NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Organization
We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately
84,000
miles of pipelines and
155
terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO
2
and other products, and our terminals transload and store petroleum products, ethanol and chemicals, and handle such products as steel, coal and petroleum coke. We are also a leading producer of CO
2
, which we and others utilize for enhanced oil recovery projects primarily in the Permian basin.
Basis of Presentation
General
Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the United States Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification, the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation.
In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair 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
2016
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.
Impairments and Losses on Divestitures, net
During the six months ended
June 30, 2017
, we recorded non-cash pre-tax losses on impairments and divestitures netting to
$6 million
related to miscellaneous asset disposals. During the three and six months ended June 30, 2016, we recorded non-cash pre-tax losses on impairments and divestitures netting to
$2 million
and
$257 million
, respectively. The six months ended June 30, 2016 included (i)
$216 million
of project write-offs across our Natural Gas Pipelines, CO
2
,
and Products Pipelines business segments, of which
$20 million
was related to our share of impairments recorded by our equity investees; (ii)
$20 million
of impairments related to certain coal facilities in our Terminals business segment; (iii)
$8 million
of loss related to the sale of a Transmix facility in our Products Pipelines business segment; and (iv)
$13 million
of net losses on miscellaneous asset disposals.
In addition, during the three and six months ended June 30, 2016 we recognized a
$12 million
gain on the sale of an equity investment, which is included in “Gain on impairments and divestitures of equity investments, net” on the accompanying consolidated statements of income.
These impairments were driven by market conditions that existed at the time and require management to estimate fair value of these assets. The impairments resulting from decisions to classify assets as held-for-sale are based on the value expected to be realized in the transaction which is generally known at the time. The estimates of fair value are based on Level 3 valuation estimates using industry standard income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect to general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. In certain cases, management’s decisions to dispose of certain assets may trigger impairments. We typically use discounted cash flow analyses to determine the fair value of our assets. We may probability weight various forecasted cash flow scenarios utilized in the analysis as we consider the possible
outcomes. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular asset.
We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill. Because certain assets, including some equity investments and oil and gas producing properties, have been recently written down to fair value, any deterioration in fair value relative to our carrying value increases the likelihood of further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to be not fully recoverable.
Goodwill
We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have
seven
reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; (vi) Terminals; and (vii) Kinder Morgan Canada. The evaluation of goodwill for impairment involves a two-step test.
Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and, if so, the amount of the impairment.
The results of our May 31, 2017 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value and step 2 was not required. For our Natural Gas Pipelines - Non-Regulated, the fair value of the reporting unit exceeded the carrying value (including approximately
$4 billion
of allocated goodwill) by
4%
.
The fair value estimates used in the step 1 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 asset.
We expect that the fair value of our Natural Gas Pipelines - Non-Regulated reporting unit will continue to exceed carrying value so long as our estimate of future cash flows and the market valuation remain consistent with current levels. A continued period of volatile commodity prices could result in further deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. 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.
Earnings per Share
We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares of common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be stock or stock units issued to management employees and include dividend equivalent payments, do not participate in excess distributions over earnings.
The following table sets forth the allocation of net income available to shareholders of Class P shares and participating securities (in millions):
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|
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Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Class P shares
|
$
|
336
|
|
|
$
|
332
|
|
|
$
|
735
|
|
|
$
|
607
|
|
Participating securities:
|
|
|
|
|
|
|
|
Restricted stock awards(a)
|
1
|
|
|
1
|
|
|
3
|
|
|
2
|
|
Net Income Available to Common Stockholders
|
$
|
337
|
|
|
$
|
333
|
|
|
$
|
738
|
|
|
$
|
609
|
|
________
|
|
(a)
|
As of
June 30, 2017
, there were approximately
9 million
restricted stock awards.
|
On May 25, 2017, approximately
293 million
of warrants expired. In addition, 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):
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|
|
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|
|
|
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|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Unvested restricted stock awards
|
9
|
|
|
8
|
|
|
9
|
|
|
8
|
|
Convertible trust preferred securities
|
3
|
|
|
8
|
|
|
3
|
|
|
8
|
|
Mandatory convertible preferred stock(a)
|
58
|
|
|
58
|
|
|
58
|
|
|
58
|
|
_______
(a) Until our mandatory convertible preferred shares are converted to common shares, on or before the expected mandatory conversion date of October 26, 2018, the holder of each preferred share participates in our earnings by receiving preferred dividends.
2. Divestitures
Sale of Approximate 30% Interest in Canadian Business
On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of
102,942,000
restricted voting shares on the Toronto Stock Exchange at a price to the public of
C$17.00
per restricted voting share for total gross proceeds of approximately
C$1,750 million
(USD
$1,299 million
). The net proceeds from the IPO were used by KML to indirectly acquire from us an approximate
30%
interest in a limited partnership that holds our Canadian business with KMI retaining the remaining
70%
interest. We used the proceeds from KML to pay down debt.
Subsequent to the IPO, we retained control of KML and the limited partnership, and as a result, they remain consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net income attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017.
The net proceeds received of
$1,247 million
are presented as “Contributions from noncontrolling interests - KML IPO” on our consolidated statement of cash flows for the six months ended June 30, 2017. Because we retained control of KML subsequent to the IPO, the
$316 million
adjustment made to “Additional paid-in capital” on our consolidated statement of stockholders equity for the six months ended June 30, 2017 represents the difference between our book value prior to the sale and our share of book value in KML’s net assets after the sale. The impact of the IPO resulted in a
$165 million
deferred income tax adjustment.
$764 million
is attributed to the KML public shareholders to reflect their proportionate ownership percentage in the net assets of KML acquired from us and is presented in “Noncontrolling interests” on our consolidated statement of stockholders equity for the six months ended June 30, 2017. The above amounts recorded to “Additional paid-in capital” and “Noncontrolling interests” are net of IPO fees, which includes
$2 million
accrued at June 30, 2017.
The above amount recorded to “Noncontrolling interests” has been reduced by
$81 million
primarily associated with the allocation of currency translation adjustments recorded in “Accumulated other comprehensive loss” to “Noncontrolling interests.”
The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that are included in our Kinder Morgan Canada, Terminals and Product Pipelines business segments and include (i) the Trans
Mountain pipeline system; (ii) the Canadian Cochin pipeline system; (iii) the Puget Sound pipeline system; (iv) the Jet Fuel pipeline system; and (v) terminal facilities located in Western Canada.
Kinder Morgan Canada Limited Partnership
In conjunction with the IPO, Kinder Morgan Canada Limited Partnership (KMC LP) and Kinder Morgan Canada GP Inc. (KMC GP) were formed to hold our Canadian business. We have determined that KMC LP is a variable interest entity because a simple majority or lower threshold of the limited partnership interests do not possess substantive “kick-out rights” (i.e., the right to remove the general partner or to dissolve (liquidate) the entity without cause) or substantive participation rights. We have also determined KMC GP is the primary beneficiary because it has the power to direct the activities that most significantly impact KMC LP’s performance, the right to receive benefits and the obligation to absorb losses, that could be significant to KMC LP. As a result, KMC GP consolidates KMC LP. KMC GP is a wholly-owned subsidiary of KML, which is indirectly controlled by us through our
100%
interest in KML’s special voting shares that represent approximately
70%
of KML’s total voting shares (comprised of restricted voting shares and special voting shares). Consequently, we consolidate KML and the variable interest entity, KMC LP, in our consolidated financial statements.
The following table shows the carrying amount and classification of KMC LP’s assets and liabilities in our consolidated balance sheets (in millions):
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June 30, 2017
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Assets
|
|
|
Total current assets
|
|
$
|
235
|
|
Property, plant and equipment, net
|
|
2,580
|
|
Total goodwill, deferred charges and other assets
|
|
298
|
|
Total assets
|
|
$
|
3,113
|
|
Liabilities
|
|
|
Total current liabilities
|
|
$
|
366
|
|
Long-term debt, excluding current maturities
|
|
—
|
|
Total other long-term liabilities and deferred credits
|
|
371
|
|
Total liabilities
|
|
$
|
737
|
|
We receive distributions from KMC LP through our indirectly owned limited partnership interests in KMC LP, but otherwise the assets of KMC LP cannot be used to settle our obligations. Our subsidiaries that are the direct owners of our limited partnership interests in KMC LP have guaranteed the obligations of KMC LP’s wholly owned subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, under the Credit Facility (see Note 3), but recourse in respect of such guarantee is limited solely to the limited partnership interests of KMC LP held by such subsidiaries and any proceeds thereof. Additionally, in connection with the Credit Facility, we entered into an Equity Nomination and Support Agreement whereby, among other things, we commit to contribute or cause to be contributed at the time of each drawdown on the construction credit facility or the contingent credit facility either equity or subordinated debt to Kinder Morgan Cochin ULC in an amount sufficient to cause the outstanding indebtedness under the credit facilities and any other funded debt for the Trans Mountain expansion project not to exceed
60%
of the total project costs for the project as projected over the six month period following the date of such drawdown. Other than such guarantees and the Equity Nomination and Support Agreement, we do not guarantee the debt, commercial paper or other similar commitments of KMC LP or any of its subsidiaries, and the obligations of KMC LP may only be settled using the assets of KMC LP. KMC LP does not guarantee the debt or other similar commitments of KMI.
Sale of Interest in Elba Liquefaction Company L.L.C. (ELC)
Effective February 28, 2017, we sold a
49%
partnership interest in ELC to investment funds managed by EIG Global Energy Partners (EIG). We continue to own a
51%
controlling interest in and operate ELC. Under the terms of ELC’s limited liability company agreement, we are responsible for placing in service and operating certain supply pipelines and terminal facilities that support the operations of ELC and which are wholly owned by us. In certain limited circumstances which are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account.
As a result of these contingencies, the sale proceeds of
$386 million
, and subsequent EIG contributions, have been recorded as a deferred credit within “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of June 30, 2017. EIG is not entitled to any specified return on its capital. Once these contingencies expire, EIG’s capital account will be reflected as noncontrolling interest on our consolidated balance sheet.
3. Debt
We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income.
The following table provides detail on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts, premiums and issuance costs (in millions):
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June 30, 2017
|
|
December 31, 2016
|
Unsecured term loan facility, variable rate, due January 26, 2019
|
$
|
1,000
|
|
|
$
|
1,000
|
|
Senior notes, 1.50% through 8.05%, due 2017 through 2098(a)
|
12,563
|
|
|
13,236
|
|
Credit facility due November 26, 2019
|
—
|
|
|
—
|
|
Commercial paper borrowings
|
115
|
|
|
—
|
|
KML Credit Facility(b)
|
146
|
|
|
—
|
|
KMP senior notes, 2.65% through 9.00%, due 2017 through 2044(c)
|
18,885
|
|
|
19,485
|
|
TGP senior notes, 7.00% through 8.375%, due 2017 through 2037(d)
|
1,240
|
|
|
1,540
|
|
EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(e)
|
760
|
|
|
1,115
|
|
CIG senior notes, 4.15% and 6.85%, due 2026 and 2037
|
475
|
|
|
475
|
|
Kinder Morgan Finance Company, LLC, senior notes, 6.00% and 6.40%, due 2018 and 2036
|
786
|
|
|
786
|
|
Hiland Partners Holdings LLC, senior note, 5.50%, due 2022
|
225
|
|
|
225
|
|
EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035
|
427
|
|
|
433
|
|
Trust I preferred securities, 4.75%, due March 31, 2028(f)
|
221
|
|
|
221
|
|
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock
|
100
|
|
|
100
|
|
Other miscellaneous debt
|
281
|
|
|
285
|
|
Total debt – KMI and Subsidiaries
|
37,224
|
|
|
38,901
|
|
Less: Current portion of debt(g)
|
3,224
|
|
|
2,696
|
|
Total long-term debt – KMI and Subsidiaries(h)
|
$
|
34,000
|
|
|
$
|
36,205
|
|
_______
|
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(a)
|
Amount includes senior notes that are denominated in Euros and have been converted to U.S. dollars and are respectively reported above at the
June 30, 2017
exchange rate of
1.1426
U.S. dollars per Euro and the
December 31, 2016
exchange rate of
1.0517
U.S. dollars per Euro. For the
six
months ended
June 30, 2017
, our debt balance increased by
$114 million
as a result of the change in the exchange rate of U.S. dollars per Euro. The increase in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “ Other long-term liabilities and deferred credits” on our consolidated balance sheets. At the time of issuance, we entered into cross-currency swap agreements associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 5 “Risk Management—
Foreign Currency Risk Management
”). In June, 2017, we repaid
$786 million
of maturing
7.00%
senior notes.
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(b)
|
The credit facility is denominated in C$ and has been converted to U.S. dollars and reported above at the June 30, 2017 exchange rate of
0.7706
U.S. dollars per C$. See
“—Credit Facilities
” below.
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(c)
|
In February 2017, we repaid
$600 million
of maturing
6.00%
senior notes.
|
|
|
(d)
|
In April 2017, we repaid
$300 million
of maturing
7.50%
senior notes.
|
|
|
(e)
|
In April 2017, we repaid
$355 million
of maturing
5.95%
senior notes.
|
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(f)
|
The Trust I Preferred Securities are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder. Prior to May 25, 2017, conversions of these securities were converted into the following mixed consideration: (i)
0.7197
of a share of our Class P common stock; (ii)
$25.18
in cash without interest; and (iii)
1.100
warrants to purchase a share of our Class P common stock. Our warrants expired on May 25, 2017, along with conversion of
1.100
warrants to purchase a share of our Class P common mixed consideration.
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(g)
|
Amounts include outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months (see “—
Current Portion of Debt
” below).
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(h)
|
Excludes our “Debt fair value adjustments” which, as of
June 30, 2017
and
December 31, 2016
, increased our combined debt balances by
$1,100 million
and
$1,149 million
, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs
|
and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements.
We and substantially all of our wholly owned domestic subsidiaries are a party to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Also, see Note 11.
Credit Facilities
As of
June 30, 2017
, we had
$4,774 million
available under our
$5.0 billion
revolving credit agreement, which is net of
$111 million
in letters of credit. Borrowings under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.
On June 16, 2017, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, our indirect subsidiaries of KML, entered into a definitive credit agreement establishing (i) a
C$4.0 billion
revolving construction facility for the purposes of funding the development, construction and completion of the Trans Mountain expansion project, (ii) a
C$1.0 billion
revolving contingent credit facility for the purpose of funding, if necessary, additional Trans Mountain expansion project costs (and, subject to the need to fund such additional costs, meeting the Canadian National Energy Board-mandated liquidity requirements) and (iii) a
C$500 million
revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “Credit Facility”). The Credit Facility has a
five
year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. Any undrawn commitments under the Credit Facility will incur a standby fee of
0.30%
to
0.625%
, with the range dependent on the credit ratings of Kinder Morgan Cochin ULC or KML. The Credit Facility is guaranteed by KML and all of the non-borrower subsidiaries of KML and are secured by a first lien security interest on all of the assets of KML and the equity and assets of the other guarantors.
Draw down of funds on the Credit Facility bear interest dependent on the type of loans requested and are as follows:
|
|
•
|
bankers’ acceptances or London Interbank Offered Rate loans are at an annual rate of approximately CDOR or the London Interbank Offered Rate, as the case may be, plus a fixed spread ranging from
1.50%
to
2.50%
;
|
|
|
•
|
loans in Canadian dollars or U.S. dollars are at an annual rate of approximately the Canadian prime rate or the U.S. dollar base rate, as the case may be, plus a fixed spread ranging from
0.50%
to
1.50%
, in each case, with the range dependent on the credit ratings of the Company;
|
|
|
•
|
letters of credit (under working capital facility only) will have issuance fees based on an annual rate of approximately CDOR plus a fixed spread ranging from
1.50%
to
2.50%
, with the range dependent on the credit ratings of the Company.
|
The foregoing rates and fees will increase by
0.25%
upon the fourth anniversary of the Credit Facility.
Our Credit Facility includes various financial and other covenants including:
|
|
•
|
a maximum ratio of consolidated total funded debt to consolidated capitalization of
70%
;
|
|
|
•
|
restrictions on ability to incur debt;
|
|
|
•
|
restrictions on ability to make dispositions, restricted payments and investments;
|
|
|
•
|
restrictions on granting liens and on sale-leaseback transactions;
|
|
|
•
|
restrictions on ability to engage in transactions with affiliates; and
|
|
|
•
|
restrictions on ability to amend organizational documents and engage in corporate reorganization transactions.
|
As of June 30, 2017, we were in compliance with all required covenants. As of June 30, 2017, we had
$126.9 million
(C
$164.7 million
) outstanding on our construction facility and
$18.9 million
(C
$24.5 million
) outstanding on our working capital facility, both included in “Current portion of debt” on our consolidated balance sheet. For the six months ended June 30, 2017, we incurred
$0.5 million
in standby fees.
Current Portion of Debt
Our current portion of debt as of
June 30, 2017
, primarily includes the following significant series of long-term notes maturing within the next 12 months:
|
|
Senior notes - $500 million 2.00% notes due December 2017
|
Kinder Morgan Finance Company, LLC, senior notes - $750 million 6.00% notes due January 2018
|
Senior notes - $82 million 7.00% notes due February 2018
|
KMP senior notes - $975 million 5.95% notes due February 2018
|
Senior notes - $477 million 7.25% notes due June 2018
|
4. Stockholders’ Equity
Common Equity
As of
June 30, 2017
, our common equity consisted of our Class P common stock. For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our
2016
Form 10-K.
KMI Common Dividends
Holders of our common stock participate in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. Our per share dividends declared for and paid in the six months periods ended
June 30, 2017
and 2016 were
$0.250
per share. On July 19, 2017, our board of directors declared a cash dividend of
$0.125
per common share for the quarterly period ended
June 30, 2017
, which is payable on August 15, 2017 to common shareholders of record as of July 31, 2017.
Warrants
On May 25, 2017,
293 million
of unexercised warrants to buy KMI common stock expired. Prior to expiration, each of the warrants entitled the holder to purchase one share of our common stock for an exercise price of
$40
per share, payable in cash or by cashless exercise.
Mandatory Convertible Preferred Stock
We have issued and outstanding
1,600,000
shares of
9.750%
Series A mandatory convertible preferred stock, with a liquidating preference of
$1,000
per share. For additional information regarding our mandatory convertible preferred stock, see Note 11 to our consolidated financial statements included in our
2016
Form 10-K.
Preferred Dividends
On April 19, 2017, our board of directors declared a cash dividend of
$24.375
per share of our mandatory convertible preferred stock (equivalent of
$1.21875
per depositary share) for the period from and including April 26, 2017 through and including July 25, 2017, which is payable on July 26, 2017 to mandatory convertible preferred shareholders of record as of July 11, 2017.
Noncontrolling Interests
KML Restricted Voting Shares
As discussed in Note 2, on May 30, 2017 our indirect subsidiary, KML, issued
102,942,000
restricted voting shares in a public offering. The public ownership of the KML restricted voting shares represents an approximate
30%
interest in our Canadian operations and is reflected within “Noncontrolling interests” in our consolidated financial statements as of and for the periods presented after May 30, 2017.
On July 19, 2017, KML’s board of directors declared a prorated dividend for the first quarter of
C$0.0571
per restricted voting share, payable on August 15, 2017, to restricted voting shareholders of record as of July 31, 2017. The initial dividend is prorated from May 30, 2017, the day that KML closed its offering, to June 30, 2017. Based on a full quarter, the dividend amounts to
C$0.1625
per restricted voting share (
C$0.65
annualized). The total KML dividend declared for the three months ended June 30, 2017 amounted to approximately
C$5.9 million
.
5. Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks. In addition, prior to May 2016, we had legacy power forward and swap contracts related to operations of acquired businesses.
Energy Commodity Price Risk Management
As of
June 30, 2017
, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
|
|
|
|
|
|
|
Net open position long/(short)
|
Derivatives designated as hedging contracts
|
|
|
|
Crude oil fixed price
|
(20.1
|
)
|
|
MMBbl
|
Crude oil basis
|
(2.7
|
)
|
|
MMBbl
|
Natural gas fixed price
|
(54.9
|
)
|
|
Bcf
|
Natural gas basis
|
(27.0
|
)
|
|
Bcf
|
Derivatives not designated as hedging contracts
|
|
|
|
|
Crude oil fixed price
|
(0.9
|
)
|
|
MMBbl
|
Crude oil basis
|
(0.5
|
)
|
|
MMBbl
|
Natural gas fixed price
|
4.6
|
|
|
Bcf
|
Natural gas basis
|
(39.0
|
)
|
|
Bcf
|
NGL and other fixed price
|
(6.1
|
)
|
|
MMBbl
|
As of
June 30, 2017
, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2021.
Interest Rate Risk Management
As of
June 30, 2017
and
December 31, 2016
, we had a combined notional principal amount of
$9,575 million
and
$9,775 million
, respectively, of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of London Interbank Offered Rate plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of
June 30, 2017
, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.
Foreign Currency Risk Management
As of
June 30, 2017
, we had a notional principal amount of
$1,358 million
of cross-currency swap agreements to manage the foreign currency risk related to our Euro denominated senior notes by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates equivalent to approximately
3.79%
and
4.67%
for the
7
-year and
12
-year senior notes, respectively. These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior notes.
Fair Value of Derivative Contracts
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivative Contracts
|
|
|
|
|
Asset derivatives
|
|
Liability derivatives
|
|
|
|
|
June 30,
2017
|
|
December 31,
2016
|
|
June 30,
2017
|
|
December 31,
2016
|
|
|
Location
|
|
Fair value
|
|
Fair value
|
Derivatives designated as hedging contracts
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude derivative contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
$
|
149
|
|
|
$
|
101
|
|
|
$
|
(6
|
)
|
|
$
|
(57
|
)
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
82
|
|
|
70
|
|
|
(2
|
)
|
|
(24
|
)
|
Subtotal
|
|
|
|
231
|
|
|
171
|
|
|
(8
|
)
|
|
(81
|
)
|
Interest rate swap agreements
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
69
|
|
|
94
|
|
|
—
|
|
|
—
|
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
211
|
|
|
206
|
|
|
(30
|
)
|
|
(57
|
)
|
Subtotal
|
|
|
|
280
|
|
|
300
|
|
|
(30
|
)
|
|
(57
|
)
|
Cross-currency swap agreements
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|
(7
|
)
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
82
|
|
|
—
|
|
|
—
|
|
|
(24
|
)
|
Subtotal
|
|
|
|
82
|
|
|
—
|
|
|
(21
|
)
|
|
(31
|
)
|
Total
|
|
|
|
593
|
|
|
471
|
|
|
(59
|
)
|
|
(169
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, crude, NGL and other derivative contracts
|
|
Fair value of derivative contracts/(Other current liabilities)
|
|
12
|
|
|
3
|
|
|
(6
|
)
|
|
(29
|
)
|
|
|
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
Subtotal
|
|
|
|
12
|
|
|
3
|
|
|
(7
|
)
|
|
(30
|
)
|
Total
|
|
|
|
12
|
|
|
3
|
|
|
(7
|
)
|
|
(30
|
)
|
Total derivatives
|
|
|
|
$
|
605
|
|
|
$
|
474
|
|
|
$
|
(66
|
)
|
|
$
|
(199
|
)
|
Effect of Derivative Contracts on the Income Statement
The following tables summarize the impact of our derivative contracts in our accompanying consolidated statements of income (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in fair value hedging relationships
|
|
Location
|
|
Gain/(loss) recognized in income
on derivatives and related hedged item
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swap agreements
|
|
Interest, net
|
|
$
|
46
|
|
|
$
|
119
|
|
|
$
|
7
|
|
|
$
|
399
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged fixed rate debt
|
|
Interest, net
|
|
$
|
(47
|
)
|
|
$
|
(120
|
)
|
|
$
|
(11
|
)
|
|
$
|
(404
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in cash flow hedging relationships
|
|
Gain/(loss)
recognized in OCI on derivative (effective portion)(a)
|
|
Location
|
|
Gain/(loss) reclassified from Accumulated OCI
into income (effective portion)(b)
|
|
Location
|
|
Gain/(loss)
recognized in income
on derivative
(ineffective portion
and amount
excluded from
effectiveness testing)
|
|
|
Three Months Ended June 30,
|
|
|
|
Three Months Ended June 30,
|
|
|
|
Three Months Ended June 30,
|
|
|
2017
|
|
2016
|
|
|
|
2017
|
|
2016
|
|
|
|
2017
|
|
2016
|
Energy commodity
derivative contracts
|
|
$
|
52
|
|
|
$
|
(111
|
)
|
|
Revenues—Natural
gas sales
|
|
$
|
(1
|
)
|
|
$
|
2
|
|
|
Revenues—Natural
gas sales
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Revenues—Product
sales and other
|
|
14
|
|
|
33
|
|
|
Revenues—Product
sales and other
|
|
5
|
|
|
(6
|
)
|
|
|
|
|
|
|
Costs of sales
|
|
1
|
|
|
(2
|
)
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
Interest rate swap
agreements(c)
|
|
(1
|
)
|
|
(1
|
)
|
|
Interest, net
|
|
(1
|
)
|
|
—
|
|
|
Interest, net
|
|
—
|
|
|
—
|
|
Cross-currency swap
|
|
57
|
|
|
(30
|
)
|
|
Other, net
|
|
62
|
|
|
(22
|
)
|
|
Other, net
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
108
|
|
|
$
|
(142
|
)
|
|
Total
|
|
$
|
75
|
|
|
$
|
11
|
|
|
Total
|
|
$
|
5
|
|
|
$
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in cash flow hedging relationships
|
|
Gain/(loss)
recognized in OCI on derivative (effective portion)(a)
|
|
Location
|
|
Gain/(loss) reclassified from Accumulated OCI
into income (effective portion)(b)
|
|
Location
|
|
Gain/(loss)
recognized in income
on derivative
(ineffective portion
and amount
excluded from
effectiveness testing)
|
|
|
Six Months Ended June 30,
|
|
|
|
Six Months Ended June 30,
|
|
|
|
Six Months Ended June 30,
|
|
|
2017
|
|
2016
|
|
|
|
2017
|
|
2016
|
|
|
|
2017
|
|
2016
|
Energy commodity
derivative contracts
|
|
$
|
120
|
|
|
$
|
(84
|
)
|
|
Revenues—Natural
gas sales
|
|
$
|
1
|
|
|
$
|
23
|
|
|
Revenues—Natural
gas sales
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Revenues—Product
sales and other
|
|
20
|
|
|
90
|
|
|
Revenues—Product
sales and other
|
|
8
|
|
|
(5
|
)
|
|
|
|
|
|
|
Costs of sales
|
|
4
|
|
|
(12
|
)
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
Interest rate swap
agreements(c)
|
|
(1
|
)
|
|
(5
|
)
|
|
Interest, net
|
|
(1
|
)
|
|
(1
|
)
|
|
Interest, net
|
|
—
|
|
|
—
|
|
Cross-currency swap
|
|
59
|
|
|
20
|
|
|
Other, net
|
|
72
|
|
|
19
|
|
|
Other, net
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
178
|
|
|
$
|
(69
|
)
|
|
Total
|
|
$
|
96
|
|
|
$
|
119
|
|
|
Total
|
|
$
|
8
|
|
|
$
|
(5
|
)
|
_____
|
|
(a)
|
We expect to reclassify an approximate
$60 million
gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of
June 30, 2017
into earnings during the next twelve months (when the associated forecasted transactions are also expected to occur), however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
|
|
|
(b)
|
Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
|
|
|
(c)
|
Amounts represent our share of an equity investee’s accumulated other comprehensive loss.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as accounting hedges
|
|
Location
|
|
Gain/(loss) recognized in income on derivatives
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Energy commodity derivative contracts
|
|
Revenues—Natural gas sales
|
|
$
|
5
|
|
|
$
|
(11
|
)
|
|
$
|
11
|
|
|
$
|
(5
|
)
|
|
|
Revenues—Product sales and other
|
|
7
|
|
|
(12
|
)
|
|
19
|
|
|
(14
|
)
|
|
|
Costs of sales
|
|
—
|
|
|
3
|
|
|
—
|
|
|
(2
|
)
|
Interest rate swap agreements
|
|
Interest, net
|
|
—
|
|
|
24
|
|
|
—
|
|
|
77
|
|
Total(a)
|
|
|
|
$
|
12
|
|
|
$
|
4
|
|
|
$
|
30
|
|
|
$
|
56
|
|
_______
(a) Three and six months ended
June 30, 2017
includes approximate gains of
$17 million
and
$29 million
, respectively, associated with natural gas, crude and NGL derivative contract settlements. Three and six months ended
June 30, 2016
includes approximate gains of
$20 million
and
$39 million
, respectively, associated with natural gas, crude and NGL derivative contract settlements.
Credit Risks
In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of
June 30, 2017
and
December 31, 2016
, we had
no
outstanding letters of credit supporting our commodity price risk management program. As of
June 30, 2017
and
December 31, 2016
, we had cash margins of
$7 million
and
$37 million
, respectively, posted by us with our counterparties as collateral and
no
amounts posted by our counterparties as collateral. The balance at
June 30, 2017
, consisted of initial margin requirements of
$14 million
, offset by variation margin requirements of
$7 million
. We also use industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of
June 30, 2017
, based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded
one
or
two
notches we would not be required to post additional collateral.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
|
|
Foreign
currency
translation
adjustments
|
|
Pension and
other
postretirement
liability adjustments
|
|
Total
accumulated other
comprehensive loss
|
Balance as of December 31, 2016
|
$
|
(1
|
)
|
|
$
|
(288
|
)
|
|
$
|
(372
|
)
|
|
$
|
(661
|
)
|
Other comprehensive gain before reclassifications
|
178
|
|
|
32
|
|
|
13
|
|
|
223
|
|
Gains reclassified from accumulated other comprehensive loss
|
(96
|
)
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
KML IPO
|
—
|
|
|
44
|
|
|
7
|
|
|
51
|
|
Net current-period other comprehensive income
|
82
|
|
|
76
|
|
|
20
|
|
|
178
|
|
Balance as of June 30, 2017
|
$
|
81
|
|
|
$
|
(212
|
)
|
|
$
|
(352
|
)
|
|
$
|
(483
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized
gains/(losses)
on cash flow
hedge derivatives
|
|
Foreign
currency
translation
adjustments
|
|
Pension and
other
postretirement
liability adjustments
|
|
Total
accumulated other
comprehensive loss
|
Balance as of December 31, 2015
|
$
|
219
|
|
|
$
|
(322
|
)
|
|
$
|
(358
|
)
|
|
$
|
(461
|
)
|
Other comprehensive (loss) gain before reclassifications
|
(69
|
)
|
|
85
|
|
|
10
|
|
|
26
|
|
Gains reclassified from accumulated other comprehensive loss
|
(119
|
)
|
|
—
|
|
|
—
|
|
|
(119
|
)
|
Net current-period other comprehensive (loss) income
|
(188
|
)
|
|
85
|
|
|
10
|
|
|
(93
|
)
|
Balance as of June 30, 2016
|
$
|
31
|
|
|
$
|
(237
|
)
|
|
$
|
(348
|
)
|
|
$
|
(554
|
)
|
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 Codification (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet asset
fair value measurements by level
|
|
|
|
Net amount
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross amount
|
|
Contracts available for netting
|
|
Cash collateral held(b)
|
As of June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
10
|
|
|
$
|
233
|
|
|
$
|
—
|
|
|
$
|
243
|
|
|
$
|
(12
|
)
|
|
$
|
(7
|
)
|
|
$
|
224
|
|
Interest rate swap agreements
|
—
|
|
|
280
|
|
|
—
|
|
|
280
|
|
|
(13
|
)
|
|
—
|
|
|
267
|
|
Cross-currency swap agreements
|
—
|
|
|
82
|
|
|
—
|
|
|
82
|
|
|
(20
|
)
|
|
—
|
|
|
62
|
|
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
6
|
|
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
174
|
|
|
$
|
(43
|
)
|
|
$
|
—
|
|
|
$
|
131
|
|
Interest rate swap agreements
|
—
|
|
|
300
|
|
|
—
|
|
|
300
|
|
|
(18
|
)
|
|
—
|
|
|
282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet liability
fair value measurements by level
|
|
|
|
Net amount
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross amount
|
|
Contracts available for netting
|
|
Collateral posted(b)
|
As of June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
(4
|
)
|
|
$
|
(11
|
)
|
|
$
|
—
|
|
|
$
|
(15
|
)
|
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
Interest rate swap agreements
|
—
|
|
|
(30
|
)
|
|
—
|
|
|
(30
|
)
|
|
13
|
|
|
—
|
|
|
(17
|
)
|
Cross-currency swap agreements
|
—
|
|
|
(21
|
)
|
|
—
|
|
|
(21
|
)
|
|
20
|
|
|
—
|
|
|
(1
|
)
|
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy commodity derivative contracts(a)
|
$
|
(29
|
)
|
|
$
|
(82
|
)
|
|
$
|
—
|
|
|
$
|
(111
|
)
|
|
$
|
43
|
|
|
$
|
37
|
|
|
$
|
(31
|
)
|
Interest rate swap agreements
|
—
|
|
|
(57
|
)
|
|
—
|
|
|
(57
|
)
|
|
18
|
|
|
—
|
|
|
(39
|
)
|
Cross-currency swap agreements
|
—
|
|
|
(31
|
)
|
|
—
|
|
|
(31
|
)
|
|
—
|
|
|
—
|
|
|
(31
|
)
|
_______
|
|
(a)
|
Level 1 consists primarily of New York Mercantile Exchange natural gas futures. Level 2 consists primarily of OTC West Texas Intermediate swaps and options.
|
|
|
(b)
|
Cash margin deposits held and posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” and “Restricted deposits,” respectively, on our accompanying consolidated balance sheets. Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.
|
The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts (in millions):
Significant unobservable inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Derivatives-net asset (liability)
|
|
|
|
|
|
|
|
Beginning of Period
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
(15
|
)
|
Total gains or (losses) included in earnings
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(9
|
)
|
Settlements
|
—
|
|
|
5
|
|
|
—
|
|
|
24
|
|
End of Period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
As of June 30, 2016, our Level 3 derivative asset and liability activity consisted primarily of power derivative contracts (which expired in April 2016), where a significant portion of fair value is calculated from underlying market data that is not readily observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value, and management would not expect materially different valuation results were we to use different input amounts within reasonable ranges.
Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
|
Carrying
value
|
|
Estimated
fair value
|
|
Carrying
value
|
|
Estimated
fair value
|
Total debt
|
$
|
38,324
|
|
|
$
|
39,915
|
|
|
$
|
40,050
|
|
|
$
|
41,015
|
|
We used Level 2 input values to measure the estimated fair value of our outstanding debt balances as of both
June 30, 2017
and
December 31, 2016
.
7. Reportable Segments
Segment results for the three and six months ended June 30, 2016 have been retrospectively adjusted to reflect the elimination of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now presented within the Corporate non-segment activities in reconciling to the consolidated totals in the respective segment reporting tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not associated with our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition, the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interest income and income tax expense previously allocated to our business segments are now included in “Interest expense, net” and “Income tax expense” for all periods presented in the following tables.
Financial information by segment follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Revenues
|
|
|
|
|
|
|
|
Natural Gas Pipelines
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
2,093
|
|
|
$
|
1,882
|
|
|
$
|
4,261
|
|
|
$
|
3,852
|
|
Intersegment revenues
|
2
|
|
|
1
|
|
|
5
|
|
|
2
|
|
CO
2
|
307
|
|
|
304
|
|
|
610
|
|
|
606
|
|
Terminals
|
|
|
|
|
|
|
|
Revenues from external customers
|
486
|
|
|
487
|
|
|
973
|
|
|
952
|
|
Intersegment revenues
|
1
|
|
|
1
|
|
|
1
|
|
|
1
|
|
Products Pipelines
|
|
|
|
|
|
|
|
Revenues from external customers
|
413
|
|
|
398
|
|
|
811
|
|
|
789
|
|
Intersegment revenues
|
5
|
|
|
3
|
|
|
9
|
|
|
8
|
|
Kinder Morgan Canada
|
60
|
|
|
63
|
|
|
119
|
|
|
122
|
|
Corporate and intersegment eliminations(a)
|
1
|
|
|
5
|
|
|
3
|
|
|
7
|
|
Total consolidated revenues
|
$
|
3,368
|
|
|
$
|
3,144
|
|
|
$
|
6,792
|
|
|
$
|
6,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Segment EBDA(b)
|
|
|
|
|
|
|
|
Natural Gas Pipelines
|
$
|
907
|
|
|
$
|
967
|
|
|
$
|
1,962
|
|
|
$
|
1,961
|
|
CO
2
|
221
|
|
|
204
|
|
|
439
|
|
|
391
|
|
Terminals
|
304
|
|
|
302
|
|
|
611
|
|
|
562
|
|
Products Pipelines
|
324
|
|
|
292
|
|
|
611
|
|
|
469
|
|
Kinder Morgan Canada
|
43
|
|
|
46
|
|
|
86
|
|
|
92
|
|
Total Segment EBDA
|
1,799
|
|
|
1,811
|
|
|
3,709
|
|
|
3,475
|
|
DD&A
|
(577
|
)
|
|
(552
|
)
|
|
(1,135
|
)
|
|
(1,103
|
)
|
Amortization of excess cost of equity investments
|
(15
|
)
|
|
(16
|
)
|
|
(30
|
)
|
|
(30
|
)
|
General and administrative and corporate charges
|
(145
|
)
|
|
(184
|
)
|
|
(326
|
)
|
|
(374
|
)
|
Interest expense, net
|
(463
|
)
|
|
(471
|
)
|
|
(928
|
)
|
|
(912
|
)
|
Income tax expense
|
(216
|
)
|
|
(213
|
)
|
|
(462
|
)
|
|
(367
|
)
|
Total consolidated net income
|
$
|
383
|
|
|
$
|
375
|
|
|
$
|
828
|
|
|
$
|
689
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
Assets
|
|
|
|
Natural Gas Pipelines
|
$
|
50,858
|
|
|
$
|
50,428
|
|
CO
2
|
4,106
|
|
|
4,065
|
|
Terminals
|
9,898
|
|
|
9,725
|
|
Products Pipelines
|
8,421
|
|
|
8,329
|
|
Kinder Morgan Canada
|
1,762
|
|
|
1,572
|
|
Corporate assets(c)
|
5,158
|
|
|
6,108
|
|
Assets held for sale
|
—
|
|
|
78
|
|
Total consolidated assets
|
$
|
80,203
|
|
|
$
|
80,305
|
|
_______
|
|
(a)
|
Includes a management fee for services we perform as operator of an equity investee.
|
|
|
(b)
|
Includes revenues, earnings from equity investments, other, net, less operating expenses, and other (income) expense, net, loss on impairments and divestitures, net and loss on impairments and divestitures of equity investments, net.
|
|
|
(c)
|
Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy operations) not allocated to the reportable segments.
|
8. Income Taxes
Income tax expense included in our accompanying consolidated statements of income were as follows (in millions, except percentages):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Income tax expense
|
$
|
216
|
|
|
$
|
213
|
|
|
$
|
462
|
|
|
$
|
367
|
|
Effective tax rate
|
36.1
|
%
|
|
36.2
|
%
|
|
35.8
|
%
|
|
34.8
|
%
|
The effective tax rate for the three and six months ended
June 30, 2017
is slightly higher than the statutory federal rate of
35%
primarily due to state and foreign income taxes, partially offset by dividend-received deductions from our investment in Florida Gas Transmission Company (Citrus) and Plantation Pipe Line.
The effective tax rate for the three months ended
June 30, 2016
is higher than the statutory federal rate of
35%
primarily due to state and foreign income taxes, partially offset by dividend-received deductions from our investment in Citrus and an increase in our deferred state income tax rate.
The effective tax rate for the six months ended
June 30, 2016
is lower than the statutory federal rate of
35%
primarily due to dividend-received deductions from our investment in Citrus and adjustments to our income tax reserve for uncertain tax positions, partially offset by state and foreign income taxes.
Adoption of ASU 2016-09 “Compensation - Stock Compensation (Topic 718)”
The tax impact of ASU 2016-09, which was adopted and effective January 1, 2017, resulted in
$9 million
of deferred tax assets being recorded through a cumulative-effect adjustment to our retained deficit. The previously unrecorded deferred tax asset is related to net operating loss carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Post-adoption the excess tax benefits or deficiencies are recognized for income tax purposes in the period in which they occur through the income statement.
9. Litigation, Environmental and Other Contingencies
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or dividends to our shareholders. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.
Federal Energy Regulatory Commission Proceedings
SFPP
The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers the most recent of which was filed in late 2015 with the FERC (docketed at OR16-6) challenging SFPP’s filed East Line rates. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. If the shippers prevail on their arguments or claims, they are entitled to seek reparations (which may reach back up to
two years
prior to the filing date of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. On March 22, 2016, the D.C. Circuit issued a decision in
United Airlines, Inc. v. FERC
remanding to FERC for further consideration of two issues: (1) the appropriate data to be used to determine the return on equity for SFPP in the underlying docket, and (2) the just and reasonable return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. On July 21, 2017, an initial decision by the Administrative Law Judge (ALJ) in OR16-6 concluded that the Complainants are due reparations, with appropriate interest, equal to the difference between what SFPP collected from the Complainants for service on the East Line and the amounts SFPP would have collected had it charged just and reasonable rates for that line. The ALJ ruled that an income tax allowance should be included in the cost of service both to determine reparations and to set going forward rates, and found that the new just and reasonable rates are not knowable until the FERC reviews the initial decision and orders a compliance filing. The FERC will determine which portions of the initial decision to affirm, reject or amend. With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking approximately
$40 million
in annual rate reductions and approximately
$210 million
in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers.
EPNG
The tariffs and rates charged by EPNG are subject to
two
ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC
generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it will apply its findings in Opinion 517-A to the same issues in the 2010 rate case. EPNG sought federal appellate review of Opinion 517-A and oral arguments were held on February 15, 2017. On February 21, 2017, the reviewing court delayed the case until the FERC rules on the rehearing requests pending in the 2010 Rate Case. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. EPNG and two intervenors sought rehearing of certain aspects of the decision, and the judicial review sought by certain intervenors has been delayed until the FERC issues an order on rehearing. All refund obligations related to the 2008 rate case were satisfied during calendar year 2015. With respect to the 2010 rate case, EPNG believes it has an appropriate reserve related to the findings in Opinions 517-A and 528-A.
NGPL and WIC
On January 19, 2017, NGPL and WIC were separately notified by the FERC of rate proceedings against them pursuant to section 5 of the Natural Gas Act (the “Orders”). The matters were set for hearings to determine whether NGPL’s and WIC’s current rates remain just and reasonable. A proceeding under section 5 of the Natural Gas Act is prospective in nature such that a change in rates charged to customers, if any, would likely only occur after the FERC has issued a final order. Both WIC and NGPL have reached settlements in principle with their respective customer groups that would resolve all matters set for hearing subject to completion of definitive documents and additional FERC approval. If such definitive documents or approvals are not obtained, an initial Administrative Law Judge decision for each proceeding would be anticipated by late February 2018, with final FERC decisions anticipated by the third quarter of 2018. We do not believe that the ultimate resolution of these proceedings will have a material adverse impact on our results of operations or cash flows from operations.
Trans Mountain Expansion Project Litigation
There are numerous legal challenges pending before the Federal Court of Appeal which have been filed by various governmental and non-governmental organizations, Aboriginal groups or other parties that seek judicial review of the recommendation of the National Energy Board (NEB) and subsequent decision by the Federal Governor in Council to conditionally approve the Trans Mountain Pipeline Expansion Project (the ‘‘Project’’). The petitions allege, among other things, that additional consultation, engagement or accommodation is required and that various non-economic impacts of the Project were not adequately considered. The remedies sought include requests that the NEB recommendation be quashed, that additional consultations be undertaken, and that the order of the Governor in Council approving the Project be quashed. A decision by the Federal Court of Appeal is subject to potential further appeal to the Supreme Court of Canada. Although we believe that each of the foregoing appeals lacks merit, in the event an applicant is successful at the Supreme Court of Canada, among other potential impacts, the NEB recommendation or Governor in Council’s approval may be quashed, permits may be revoked, the Project may be subject to additional significant regulatory reviews, there may be significant changes to the Project plans, further obligations or restrictions may be implemented, or the Project may be stopped altogether, which could materially impact the overall feasibility or economic benefits of the Project, which in turn would have a material adverse effect on the Project and, consequently, our investment in KML.
In addition to the judicial reviews of the NEB recommendation report and Governor in Council’s order, three judicial review proceedings have been commenced at the Supreme Court of British Columbia (Squamish Nation; the City of Vancouver; and Democracy Watch et al.). The petitions allege a duty and failure to consult or accommodate First Nations, apprehension of bias of decision makers, and generally, among other claims, that the Province ought not to have approved the Project. Each Applicant seeks to quash the Environmental Assessment Certificate that was issued by the BC Environmental Assessment Office. In the event that an applicant for judicial review is successful, among other potential impacts, the Environmental Assessment Certificate may be quashed, provincial permits may be revoked, the Project may be subject to additional significant regulatory reviews, there may be significant changes to the Project plans, further obligations or restrictions may be imposed or the Project may be stopped altogether. In the event that an applicant is unsuccessful at the Supreme Court of British Columbia, they may further seek to appeal the decision to the British Columbia Court of Appeal. Any decision of the British Columbia Court of Appeal may be appealed to the Supreme Court of Canada. A successful appeal at either of these levels could result in the same types of consequences described above.
Other Commercial Matters
Union Pacific Railroad Company Easements & Related Litigation
SFPP and Union Pacific Railroad Company (UPRR) have been engaged in a proceeding to determine the extent, if any, to which rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten-year period beginning January 1, 2004 (
Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., et al, ,
Superior Court of the State of California, County of Los Angeles, Case No. BC319170). In September 2011, the trial judge determined that the annual rent payable as of January 1, 2004 was
$14 million
, subject to annual consumer price index increases. SFPP appealed the judgment.
In addition, as part of the second ten-year rent setting period, in 2013 UPRR demanded the payment of
$22.3 million
in rent for the first year of the next ten-year period beginning January 1, 2014, which SFPP rejected. On November 5, 2014, the Court of Appeals issued an opinion which reversed the judgment, including the award of prejudgment interest, and remanded the matter to the trial court for a determination of UPRR’s property interest in its right-of-way, including whether UPRR has sufficient interest to grant SFPP’s easements. UPRR filed a petition for review to the California Supreme Court which was denied. In July 2017, UPRR and SFPP reached a settlement of the rental disputes on terms that are confidential and within the right-of-way liability previously recorded for back rent.
After the above-referenced decision by the California Court of Appeals which held that UPRR does not own the subsurface rights to grant certain easements and may not be able to collect rent from those easements, a purported class action lawsuit was filed in 2015 in California federal court by private landowners in California who claim to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP. Substantially similar follow-on lawsuits were filed and are pending in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which are brought purportedly as class actions on behalf of all landowners who own land in fee adjacent to and underlying the railroad easement under which the SFPP pipeline is located in those respective states, assert claims against UPRR, SFPP, KMGP, and Kinder Morgan Operating L.P. “D” for declaratory judgment, trespass, ejectment, quiet title, unjust enrichment, inverse condemnation and accounting arising from defendants’ alleged improper use or occupation of subsurface real property. Plaintiffs’ motions for class certification were denied by the federal district courts in Arizona and California, and plaintiffs are pursuing an appeal to the 9th Circuit Court of Appeals. The New Mexico and Nevada lawsuits have been stayed. SFPP views these cases as primarily a dispute between UPRR and the plaintiffs. UPRR purported to grant SFPP a network of subsurface pipeline easements along UPRR’s railroad right-of-way. SFPP relied on the validity of those easements and paid rent to UPRR for the value of those easements.
SFPP and UPRR have also engaged in multiple disputes since 2000 over the circumstances and conditions under which SFPP must pay to relocate its pipeline within the UPRR right-of-way. In July 2017, UPRR and SFPP reached a settlement of the relocation disputes on terms that are confidential but which generally require the parties to share and allocate the cost of future relocations. Although the cost sharing mechanism in the settlement is expected to reduce the cost of future relocations, SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations such that it is difficult to quantify the cost of future potential relocations. Such costs could have an adverse effect on our financial position, results of operations, cash flows, and dividends to our shareholders.
Gulf LNG Facility Arbitration
On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Disagreement and Disputed Statements and a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that is not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA seeks declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. As set forth in the terminal use agreement, disputes are meant to be resolved by final and binding arbitration. A three-member arbitration panel conducted an arbitration hearing in January 2017. We expect the arbitration panel will issue its decision before the end of the third quarter 2017. Eni USA has indicated that it will continue to pay the amounts claimed to be due pending resolution of the dispute. The successful assertion by Eni USA of its claim to terminate or amend its payment obligations under the agreement prior to the expiration of its initial term could have an adverse effect on the business, financial
position, results of operations, or cash flows of GLNG and distributions to KMI, a
50%
shareholder of GLNG. We view the demand for arbitration to be without merit, and we will continue to contest it vigorously.
Brinckerhoff Merger Litigation
In April 2017, a purported class action suit was filed in the Delaware Court of Chancery by a former EPB unitholder on behalf of a class of former unaffiliated unitholders of EPB, seeking to challenge the
$9.2 billion
merger of EPB into a subsidiary of KMI as part of a series of transactions in November 2014 whereby KMI acquired all of the outstanding equity interests in KMP, KMR, and EPB that KMI and its subsidiaries did not already own. The suit alleges that the merger consideration did not sufficiently compensate EPB unitholders for the value of three derivative suits concerning drop down transactions which the derivative plaintiff lost standing to pursue after the merger and which the present suit now alleges were collectively worth as much as
$700 million
. The suit claims that the alleged failure to obtain sufficient merger consideration for the drop down lawsuits constitutes a breach of the EPB limited partnership agreement and the implied covenant of good faith and fair dealing. The suit also asserts claims against KMI and certain individual defendants for allegedly tortiously interfering with and/or aiding and abetting the alleged breach of the limited partnership agreement. Defendants have moved to dismiss the suit. We continue to believe that both the merger and the drop down transactions were appropriate and in the best interests of EPB, and we intend to defend this lawsuit vigorously.
Price Reporting Litigation
Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which are pending in Nevada federal district court, were dismissed, but the dismissal was reversed by the 9
th
Circuit Court of Appeals. The U.S. Supreme Court affirmed the 9
th
Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the Nevada federal district court for further consideration and trial, if necessary, of numerous remaining issues. On May 24, 2016, the district court granted a motion for summary judgment dismissing a lawsuit brought by an industrial consumer in Kansas in which approximately
$500 million
in damages has been alleged. That ruling has been appealed to the 9
th
Circuit Court of Appeals. Tentative settlements have been reached in class actions originally filed in Kansas and Missouri, which settlements are subject to final court approval. In the remaining case, a Wisconsin class action in which approximately
$300 million
in damages has been alleged against all defendants, the district court denied plaintiff’s motion for class certification. The 9
th
Circuit Court of Appeals granted plaintiff’s request for an interlocutory appeal of this ruling. There remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, which may be allocated to us in the remaining lawsuits and therefore, our legal exposure, if any, and costs are not currently determinable.
Pipeline Integrity and Releases
From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
General
As of
June 30, 2017
and December 31, 2016, our total reserve for legal matters was
$389 million
and
$407 million
, respectively. The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline segments.
Environmental Matters
We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline,
terminal and CO
2
field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations, including alleged violations of the Risk Management Program and leak detection and repair requirements of the Clean Air Act. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties, individually or in the aggregate, will be material. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the cleanup.
In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas and CO
2
.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
In December 2000, the EPA issued General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned
two
liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member and pays a minimal fee to be part of the group. The LWG agreed to conduct the remedial investigation and feasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland Harbor site. The EPA issued the FS and the Proposed Plan on June 8, 2016 which included a proposed combination of dredging, capping, and enhanced natural recovery. On January 6, 2017, the EPA issued its Record of Decision (ROD) for the final cleanup plan. The final remedy is more stringent than the remedy proposed in the EPA’s Proposed Plan. The estimated cost increased from approximately
$750 million
to approximately
$1.1 billion
and active cleanup is now expected to take as long as
13
years to complete. KMLT and
90
other parties are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs. We are participating in the allocation process on behalf of KMLT and KMBT in connection with their current or former ownership or operation of
four
facilities located in Portland Harbor. Our share of responsibility for Portland Harbor Superfund Site costs will not be determined until the ongoing non-judicial allocation process is concluded in several years or a lawsuit is filed that results in a judicial decision allocating responsibility. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the site. 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.
Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona
The Roosevelt Irrigation District sued KMGP, KMEP and others under CERCLA for alleged contamination of the water purveyor’s wells. The First Amended Complaint sought
$175 million
in damages from approximately
70
defendants. On August 6, 2013 plaintiffs filed their Second Amended Complaint seeking monetary damages in unspecified amounts and reducing the number of defendants to
26
including KMEP and SFPP. The claims now presented against KMEP and SFPP are related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. We have filed an answer, general denial, and affirmative defenses in response to the Second Amended Complaint and fact discovery is proceeding.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately
twenty
uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a potentially responsible party within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order
on Consent and Scope of Work pursuant to which EPNG is conducting a radiological assessment of the surface of the mines. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona (Case No. 3:14-08165-DGC) seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given the pervasive control of such federal agencies over all aspects of the nuclear weapons program. Defendants filed an answer and counterclaims seeking contribution and recovery of response costs allegedly incurred by the federal agencies in investigating uranium impacts on the Navajo Reservation. The counterclaim of defendant EPA has been settled, and no viable claims for reimbursement by the other defendants are known to exist.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, Essex, Hudson, Bergen and Passaic Counties, New Jersey
EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area Superfund Site (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be potentially responsible parties (PRPs) under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately
70
cooperating parties, referred to as the Cooperating Parties Group (CPG), which has entered into AOCs and is directing and funding the work required by the EPA. Under the first AOC, draft remedial investigation and feasibility studies (RI/FS) of the Site were submitted to the EPA in 2015, and comments from the EPA remain pending. Under the second AOC, the CPG members conducted a CERCLA removal action at the Passaic River Mile 10.9, and the group is currently conducting EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with the AOCs.
On April 11, 2014, the EPA announced the issuance of its Focused Feasibility Study (FFS) for the lower eight miles of the Passaic River Study Area, and its proposed plan for remedial alternatives to address the dioxin sediment contamination from the mouth of Newark Bay to River Mile 8.3. The EPA estimates the cost for the alternatives will range from
$365 million
to
$3.2 billion
. The EPA’s preferred alternative would involve dredging the river bank-to-bank and installing an engineered cap at an estimated cost of
$1.7 billion
. On March 4, 2016, the EPA issued its ROD for the lower 8.3 miles of the Passaic River Study area. The final cleanup plan in the ROD is substantially similar to the EPA’s preferred alternative announced on April 11, 2014. On October 5, 2016, the EPA entered into an AOC with one member of the PRP group requiring such member to spend
$165 million
to perform engineering and design work necessary to begin the cleanup of the lower 8.3 miles of the Passaic River. The design work is expected to take
four
years to complete and the cleanup is expected to take
six
years to complete.
In addition, the EPA has notified over
80
other PRPs, including EPEC Polymers and EPEC Oil Trust (the Notice), that the EPA intends to pursue agreements with other “major PRPs” and initiate negotiations over cash buyouts with parties whom the EPA does not consider “major PRPs.” The Notice creates significant uncertainty as to the implementation and associated costs of the remedy set forth in the FFS and ROD, and provides no guidance as to the EPA’s definition of a “major PRP” or the potential amount or range of cash buyouts. There is also uncertainty as to the impact of the RI/FS that the CPG is currently preparing for portions of the Site. The draft RI/FS was submitted by the CPG earlier in 2015 and proposes a different remedy than the FFS announced by the EPA. Therefore, the scope of potential EPA claims for the lower eight miles of the Passaic River is not reasonably estimable at this time.
Southeast Louisiana Flood Protection Litigation
On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (SLFPA) filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against TGP, SNG and approximately
100
other energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The SLFPA asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On February 13, 2015, the Court granted defendants’ motion to dismiss the suit for failure to state a claim, and issued an order dismissing the SLFPA’s claims with prejudice. On March 3, 2017, the U.S. Court of Appeals for the Fifth Circuit affirmed the U.S. District Court’s decision. On March 17, 2017, the SLFPA filed a petition seeking
en banc
review and reconsideration of the decision by the Fifth Circuit, and such petition was denied.
Plaquemines Parish Louisiana Coastal Zone Litigation
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana (Docket No. 60-999) against TGP and
17
other energy companies, alleging that defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. In connection with this suit, TGP has made two tenders for defense and indemnity: (1) to Anadarko, as successor to the entity that purchased TGP’s oil and gas assets in Bastian Bay, and (2) to Kinetica, which purchased TGP’s pipeline assets in Bastian Bay in 2013. Anadarko has accepted TGP’s tender (limited to oil and gas assets), and Kinetica rejected TGP’s tender. TGP responded to Kinetica by reasserting TGP’s demand for defense and indemnity and reserving its rights. On November 12, 2015, the Plaquemines Parish Council adopted a resolution directing its legal counsel in all its Coastal Zone cases to take all actions necessary to cause the dismissal of all such cases. On April 14, 2016, following interventions in the suit by the Louisiana Department of Natural Resources and Attorney General, the Parish Council passed a resolution rescinding its November 12, 2015 resolution that had directed its counsel to dismiss the suit. We intend to continue to vigorously defend the suit.
Vermilion Parish Louisiana Coastal Zone Litigation
On July 28, 2016, the District Attorney for the 15
th
Judicial District of Louisiana, purporting to act on behalf of Vermilion Parish and the State of Louisiana, filed suit in the state district court for Vermilion Parish, Louisiana against TGP and
52
other energy companies, alleging that the defendants’ oil and gas and transportation operations associated with the development of several fields in Vermilion Parish (Operational Areas) were conducted in violation of the Coastal Zone Management Act. The suit alleges such operations caused substantial damage to the coastal waters and nearby lands (Coastal Zone) of Vermilion Parish, resulting in the release of pollutants and contaminants into the environment, improper discharge of oil field wastes, the improper use of waste pits and failure to close such pits, and the dredging of canals, which resulted in degradation of the Operational Areas, including erosion of marshes and degradation of terrestrial and aquatic life therein. As a result of such alleged violations of the Coastal Zone Management Act, the suit seeks a judgment against the defendants awarding all appropriate damages, the payment of costs to clear, revegetate, detoxify and otherwise restore the Vermilion Parish Coastal Zone, actual restoration of the affected Coastal Zone to its original condition, and reasonable costs and attorney fees. On September 2, 2016, the case was removed to the United States District Court for the Western District of Louisiana. Plaintiffs filed a motion to remand the case to the state district court, and such motion remains pending.
Vintage Assets, Inc. Coastal Erosion Litigation
On December 18, 2015, Vintage Assets, Inc. and several individual landowners filed a petition in the 25th Judicial District Court for Plaquemines Parish, Louisiana alleging that its 5,000 acre property is composed of coastal wetlands, and that SNG and TGP failed to maintain pipeline canals and banks, causing widening of the canals, land loss, and damage to the ecology and hydrology of the marsh, in breach of right of way agreements, prudent operating practices, and Louisiana law. The suit also claims that defendants’ alleged failure to maintain pipeline canals and banks constitutes negligence and has resulted in encroachment of the canals, constituting trespass. The suit seeks in excess of
$80
million in money damages, including recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and projected reconstruction cost of replacing or restoring wetlands. The suit was removed to the U.S. District Court for the Eastern District of Louisiana. The SNG assets at issue were sold to Highpoint Gas Transmission, LLC in 2011, which was subsequently purchased by American Midstream Partners, LP. In response to SNG’s demand for defense and indemnity, American Midstream Partners agreed to pay
50%
of joint defense costs and expenses, with a percentage of indemnity to be determined upon final resolution of the suit. On October 20, 2016, plaintiffs filed an amended complaint naming Highpoint Gas Transmission, LLC as an additional defendant. A non-jury trial is scheduled to begin on September 11, 2017 and we intend to vigorously defend the suit.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our
business, financial position, results of operations or cash flows. As of
June 30, 2017 and December 31, 2016
, we have accrued a total reserve for environmental liabilities in the amount of
$294 million
and
$302 million
, respectively. In addition, as of both
June 30, 2017 and December 31, 2016
, we have recorded a receivable of
$13 million
, for expected cost recoveries that have been deemed probable.
10. Recent Accounting Pronouncements
Topic 606
On May 28, 2014, the FASB issued ASU No. 2014-09, “
Revenue from Contracts with Customers
” followed by a series of related accounting standard updates (collectively referred to as “Topic 606”). Topic 606 is designed to create greater revenue recognition and disclosure comparability in financial statements. The provisions of Topic 606 include a five-step process by which an entity will determine revenue recognition, depicting the transfer of goods or services to customers in amounts reflecting the payment to which an entity expects to be entitled in exchange for those goods or services. Topic 606 requires certain disclosures about contracts with customers and provides more comprehensive guidance for transactions such as service revenue, contract modifications, and multiple-element arrangements.
We are in the process of comparing our current revenue recognition policies to the requirements of Topic 606 for each of our revenue categories. While we have not identified any material differences in the amount and timing of revenue recognition for the categories we have reviewed to date, our evaluation is not complete, and we have not concluded on the overall impacts of adopting Topic 606. Topic 606 will require that our revenue recognition policy disclosure include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. Topic 606 will also require disclosure of significant changes in contract asset and contract liability balances period to period and the amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period, as applicable. We anticipate utilizing the modified retrospective method to adopt the provisions of this standard effective January 1, 2018, which requires us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to equity. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 will not be revised.
ASU No. 2015-11
On July 22, 2015, the FASB issued ASU No. 2015-11, “
Inventory (Topic 330): Simplifying the Measurement of Inventory
.” This ASU requires entities to subsequently measure inventory at the lower of cost and net realizable value, and defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. ASU No. 2015-11 was effective January 1, 2017. We adopted ASU No. 2015-11 with no material impact to our financial statements.
ASU No. 2016-02
On February 25, 2016, the FASB issued ASU No. 2016-02, “
Leases (Topic 842)
.” This ASU requires that lessees will be required to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 will be effective for us as of January 1, 2019. We are currently reviewing the effect of ASU No. 2016-02.
ASU No. 2016-09
On March 30, 2016, the FASB issued ASU No. 2016-09,
“Compensation - Stock Compensation (Topic 718).”
This ASU was issued as part of the FASB’s simplification initiative and affects all entities that issue share-based payment awards to their employees. This ASU covers accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU No. 2016-09 was effective January 1, 2017. We adopted ASU No. 2016-09 with no material impact to our financial statements. See Note 8.
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 to utilize an expected loss methodology
in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. ASU No. 2016-13 will be effective for us as of January 1, 2020. We are currently reviewing the effect of ASU No. 2016-13.
ASU No. 2016-18
On November 17, 2016, the FASB issued ASU No. 2016-18, “
Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).
” This ASU requires the statement of cash flows to explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statement of cash flows. ASU No. 2016-18 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2017-04
On January 26, 2017, the FASB issued ASU No. 2017-04, “
Simplifying the Test for Goodwill Impairment (Topic 350)
” to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us as of January 1, 2020. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2017-05
On February 22, 2017, the FASB issued ASU No. 2017-05, “
Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets
.” This ASU clarifies the scope and accounting of a financial asset that meets the definition of an “in-substance nonfinancial asset” and defines the term “in-substance nonfinancial asset.” This ASU also adds guidance for partial sales of nonfinancial assets. ASU 2017-05 will be effective at the same time Topic 606,
Revenue from Contracts with Customers
, is effective. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2017-07
On March 10, 2017, the FASB issued ASU No. 2017-07, “
Compensation - Retirement Benefits (Topic 715)
.” This ASU requires an employer to disaggregate the service cost component from the other components of net benefit cost, allow only the service cost component of net benefit cost to be eligible for capitalization, and how to present the service cost component and the other components of net benefit cost in the income statement. ASU No. 2017-07 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements.
11. Guarantee of Securities of Subsidiaries
KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of KMI’s wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuer and other subsidiaries are all guarantors of each series of public debt. As a result of the cross guarantee agreement, a holder of any of the guaranteed public debt securities issued by KMI or KMP is in the same position with respect to the net assets, income and cash flows of KMI and the Subsidiary Issuer and Guarantors. The only amounts that are not available to the holders of each of the guaranteed public debt securities to satisfy the repayment of such securities are the net assets, income and cash flows of the Subsidiary Non-Guarantors.
In lieu of providing separate financial statements for subsidiary issuer and guarantor, we have included the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X. We have presented each of the parent and subsidiary issuer in separate columns in this single set of condensed consolidating financial statements.
On September 30, 2016, Copano (previously reflected as a Subsidiary Issuer and Guarantor) repaid the
$332 million
principal amount of its
7.125%
senior notes due 2021. Copano continues to be a subsidiary guarantor under the cross guarantee agreement mentioned above. For all periods presented, financial statement balances and activities for Copano are now reflected within the Subsidiary Guarantor column, and the Subsidiary Issuer and Guarantor-Copano column has been eliminated.
On September 1, 2016, we sold a
50%
equity interest in SNG. Subsequent to the transaction, we deconsolidated SNG and now account for our equity interest in SNG as an equity investment. Our wholly owned subsidiary which holds our interest in SNG is reflected within the Subsidiary Guarantors column of these condensed consolidating financial statements.
Excluding fair value adjustments, as of
June 30, 2017
, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had
$13,678 million
,
$18,885 million
, and
$3,535 million
, respectively, of Guaranteed Notes outstanding. Included in the Subsidiary Guarantors debt balance as presented in the accompanying
June 30, 2017
condensed consolidating balance sheet is approximately
$165 million
of capital lease obligations that are not subject to the cross guarantee agreement.
The accounts within the Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Guarantors and Subsidiary Non-Guarantors are presented using the equity method of accounting for investments in subsidiaries, including subsidiaries that are guarantors and non-guarantors, for purposes of these condensed consolidating financial statements only. These intercompany investments and related activities eliminate in consolidation and are presented separately in the accompanying condensed consolidating balance sheets and statements of income and cash flows.
A significant amount of each Issuers’ income and cash flow is generated by its respective subsidiaries. As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries. We utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the Subsidiary Issuers and Guarantors and Subsidiary Non-Guarantors. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities.
Condensed Consolidating Statements of Income and Comprehensive Income
for the Three Months Ended June 30, 2017
(In Millions)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Total Revenues
|
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
3,002
|
|
$
|
—
|
|
$
|
402
|
|
|
$
|
(45
|
)
|
|
$
|
3,368
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs, Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
1,041
|
|
—
|
|
83
|
|
|
(34
|
)
|
|
1,090
|
|
Depreciation, depletion and amortization
|
|
4
|
|
|
—
|
|
|
488
|
|
—
|
|
85
|
|
|
—
|
|
|
577
|
|
Other operating expenses
|
|
10
|
|
|
—
|
|
|
686
|
|
—
|
|
94
|
|
|
(11
|
)
|
|
779
|
|
Total Operating Costs, Expenses and Other
|
|
14
|
|
|
—
|
|
|
2,215
|
|
|
262
|
|
|
(45
|
)
|
|
2,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
(5
|
)
|
|
—
|
|
|
787
|
|
|
140
|
|
|
—
|
|
|
922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from consolidated subsidiaries
|
|
747
|
|
—
|
|
739
|
|
|
110
|
|
—
|
|
17
|
|
|
(1,613
|
)
|
|
—
|
|
Earnings from equity investments
|
|
—
|
|
—
|
|
—
|
|
|
135
|
|
—
|
|
—
|
|
|
—
|
|
|
135
|
|
Interest, net
|
|
(177
|
)
|
—
|
|
4
|
|
|
(273
|
)
|
—
|
|
(17
|
)
|
|
—
|
|
|
(463
|
)
|
Amortization of excess cost of equity investments and other, net
|
|
—
|
|
—
|
|
—
|
|
|
1
|
|
—
|
|
4
|
|
|
—
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
565
|
|
|
743
|
|
|
760
|
|
|
144
|
|
|
(1,613
|
)
|
|
599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
(189
|
)
|
—
|
|
(1
|
)
|
|
(18
|
)
|
—
|
|
(8
|
)
|
|
—
|
|
|
(216
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
376
|
|
|
742
|
|
|
742
|
|
|
136
|
|
|
(1,613
|
)
|
|
383
|
|
Net Income Attributable to Noncontrolling Interests
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
(7
|
)
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Controlling Interests
|
|
376
|
|
|
742
|
|
|
742
|
|
|
136
|
|
|
(1,620
|
)
|
|
376
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock Dividends
|
|
(39
|
)
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
(39
|
)
|
Net Income Available to Common Stockholders
|
|
$
|
337
|
|
|
$
|
742
|
|
|
$
|
742
|
|
|
$
|
136
|
|
|
$
|
(1,620
|
)
|
|
$
|
337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
376
|
|
|
$
|
742
|
|
|
$
|
742
|
|
|
$
|
136
|
|
|
$
|
(1,613
|
)
|
|
$
|
383
|
|
Total other comprehensive income
|
|
59
|
|
—
|
|
168
|
|
|
194
|
|
—
|
|
52
|
|
|
(395
|
)
|
|
78
|
|
Comprehensive income
|
|
435
|
|
|
910
|
|
|
936
|
|
|
188
|
|
|
(2,008
|
)
|
|
461
|
|
Comprehensive income attributable to noncontrolling interests
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
(26
|
)
|
|
(26
|
)
|
Comprehensive income attributable to controlling interests
|
|
$
|
435
|
|
|
$
|
910
|
|
—
|
|
$
|
936
|
|
|
$
|
188
|
|
|
$
|
(2,034
|
)
|
|
$
|
435
|
|
Condensed Consolidating Statements of Income and Comprehensive Income
for the Three Months Ended June 30, 2016
(In Millions)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Total Revenues
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
2,777
|
|
$
|
—
|
|
$
|
371
|
|
$
|
—
|
|
$
|
(12
|
)
|
|
$
|
3,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs, Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
693
|
|
|
60
|
|
|
(1
|
)
|
|
752
|
|
Depreciation, depletion and amortization
|
|
4
|
|
|
—
|
|
|
470
|
|
—
|
|
78
|
|
—
|
|
—
|
|
|
552
|
|
Other operating expenses
|
|
30
|
|
|
2
|
|
|
683
|
|
—
|
|
196
|
|
—
|
|
(11
|
)
|
|
900
|
|
Total Operating Costs, Expenses and Other
|
|
34
|
|
|
2
|
|
|
1,846
|
|
|
334
|
|
|
(12
|
)
|
|
2,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
(26
|
)
|
|
(2
|
)
|
|
931
|
|
|
37
|
|
|
—
|
|
|
940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from consolidated subsidiaries
|
|
752
|
|
—
|
|
734
|
|
—
|
|
52
|
|
—
|
|
17
|
|
—
|
|
(1,555
|
)
|
|
—
|
|
Earnings from equity investments
|
|
—
|
|
—
|
|
—
|
|
—
|
|
118
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
118
|
|
Interest, net
|
|
(176
|
)
|
—
|
|
34
|
|
—
|
|
(316
|
)
|
—
|
|
(13
|
)
|
—
|
|
—
|
|
|
(471
|
)
|
Amortization of excess cost of equity investments and other, net
|
|
1
|
|
—
|
|
—
|
|
—
|
|
(6
|
)
|
—
|
|
6
|
|
—
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
551
|
|
|
766
|
|
|
779
|
|
|
47
|
|
|
(1,555
|
)
|
|
588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
(179
|
)
|
—
|
|
(1
|
)
|
—
|
|
(16
|
)
|
—
|
|
(17
|
)
|
—
|
|
—
|
|
|
(213
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
372
|
|
|
765
|
|
|
763
|
|
|
30
|
|
|
(1,555
|
)
|
|
375
|
|
Net Income Attributable to Noncontrolling Interests
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(3
|
)
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Controlling Interests
|
|
372
|
|
|
765
|
|
|
763
|
|
|
30
|
|
|
(1,558
|
)
|
|
372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock Dividends
|
|
(39
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
(39
|
)
|
Net Income Available to Common Stockholders
|
|
333
|
|
|
765
|
|
|
763
|
|
|
30
|
|
|
(1,558
|
)
|
|
333
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
372
|
|
|
$
|
765
|
|
|
$
|
763
|
|
|
$
|
30
|
|
|
$
|
(1,555
|
)
|
|
$
|
375
|
|
Total other comprehensive (loss) income
|
|
(140
|
)
|
—
|
|
(213
|
)
|
—
|
|
(223
|
)
|
—
|
|
8
|
|
—
|
|
428
|
|
|
(140
|
)
|
Comprehensive income
|
|
232
|
|
|
552
|
|
|
540
|
|
|
38
|
|
|
(1,127
|
)
|
|
235
|
|
Comprehensive income attributable to noncontrolling interests
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(3
|
)
|
|
(3
|
)
|
Comprehensive income attributable to controlling interests
|
|
$
|
232
|
|
|
$
|
552
|
|
|
$
|
540
|
|
|
$
|
38
|
|
|
$
|
(1,130
|
)
|
|
$
|
232
|
|
Condensed Consolidating Statements of Income and Comprehensive Income
for the Six Months Ended June 30, 2017
(In Millions)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Total Revenues
|
|
$
|
18
|
|
|
$
|
—
|
|
|
$
|
6,060
|
|
|
$
|
777
|
|
|
$
|
(63
|
)
|
|
$
|
6,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs, Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
2,058
|
|
|
154
|
|
|
(41
|
)
|
|
2,171
|
|
Depreciation, depletion and amortization
|
|
8
|
|
|
—
|
|
|
964
|
|
|
163
|
|
|
—
|
|
|
1,135
|
|
Other operating expenses
|
|
25
|
|
|
—
|
|
|
1,354
|
|
|
227
|
|
|
(22
|
)
|
|
1,584
|
|
Total Operating Costs, Expenses and Other
|
|
33
|
|
|
—
|
|
|
4,376
|
|
|
544
|
|
|
(63
|
)
|
|
4,890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
(15
|
)
|
|
—
|
|
|
1,684
|
|
|
233
|
|
|
—
|
|
|
1,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from consolidated subsidiaries
|
|
1,593
|
|
|
1,570
|
|
|
212
|
|
|
35
|
|
|
(3,410
|
)
|
|
—
|
|
Earnings from equity investments
|
|
—
|
|
|
—
|
|
|
310
|
|
|
—
|
|
|
—
|
|
|
310
|
|
Interest, net
|
|
(354
|
)
|
|
10
|
|
|
(555
|
)
|
|
(29
|
)
|
|
—
|
|
|
(928
|
)
|
Amortization of excess cost of equity investments and other, net
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
8
|
|
|
—
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
|
1,224
|
|
|
1,580
|
|
|
1,649
|
|
|
247
|
|
|
(3,410
|
)
|
|
1,290
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
(408
|
)
|
|
(3
|
)
|
|
(35
|
)
|
|
(16
|
)
|
|
—
|
|
|
(462
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
816
|
|
|
1,577
|
|
|
1,614
|
|
|
231
|
|
|
(3,410
|
)
|
|
828
|
|
Net Income Attributable to Noncontrolling Interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Controlling Interests
|
|
816
|
|
|
1,577
|
|
|
1,614
|
|
|
231
|
|
|
(3,422
|
)
|
|
816
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock Dividends
|
|
(78
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(78
|
)
|
Net Income Available to Common Stockholders
|
|
$
|
738
|
|
|
$
|
1,577
|
|
|
$
|
1,614
|
|
|
$
|
231
|
|
|
$
|
(3,422
|
)
|
|
$
|
738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
816
|
|
|
$
|
1,577
|
|
|
$
|
1,614
|
|
|
$
|
231
|
|
|
$
|
(3,410
|
)
|
|
$
|
828
|
|
Total other comprehensive income
|
|
127
|
|
|
274
|
|
|
293
|
|
|
73
|
|
|
(621
|
)
|
|
146
|
|
Comprehensive income
|
|
943
|
|
|
1,851
|
|
|
1,907
|
|
|
304
|
|
|
(4,031
|
)
|
|
974
|
|
Comprehensive income attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(31
|
)
|
|
(31
|
)
|
Comprehensive income attributable to controlling interests
|
|
$
|
943
|
|
|
$
|
1,851
|
|
|
$
|
1,907
|
|
|
$
|
304
|
|
|
$
|
(4,062
|
)
|
|
$
|
943
|
|
Condensed Consolidating Statements of Income and Comprehensive Income
for the Six Months Ended June 30, 2016
(In Millions)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating Adjustments
|
|
Consolidated KMI
|
Total Revenues
|
|
$
|
17
|
|
|
$
|
—
|
|
|
$
|
5,602
|
|
|
$
|
741
|
|
|
$
|
(21
|
)
|
|
$
|
6,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs, Expenses and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
—
|
|
|
—
|
|
|
1,345
|
|
|
136
|
|
|
2
|
|
|
1,483
|
|
Depreciation, depletion and amortization
|
|
9
|
|
|
—
|
|
|
934
|
|
|
160
|
|
|
—
|
|
|
1,103
|
|
Other operating expenses
|
|
49
|
|
|
4
|
|
|
1,499
|
|
|
468
|
|
|
(23
|
)
|
|
1,997
|
|
Total Operating Costs, Expenses and Other
|
|
58
|
|
|
4
|
|
|
3,778
|
|
|
764
|
|
|
(21
|
)
|
|
4,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
(41
|
)
|
|
(4
|
)
|
|
1,824
|
|
|
(23
|
)
|
|
—
|
|
|
1,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from consolidated subsidiaries
|
|
1,410
|
|
|
1,331
|
|
|
75
|
|
|
31
|
|
|
(2,847
|
)
|
|
—
|
|
Earnings from equity investments
|
|
—
|
|
|
—
|
|
|
212
|
|
|
—
|
|
|
—
|
|
|
212
|
|
Interest, net
|
|
(346
|
)
|
|
97
|
|
|
(637
|
)
|
|
(26
|
)
|
|
—
|
|
|
(912
|
)
|
Amortization of excess cost of equity investments and other, net
|
|
1
|
|
|
—
|
|
|
(11
|
)
|
|
10
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
|
1,024
|
|
|
1,424
|
|
|
1,463
|
|
|
(8
|
)
|
|
(2,847
|
)
|
|
1,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
(337
|
)
|
|
(3
|
)
|
|
(10
|
)
|
|
(17
|
)
|
|
—
|
|
|
(367
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
687
|
|
|
1,421
|
|
|
1,453
|
|
|
(25
|
)
|
|
(2,847
|
)
|
|
689
|
|
Net Income Attributable to Noncontrolling Interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Controlling Interests
|
|
687
|
|
|
1,421
|
|
|
1,453
|
|
|
(25
|
)
|
|
(2,849
|
)
|
|
687
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock Dividends
|
|
(78
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(78
|
)
|
Net Income (Loss) Available to Common Stockholders
|
|
609
|
|
|
1,421
|
|
|
1,453
|
|
|
(25
|
)
|
|
(2,849
|
)
|
|
609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
$
|
687
|
|
|
$
|
1,421
|
|
|
$
|
1,453
|
|
|
$
|
(25
|
)
|
|
$
|
(2,847
|
)
|
|
$
|
689
|
|
Total other comprehensive (loss) income
|
|
(93
|
)
|
|
(161
|
)
|
|
(229
|
)
|
|
132
|
|
|
258
|
|
|
(93
|
)
|
Comprehensive income
|
|
594
|
|
|
1,260
|
|
|
1,224
|
|
|
107
|
|
|
(2,589
|
)
|
|
596
|
|
Comprehensive income attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
Comprehensive income attributable to controlling interests
|
|
$
|
594
|
|
|
$
|
1,260
|
|
|
$
|
1,224
|
|
|
$
|
107
|
|
|
$
|
(2,591
|
)
|
|
$
|
594
|
|
Condensed Consolidating Balance Sheets as of June 30, 2017
(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
|
|
$
|
36
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422
|
|
|
$
|
(6
|
)
|
|
$
|
452
|
|
Other current assets - affiliates
|
|
9,432
|
|
|
4,949
|
|
|
15,990
|
|
|
766
|
|
|
(31,137
|
)
|
|
—
|
|
All other current assets
|
|
246
|
|
|
87
|
|
|
1,740
|
|
|
206
|
|
|
(5
|
)
|
|
2,274
|
|
Property, plant and equipment, net
|
|
253
|
|
|
—
|
|
|
30,770
|
|
|
8,400
|
|
|
—
|
|
|
39,423
|
|
Investments
|
|
665
|
|
|
—
|
|
|
6,648
|
|
|
129
|
|
|
—
|
|
|
7,442
|
|
Investments in subsidiaries
|
|
27,176
|
|
|
28,902
|
|
|
5,118
|
|
|
4,025
|
|
|
(65,221
|
)
|
|
—
|
|
Goodwill
|
|
13,789
|
|
|
22
|
|
|
5,168
|
|
|
3,180
|
|
|
—
|
|
|
22,159
|
|
Notes receivable from affiliates
|
|
1,228
|
|
|
20,794
|
|
|
1,195
|
|
|
514
|
|
|
(23,731
|
)
|
|
—
|
|
Deferred income taxes
|
|
5,963
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,344
|
)
|
|
3,619
|
|
Other non-current assets
|
|
158
|
|
|
208
|
|
|
4,287
|
|
|
181
|
|
|
—
|
|
|
4,834
|
|
Total assets
|
|
$
|
58,946
|
|
|
$
|
54,962
|
|
|
$
|
70,916
|
|
|
$
|
17,823
|
|
|
$
|
(122,444
|
)
|
|
$
|
80,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of debt
|
|
$
|
1,174
|
|
|
$
|
975
|
|
|
$
|
806
|
|
|
$
|
269
|
|
|
$
|
—
|
|
|
$
|
3,224
|
|
Other current liabilities - affiliates
|
|
6,784
|
|
|
15,362
|
|
|
8,317
|
|
|
674
|
|
|
(31,137
|
)
|
|
—
|
|
All other current liabilities
|
|
339
|
|
|
346
|
|
|
1,923
|
|
|
542
|
|
|
(11
|
)
|
|
3,139
|
|
Long-term debt
|
|
12,841
|
|
|
18,293
|
|
|
3,299
|
|
|
667
|
|
|
—
|
|
|
35,100
|
|
Notes payable to affiliates
|
|
1,937
|
|
|
448
|
|
|
20,983
|
|
|
363
|
|
|
(23,731
|
)
|
|
—
|
|
Deferred income taxes
|
|
—
|
|
|
—
|
|
|
712
|
|
|
1,632
|
|
|
(2,344
|
)
|
|
—
|
|
All other long-term liabilities and deferred credits
|
|
722
|
|
|
100
|
|
|
1,239
|
|
|
465
|
|
|
—
|
|
|
2,526
|
|
Total liabilities
|
|
23,797
|
|
|
35,524
|
|
|
37,279
|
|
|
4,612
|
|
|
(57,223
|
)
|
|
43,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Total KMI equity
|
|
35,149
|
|
|
19,438
|
|
|
33,637
|
|
|
13,211
|
|
|
(66,286
|
)
|
|
35,149
|
|
Noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,065
|
|
|
1,065
|
|
Total stockholders’ Equity
|
|
35,149
|
|
|
19,438
|
|
|
33,637
|
|
|
13,211
|
|
|
(65,221
|
)
|
|
36,214
|
|
Total Liabilities and Stockholders’ Equity
|
|
$
|
58,946
|
|
|
$
|
54,962
|
|
|
$
|
70,916
|
|
|
$
|
17,823
|
|
|
$
|
(122,444
|
)
|
|
$
|
80,203
|
|
Condensed Consolidating Balance Sheets as of December 31, 2016
(In Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
Issuer and
Guarantor
|
|
Subsidiary
Issuer and
Guarantor -
KMP
|
|
Subsidiary
Guarantors
|
|
Subsidiary
Non-Guarantors
|
|
Consolidating
Adjustments
|
|
Consolidated KMI
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
471
|
|
|
$
|
—
|
|
|
$
|
9
|
|
|
$
|
205
|
|
|
$
|
(1
|
)
|
|
$
|
684
|
|
Other current assets - affiliates
|
|
5,739
|
|
|
1,999
|
|
|
13,207
|
|
|
655
|
|
|
(21,600
|
)
|
|
—
|
|
All other current assets
|
|
269
|
|
|
139
|
|
|
1,935
|
|
|
205
|
|
|
(3
|
)
|
|
2,545
|
|
Property, plant and equipment, net
|
|
242
|
|
|
—
|
|
|
30,795
|
|
|
7,668
|
|
|
—
|
|
|
38,705
|
|
Investments
|
|
665
|
|
|
2
|
|
|
6,236
|
|
|
124
|
|
|
—
|
|
|
7,027
|
|
Investments in subsidiaries
|
|
26,907
|
|
|
29,421
|
|
|
4,307
|
|
|
4,028
|
|
|
(64,663
|
)
|
|
—
|
|
Goodwill
|
|
13,789
|
|
|
22
|
|
|
5,167
|
|
|
3,174
|
|
|
—
|
|
|
22,152
|
|
Notes receivable from affiliates
|
|
516
|
|
|
21,608
|
|
|
1,132
|
|
|
412
|
|
|
(23,668
|
)
|
|
—
|
|
Deferred income taxes
|
|
6,647
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,295
|
)
|
|
4,352
|
|
Other non-current assets
|
|
72
|
|
|
206
|
|
|
4,455
|
|
|
107
|
|
|
—
|
|
|
4,840
|
|
Total assets
|
|
$
|
55,317
|
|
|
$
|
53,397
|
|
|
$
|
67,243
|
|
|
$
|
16,578
|
|
|
$
|
(112,230
|
)
|
|
$
|
80,305
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of debt
|
|
$
|
1,286
|
|
|
$
|
600
|
|
|
$
|
687
|
|
|
$
|
123
|
|
|
$
|
—
|
|
|
$
|
2,696
|
|
Other current liabilities - affiliates
|
|
3,551
|
|
|
13,299
|
|
|
4,197
|
|
|
553
|
|
|
(21,600
|
)
|
|
—
|
|
All other current liabilities
|
|
432
|
|
|
362
|
|
|
2,016
|
|
|
422
|
|
|
(4
|
)
|
|
3,228
|
|
Long-term debt
|
|
13,308
|
|
|
19,277
|
|
|
4,095
|
|
|
674
|
|
|
—
|
|
|
37,354
|
|
Notes payable to affiliates
|
|
1,533
|
|
|
448
|
|
|
20,520
|
|
|
1,167
|
|
|
(23,668
|
)
|
|
—
|
|
Deferred income taxes
|
|
—
|
|
|
—
|
|
|
681
|
|
|
1,614
|
|
|
(2,295
|
)
|
|
—
|
|
Other long-term liabilities and deferred credits
|
|
776
|
|
|
111
|
|
|
821
|
|
|
517
|
|
|
—
|
|
|
2,225
|
|
Total liabilities
|
|
20,886
|
|
|
34,097
|
|
|
33,017
|
|
|
5,070
|
|
|
(47,567
|
)
|
|
45,503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity
|
|
|
|
|
|
|
|
|
|
|
|
|
Total KMI equity
|
|
34,431
|
|
|
19,300
|
|
|
34,226
|
|
|
11,508
|
|
|
(65,034
|
)
|
|
34,431
|
|
Noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
371
|
|
|
371
|
|
Total stockholders’ Equity
|
|
34,431
|
|
|
19,300
|
|
|
34,226
|
|
|
11,508
|
|
|
(64,663
|
)
|
|
34,802
|
|
Total Liabilities and Stockholders’ Equity
|
|
$
|
55,317
|
|
|
$
|
53,397
|
|
|
$
|
67,243
|
|
|
$
|
16,578
|
|
|
$
|
(112,230
|
)
|
|
$
|
80,305
|
|
Condensed Consolidating Statements of Cash Flows for the Six Months Ended June 30, 2017
(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
|
|
$
|
(1,460
|
)
|
|
$
|
2,076
|
|
|
$
|
5,813
|
|
|
$
|
509
|
|
|
$
|
(4,772
|
)
|
|
$
|
2,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of assets and investments, net of cash acquired
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
Capital expenditures
|
|
(23
|
)
|
|
—
|
|
|
(1,062
|
)
|
|
(251
|
)
|
|
—
|
|
|
(1,336
|
)
|
Sales of property, plant and equipment, and other net assets, net of removal costs
|
|
5
|
|
|
—
|
|
|
45
|
|
|
21
|
|
|
—
|
|
|
71
|
|
Contributions to investments
|
|
(215
|
)
|
|
—
|
|
|
(327
|
)
|
|
(6
|
)
|
|
—
|
|
|
(548
|
)
|
Distributions from equity investments in excess of cumulative earnings
|
|
1,025
|
|
|
—
|
|
|
195
|
|
|
—
|
|
|
(1,006
|
)
|
|
214
|
|
Funding (to) from affiliates
|
|
(2,806
|
)
|
|
657
|
|
|
(4,013
|
)
|
|
(482
|
)
|
|
6,644
|
|
|
—
|
|
Other, net
|
|
(8
|
)
|
|
30
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
30
|
|
Net cash (used in) provided by investing activities
|
|
(2,022
|
)
|
|
687
|
|
|
(5,166
|
)
|
|
(710
|
)
|
|
5,638
|
|
|
(1,573
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuances of debt
|
|
4,187
|
|
|
—
|
|
|
—
|
|
|
143
|
|
|
—
|
|
|
4,330
|
|
Payments of debt
|
|
(4,858
|
)
|
|
(600
|
)
|
|
(659
|
)
|
|
(7
|
)
|
|
—
|
|
|
(6,124
|
)
|
Debt issue costs
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(54
|
)
|
|
—
|
|
|
(60
|
)
|
Cash dividends - common shares
|
|
(560
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(560
|
)
|
Cash dividends - preferred shares
|
|
(78
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(78
|
)
|
Funding from (to) affiliates
|
|
4,356
|
|
|
406
|
|
|
2,444
|
|
|
(562
|
)
|
|
(6,644
|
)
|
|
—
|
|
Contributions from investment partner
|
|
—
|
|
|
—
|
|
|
415
|
|
|
—
|
|
|
—
|
|
|
415
|
|
Contributions from parents/net proceeds from KML IPO
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
1,253
|
|
|
(1,251
|
)
|
|
—
|
|
Contributions from noncontrolling interests - net proceeds from KML IPO
|
|
7
|
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
1,240
|
|
|
1,247
|
|
Contributions from noncontrolling interests - other
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
11
|
|
Distributions to parents
|
|
—
|
|
|
(2,569
|
)
|
|
(2,854
|
)
|
|
(365
|
)
|
|
5,788
|
|
|
—
|
|
Distributions to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15
|
)
|
|
(15
|
)
|
Other, net
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
Net cash provided by (used in) financing activities
|
|
3,047
|
|
|
(2,763
|
)
|
|
(656
|
)
|
|
408
|
|
|
(871
|
)
|
|
(835
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
(435
|
)
|
|
—
|
|
|
(9
|
)
|
|
217
|
|
|
(5
|
)
|
|
(232
|
)
|
Cash and cash equivalents, beginning of period
|
|
471
|
|
|
—
|
|
|
9
|
|
|
205
|
|
|
(1
|
)
|
|
684
|
|
Cash and cash equivalents, end of period
|
|
$
|
36
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422
|
|
|
$
|
(6
|
)
|
|
$
|
452
|
|
Condensed Consolidating Statements of Cash Flows for the Six Months Ended June 30, 2016
(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
|
|
$
|
(1,949
|
)
|
|
$
|
2,976
|
|
|
$
|
5,368
|
|
|
$
|
326
|
|
|
$
|
(4,376
|
)
|
|
$
|
2,345
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of assets and investments, net of cash acquired
|
|
(2
|
)
|
|
—
|
|
|
(331
|
)
|
|
—
|
|
|
—
|
|
|
(333
|
)
|
Capital expenditures
|
|
(37
|
)
|
|
—
|
|
|
(929
|
)
|
|
(504
|
)
|
|
—
|
|
|
(1,470
|
)
|
Sales of property, plant and equipment, and other net assets, net of removal costs
|
|
—
|
|
|
—
|
|
|
220
|
|
|
—
|
|
|
—
|
|
|
220
|
|
Contributions to investments
|
|
(343
|
)
|
|
—
|
|
|
(13
|
)
|
|
(7
|
)
|
|
—
|
|
|
(363
|
)
|
Distributions from equity investments in excess of cumulative earnings
|
|
1,443
|
|
|
298
|
|
|
68
|
|
|
—
|
|
|
(1,728
|
)
|
|
81
|
|
Funding to affiliates
|
|
(1,670
|
)
|
|
(770
|
)
|
|
(2,416
|
)
|
|
(228
|
)
|
|
5,084
|
|
|
—
|
|
Other, net
|
|
—
|
|
|
(54
|
)
|
|
37
|
|
|
2
|
|
|
—
|
|
|
(15
|
)
|
Net cash used in investing activities
|
|
(609
|
)
|
|
(526
|
)
|
|
(3,364
|
)
|
|
(737
|
)
|
|
3,356
|
|
|
(1,880
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuances of debt
|
|
6,847
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,847
|
|
Payments of debt
|
|
(5,191
|
)
|
|
(500
|
)
|
|
(1,104
|
)
|
|
(5
|
)
|
|
—
|
|
|
(6,800
|
)
|
Debt issue costs
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Cash dividends - common shares
|
|
(559
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(559
|
)
|
Cash dividends - preferred shares
|
|
(76
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(76
|
)
|
Funding from affiliates
|
|
1,429
|
|
|
882
|
|
|
2,333
|
|
|
440
|
|
|
(5,084
|
)
|
|
—
|
|
Contributions from parents
|
|
—
|
|
|
—
|
|
|
—
|
|
|
87
|
|
|
(87
|
)
|
|
—
|
|
Contributions from noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
87
|
|
|
87
|
|
Distributions to parents
|
|
—
|
|
|
(2,832
|
)
|
|
(3,234
|
)
|
|
(90
|
)
|
|
6,156
|
|
|
—
|
|
Distributions to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
(11
|
)
|
Other, net
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
Net cash provided by (used in) financing activities
|
|
2,443
|
|
|
(2,450
|
)
|
|
(2,005
|
)
|
|
432
|
|
|
1,061
|
|
|
(519
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
(115
|
)
|
|
—
|
|
|
(1
|
)
|
|
26
|
|
|
41
|
|
|
(49
|
)
|
Cash and cash equivalents, beginning of period
|
|
123
|
|
|
—
|
|
|
12
|
|
|
142
|
|
|
(48
|
)
|
|
229
|
|
Cash and cash equivalents, end of period
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
11
|
|
|
$
|
168
|
|
|
$
|
(7
|
)
|
|
$
|
180
|
|