers are seeking approximately $30 million in annual rate reductions and approximately $330 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, as well as the compliance filing methodology recently approved by the FERC 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. All refund obligations related to the 2008 rate case were satisfied in 2015. EPNG sought federal appellate review of Opinion 517-A. On February 21, 2017, the reviewing court delayed the case until the FERC ruled 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. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A and requiring EPNG to implement the rates required by its rulings and provide refunds within 60 days. On July 2, 2018, EPNG reported to the FERC the refund calculations, and that the refunds had been provided as ordered. Also on July 2, 2018, EPNG initiated appellate review of Opinions 528, 528-A and 528-B. On August 23, 2018, the reviewing court established a briefing schedule and consolidated EPNG’s delayed appeal from the 2008 rate case, EPNG’s appeal from the 2010 rate case, and the intervenors’ delayed appeal in the 2010 case. In accordance with that schedule, briefing has been completed and oral argument is scheduled for November 25, 2019.
Other Commercial Matters
Gulf LNG Facility Arbitration
On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received 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 was 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 sought 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. On June 29, 2018, the arbitration panel delivered its Award, and the panel's ruling called for the termination of the agreement and Eni USA's payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On September 25, 2018, GLNG filed a lawsuit against Eni USA in the Delaware Court of Chancery to enforce the Award. On February 1, 2019, the Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019. On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. On June 3, 2019, Eni USA
filed a second Notice of Arbitration against GLNG asserting the same breach of contract claim that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA seeks to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Delaware Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Delaware Court of Chancery together with a motion seeking to permanently enjoin the arbitration. The Delaware Court of Chancery heard oral argument on GLNG’s complaint and related motion in August 2019, and all deadlines in the Second Arbitration are stayed pending the Court’s decision. GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings.
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. All of the cases have been settled or dismissed, including the settlement of the final Wisconsin class action lawsuit which was approved by the U.S. District Court in Nevada on August 5, 2019. The amount that was paid in settlement of this matter is not material to our results of operations, cash flows or dividends to shareholders.
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 September 30, 2019 and December 31, 2018, our total reserve for legal matters was $188 million and $207 million, respectively.
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.
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 remediation.
In addition, we are involved with and have been identified as a potentially responsible party (PRP) 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
On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site. The cost for the final remedy is estimated by the EPA to be approximately $1.1 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities acquired from GATX Terminals Corporation) and KMBT (in connection with its ownership or operation of two facilities). Our share of responsibility for Portland Harbor Superfund Site costs will not be determined until the ongoing non-judicial allocation process is concluded 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. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the site. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately 20 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 PRP 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 environmental assessments of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given the U.S. is the owner of the Navajo Reservation, the U.S.’s exploration and reclamation activities at the mines, and the pervasive control of such federal agencies over all aspects of the nuclear weapons program. After a trial which concluded in March 2019, the U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the government. The decision was not appealed by any party. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. Because costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that this decision will have a material adverse impact to our results of operations, cash flows, or dividends to KMI shareholders.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, 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 (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be 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 two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.
On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Site. The final cleanup plan in the ROD is estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Site. The design work is expected to take four years to complete and the cleanup is expected to take six years to complete. On June 30, 2018 and July 13, 2018, respectively, OCC filed two separate lawsuits in the U.S. District Court for the District of New Jersey seeking cost recovery and contribution under CERCLA from more than 120 defendants, including EPEC Polymers. OCC alleges that each
defendant is responsible to reimburse OCC for a proportionate share of the $165 million OCC is required to spend pursuant to its AOC. EPEC Polymers was dismissed without prejudice from the lawsuit on August 8, 2018.
In addition, the EPA and numerous PRPs, including EPEC Polymers, are engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the recent EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until this FS is completed and the RI/FS is finalized and allocations are determined, the scope of potential EPA claims for the Site and liability therefor are not reasonably estimable.
Louisiana Governmental Coastal Zone Erosion Litigation
Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA). The Plaintiffs allege the defendants’ operations caused substantial damage to the coastal waters of Louisiana and nearby lands, including marsh (Coastal Zone). The alleged damages include erosion of property within the Coastal Zone, and discharge of pollutants that are alleged to have adversely impacted the Coastal Zone, including plants and wildlife. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected Coastal Zone to its original condition. The Louisiana Department of Natural Resources (LDNR) and the Louisiana Attorney General (LAG) routinely intervene in these cases, and we expect the LDNR and LAG to intervene in any additional cases that may be filed. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below.
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and that those operations caused substantial damage to the Coastal Zone. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. In 2016, the LAG and LDNR intervened in the lawsuit. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana on several grounds including federal officer liability. Plaquemines Parish, along with the intervenors, moved to remand the case to the state district court. On May 28, 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified the federal officer liability jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals and on June 11, 2019, the U.S. District Court stayed the remand order pending the outcome of that review. The case is effectively stayed pending resolution of the federal officer liability issue by the Court of Appeals. We will continue to vigorously defend this case.
On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the Coastal Zone. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to remediate, restore, vegetate and detoxify the affected Coastal Zone property. On April 5, 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. On May 28, 2019, Orleans moved to remand the case to the state district court. We will continue to vigorously defend this case.
Louisiana Landowner Coastal Erosion Litigation
Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including two cases against TGP, two cases against SNG, and two cases against both TGP and SNG. In these cases, the Plaintiffs allege that defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. Plaintiffs allege that defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected
property. Plaintiffs allege that defendants are obligated to restore and remediate the affected property without regard to the value of the property. Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. In one case filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and another defendant that was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana, $80 million was sought 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. On May 4, 2018, the District Court entered a judgment dismissing the tort and negligence claims against all of the defendants, and dismissing certain of the contract claims against TGP. In ruling in favor of plaintiffs on the remaining contract claims, the District Court ordered the defendants to pay $1,104 in money damages, and issued a permanent injunction ordering the defendants to restore a total of 9.6 acres of land and maintain certain canals at widths designated by the right of way agreements in effect. The Court stayed the judgment and the injunction pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. On September 13, 2018, the third-party defendant filed a motion to vacate the judgment and dismiss all of the appeals for lack of subject matter jurisdiction. On October 2, 2018 the Court of Appeals dismissed the appeals and on April 17, 2019 the case was remanded to the state district court for Plaquemines Parish, Louisiana for further proceedings. The case is set for trial February 3, 2020. We will continue to vigorously defend these cases.
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 September 30, 2019 and December 31, 2018, we have accrued a total reserve for environmental liabilities in the amount of $258 million and $271 million, respectively. In addition, as of both September 30, 2019 and December 31, 2018, we have recorded a receivable of $13 million for expected cost recoveries that have been deemed probable.
12. Recent Accounting Pronouncements
ASU No. 2016-13
On June 16, 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to utilize a new forward-looking “expected loss” methodology that generally will result in the earlier recognition of allowance for losses. ASU No. 2016-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. 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 No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This ASU simplifies the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. 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, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2018-13
On August 28, 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU amends existing fair value measurement disclosure requirements by adding, changing, or removing certain disclosures. ASU No. 2018-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2018-14
On August 28, 2018, the FASB issued ASU No. 2018-14, “Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU amends existing annual disclosure requirements applicable to all employers that sponsor defined benefit pension and other postretirement plans by adding, removing, and clarifying certain disclosures. ASU No. 2018-14 will be effective for us
for the fiscal year ending December 31, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
13. 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.
Excluding fair value adjustments, as of September 30, 2019, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $15,220 million, $16,610 million, and $2,535 million, respectively, of Guaranteed Notes outstanding. Included in the Subsidiary Guarantors debt balance as presented in the accompanying September 30, 2019 condensed consolidating balance sheet is approximately $169 million of other financing obligations that are not subject to the cross guarantee agreement.
Condensed Consolidating Statements of Income and Comprehensive Income
for the Three Months Ended September 30, 2019
(In Millions, Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Total Revenues
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,910
|
|
|
$
|
317
|
|
|
$
|
(13
|
)
|
|
$
|
3,214
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs, Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
734
|
|
|
29
|
|
|
(1
|
)
|
|
762
|
|
Depreciation, depletion and amortization
|
|
5
|
|
|
—
|
|
|
505
|
|
|
68
|
|
|
—
|
|
|
578
|
|
Other operating expense
|
|
2
|
|
|
1
|
|
|
804
|
|
|
128
|
|
|
(12
|
)
|
|
923
|
|
Total Operating Costs, Expenses and Other
|
|
7
|
|
|
1
|
|
|
2,043
|
|
|
225
|
|
|
(13
|
)
|
|
2,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (Loss) Income
|
|
(7
|
)
|
|
(1
|
)
|
|
867
|
|
|
92
|
|
|
—
|
|
|
951
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from consolidated subsidiaries
|
|
840
|
|
|
780
|
|
|
92
|
|
|
17
|
|
|
(1,729
|
)
|
|
—
|
|
Earnings from equity investments
|
|
—
|
|
|
—
|
|
|
173
|
|
|
—
|
|
|
—
|
|
|
173
|
|
Interest, net
|
|
(191
|
)
|
|
1
|
|
|
(253
|
)
|
|
(4
|
)
|
|
—
|
|
|
(447
|
)
|
Amortization of excess cost of equity investments and other, net
|
|
(4
|
)
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Tax
|
|
638
|
|
|
780
|
|
|
874
|
|
|
105
|
|
|
(1,729
|
)
|
|
668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
(132
|
)
|
|
—
|
|
|
(16
|
)
|
|
(3
|
)
|
|
—
|
|
|
(151
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
506
|
|
|
780
|
|
|
858
|
|
|
102
|
|
|
(1,729
|
)
|
|
517
|
|
Net Income Attributable to Noncontrolling Interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
(11
|
)
|
Net Income Attributable to Controlling Interests
|
|
$
|
506
|
|
|
$
|
780
|
|
|
$
|
858
|
|
|
$
|
102
|
|
|
$
|
(1,740
|
)
|
|
$
|
506
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
506
|
|
|
$
|
780
|
|
|
$
|
858
|
|
|
$
|
102
|
|
|
$
|
(1,729
|
)
|
|
$
|
517
|
|
Total other comprehensive income (loss)
|
|
64
|
|
|
83
|
|
|
81
|
|
|
(5
|
)
|
|
(162
|
)
|
|
61
|
|
Comprehensive income
|
|
570
|
|
|
863
|
|
|
939
|
|
|
97
|
|
|
(1,891
|
)
|
|
578
|
|
Comprehensive income attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
(8
|
)
|
Comprehensive income attributable to controlling interests
|
|
$
|
570
|
|
|
$
|
863
|
|
|
$
|
939
|
|
|
$
|
97
|
|
|
$
|
(1,899
|
)
|
|
$
|
570
|
|
Condensed Consolidating Statements of Income and Comprehensive Income
for the Three Months Ended September 30, 2018
(In Millions, Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Total Revenues
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,159
|
|
|
$
|
385
|
|
|
$
|
(27
|
)
|
|
$
|
3,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs, Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
1,083
|
|
|
68
|
|
|
(16
|
)
|
|
1,135
|
|
Depreciation, depletion and amortization
|
|
5
|
|
|
—
|
|
|
487
|
|
|
77
|
|
|
—
|
|
|
569
|
|
Other operating (income) expense
|
|
(23
|
)
|
|
—
|
|
|
783
|
|
|
(451
|
)
|
|
(11
|
)
|
|
298
|
|
Total Operating Costs, Expenses and Other
|
|
(18
|
)
|
|
—
|
|
|
2,353
|
|
|
(306
|
)
|
|
(27
|
)
|
|
2,002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
18
|
|
|
—
|
|
|
806
|
|
|
691
|
|
|
—
|
|
|
1,515
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from consolidated subsidiaries
|
|
1,183
|
|
|
1,138
|
|
|
579
|
|
|
28
|
|
|
(2,928
|
)
|
|
—
|
|
Earnings from equity investments
|
|
—
|
|
|
—
|
|
|
160
|
|
|
—
|
|
|
—
|
|
|
160
|
|
Interest, net
|
|
(201
|
)
|
|
(2
|
)
|
|
(273
|
)
|
|
3
|
|
|
—
|
|
|
(473
|
)
|
Amortization of excess cost of equity investments and other, net
|
|
7
|
|
|
—
|
|
|
1
|
|
|
(9
|
)
|
|
—
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Tax
|
|
1,007
|
|
|
1,136
|
|
|
1,273
|
|
|
713
|
|
|
(2,928
|
)
|
|
1,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax (Expense) Benefit
|
|
(275
|
)
|
|
73
|
|
|
(20
|
)
|
|
26
|
|
|
—
|
|
|
(196
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
732
|
|
|
1,209
|
|
|
1,253
|
|
|
739
|
|
|
(2,928
|
)
|
|
1,005
|
|
Net Income Attributable to Noncontrolling Interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(273
|
)
|
|
(273
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Controlling Interests
|
|
732
|
|
|
1,209
|
|
|
1,253
|
|
|
739
|
|
|
(3,201
|
)
|
|
732
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock Dividends
|
|
(39
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39
|
)
|
Net Income Available to Common Shareholders
|
|
$
|
693
|
|
|
$
|
1,209
|
|
|
$
|
1,253
|
|
|
$
|
739
|
|
|
$
|
(3,201
|
)
|
|
$
|
693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
732
|
|
|
$
|
1,209
|
|
|
$
|
1,253
|
|
|
$
|
739
|
|
|
$
|
(2,928
|
)
|
|
$
|
1,005
|
|
Total other comprehensive income
|
|
195
|
|
|
207
|
|
|
166
|
|
|
431
|
|
|
(738
|
)
|
|
261
|
|
Comprehensive income
|
|
927
|
|
|
1,416
|
|
|
1,419
|
|
|
1,170
|
|
|
(3,666
|
)
|
|
1,266
|
|
Comprehensive income attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(339
|
)
|
|
(339
|
)
|
Comprehensive income attributable to controlling interests
|
|
$
|
927
|
|
|
$
|
1,416
|
|
|
$
|
1,419
|
|
|
$
|
1,170
|
|
|
$
|
(4,005
|
)
|
|
$
|
927
|
|
Condensed Consolidating Statements of Income and Comprehensive Income
for the Nine Months Ended September 30, 2019
(In Millions, Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Total Revenues
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8,994
|
|
|
$
|
941
|
|
|
$
|
(78
|
)
|
|
$
|
9,857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs, Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
2,413
|
|
|
117
|
|
|
(43
|
)
|
|
2,487
|
|
Depreciation, depletion and amortization
|
|
15
|
|
|
—
|
|
|
1,531
|
|
|
204
|
|
|
—
|
|
|
1,750
|
|
Other operating expense
|
|
5
|
|
|
1
|
|
|
2,312
|
|
|
395
|
|
|
(35
|
)
|
|
2,678
|
|
Total Operating Costs, Expenses and Other
|
|
20
|
|
|
1
|
|
|
6,256
|
|
|
716
|
|
|
(78
|
)
|
|
6,915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (Loss) Income
|
|
(20
|
)
|
|
(1
|
)
|
|
2,738
|
|
|
225
|
|
|
—
|
|
|
2,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from consolidated subsidiaries
|
|
2,579
|
|
|
2,438
|
|
|
226
|
|
|
53
|
|
|
(5,296
|
)
|
|
—
|
|
Earnings from equity investments
|
|
—
|
|
|
—
|
|
|
526
|
|
|
—
|
|
|
—
|
|
|
526
|
|
Interest, net
|
|
(575
|
)
|
|
(4
|
)
|
|
(761
|
)
|
|
(19
|
)
|
|
—
|
|
|
(1,359
|
)
|
Amortization of excess cost of equity investments and other, net
|
|
(11
|
)
|
|
—
|
|
|
(13
|
)
|
|
(2
|
)
|
|
—
|
|
|
(26
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Tax
|
|
1,973
|
|
|
2,433
|
|
|
2,716
|
|
|
257
|
|
|
(5,296
|
)
|
|
2,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
(393
|
)
|
|
(2
|
)
|
|
(58
|
)
|
|
(18
|
)
|
|
—
|
|
|
(471
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
1,580
|
|
|
2,431
|
|
|
2,658
|
|
|
239
|
|
|
(5,296
|
)
|
|
1,612
|
|
Net Income Attributable to Noncontrolling Interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(32
|
)
|
|
(32
|
)
|
Net Income Attributable to Controlling Interests
|
|
$
|
1,580
|
|
|
$
|
2,431
|
|
|
$
|
2,658
|
|
|
$
|
239
|
|
|
$
|
(5,328
|
)
|
|
$
|
1,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
1,580
|
|
|
$
|
2,431
|
|
|
$
|
2,658
|
|
|
$
|
239
|
|
|
$
|
(5,296
|
)
|
|
$
|
1,612
|
|
Total other comprehensive (loss) income
|
|
(54
|
)
|
|
(66
|
)
|
|
(75
|
)
|
|
30
|
|
|
107
|
|
|
(58
|
)
|
Comprehensive income
|
|
1,526
|
|
|
2,365
|
|
|
2,583
|
|
|
269
|
|
|
(5,189
|
)
|
|
1,554
|
|
Comprehensive income attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(28
|
)
|
|
(28
|
)
|
Comprehensive income attributable to controlling interests
|
|
$
|
1,526
|
|
|
$
|
2,365
|
|
|
$
|
2,583
|
|
|
$
|
269
|
|
|
$
|
(5,217
|
)
|
|
$
|
1,526
|
|
Condensed Consolidating Statements of Income and Comprehensive Income
for the Nine Months Ended September 30, 2018
(In Millions, Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Total Revenues
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,286
|
|
|
$
|
1,170
|
|
|
$
|
(93
|
)
|
|
$
|
10,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs, Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
3,084
|
|
|
197
|
|
|
(59
|
)
|
|
3,222
|
|
Depreciation, depletion and amortization
|
|
14
|
|
|
—
|
|
|
1,457
|
|
|
239
|
|
|
—
|
|
|
1,710
|
|
Other operating (income) expense
|
|
(42
|
)
|
|
1
|
|
|
2,903
|
|
|
(133
|
)
|
|
(34
|
)
|
|
2,695
|
|
Total Operating Costs, Expenses and Other
|
|
(28
|
)
|
|
1
|
|
|
7,444
|
|
|
303
|
|
|
(93
|
)
|
|
7,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss)
|
|
28
|
|
|
(1
|
)
|
|
1,842
|
|
|
867
|
|
|
—
|
|
|
2,736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from consolidated subsidiaries
|
|
1,987
|
|
|
1,828
|
|
|
726
|
|
|
48
|
|
|
(4,589
|
)
|
|
—
|
|
Earnings from equity investments
|
|
—
|
|
|
—
|
|
|
438
|
|
|
—
|
|
|
—
|
|
|
438
|
|
Interest, net
|
|
(578
|
)
|
|
(8
|
)
|
|
(819
|
)
|
|
(51
|
)
|
|
—
|
|
|
(1,456
|
)
|
Amortization of excess cost of equity investments and other, net
|
|
20
|
|
|
—
|
|
|
(14
|
)
|
|
7
|
|
|
—
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Tax
|
|
1,457
|
|
|
1,819
|
|
|
2,173
|
|
|
871
|
|
|
(4,589
|
)
|
|
1,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax (Expense) Benefit
|
|
(342
|
)
|
|
69
|
|
|
(65
|
)
|
|
24
|
|
|
—
|
|
|
(314
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
1,115
|
|
|
1,888
|
|
|
2,108
|
|
|
895
|
|
|
(4,589
|
)
|
|
1,417
|
|
Net Income Attributable to Noncontrolling Interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(302
|
)
|
|
(302
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Controlling Interests
|
|
1,115
|
|
|
1,888
|
|
|
2,108
|
|
|
895
|
|
|
(4,891
|
)
|
|
1,115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock Dividends
|
|
(117
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(117
|
)
|
Net Income Available to Common Shareholders
|
|
$
|
998
|
|
|
$
|
1,888
|
|
|
$
|
2,108
|
|
|
$
|
895
|
|
|
$
|
(4,891
|
)
|
|
$
|
998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
1,115
|
|
|
$
|
1,888
|
|
|
$
|
2,108
|
|
|
$
|
895
|
|
|
$
|
(4,589
|
)
|
|
$
|
1,417
|
|
Total other comprehensive income
|
|
155
|
|
|
109
|
|
|
65
|
|
|
295
|
|
|
(443
|
)
|
|
181
|
|
Comprehensive income
|
|
1,270
|
|
|
1,997
|
|
|
2,173
|
|
|
1,190
|
|
|
(5,032
|
)
|
|
1,598
|
|
Comprehensive income attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(328
|
)
|
|
(328
|
)
|
Comprehensive income attributable to controlling interests
|
|
$
|
1,270
|
|
|
$
|
1,997
|
|
|
$
|
2,173
|
|
|
$
|
1,190
|
|
|
$
|
(5,360
|
)
|
|
$
|
1,270
|
|
Condensed Consolidating Balance Sheets as of September 30, 2019
(In Millions, Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating
Adjustments
|
|
Consolidated KMI
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
239
|
|
|
$
|
—
|
|
|
$
|
241
|
|
Other current assets - affiliates
|
|
5,615
|
|
|
4,253
|
|
|
28,568
|
|
|
1,063
|
|
|
(39,499
|
)
|
|
—
|
|
All other current assets
|
|
121
|
|
|
40
|
|
|
1,781
|
|
|
201
|
|
|
(19
|
)
|
|
2,124
|
|
Property, plant and equipment, net
|
|
236
|
|
|
—
|
|
|
30,725
|
|
|
6,973
|
|
|
—
|
|
|
37,934
|
|
Investments
|
|
664
|
|
|
—
|
|
|
7,625
|
|
|
98
|
|
|
—
|
|
|
8,387
|
|
Investments in subsidiaries
|
|
45,755
|
|
|
42,907
|
|
|
4,514
|
|
|
4,401
|
|
|
(97,577
|
)
|
|
—
|
|
Goodwill
|
|
13,789
|
|
|
22
|
|
|
5,165
|
|
|
2,988
|
|
|
—
|
|
|
21,964
|
|
Notes receivable from affiliates
|
|
920
|
|
|
20,334
|
|
|
481
|
|
|
1,241
|
|
|
(22,976
|
)
|
|
—
|
|
Deferred income taxes
|
|
2,757
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,433
|
)
|
|
1,324
|
|
Other non-current assets
|
|
686
|
|
|
279
|
|
|
3,878
|
|
|
469
|
|
|
(355
|
)
|
|
4,957
|
|
Total assets
|
|
$
|
70,545
|
|
|
$
|
67,835
|
|
|
$
|
82,737
|
|
|
$
|
17,673
|
|
|
$
|
(161,859
|
)
|
|
$
|
76,931
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of debt
|
|
$
|
2,381
|
|
|
$
|
1,835
|
|
|
$
|
30
|
|
|
$
|
160
|
|
|
$
|
—
|
|
|
$
|
4,406
|
|
Other current liabilities - affiliates
|
|
18,152
|
|
|
14,212
|
|
|
6,101
|
|
|
1,034
|
|
|
(39,499
|
)
|
|
—
|
|
All other current liabilities
|
|
427
|
|
|
142
|
|
|
1,495
|
|
|
367
|
|
|
(11
|
)
|
|
2,420
|
|
Long-term debt
|
|
13,259
|
|
|
15,197
|
|
|
3,009
|
|
|
646
|
|
|
—
|
|
|
32,111
|
|
Notes payable to affiliates
|
|
1,644
|
|
|
448
|
|
|
20,529
|
|
|
355
|
|
|
(22,976
|
)
|
|
—
|
|
Deferred income taxes
|
|
—
|
|
|
—
|
|
|
556
|
|
|
877
|
|
|
(1,433
|
)
|
|
—
|
|
All other long-term liabilities and deferred credits
|
|
1,049
|
|
|
30
|
|
|
1,202
|
|
|
801
|
|
|
(363
|
)
|
|
2,719
|
|
Total liabilities
|
|
36,912
|
|
|
31,864
|
|
|
32,922
|
|
|
4,240
|
|
|
(64,282
|
)
|
|
41,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redeemable noncontrolling interest
|
|
—
|
|
|
—
|
|
|
801
|
|
|
—
|
|
|
—
|
|
|
801
|
|
Stockholders’ equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Total KMI equity
|
|
33,633
|
|
|
35,971
|
|
|
49,014
|
|
|
13,433
|
|
|
(98,418
|
)
|
|
33,633
|
|
Noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
841
|
|
|
841
|
|
Total stockholders’ equity
|
|
33,633
|
|
|
35,971
|
|
|
49,014
|
|
|
13,433
|
|
|
(97,577
|
)
|
|
34,474
|
|
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity
|
|
$
|
70,545
|
|
|
$
|
67,835
|
|
|
$
|
82,737
|
|
|
$
|
17,673
|
|
|
$
|
(161,859
|
)
|
|
$
|
76,931
|
|
Condensed Consolidating Balance Sheets as of December 31, 2018
(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
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,277
|
|
|
$
|
(5
|
)
|
|
$
|
3,280
|
|
Other current assets - affiliates
|
|
4,465
|
|
|
4,788
|
|
|
23,851
|
|
|
1,031
|
|
|
(34,135
|
)
|
|
—
|
|
All other current assets
|
|
171
|
|
|
17
|
|
|
2,056
|
|
|
212
|
|
|
(14
|
)
|
|
2,442
|
|
Property, plant and equipment, net
|
|
231
|
|
|
—
|
|
|
30,750
|
|
|
6,916
|
|
|
—
|
|
|
37,897
|
|
Investments
|
|
664
|
|
|
—
|
|
|
6,718
|
|
|
99
|
|
|
—
|
|
|
7,481
|
|
Investments in subsidiaries
|
|
42,096
|
|
|
40,049
|
|
|
6,077
|
|
|
4,324
|
|
|
(92,546
|
)
|
|
—
|
|
Goodwill
|
|
13,789
|
|
|
22
|
|
|
5,166
|
|
|
2,988
|
|
|
—
|
|
|
21,965
|
|
Notes receivable from affiliates
|
|
945
|
|
|
20,345
|
|
|
247
|
|
|
1,043
|
|
|
(22,580
|
)
|
|
—
|
|
Deferred income taxes
|
|
3,137
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,571
|
)
|
|
1,566
|
|
Other non-current assets
|
|
233
|
|
|
105
|
|
|
3,823
|
|
|
74
|
|
|
—
|
|
|
4,235
|
|
Total assets
|
|
$
|
65,739
|
|
|
$
|
65,326
|
|
|
$
|
78,688
|
|
|
$
|
19,964
|
|
|
$
|
(150,851
|
)
|
|
$
|
78,866
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of debt
|
|
$
|
1,933
|
|
|
$
|
1,300
|
|
|
$
|
30
|
|
|
$
|
125
|
|
|
$
|
—
|
|
|
$
|
3,388
|
|
Other current liabilities - affiliates
|
|
14,189
|
|
|
14,087
|
|
|
4,898
|
|
|
961
|
|
|
(34,135
|
)
|
|
—
|
|
All other current liabilities
|
|
486
|
|
|
354
|
|
|
1,838
|
|
|
1,510
|
|
|
(19
|
)
|
|
4,169
|
|
Long-term debt
|
|
13,474
|
|
|
16,799
|
|
|
3,020
|
|
|
643
|
|
|
—
|
|
|
33,936
|
|
Notes payable to affiliates
|
|
1,234
|
|
|
448
|
|
|
20,543
|
|
|
355
|
|
|
(22,580
|
)
|
|
—
|
|
Deferred income taxes
|
|
—
|
|
|
—
|
|
|
503
|
|
|
1,068
|
|
|
(1,571
|
)
|
|
—
|
|
Other long-term liabilities and deferred credits
|
|
745
|
|
|
59
|
|
|
944
|
|
|
428
|
|
|
—
|
|
|
2,176
|
|
Total liabilities
|
|
32,061
|
|
|
33,047
|
|
|
31,776
|
|
|
5,090
|
|
|
(58,305
|
)
|
|
43,669
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redeemable noncontrolling interest
|
|
—
|
|
|
—
|
|
|
666
|
|
|
—
|
|
|
—
|
|
|
666
|
|
Stockholders’ equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Total KMI equity
|
|
33,678
|
|
|
32,279
|
|
|
46,246
|
|
|
14,874
|
|
|
(93,399
|
)
|
|
33,678
|
|
Noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
853
|
|
|
853
|
|
Total stockholders’ equity
|
|
33,678
|
|
|
32,279
|
|
|
46,246
|
|
|
14,874
|
|
|
(92,546
|
)
|
|
34,531
|
|
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity
|
|
$
|
65,739
|
|
|
$
|
65,326
|
|
|
$
|
78,688
|
|
|
$
|
19,964
|
|
|
$
|
(150,851
|
)
|
|
$
|
78,866
|
|
Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2019
(In Millions, Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Net cash (used in) provided by operating activities
|
|
$
|
(2,666
|
)
|
|
$
|
3,126
|
|
|
$
|
10,978
|
|
|
$
|
299
|
|
|
$
|
(8,616
|
)
|
|
$
|
3,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(28
|
)
|
|
—
|
|
|
(28
|
)
|
Acquisitions of assets and investments
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
Capital expenditures
|
|
(27
|
)
|
|
—
|
|
|
(1,325
|
)
|
|
(367
|
)
|
|
—
|
|
|
(1,719
|
)
|
Proceeds from sales of equity investments
|
|
—
|
|
|
—
|
|
|
108
|
|
|
—
|
|
|
—
|
|
|
108
|
|
Contributions to investments
|
|
(128
|
)
|
|
—
|
|
|
(1,018
|
)
|
|
(2
|
)
|
|
—
|
|
|
(1,148
|
)
|
Distributions from equity investments in excess of cumulative earnings
|
|
1,315
|
|
|
—
|
|
|
197
|
|
|
—
|
|
|
(1,305
|
)
|
|
207
|
|
Funding to affiliates
|
|
(4,604
|
)
|
|
(255
|
)
|
|
(7,583
|
)
|
|
(649
|
)
|
|
13,091
|
|
|
—
|
|
Loans to related party
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
Other, net
|
|
7
|
|
|
—
|
|
|
(5
|
)
|
|
(6
|
)
|
|
—
|
|
|
(4
|
)
|
Net cash used in investing activities
|
|
(3,437
|
)
|
|
(255
|
)
|
|
(9,652
|
)
|
|
(1,052
|
)
|
|
11,786
|
|
|
(2,610
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuances of debt
|
|
5,027
|
|
|
—
|
|
|
—
|
|
|
91
|
|
|
—
|
|
|
5,118
|
|
Payments of debt
|
|
(4,928
|
)
|
|
(1,300
|
)
|
|
(8
|
)
|
|
(67
|
)
|
|
—
|
|
|
(6,303
|
)
|
Debt issue costs
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(9
|
)
|
Cash dividends - common shares
|
|
(1,593
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,593
|
)
|
Repurchases of common shares
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
Funding from affiliates
|
|
7,629
|
|
|
2,145
|
|
|
2,744
|
|
|
573
|
|
|
(13,091
|
)
|
|
—
|
|
Contributions from investment partner
|
|
—
|
|
|
—
|
|
|
135
|
|
|
—
|
|
|
—
|
|
|
135
|
|
Contributions from parents
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
Contributions from noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
Distributions to parents
|
|
—
|
|
|
(3,716
|
)
|
|
(4,200
|
)
|
|
(2,931
|
)
|
|
10,847
|
|
|
—
|
|
Distribution to noncontrolling interests - KML distribution of the TMPL Sale proceeds
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(879
|
)
|
|
(879
|
)
|
Distributions to noncontrolling interests - other
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(42
|
)
|
|
(42
|
)
|
Other, net
|
|
(28
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(28
|
)
|
Net cash provided by (used in) financing activities
|
|
6,097
|
|
|
(2,871
|
)
|
|
(1,326
|
)
|
|
(2,335
|
)
|
|
(3,165
|
)
|
|
(3,600
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash, cash equivalents and restricted deposits
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in Cash, Cash Equivalents and Restricted Deposits
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(3,062
|
)
|
|
5
|
|
|
(3,063
|
)
|
Cash, Cash Equivalents, and Restricted Deposits, beginning of period
|
|
8
|
|
|
—
|
|
|
—
|
|
|
3,328
|
|
|
(5
|
)
|
|
3,331
|
|
Cash, Cash Equivalents, and Restricted Deposits, end of period
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
266
|
|
|
$
|
—
|
|
|
$
|
268
|
|
Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2018
(In Millions, Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Net cash (used in) provided by operating activities
|
|
$
|
(2,355
|
)
|
|
$
|
2,879
|
|
|
$
|
8,204
|
|
|
$
|
869
|
|
|
$
|
(6,222
|
)
|
|
$
|
3,375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,003
|
|
|
—
|
|
|
3,003
|
|
Acquisitions of assets and investments
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
Capital expenditures
|
|
(3
|
)
|
|
—
|
|
|
(1,433
|
)
|
|
(770
|
)
|
|
—
|
|
|
(2,206
|
)
|
Proceeds from sales of equity investments
|
|
—
|
|
|
—
|
|
|
33
|
|
|
—
|
|
|
—
|
|
|
33
|
|
Contributions to investments
|
|
—
|
|
|
—
|
|
|
(287
|
)
|
|
(7
|
)
|
|
—
|
|
|
(294
|
)
|
Distributions from equity investments in excess of cumulative earnings
|
|
1,932
|
|
|
—
|
|
|
197
|
|
|
—
|
|
|
(1,932
|
)
|
|
197
|
|
Funding to affiliates
|
|
(5,452
|
)
|
|
(30
|
)
|
|
(5,366
|
)
|
|
(780
|
)
|
|
11,628
|
|
|
—
|
|
Loans to related party
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
Other, net
|
|
6
|
|
|
—
|
|
|
(18
|
)
|
|
8
|
|
|
—
|
|
|
(4
|
)
|
Net cash (used in) provided by investing activities
|
|
(3,517
|
)
|
|
(30
|
)
|
|
(6,917
|
)
|
|
1,454
|
|
|
9,696
|
|
|
686
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuances of debt
|
|
11,229
|
|
|
—
|
|
|
—
|
|
|
608
|
|
|
—
|
|
|
11,837
|
|
Payments of debt
|
|
(9,277
|
)
|
|
(975
|
)
|
|
(780
|
)
|
|
(189
|
)
|
|
—
|
|
|
(11,221
|
)
|
Debt issue costs
|
|
(24
|
)
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
(31
|
)
|
Cash dividends - common shares
|
|
(1,163
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,163
|
)
|
Cash dividends - preferred shares
|
|
(117
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(117
|
)
|
Repurchases of common shares
|
|
(250
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(250
|
)
|
Funding from affiliates
|
|
5,484
|
|
|
1,971
|
|
|
3,510
|
|
|
663
|
|
|
(11,628
|
)
|
|
—
|
|
Contribution from investment partner
|
|
—
|
|
|
—
|
|
|
148
|
|
|
—
|
|
|
—
|
|
|
148
|
|
Contributions from parents
|
|
—
|
|
|
—
|
|
|
19
|
|
|
—
|
|
|
(19
|
)
|
|
—
|
|
Contributions from noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
19
|
|
Distributions to parents
|
|
—
|
|
|
(3,801
|
)
|
|
(4,184
|
)
|
|
(228
|
)
|
|
8,213
|
|
|
—
|
|
Distributions to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(58
|
)
|
|
(58
|
)
|
Other, net
|
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
(17
|
)
|
Net cash provided by (used in) financing activities
|
|
5,870
|
|
|
(2,805
|
)
|
|
(1,287
|
)
|
|
842
|
|
|
(3,473
|
)
|
|
(853
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash, cash equivalents and restricted deposits
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits
|
|
(2
|
)
|
|
44
|
|
|
—
|
|
|
3,191
|
|
|
1
|
|
|
3,234
|
|
Cash, Cash Equivalents, and Restricted Deposits, beginning of period
|
|
3
|
|
|
1
|
|
|
—
|
|
|
323
|
|
|
(1
|
)
|
|
326
|
|
Cash, Cash Equivalents, and Restricted Deposits, end of period
|
|
$
|
1
|
|
|
$
|
45
|
|
|
$
|
—
|
|
|
$
|
3,514
|
|
|
$
|
—
|
|
|
$
|
3,560
|
|