(Exact name of registrant as specified in its charter)
Delaware
80-0682103
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
1001 Louisiana Street, Suite 1000, Houston, Texas77002
(Address of principal executive offices)(zip code)
Registrant’s telephone number, including area code: 713-369-9000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Class P Common Stock
KMI
New York Stock Exchange
1.500% Senior Notes due 2022
KMI 22
New York Stock Exchange
2.250% Senior Notes due 2027
KMI 27 A
New York Stock Exchange
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yesþ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerþ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No þ
As of July 22, 2021, the registrant had 2,266,520,797 Class P shares outstanding.
Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries
SNG
=
Southern Natural Gas Company, L.L.C.
TGP
=
Tennessee Gas Pipeline Company, L.L.C.
KMLT
=
Kinder Morgan Liquid Terminals, LLC
Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.
Common Industry and Other Terms
/d
=
per day
EPA
=
U.S. Environmental Protection Agency
Bbl
=
barrel
FASB
=
Financial Accounting Standards Board
BBtu
=
billion British Thermal Units
FERC
=
Federal Energy Regulatory Commission
Bcf
=
billion cubic feet
GAAP
=
U.S. Generally Accepted Accounting Principles
CERCLA
=
Comprehensive Environmental Response, Compensation and Liability Act
LLC
=
limited liability company
LIBOR
=
London Interbank Offered Rate
CO2
=
carbon dioxide or our CO2 business segment
MBbl
=
thousand barrels
COVID-19
=
Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturn
MMBbl
=
million barrels
MMtons
=
million tons
DCF
=
distributable cash flow
NGL
=
natural gas liquids
DD&A
=
depreciation, depletion and amortization
NYMEX
=
New York Mercantile Exchange
EBDA
=
earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments
OTC
=
over-the-counter
ROU
=
Right-of-Use
EBITDA
=
earnings before interest, income taxes, depreciation, depletion and amortization expenses, and amortization of excess cost of equity investments
U.S.
=
United States of America
WTI
=
West Texas Intermediate
2
Information Regarding Forward-Looking Statements
This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements. Forward-looking statements in this report include, among others, express or implied statements pertaining to: the long-term demand for our assets and services, our anticipated dividends, our proposed acquisition of Kinetrex Energy and our capital projects, including expected completion timing and benefits of the acquisition and those projects.
Important factors that could cause actual results to differ materially from those expressed in or implied by the forward-looking statements in this report include: the impacts of the COVID-19 pandemic and the pace and extent of economic recovery; the timing and extent of changes in the supply of and demand for the products we transport and handle; commodity prices; and the other risks and uncertainties described in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition of Operations” and Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” in this report, as well as “Information Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2020 (except to the extent such information is modified or superseded by information in subsequent reports).
You should keep these risk factors in mind when considering forward-looking statements. These risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Because of these risks and uncertainties, you should not place undue reliance on any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.
3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts, unaudited)
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
Revenues
Services
$
1,889
$
1,791
$
3,806
$
3,783
Commodity sales
1,246
723
4,475
1,790
Other
15
46
80
93
Total Revenues
3,150
2,560
8,361
5,666
Operating Costs, Expenses and Other
Costs of sales
936
441
2,945
1,104
Operations and maintenance
582
606
1,096
1,226
Depreciation, depletion and amortization
528
532
1,069
1,097
General and administrative
160
155
316
308
Taxes, other than income taxes
108
103
218
195
Loss on impairments and divestitures, net (Note 2)
1,602
1,005
1,598
1,976
Other income, net
(2)
—
(3)
(1)
Total Operating Costs, Expenses and Other
3,914
2,842
7,239
5,905
Operating (Loss) Income
(764)
(282)
1,122
(239)
Other Income (Expense)
Earnings from equity investments
157
176
223
368
Amortization of excess cost of equity investments
(13)
(35)
(35)
(67)
Interest, net
(377)
(395)
(754)
(831)
Other, net (Note 2)
20
16
243
18
Total Other Expense
(213)
(238)
(323)
(512)
(Loss) Income Before Income Taxes
(977)
(520)
799
(751)
Income Tax Benefit (Expense)
237
(104)
(114)
(164)
Net (Loss) Income
(740)
(624)
685
(915)
Net Income Attributable to Noncontrolling Interests
(17)
(13)
(33)
(28)
Net (Loss) Income Attributable to Kinder Morgan, Inc.
$
(757)
$
(637)
$
652
$
(943)
Class P Shares
Basic and Diluted (Loss) Earnings Per Share
$
(0.34)
$
(0.28)
$
0.29
$
(0.42)
Basic and Diluted Weighted Average Shares Outstanding
2,265
2,261
2,264
2,263
The accompanying notes are an integral part of these consolidated financial statements.
4
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(In millions, unaudited)
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
Net (loss) income
$
(740)
$
(624)
$
685
$
(915)
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $47, $57, $94 and $(12), respectively)
(157)
(189)
(313)
40
Reclassification of change in fair value of derivatives to net (loss) income (net of tax expense of $9, $14, $27 and $23, respectively)
30
47
89
77
Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively)
—
—
—
1
Benefit plan adjustments (net of tax expense of $1, $2, $5 and $5, respectively)
5
5
22
16
Total other comprehensive (loss) income
(122)
(137)
(202)
134
Comprehensive (loss) income
(862)
(761)
483
(781)
Comprehensive income attributable to noncontrolling interests
(17)
(13)
(33)
(28)
Comprehensive (loss) income attributable to Kinder Morgan, Inc.
$
(879)
$
(774)
$
450
$
(809)
The accompanying notes are an integral part of these consolidated financial statements.
5
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except per share amounts, unaudited)
June 30, 2021
December 31, 2020
ASSETS
Current Assets
Cash and cash equivalents
$
1,365
$
1,184
Restricted deposits
604
25
Accounts receivable
1,416
1,293
Fair value of derivative contracts
221
185
Inventories
396
348
Other current assets
281
168
Total current assets
4,283
3,203
Property, plant and equipment, net
34,570
35,836
Investments
7,650
7,917
Goodwill
19,851
19,851
Other intangibles, net
1,585
2,453
Deferred income taxes
492
536
Deferred charges and other assets
1,744
2,177
Total Assets
$
70,175
$
71,973
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt
$
2,183
$
2,558
Accounts payable
949
837
Accrued interest
479
525
Accrued taxes
217
267
Accrued contingencies
232
307
Other current liabilities
999
580
Total current liabilities
5,059
5,074
Long-term liabilities and deferred credits
Long-term debt
Outstanding
30,008
30,838
Debt fair value adjustments
1,069
1,293
Total long-term debt
31,077
32,131
Other long-term liabilities and deferred credits
2,216
2,202
Total long-term liabilities and deferred credits
33,293
34,333
Total Liabilities
38,352
39,407
Commitments and contingencies (Notes 3 and 9)
Redeemable Noncontrolling Interest
683
728
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,604,747and 2,264,257,336 shares, respectively, issued and outstanding
23
23
Additional paid-in capital
41,793
41,756
Accumulated deficit
(10,496)
(9,936)
Accumulated other comprehensive loss
(609)
(407)
Total Kinder Morgan, Inc.’s stockholders’ equity
30,711
31,436
Noncontrolling interests
429
402
Total Stockholders’ Equity
31,140
31,838
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity
$
70,175
$
71,973
The accompanying notes are an integral part of these consolidated financial statements.
6
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Six Months Ended June 30,
2021
2020
Cash Flows From Operating Activities
Net income (loss)
$
685
$
(915)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization
1,069
1,097
Deferred income taxes
105
28
Amortization of excess cost of equity investments
35
67
Loss on impairments and divestitures, net (Note 2)
1,598
1,976
Gain on sale of interest in equity investment (Note 2)
(206)
—
Earnings from equity investments
(223)
(368)
Distributions from equity investment earnings
346
317
Changes in components of working capital
Accounts receivable
(130)
335
Inventories
(51)
28
Other current assets
(31)
48
Accounts payable
145
(182)
Accrued interest, net of interest rate swaps
(42)
(65)
Accrued taxes
(51)
(23)
Other current liabilities
195
(96)
Rate reparations, refunds and other litigation reserve adjustments
(102)
(12)
Other, net
(31)
(3)
Net Cash Provided by Operating Activities
3,311
2,232
Cash Flows From Investing Activities
Capital expenditures
(545)
(963)
Proceeds from sales of investments
413
907
Contributions to investments
(26)
(225)
Distributions from equity investments in excess of cumulative earnings
48
86
Other, net
(1)
(46)
Net Cash Used in Investing Activities
(111)
(241)
Cash Flows From Financing Activities
Issuances of debt
3,110
2,652
Payments of debt
(4,273)
(3,037)
Debt issue costs
(12)
(11)
Dividends
(1,212)
(1,166)
Repurchases of shares
—
(50)
Contributions from investment partner and noncontrolling interests
3
9
Distributions to investment partner
(45)
(38)
Distributions to noncontrolling interests
(8)
(7)
Other, net
(3)
(1)
Net Cash Used in Financing Activities
(2,440)
(1,649)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits
—
(5)
Net Increase in Cash, Cash Equivalents and Restricted Deposits
760
337
Cash, Cash Equivalents, and Restricted Deposits, beginning of period
1,209
209
Cash, Cash Equivalents, and Restricted Deposits, end of period
$
1,969
$
546
7
KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Six Months Ended June 30,
2021
2020
Cash and Cash Equivalents, beginning of period
$
1,184
$
185
Restricted Deposits, beginning of period
25
24
Cash, Cash Equivalents, and Restricted Deposits, beginning of period
1,209
209
Cash and Cash Equivalents, end of period
1,365
526
Restricted Deposits, end of period
604
20
Cash, Cash Equivalents, and Restricted Deposits, end of period
1,969
546
Net Increase in Cash, Cash Equivalents and Restricted Deposits
$
760
$
337
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized
$
28
$
8
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)
807
891
Cash paid during the period for income taxes, net
8
136
The accompanying notes are an integral part of these consolidated financial statements.
8
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In millions, unaudited)
Common stock
Issued shares
Par value
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Stockholders’ equity attributable to KMI
Non-controlling interests
Total
Balance at March 31, 2021
2,264
$
23
$
41,775
$
(9,124)
$
(487)
$
32,187
$
416
$
32,603
Restricted shares
1
18
18
18
Net (loss) income
(757)
(757)
17
(740)
Distributions
—
(5)
(5)
Contributions
—
1
1
Dividends
(615)
(615)
(615)
Other comprehensive loss
(122)
(122)
(122)
Balance at June 30, 2021
2,265
$
23
$
41,793
$
(10,496)
$
(609)
$
30,711
$
429
$
31,140
Common stock
Issued shares
Par value
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Stockholders’ equity attributable to KMI
Non-controlling interests
Total
Balance at March 31, 2020
2,261
$
23
$
41,713
$
(8,568)
$
(62)
$
33,106
$
358
$
33,464
Restricted shares
18
18
18
Net (loss) income
(637)
(637)
13
(624)
Distributions
—
(4)
(4)
Contributions
—
4
4
Dividends
(597)
(597)
(597)
Other comprehensive loss
(137)
(137)
(137)
Balance at June 30, 2020
2,261
$
23
$
41,731
$
(9,802)
$
(199)
$
31,753
$
371
$
32,124
The accompanying notes are an integral part of these consolidated financial statements.
9
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)
(In millions, unaudited)
Common stock
Issued shares
Par value
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Stockholders’ equity attributable to KMI
Non-controlling interests
Total
Balance at December 31, 2020
2,264
$
23
$
41,756
$
(9,936)
$
(407)
$
31,436
$
402
$
31,838
Restricted shares
1
37
37
37
Net income
652
652
33
685
Distributions
—
(8)
(8)
Contributions
—
3
3
Dividends
(1,212)
(1,212)
(1,212)
Other
—
(1)
(1)
Other comprehensive loss
(202)
(202)
(202)
Balance at June 30, 2021
2,265
$
23
$
41,793
$
(10,496)
$
(609)
$
30,711
$
429
$
31,140
Common stock
Issued shares
Par value
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Stockholders’ equity attributable to KMI
Non-controlling interests
Total
Balance at December 31, 2019
2,265
$
23
$
41,745
$
(7,693)
$
(333)
$
33,742
$
344
$
34,086
Repurchases of shares
(4)
(50)
(50)
(50)
Restricted shares
36
36
36
Net (loss) income
(943)
(943)
28
(915)
Distributions
—
(7)
(7)
Contributions
—
6
6
Dividends
(1,166)
(1,166)
(1,166)
Other comprehensive income
134
134
134
Balance at June 30, 2020
2,261
$
23
$
41,731
$
(9,802)
$
(199)
$
31,753
$
371
$
32,124
The accompanying notes are an integral part of these consolidated financial statements.
10
KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
Organization
We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 83,000 miles of pipelines and 144 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, metals and petroleum coke.
Basis of Presentation
General
Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. In compliance with such rules and regulations, all significant intercompany items have been eliminated in consolidation.
In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2020 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.
Stagecoach Acquisition
On July 9, 2021, we completed the acquisition of subsidiaries of Stagecoach Gas Services LLC (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1.228 billion, including a preliminary purchase price adjustment for working capital. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the northeast region of the U.S., including TGP.
Kinetrex Energy Acquisition
On July 16, 2021, we announced an agreement to acquire Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $310 million. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana as well as signed commercial agreements to begin construction on three additional landfill based RNG facilities. The transaction requires regulatory approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and is expected to close in the third quarter of 2021.
Goodwill
In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, we evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; and (vi) Terminals. See Note 2 for results of our May 31, 2021 goodwill impairment test.
11
Earnings per Share
We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and which include dividend equivalent payments, do not participate in excess distributions over earnings.
The following table sets forth the allocation of net (loss) income available to shareholders of Class P shares and participating securities:
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions, except per share amounts)
Net (Loss) Income Available to Stockholders
$
(757)
$
(637)
$
652
$
(943)
Participating securities:
Less: Net Income allocated to restricted stock awards(a)
(3)
(3)
(6)
(6)
Net (Loss) Income Allocated to Class P Stockholders
$
(760)
$
(640)
$
646
$
(949)
Basic Weighted Average Shares Outstanding
2,265
2,261
2,264
2,263
Basic (Loss) Earnings Per Share
$
(0.34)
$
(0.28)
$
0.29
$
(0.42)
(a)As of June 30, 2021, there were approximately 12 million restricted stock awards outstanding.
The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions on a weighted average basis)
Unvested restricted stock awards
12
12
12
12
Convertible trust preferred securities
3
3
3
3
12
2. Losses and Gains on Impairments, Divestitures and Other Write-downs
We recognized the following pre-tax losses (gains) on impairments, divestitures and other write-downs, net on assets during the three and six months ended June 30, 2021 and 2020:
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a)
$
1,600
$
—
$
1,600
$
—
Impairment of goodwill(a)
—
1,000
—
1,000
Gain on sale of interest in NGPL Holdings LLC(a)
—
—
(206)
—
Loss on write-down of related party note receivable(a)
—
—
117
—
Gain on divestitures of long-lived assets
(1)
—
(1)
—
Products Pipelines
Impairment of long-lived and intangible assets
—
—
—
21
Terminals
Impairment of long-lived and intangible assets
—
5
—
5
Loss on divestitures of long-lived assets
1
—
—
—
CO2
Impairment of goodwill(a)
—
—
—
600
Impairment of long-lived assets(a)
—
—
—
350
Loss on divestitures of long-lived assets
3
—
3
—
Other gain on divestitures of long-lived assets
(1)
—
(4)
—
Pre-tax loss on impairments, divestitures and other write-downs, net
$
1,602
$
1,005
$
1,509
$
1,976
(a)See below for a further discussion of these items.
Impairments
Long-lived Assets
During the quarter ended June 30, 2021, we recognized a non-cash, long-lived asset impairment of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipeline business segment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. The long-lived asset impairment test involves two steps. Step one is an assessment as to whether the asset’s net book value is expected to be recovered from the estimated undiscounted future cash flows. To compute the estimated undiscounted future cash flows we included an unfavorable adjustment for the upcoming contract expirations. With this inclusion, our South Texas gathering and processing assets failed step one. In step two, we utilized an income approach to estimate fair value and compared it to the carrying value. We applied an approximate 8.5% discount rate, which we believe represented the estimated weighted average cost of capital of a theoretical market participant.
During the six months ended June 30, 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering event that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 business segment which resulted in a non-cash impairment of long-lived assets within our CO2 business segment shown in the above table during the six months ended June 30, 2020.
Goodwill
The results of our May 31, 2021 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. The fair value estimates used in the goodwill impairment test are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect
13
to market multiples, comparable sales transactions, 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 future cash flows based on production growth rate assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit.
During the first quarter of 2020, we conducted interim tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the three months ended June 30, 2020, we conducted our annual test of the recoverability of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 business segment during the six months ended June 30, 2020 and within our Natural Gas Pipelines business segment during the three and six months ended June 30, 2020 as shown in the table above.
As conditions warrant, we routinely evaluate our assets for potential triggering events that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.
Sale of an Interest in NGPL Holdings
On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $413 million for our proportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the six months ended June 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.
Other Write-downs
During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our equity investee, Ruby, driven by the recent impairment by Ruby of its assets, which is included within “Earnings from equity investments” in our accompanying consolidated statement of operations. The impairment at Ruby was the result of upcoming contract expirations and additional uncertainty identified in late February 2021 regarding the proposed development of a third party liquefied natural gas exporting facility that could significantly increase the demand for its services.
14
3. Debt
The following table provides information on the principal amount of our outstanding debt balances:
June 30, 2021
December 31, 2020
(In millions, unless otherwise stated)
Current portion of debt
$4 billion credit facility due November 16, 2023
$
—
$
—
Commercial paper notes
—
—
Current portion of senior notes
5.00%, due February 2021(a)
—
750
3.50%, due March 2021(a)
—
750
5.80%, due March 2021(a)
—
400
5.00%, due October 2021(b)
500
500
8.625%, due January 2022
260
—
4.15%, due March 2022
375
—
1.50%, due March 2022(c)
890
—
Trust I preferred securities, 4.75%, due March 2028
111
111
Current portion of other debt
47
47
Total current portion of debt
2,183
2,558
Long-term debt (excluding current portion)
Senior notes
29,320
30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035
357
364
Trust I preferred securities, 4.75%, due March 2028
110
110
Other
221
223
Total long-term debt
30,008
30,838
Total debt(d)
$
32,191
$
33,396
(a)We repaid the principal amounts on these senior notes during the first quarter of 2021.
(b)These notes were repaid on July 1, 2021. As of June 30, 2021, $506 million for the repayment of these maturing notes and associated accrued interest were held in escrow and included in the accompanying consolidated balance sheet within “Restricted deposits.”
(c)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The June 30, 2021 balance is reported above at the exchange rate of 1.1858 U.S. dollars per Euro. As of June 30, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our debt balance of $75 million related to these notes. The cumulative increase in debt due to the changes in exchange rates for the 1.50% notes due 2022 is offset by a corresponding change in the value of cross-currency swaps reflected in “Other current assets” and “Other current liabilities” on our accompanying consolidated balance sheets. At the time of issuance, we entered into foreign currency contracts 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”).
(d)Excludes our “Debt fair value adjustments” which, as of June 30, 2021 and December 31, 2020, increased our total debt balances by $1,069 million and $1,293 million, respectively.
We and substantially all of our wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement.
On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million. These notes are guaranteed through the cross guarantee agreement discussed above.
Credit Facility
As of June 30, 2021, we had no borrowings outstanding under our $4.0 billion credit facility, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of June 30, 2021 was $3,919 million. As of June 30, 2021, we were in compliance with all required covenants.
15
Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances are disclosed below:
June 30, 2021
December 31, 2020
Carrying value
Estimated fair value
Carrying value
Estimated fair value
(In millions)
Total debt
$
33,260
$
38,498
$
34,689
$
39,622
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both June 30, 2021 and December 31, 2020.
4. Stockholders’ Equity
Class P Stock
On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. Since December 2017, in total, we have repurchased approximately 32 million of our Class P shares under the program at an average price of approximately $17.71 per share for approximately $575 million.
Dividends
The following table provides information about our per share dividends:
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
Per share cash dividend declared for the period
$
0.27
$
0.2625
$
0.54
$
0.525
Per share cash dividend paid in the period
0.27
0.2625
0.5325
0.5125
On July 21, 2021, our board of directors declared a cash dividend of $0.27 per share for the quarterly period ended June 30, 2021, which is payable on August 16, 2021 to shareholders of record as of the close of business on August 2, 2021.
Accumulated Other Comprehensive Loss
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:
Net unrealized gains/(losses) on cash flow hedge derivatives
Foreign currency translation adjustments
Pension and other postretirement liability adjustments
Total accumulated other comprehensive loss
(In millions)
Balance as of December 31, 2020
$
(13)
$
—
$
(394)
$
(407)
Other comprehensive (loss) gain before reclassifications
(313)
—
22
(291)
Loss reclassified from accumulated other comprehensive loss
89
—
—
89
Net current-period change in accumulated other comprehensive loss
(224)
—
22
(202)
Balance as of June 30, 2021
$
(237)
$
—
$
(372)
$
(609)
16
Net unrealized gains/(losses) on cash flow hedge derivatives
Foreign currency translation adjustments
Pension and other postretirement liability adjustments
Total accumulated other comprehensive loss
(In millions)
Balance as of December 31, 2019
$
(7)
$
—
$
(326)
$
(333)
Other comprehensive gain before reclassifications
40
1
16
57
Loss reclassified from accumulated other comprehensive loss
77
—
—
77
Net current-period change in accumulated other comprehensive (loss) income
117
1
16
134
Balance as of June 30, 2020
$
110
$
1
$
(310)
$
(199)
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.
Energy Commodity Price Risk Management
As of June 30, 2021, 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
(15.9)
MMBbl
Crude oil basis
(7.9)
MMBbl
Natural gas fixed price
(31.7)
Bcf
Natural gas basis
(26.2)
Bcf
NGL fixed price
(1.0)
MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price
(1.2)
MMBbl
Crude oil basis
(9.8)
MMBbl
Natural gas fixed price
(3.4)
Bcf
Natural gas basis
(15.8)
Bcf
NGL fixed price
(2.1)
MMBbl
As of June 30, 2021, 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 2025.
17
Interest Rate Risk Management
We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of June 30, 2021:
Notional amount
Accounting treatment
Maximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)
$
7,100
Fair value hedge
March 2035
Variable-to-fixed interest rate contracts
250
Cash flow hedge
January 2023
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts
2,500
Mark-to-Market
December 2021
(a)The principal amount of hedged senior notes consisted of $250 million included in “Current portion of debt” and $6,850 million included in “Long-term debt” on our accompanying consolidated balance sheet.
During the three months ended March 31, 2021, we entered into fixed-to-variable interest rate swap agreements with a combined notional principal amount of $375 million. These agreements were designated as accounting hedges and convert a portion of our fixed rate debt to variable rate through February 2028.
Foreign Currency Risk Management
We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of June 30, 2021:
Notional amount
Accounting treatment
Maximum term
(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)
$
1,358
Cash flow hedge
March 2027
(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.
18
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:
Fair Value of Derivative Contracts
Derivatives Asset
Derivatives Liability
June 30, 2021
December 31, 2020
June 30, 2021
December 31, 2020
Location
Fair value
Fair value
(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Other current liabilities)
$
18
$
42
$
(206)
$
(33)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
2
33
(87)
(8)
Subtotal
20
75
(293)
(41)
Interest rate contracts
Fair value of derivative contracts/(Other current liabilities)
118
119
(3)
(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
395
575
(12)
(7)
Subtotal
513
694
(15)
(10)
Foreign currency contracts
Fair value of derivative contracts/(Other current liabilities)
67
—
(8)
(6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
38
138
—
—
Subtotal
105
138
(8)
(6)
Total
638
907
(316)
(57)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Other current liabilities)
18
24
(46)
(21)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
—
—
(5)
—
Subtotal
18
24
(51)
(21)
Interest rate contracts
Fair value of derivative contracts/(Other current liabilities)
—
—
(1)
—
Subtotal
—
—
(1)
—
Total
18
24
(52)
(21)
Total derivatives
$
656
$
931
$
(368)
$
(78)
19
The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
Balance sheet asset fair value measurements by level
Level 1
Level 2
Level 3
Gross amount
Contracts available for netting
Cash collateral held(b)
Net amount
(In millions)
As of June 30, 2021
Energy commodity derivative contracts(a)
$
18
$
20
$
—
$
38
$
(35)
$
—
$
3
Interest rate contracts
—
513
—
513
(5)
—
508
Foreign currency contracts
—
105
—
105
(8)
—
97
As of December 31, 2020
Energy commodity derivative contracts(a)
$
6
$
93
$
—
$
99
$
(35)
$
—
$
64
Interest rate contracts
—
694
—
694
(2)
—
692
Foreign currency contracts
—
138
—
138
(6)
—
132
Balance sheet liability fair value measurements by level
Level 1
Level 2
Level 3
Gross amount
Contracts available for netting
Cash collateral posted(b)
Net amount
(In millions)
As of June 30, 2021
Energy commodity derivative contracts(a)
$
(46)
$
(298)
$
—
$
(344)
$
35
$
55
$
(254)
Interest rate contracts
—
(16)
—
(16)
5
—
(11)
Foreign currency contracts
—
(8)
—
(8)
8
—
—
As of December 31, 2020
Energy commodity derivative contracts(a)
$
(7)
$
(56)
$
—
$
(63)
$
35
$
(8)
$
(36)
Interest rate contracts
—
(10)
—
(10)
2
—
(8)
Foreign currency contracts
—
(6)
—
(6)
6
—
—
(a)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.
(b)Any cash collateral paid or received is reflected in this table, but only to the extent that 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 following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of operations and comprehensive income (loss):
Derivatives in fair value hedging relationships
Location
Gain/(loss) recognized in income on derivative and related hedged item
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions)
Interest rate contracts
Interest, net
$
28
$
26
$
(189)
$
459
Hedged fixed rate debt(a)
Interest, net
$
(28)
$
(28)
$
190
$
(468)
(a)As of June 30, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $512 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.
20
Derivatives in cash flow hedging relationships
Gain/(loss) recognized in OCI on derivative(a)
Location
Gain/(loss) reclassified from Accumulated OCI into income(b)
Three Months Ended June 30,
Three Months Ended June 30,
2021
2020
2021
2020
(In millions)
(In millions)
Energy commodity derivative contracts
$
(215)
$
(273)
Revenues—Commodity sales
$
(53)
$
(84)
Costs of sales
(2)
(2)
Interest rate contracts
1
(1)
Earnings from equity investments(c)
—
—
Foreign currency contracts
10
28
Other, net
16
25
Total
$
(204)
$
(246)
Total
$
(39)
$
(61)
Derivatives in cash flow hedging relationships
Gain/(loss) recognized in OCI on derivative(a)
Location
Gain/(loss) reclassified from Accumulated OCI into income(b)
Six Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions)
(In millions)
Energy commodity derivative contracts
$
(374)
$
114
Revenues—Commodity sales
$
(73)
$
(98)
Costs of sales
2
(5)
Interest rate contracts
2
(9)
Earnings from equity investments(c)
—
—
Foreign currency contracts
(35)
(53)
Other, net
(45)
3
Total
$
(407)
$
52
Total
$
(116)
$
(100)
(a)We expect to reclassify approximately $121 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 30, 2021 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)During the six months ended June 30, 2021, we recognized gains of $6 million associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
(c)Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss).
Derivatives not designated as accounting hedges
Location
Gain/(loss) recognized in income on derivatives
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions)
Energy commodity derivative contracts
Revenues—Commodity sales
$
(33)
$
149
$
(663)
$
266
Costs of sales
(2)
2
160
6
Earnings from equity investments
(2)
—
(2)
—
Total(a)
$
(37)
$
151
$
(505)
$
272
(a)The three and six months ended June 30, 2021 amounts include approximate losses of $7 million and $455 million, respectively, and the three and six months ended June 30, 2020 amounts include approximate gains of $179 million and $253 million, respectively. These gains and losses were 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, 2021 and December 31, 2020, we had no
21
outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2021, we had cash margins of $77 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, 2020, we had cash margins of $3 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at June 30, 2021 represents the net of our initial margin requirements of $22 million and counterparty variation margin requirements of $55 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of June 30, 2021, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post $169 million of additional collateral.
6. Revenue Recognition
Disaggregation of Revenues
The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:
Three Months Ended June 30, 2021
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
799
$
66
$
198
$
—
$
—
$
1,063
Fee-based services
176
244
84
10
—
514
Total services
975
310
282
10
—
1,577
Commodity sales
Natural gas sales
674
—
—
1
(3)
672
Product sales
248
157
7
258
(13)
657
Total commodity sales
922
157
7
259
(16)
1,329
Total revenues from contracts with customers
1,897
467
289
269
(16)
2,906
Other revenues(c)
Leasing services(d)
118
43
144
15
1
321
Derivatives adjustments on commodity sales
(37)
(1)
—
(47)
—
(85)
Other
(2)
5
—
6
(1)
8
Total other revenues
79
47
144
(26)
—
244
Total revenues
$
1,976
$
514
$
433
$
243
$
(16)
$
3,150
22
Three Months Ended June 30, 2020
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
796
$
67
$
189
$
—
$
—
$
1,052
Fee-based services
157
182
95
10
(2)
442
Total services
953
249
284
10
(2)
1,494
Commodity sales
Natural gas sales
377
—
—
—
(1)
376
Product sales
102
49
3
134
(4)
284
Total commodity sales
479
49
3
134
(5)
660
Total revenues from contracts with customers
1,432
298
287
144
(7)
2,154
Other revenues(c)
Leasing services(d)
114
42
132
11
—
299
Derivatives adjustments on commodity sales
(11)
—
—
75
—
64
Other
36
5
—
2
—
43
Total other revenues
139
47
132
88
—
406
Total revenues
$
1,571
$
345
$
419
$
232
$
(7)
$
2,560
Six Months Ended June 30, 2021
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
1,665
$
125
$
389
$
—
$
—
$
2,179
Fee-based services
354
465
165
25
—
1,009
Total services
2,019
590
554
25
—
3,188
Commodity sales
Natural gas sales
3,993
—
—
2
(8)
3,987
Product sales
468
282
12
487
(23)
1,226
Total commodity sales
4,461
282
12
489
(31)
5,213
Total revenues from contracts with customers
6,480
872
566
514
(31)
8,401
Other revenues(c)
Leasing services(d)
237
86
287
27
—
637
Derivatives adjustments on commodity sales
(655)
(1)
—
(80)
—
(736)
Other
39
10
—
11
(1)
59
Total other revenues
(379)
95
287
(42)
(1)
(40)
Total revenues
$
6,101
$
967
$
853
$
472
$
(32)
$
8,361
23
Six Months Ended June 30, 2020
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
1,661
$
146
$
378
$
—
$
—
$
2,185
Fee-based services
350
442
216
23
(2)
1,029
Total services
2,011
588
594
23
(2)
3,214
Commodity sales
Natural gas sales
878
—
—
—
(3)
875
Product sales
238
158
6
366
(17)
751
Total commodity sales
1,116
158
6
366
(20)
1,626
Total revenues from contracts with customers
3,127
746
600
389
(22)
4,840
Other revenues(c)
Leasing services(d)
227
84
261
21
—
593
Derivatives adjustments on commodity sales
41
—
—
127
—
168
Other
51
10
—
4
—
65
Total other revenues
319
94
261
152
—
826
Total revenues
$
3,446
$
840
$
861
$
541
$
(22)
$
5,666
(a)Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.
(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 5 for additional information related to our derivative contracts.
(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.
Contract Balances
As of June 30, 2021 and December 31, 2020, our contract asset balances were $48 million and $20 million, respectively. Of the contract asset balance at December 31, 2020, $12 million was transferred to accounts receivable during the six months ended June 30, 2021. As of June 30, 2021 and December 31, 2020, our contract liability balances were $232 million and $239 million, respectively. Of the contract liability balance at December 31, 2020, $45 million was recognized as revenue during the six months ended June 30, 2021.
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Revenue Allocated to Remaining Performance Obligations
The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of June 30, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:
Year
Estimated Revenue
(In millions)
Six months ended December 31, 2021
$
2,232
2022
3,766
2023
3,040
2024
2,590
2025
2,191
Thereafter
13,776
Total
$
27,595
Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical expedient that we elected to apply, remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
7. Reportable Segments
Financial information by segment follows:
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers
$
1,960
$
1,565
$
6,070
$
3,426
Intersegment revenues
16
6
31
20
Products Pipelines
514
345
967
840
Terminals
Revenues from external customers
433
418
852
859
Intersegment revenues
—
1
1
2
CO2
243
232
472
541
Corporate and intersegment eliminations
(16)
(7)
(32)
(22)
Total consolidated revenues
$
3,150
$
2,560
$
8,361
$
5,666
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Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions)
Segment EBDA(a)
Natural Gas Pipelines
$
(570)
$
(3)
$
1,533
$
1,193
Products Pipelines
265
227
513
496
Terminals
246
229
473
486
CO2
150
146
436
(609)
Total Segment EBDA
91
599
2,955
1,566
DD&A
(528)
(532)
(1,069)
(1,097)
Amortization of excess cost of equity investments
(13)
(35)
(35)
(67)
General and administrative and corporate charges
(150)
(157)
(298)
(322)
Interest, net
(377)
(395)
(754)
(831)
Income tax benefit (expense)
237
(104)
(114)
(164)
Total consolidated net (loss) income
$
(740)
$
(624)
$
685
$
(915)
June 30, 2021
December 31, 2020
(In millions)
Assets
Natural Gas Pipelines
$
46,445
$
48,597
Products Pipelines
9,138
9,182
Terminals
8,555
8,639
CO2
2,433
2,478
Corporate assets(b)
3,604
3,077
Total consolidated assets
$
70,175
$
71,973
(a)Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.
8. Income Taxes
Income tax (benefit) expense included in our accompanying consolidated statements of operations is as follows:
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions, except percentages)
Income tax (benefit) expense
$
(237)
$
104
$
114
$
164
Effective tax rate
24.3
%
(20.0)
%
14.3
%
(21.8)
%
The effective tax rate for the three months ended June 30, 2021 is higher than the statutory federal rate of 21% primarily due to state income taxes.
The effective tax rate for the six months ended June 30, 2021 is lower than the statutory federal rate of 21% primarily due to the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL Holdings, and dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.
The effective tax rate for the three months ended June 30, 2020 is “negative” and lower than the statutory federal rate of 21% due to the $1,000 million impairment of non-tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit. This was partially offset by the dividend-received deductions from our investments in Citrus and PPL.
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The effective tax rate for the six months ended June 30, 2020 is “negative” and lower than the statutory federal rate of 21% primarily due to the $1,600 million impairment of non-tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit. This was partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus and PPL.
While we would normally expect a federal income tax benefit from our loss before income taxes for the three and six months ended June 30, 2020, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for these periods.
9. Litigation and Environmental
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. 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.
SFPP FERC Proceedings
The FERC approved the SFPP East Line Settlement in Docket No. IS21-138 (“EL Settlement”) on December 31, 2020 and it became final and effective on February 2, 2021. The EL Settlement resolved certain dockets in their entirety (IS09-437 and OR16-6) and resolved the SFPP East Line related disputes in other dockets which remain ongoing (OR14-35/36 and OR19-21/33/37). The amounts SFPP agreed to pay pursuant to the EL Settlement were fully accrued on or before December 31, 2020.
The tariffs and rates charged by SFPP which were not fully resolved by the EL Settlement are subject to a number of ongoing shipper-initiated proceedings at the FERC. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. If the shippers prevail on their arguments or claims, they would be entitled to seek reparations for the two-year period preceding the filing date of their complaints and/or prospective refunds in protest cases from the date of protest, and SFPP may be required to reduce its rates going forward. With respect to the ongoing shipper-initiated proceedings at the FERC that were not fully resolved by the EL Settlement, the shippers pleaded claims to at least $50 million in rate refunds and unspecified rate reductions as of the date of their complaints in 2014 and 2018. The claims pleaded by the shippers are expected to change due to the passage of time and interest. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. We do not believe the ultimate resolution of the shipper complaints and protests seeking rate reductions or refunds in the ongoing proceedings will have a material adverse impact on our business.
Gulf LNG Facility Disputes
On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that was not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA sought declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. On June 29, 2018, the arbitration tribunal delivered an Award that called for the termination of the agreement and Eni USA’s payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash
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impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.
On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. This lawsuit remains pending.
On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On cross-appeals from an Order and Final Judgment of the Court of Chancery, the Delaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from re-arbitrating both the breach of contract and negligent misrepresentation claims. On April 15, 2021, Eni USA filed a petition for writ of certiorari with the U.S. Supreme Court seeking review of the Delaware Supreme Court’s decision. This petition remains pending.
On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A., filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also sought a declaration on substantially the same allegations asserted previously by Eni USA in arbitration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project gave rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also sought a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. On July 15, 2021, the arbitration tribunal delivered a Final Award on the merits of all claims submitted to the tribunal and denied all of ALSS’s claims with prejudice.
Continental Resources, Inc. v. Hiland Partners Holdings, LLC
On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties). CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $225 million. Hiland Partners denies and will vigorously defend against these claims.
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, 2021 and December 31, 2020, our total reserve for legal matters was $185 million and $273 million, respectively.
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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 local, state and federal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, 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.
We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations. 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 will be material to our business, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related remediation programs. We have established a reserve to address the costs associated with the remediation efforts.
In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas or CO2.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated by the EPA to be more than $3 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time we anticipate the non-judicial allocation process will be complete in or around October 2023. 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 PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.
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 PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately 20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a PRP within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG is conducting environmental assessments of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the
29
mines. The U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the U.S. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. Because costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey
EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.
On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Site. At that time the final cleanup plan in the ROD was estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Site. The design work is underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins.
In addition, the EPA and numerous PRPs, including EPEC Polymers, engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. That process was completed December 28, 2020 and certain PRPs, including EPEC Polymers, are engaged in discussions with the EPA as a result thereof. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD as well as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the ongoing discussions with the EPA conclude, or the FS is completed and the RI/FS is finalized, we are unable to reasonably estimate the extent of our potential liability. We do not anticipate that our share of the costs to resolve this matter, including the costs of any remediation, will have a material adverse impact to our business.
Louisiana Governmental Coastal Zone Erosion Litigation
Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below.
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August
30
10, 2020, the Fifth Circuit affirmed remand.The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Fifth Circuit. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.
On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, Orleans moved to remand the case to the state district court. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party; Parish of Cameron vs. Auster Oil & Gas, Inc., pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.
Louisiana Landowner Coastal Erosion Litigation
Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including four cases against TGP, three cases against SNG, and one case against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The Plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. We will continue to vigorously defend the remaining cases.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of June 30, 2021 and December 31, 2020, we have accrued a total reserve for environmental liabilities in the amount of $248 million and $250 million, respectively. In addition, as of both June 30, 2021 and December 31, 2020, we had a receivable of $12 million recorded for expected cost recoveries that have been deemed probable.
10. Recent Accounting Pronouncements
Reference Rate Reform (Topic 848)
On March 12, 2020, the FASB issued Accounting Standards Update (ASU) No. 2020-04, “Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate. Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.
On January 7, 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (the “Discounting Transition”) are in the scope of ASC 848 and therefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition.
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The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of Topic 848 to our financial statements.
ASU No. 2020-06
On August 5, 2020, the FASB issued ASU No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features; (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted method; and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. ASU No. 2020-06 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
ASU No. 2021-05
On July 19, 2021, the FASB issued ASU No. 2021-05, “Leases (Topic 842); Lessors - Certain Leases with Variable Lease Payments.” This ASU requires a lessor to classify a lease with entirely or partially variable payments that do not depend on an index or rate as an operating lease if another classification (i.e. sales-type or direct financing) would trigger a day-one loss. ASU No. 2021-05 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
General and Basis of Presentation
The following discussion and analysis should be read in conjunction with our accompanying interim consolidated financial statements and related notes included elsewhere in this report, and in conjunction with (i) our consolidated financial statements and related notes in our 2020 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2020 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2020 Form 10-K; and (iv) “Risk Factors” in our 2020 Form 10-K.
Long-lived Asset Impairment
During the quarter ended June 30, 2021, we recognized a non-cash, long-lived asset impairment of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipeline business segment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024.
Stagecoach Acquisition
On July 9, 2021, we completed the acquisition of subsidiaries of Stagecoach Gas Services LLC (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1.228 billion, including a preliminary purchase price adjustment for working capital. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the northeast region of the U.S., including TGP.
Kinetrex Energy Acquisition
On July 16, 2021, we announced an agreement to acquire Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $310 million. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana as well as signed commercial agreements to begin construction on three additional landfill based RNG facilities. Once they all become operational next year, total annual RNG production from the four sites is estimated to be over 4 Bcf. The transaction requires regulatory approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and is expected to close in the third quarter of 2021.
Sale of an Interest in NGPL Holdings LLC
On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $413 million for our proportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the six months ended June 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.
February 2021 Winter Storm
Our year-to-date earnings reflect impacts of the February 2021 winter storm that affected Texas, which are largely nonrecurring. See “—Segment Earnings Results” below. Some of the transactions executed during the winter storm remain subject to risks, including counterparty financial risk, potential disputed purchases and sales and potential legislative or regulatory action in response to, or litigation arising out of, the unprecedented circumstances of the winter storm, which could adversely affect our future earnings, cash flows and financial condition.
2021 Dividends and Discretionary Capital
We expect to declare dividends of $1.08 per share for 2021, a 3% increase from the 2020 declared dividends of $1.05 per share. Excluding the recent acquisitions, we expect to invest $0.8 billion in expansion projects and contributions to joint ventures during 2021.
33
The expectations for 2021 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement.
Results of Operations
Overview
As described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA (as presented in Note 7, “Reportable Segments”) and Net (loss) income attributable to Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA and Net Debt.
GAAP Financial Measures
The Consolidated Earnings Results for the three and six months ended June 30, 2021 and 2020 present Segment EBDA and Net (loss) income attributable to Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.
Non-GAAP Financial Measures
Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net (loss) income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of these non-GAAP financial measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.
Certain Items
Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net (loss) income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below and the tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,”“—Non-GAAP Financial Measures—Reconciliation of Net (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Non-GAAP Financial Measures—Supplemental Information” below). In addition, Certain Items are described in more detail in the footnotes to tables included in “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.
Adjusted Earnings
Adjusted Earnings is calculated by adjusting Net (loss) income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us and certain external users of our financial statements to assess the earnings of our business excluding Certain Items as another reflection of our ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is Net (loss) income attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic (loss) earnings per share. See “—Non-GAAP Financial Measures—Reconciliation of Net (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.
34
DCF
DCF is calculated by adjusting Net (loss) income attributable to Kinder Morgan, Inc. for Certain Items (Adjusted Earnings), and further by DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also include amounts from joint ventures for income taxes, DD&A and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as dividends, stock repurchases, retirement of debt, or expansion capital expenditures. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is Net (loss) income attributable to Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” and “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” below.
Adjusted Segment EBDA
Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management and external users of our financial statements additional insight into the ability of our segments to generate cash earnings on an ongoing basis. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Adjusted Segment EBDA is Segment EBDA. See “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results” for a reconciliation of Segment EBDA to Adjusted Segment EBDA by business segment.
Adjusted EBITDA
Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management and external users, in conjunction with our Net Debt (as described further below), to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net (loss) income attributable to Kinder Morgan, Inc. In prior periods Net (loss) income was considered the comparable GAAP measure and has been updated to Net (loss) income attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” below.
Amounts from Joint Ventures
Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries. (See “—Non-GAAP Financial Measures—Supplemental Information” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.
Net Debt
Net Debt is calculated, based on amounts as of June 30, 2021, by subtracting the following amounts from our debt balance of $33,260 million: (i) cash and cash equivalents of $1,365 million (which, as of June 30, 2021, the cash and cash equivalents component of Net Debt includes “Restricted deposits” of approximately $506 million held in escrow that were used on July 1, 2021 for the repayment of senior notes plus associated accrued interest); (ii) debt fair value adjustments of $1,069 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $125 million for which we have entered into currency swaps. Net Debt is a non-GAAP financial measure that is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents.
35
Consolidated Earnings Results (GAAP)
The following tables summarize the key components of our consolidated earnings results.
Three Months Ended June 30,
2021
2020
Earnings increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines
$
(570)
$
(3)
$
(567)
(18,900)
%
Products Pipelines
265
227
38
17
%
Terminals
246
229
17
7
%
CO2
150
146
4
3
%
Total Segment EBDA
91
599
(508)
(85)
%
DD&A
(528)
(532)
4
1
%
Amortization of excess cost of equity investments
(13)
(35)
22
63
%
General and administrative and corporate charges
(150)
(157)
7
4
%
Interest, net
(377)
(395)
18
5
%
Loss before income taxes
(977)
(520)
(457)
(88)
%
Income tax benefit (expense)
237
(104)
341
328
%
Net loss
(740)
(624)
(116)
(19)
%
Net income attributable to noncontrolling interests
(17)
(13)
(4)
(31)
%
Net loss attributable to Kinder Morgan, Inc.
$
(757)
$
(637)
$
(120)
(19)
%
Six Months Ended June 30,
2021
2020
Earnings increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines
$
1,533
$
1,193
$
340
28
%
Products Pipelines
513
496
17
3
%
Terminals
473
486
(13)
(3)
%
CO2
436
(609)
1,045
172
%
Total Segment EBDA
2,955
1,566
1,389
89
%
DD&A
(1,069)
(1,097)
28
3
%
Amortization of excess cost of equity investments
(35)
(67)
32
48
%
General and administrative and corporate charges
(298)
(322)
24
7
%
Interest, net
(754)
(831)
77
9
%
Income (loss) before income taxes
799
(751)
1,550
206
%
Income tax expense
(114)
(164)
50
30
%
Net income (loss)
685
(915)
1,600
175
%
Net income attributable to noncontrolling interests
(33)
(28)
(5)
(18)
%
Net income (loss) attributable to Kinder Morgan, Inc.
$
652
$
(943)
$
1,595
169
%
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss on impairments and divestitures, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
36
Net loss attributable to Kinder Morgan, Inc. increased $120 million for the three months ended June 30, 2021 and Net income attributable to Kinder Morgan, Inc. increased $1,595 million for the six months ended June 30, 2021 as compared to the respective prior year periods. The second quarter increased loss was primarily due to a $1,600 million pre-tax non-cash impairment loss related to South Texas gathering and processing assets within our Natural Gas Pipeline segment in 2021 resulting from anticipated lower volumes and rates on contract renewals compared to the $1 billion non-cash impairment of goodwill associated with our Natural Gas Pipelines Non-Regulated reporting unit recognized in 2020. The year-to-date increase was primarily impacted by higher earnings from our Natural Gas Pipelines and CO2 business segments primarily related to the February 2021 winter storm and therefore largely nonrecurring, and a decrease of $350 million of impairments in 2021 as compared to 2020 reflecting the $1,600 million pre-tax non-cash asset impairment loss in 2021 in our Natural Gas Pipeline business segment compared to the combined $1,950 million of non-cash impairments recognized in 2020 of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units and non-cash asset impairments of certain oil and gas producing assets in our CO2 business segment. The impacts of the long-lived asset impairments for both periods were partially offset by associated tax benefits. In addition to the above, the second quarter and year-to-date changes were favorably impacted by higher earnings from our Products Pipelines business segment, lower interest expense, DD&A expense (including amortization of excess cost of equity investments), and general and administrative and corporate charges expense.
Certain Items Affecting Consolidated Earnings Results
Three Months Ended June 30,
2021
2020
GAAP
Certain Items
Adjusted
GAAP
Certain Items
Adjusted
Adjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines
$
(570)
$
1,634
$
1,064
$
(3)
$
1,019
$
1,016
$
48
Products Pipelines
265
28
293
227
—
227
66
Terminals
246
—
246
229
—
229
17
CO2
150
1
151
146
10
156
(5)
Total Segment EBDA(a)
91
1,663
1,754
599
1,029
1,628
126
DD&A and amortization of excess cost of equity investments
(541)
—
(541)
(567)
—
(567)
26
General and administrative and corporate charges(a)
(150)
—
(150)
(157)
—
(157)
7
Interest, net(a)
(377)
(3)
(380)
(395)
(1)
(396)
16
(Loss) income before income taxes
(977)
1,660
683
(520)
1,028
508
175
Income tax benefit (expense)(b)
237
(387)
(150)
(104)
(10)
(114)
(36)
Net (loss) income
(740)
1,273
533
(624)
1,018
394
139
Net income attributable to noncontrolling interests(a)
(17)
—
(17)
(13)
—
(13)
(4)
Net (loss) income attributable to Kinder Morgan, Inc.
$
(757)
$
1,273
$
516
$
(637)
$
1,018
$
381
$
135
37
Six Months Ended June 30,
2021
2020
GAAP
Certain Items
Adjusted
GAAP
Certain Items
Adjusted
Adjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines
$
1,533
$
1,625
$
3,158
$
1,193
$
1,002
$
2,195
$
963
Products Pipelines
513
43
556
496
4
500
56
Terminals
473
—
473
486
—
486
(13)
CO2
436
6
442
(609)
940
331
111
Total Segment EBDA(a)
2,955
1,674
4,629
1,566
1,946
3,512
1,117
DD&A and amortization of excess cost of equity investments
(1,104)
—
(1,104)
(1,164)
—
(1,164)
60
General and administrative and corporate charges(a)
(298)
—
(298)
(322)
25
(297)
(1)
Interest, net(a)
(754)
(9)
(763)
(831)
—
(831)
68
Income (loss) before income taxes
799
1,665
2,464
(751)
1,971
1,220
1,244
Income tax expense(b)
(114)
(427)
(541)
(164)
(106)
(270)
(271)
Net income (loss)
685
1,238
1,923
(915)
1,865
950
973
Net income attributable to noncontrolling interests(a)
(33)
—
(33)
(28)
—
(28)
(5)
Net income (loss) attributable to Kinder Morgan, Inc.
$
652
$
1,238
$
1,890
$
(943)
$
1,865
$
922
$
968
(a)For a more detailed discussion of Certain Items, see the footnotes to the tables within “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
(b)The combined net effect of the income tax Certain Items represents the income tax provision on Certain Items plus discrete income tax items.
Net income attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) increased by $135 million and $968 million for the three and six months ended June 30, 2021, respectively, as compared to the respective prior year periods. The second quarter increase was primarily due to higher earnings from our Products Pipelines and Natural Gas Pipelines business segments and lower DD&A expense and interest expense. The year-to-date increase was impacted by higher earnings from our Natural Gas Pipelines and CO2 business segments primarily related to the February 2021 winter storm, and therefore largely nonrecurring, higher earnings from our Products Pipelines business segment and lower interest expense and DD&A expense.
38
Non-GAAP Financial Measures
Reconciliation of Net (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions)
Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)
$
(757)
$
(637)
$
652
$
(943)
Total Certain Items
1,273
1,018
1,238
1,865
Adjusted Earnings(a)
516
381
1,890
922
DD&A and amortization of excess cost of equity investments for DCF(b)
604
659
1,242
1,350
Income tax expense for DCF(a)(b)
170
132
589
313
Cash taxes(b)
(45)
(5)
(44)
(8)
Sustaining capital expenditures(b)
(210)
(159)
(317)
(300)
Other items(c)
(10)
(7)
(6)
(15)
DCF
$
1,025
$
1,001
$
3,354
$
2,262
Adjusted Segment EBDA to Adjusted EBITDA to DCF
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions, except per share amounts)
Natural Gas Pipelines
$
1,064
$
1,016
$
3,158
$
2,195
Products Pipelines
293
227
556
500
Terminals
246
229
473
486
CO2
151
156
442
331
Adjusted Segment EBDA(a)
1,754
1,628
4,629
3,512
General and administrative and corporate charges(a)
(150)
(157)
(298)
(297)
Joint venture DD&A and income tax expense(a)(b)
83
110
186
229
Net income attributable to noncontrolling interests(a)
(17)
(13)
(33)
(28)
Adjusted EBITDA
1,670
1,568
4,484
3,416
Interest, net(a)
(380)
(396)
(763)
(831)
Cash taxes(b)
(45)
(5)
(44)
(8)
Sustaining capital expenditures(b)
(210)
(159)
(317)
(300)
Other items(c)
(10)
(7)
(6)
(15)
DCF
$
1,025
$
1,001
$
3,354
$
2,262
Adjusted Earnings per share
$
0.23
$
0.17
$
0.83
$
0.40
Weighted average shares outstanding for dividends(d)
2,277
2,274
2,277
2,275
DCF per share
$
0.45
$
0.44
$
1.47
$
0.99
Declared dividends per share
$
0.27
$
0.2625
$
0.54
$
0.525
(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.
(b)Includes or represents DD&A, income tax expense, cash taxes and/or sustaining capital expenditures (as applicable for each item) from joint ventures. See tables included in “—Supplemental Information” below.
(c)Includes non-cash compensation associated with our restricted stock program, non-cash pension expense and pension contributions.
(d)Includes restricted stock awards that participate in dividends.
39
Reconciliation of Net (Loss) Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions)
Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)(a)
$
(757)
$
(637)
$
652
$
(943)
Certain Items:
Fair value amortization
(4)
(4)
(8)
(12)
Legal, environmental and taxes other than income tax reserves
28
—
112
(8)
Change in fair value of derivative contracts(b)
28
32
42
(4)
Loss on impairments, divestitures and other write-downs, net(c)
1,600
—
1,511
371
Loss on impairments of goodwill(d)
—
1,000
—
1,600
Income tax Certain Items
(387)
(10)
(427)
(106)
Other
8
—
8
24
Total Certain Items(e)
1,273
1,018
1,238
1,865
DD&A and amortization of excess cost of equity investments
541
567
1,104
1,164
Income tax expense(f)
150
114
541
270
Joint venture DD&A and income tax expense(f)(g)
83
110
186
229
Interest, net(f)
380
396
763
831
Adjusted EBITDA
$
1,670
$
1,568
$
4,484
$
3,416
(a)In prior periods, Net (loss) income was considered the comparable GAAP measure and has been updated to Net (loss) income attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures.
(b)Gains or losses are reflected in our DCF when realized.
(c)Three and six months ended June 30, 2021 amounts include a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment resulting from anticipated lower volumes and rates on contract renewals. Six months ended June 30, 2021 amount also includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings, offset partially by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby. Six months ended June 30, 2020 amount includes a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO2 business segment driven by low oil prices and $21 million for asset impairments in our Products Pipelines business segment, which are reported within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of operations.
(d)Three and six months ended June 30, 2020 amounts include a non-cash impairment of goodwill associated with our Natural Gas Pipelines Non-Regulated reporting unit. Six months ended June 30, 2020 amount also includes a non-cash impairment of goodwill associated with our CO2 reporting unit.
(e)2021 amount includes $127 million and 2020 amount includes less than $1 million reported within “Earnings from equity investments” on our consolidated statements of operations.
(f)Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.
(g)Represents joint venture DD&A and income tax expense. See tables included in “—Supplemental Information” below.
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Supplemental Information
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions)
DD&A (GAAP)
$
528
$
532
$
1,069
$
1,097
Amortization of excess cost of equity investments (GAAP)
13
35
35
67
DD&A and amortization of excess cost of equity investments
541
567
1,104
1,164
Joint venture DD&A
63
92
138
186
DD&A and amortization of excess cost of equity investments for DCF
$
604
$
659
$
1,242
$
1,350
Income tax (benefit) expense (GAAP)
$
(237)
$
104
$
114
$
164
Certain Items
387
10
427
106
Income tax expense(a)
150
114
541
270
Unconsolidated joint venture income tax expense(a)(b)
20
18
48
43
Income tax expense for DCF(a)
$
170
$
132
$
589
$
313
Additional joint venture information
Unconsolidated joint venture DD&A
$
74
$
102
$
160
$
205
Less: Consolidated joint venture partners’ DD&A
11
10
22
19
Joint venture DD&A
63
92
138
186
Unconsolidated joint venture income tax expense(a)(b)
20
18
48
43
Joint venture DD&A and income tax expense(a)
$
83
$
110
$
186
$
229
Unconsolidated joint venture cash taxes(b)
$
(34)
$
(6)
$
(34)
$
(10)
Unconsolidated joint venture sustaining capital expenditures
$
(32)
$
(26)
$
(52)
$
(52)
Less: Consolidated joint venture partners’ sustaining capital expenditures
(2)
(1)
(3)
(2)
Joint venture sustaining capital expenditures
$
(30)
$
(25)
$
(49)
$
(50)
(a)Amounts are adjusted for Certain Items.
(b)Amounts are associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments.
41
Segment Earnings Results
Natural Gas Pipelines
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions, except operating statistics)
Revenues
$
1,976
$
1,571
$
6,101
$
3,446
Operating expenses
(1,077)
(729)
(3,347)
(1,577)
Loss on impairments and divestitures, net
(1,599)
(1,000)
(1,599)
(1,000)
Other income
1
—
2
1
Earnings from equity investments
126
151
167
315
Other, net
3
4
209
8
Segment EBDA
(570)
(3)
1,533
1,193
Certain Items(a)
1,634
1,019
1,625
1,002
Adjusted Segment EBDA
$
1,064
$
1,016
$
3,158
$
2,195
Change from prior period
Increase/(Decrease)
Adjusted Segment EBDA
$
48
$
963
Volumetric data(b)
Transport volumes (BBtu/d)
36,537
35,080
36,878
36,704
Sales volumes (BBtu/d)
2,561
2,112
2,411
2,303
Gathering volumes (BBtu/d)
2,667
3,043
2,588
3,202
NGLs (MBbl/d)
30
29
30
30
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $1,634 million and $1,625 million for the three and six months ended June 30, 2021, respectively, and $1,019 million and $1,002 million for the three and six months ended June 30, 2020, respectively. Three and six months ended June 30, 2021 amounts include a pre-tax non-cash asset impairment loss of $1,600 million resulting from anticipated lower volumes and rates on contract renewals related to our South Texas gathering and processing assets and decreases in revenues of $16 million and $22 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. Six months ended June 30, 2021 amount also includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings, partially offset by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $69 million related to a certain litigation matter. Three and six months ended June 30, 2020 amounts primarily resulted from a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit and a decrease in revenues of $23 million and an increase in revenues of $1 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales.
Other
(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.
42
Below are the changes in Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:
Three Months Ended June 30, 2021 versus Three Months Ended June 30, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Midstream
$
68
29%
West Region
(18)
(7)%
East Region
(2)
—%
Total Natural Gas Pipelines
$
48
5
%
Six Months Ended June 30, 2021 versus Six Months Ended June 30, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Midstream
$
969
177%
West Region
(23)
(4)%
East Region
17
2%
Total Natural Gas Pipelines
$
963
44
%
The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:
•$68 million (29%) and $969 million (177%) increases, respectively, in Midstream were primarily due to (i) higher sales margins driven by higher commodity prices on our Texas intrastate natural gas pipeline operations; (ii) higher volumes on our Hiland Midstream assets; and (iii) higher equity earnings due to the Permian Highway Pipeline being placed in service in January 2021. These increases were partially offset by lower earnings on KinderHawk and South Texas assets due to lower volumes. The year-to-date increase was also impacted by higher commodity prices as a result of the February 2021 winter storm on our South Texas assets and Texas intrastate natural gas pipeline operations partially offset by the impacts to certain purchase contracts on our Oklahoma assets. Overall Midstream’s revenues increased primarily due to higher commodity prices which was partially offset by corresponding increases in costs of sales;
•$18 million (7%) and $23 million (4%) decreases, respectively, in the West Region were primarily due to lower earnings from Wyoming Interstate Company, LLC and Colorado Interstate Gas Company, L.L.C. as a result of lower revenues due to contract expirations; and
•$2 million (—%) decrease and $17 million (2%) increase, respectively, in the East Region were primarily due to (i) lower earnings on Fayetteville Express Pipeline LLC driven by lower revenues as a result of contract expirations; (ii) higher earnings from TGP due to weather-driven increases in reservation and park and loan revenues mostly during first quarter of 2021; and (iii) increased earnings from Elba Liquefaction Company, L.L.C. resulting from the liquefaction units of the Elba Liquefaction project being fully operational as of August 2020.
43
Products Pipelines
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions, except operating statistics)
Revenues
$
514
$
345
$
967
$
840
Operating expenses
(268)
(131)
(487)
(352)
Loss on impairments and divestitures, net
—
—
—
(21)
Earnings from equity investments
19
13
33
28
Other, net
—
—
—
1
Segment EBDA
265
227
513
496
Certain Items(a)
28
—
43
4
Adjusted Segment EBDA
$
293
$
227
$
556
$
500
Change from prior period
Increase/(Decrease)
Adjusted Segment EBDA
$
66
$
56
Volumetric data(b)
Gasoline(c)
1,046
762
969
862
Diesel fuel
418
371
398
365
Jet fuel
224
98
200
196
Total refined product volumes
1,688
1,231
1,567
1,423
Crude and condensate
510
479
508
590
Total delivery volumes (MBbl/d)
2,198
1,710
2,075
2,013
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $28 million and $43 million for the three and six months ended June 30, 2021, respectively, and $4 million for the six months ended June 30, 2020. Three and six month 2021 amounts include increases in expense of $28 million related to an adjustment to a litigation reserve. Six month 2021 amount also includes an increase in expense of $15 million related to an environmental reserve adjustment. Six month 2020 amount includes a non-cash loss on impairment of our Belton Terminal of $21 million and a $17 million favorable adjustment for tax reserves, other than income taxes.
Other
(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.
44
Below are the changes in Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:
Three Months Ended June 30, 2021 versus Three Months Ended June 30, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
West Coast Refined Products
$
34
36
%
Southeast Refined Products
20
41
%
Crude and Condensate
12
14
%
Total Products Pipelines
$
66
29
%
Six Months Ended June 30, 2021 versus Six Months Ended June 30, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
West Coast Refined Products
$
21
10
%
Southeast Refined Products
33
33
%
Crude and Condensate
2
1
%
Total Products Pipelines
$
56
11
%
The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:
•$34 million (36%) and $21 million (10%) increases, respectively, in West Coast Refined Products were primarily due to increased earnings on Pacific (SFPP) and Calnev Pipe Line LLC driven by higher revenues from the recovery of volumes in second quarter 2021 compared to 2020 which was impacted by COVID, partially offset by an increase in expense related to an adjustment to a litigation reserve on SFPP. The year-to-date increase was partially offset by higher operating expense primarily as a result of higher integrity management spending on SFPP;
•$20 million (41%) and $33 million (33%) increases, respectively, in Southeast Refined Products were primarily due to an increase in equity earnings from Products (SE) Pipe Line and increased revenues from our South East Terminals as a result of higher volumes and from our Transmix processing operations primarily due to higher prices. The year-to-date increase was also driven by higher 2021 earnings at our Transmix processing operations primarily due to first quarter 2020 unfavorable inventory adjustments and by product net gains as a result of higher prices and volumes on South East Terminals; and
•$12 million (14%) and $2 million (1%) increases, respectively, in Crude and Condensate were primarily due to increased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets. KMCC’s increased earnings were primarily due to higher deficiency revenues partially offset by contract expirations. The Bakken Crude assets’ second quarter increase in earnings was primarily driven by higher commodity prices and higher volumes. Bakken Crude assets’ year-to-date increase in earnings was impacted by lower field operating expenses partially offset by renegotiated contracts at lower average rates and by contract expirations. KMCC and Bakken Crude assets year-to-date increases were also due to lower operating expenses attributable to first quarter 2020 unfavorable inventory valuation adjustments.
45
Terminals
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions, except operating statistics)
Revenues
$
433
$
419
$
853
$
861
Operating expenses
(191)
(193)
(388)
(385)
Loss on impairments and divestitures, net
(1)
(5)
—
(5)
Earnings from equity investments
4
7
7
12
Other, net
1
1
1
3
Segment EBDA
246
229
473
486
Certain Items
—
—
—
—
Adjusted Segment EBDA
$
246
$
229
$
473
$
486
Change from prior period
Increase/(Decrease)
Adjusted Segment EBDA
$
17
$
(13)
Volumetric data(a)
Liquids leasable capacity (MMBbl)
79.9
79.6
79.9
79.6
Liquids utilization %(b)
93.6
%
95.6
%
93.6
%
95.6
%
Bulk transload tonnage (MMtons)
13.6
11.1
24.6
24.0
Other
(a)Volumes for assets sold are excluded for all periods presented.
(b)The ratio of our tankage capacity in service to tankage capacity available for service.
46
Below are the changes in Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:
Three Months Ended June 30, 2021 versus Three Months Ended June 30, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Northeast
$
8
38
%
Midwest
6
50
%
Mid Atlantic
6
50
%
Gulf Central
3
10
%
Marine operations
(14)
(27)
%
All others (including intrasegment eliminations)
8
8
%
Total Terminals
$
17
7
%
Six Months Ended June 30, 2021 versus Six Months Ended June 30, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Northeast
$
11
24
%
Midwest
5
17
%
Mid Atlantic
4
14
%
Gulf Central
(12)
(19)
%
Marine operations
(24)
(23)
%
All others (including intrasegment eliminations)
3
1
%
Total Terminals
$
(13)
(3)
%
The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:
•$8 million (38%) and $11 million (24%) increases, respectively, in the Northeast terminals were primarily driven by increased revenues associated with higher throughput levels and new contracts;
•$6 million (50%) and $5 million (17%) increases, respectively, in the Midwest terminals were primarily the result of an impairment associated with our Muscatine facility realized in the second quarter of 2020;
•$6 million (50%) and $4 million (14%) increases, respectively, in the Mid Atlantic terminals were primarily due to higher coal volumes at our Pier IX facility;
•$3 million (10%) increase and $12 million (19%) decrease, respectively, in the Gulf Central terminals. The second quarter increase in earnings was primarily due to higher revenues resulting from higher ethanol and coal volumes. The year-to-date decrease in earnings was primarily driven by unfavorable petroleum coke volumes due to refinery outages associated with the February 2021 winter storm as well as an increase in property tax expense at Battleground Oil Specialty Terminal Company LLC; and
•$14 million (27%) and $24 million (23%) decreases, respectively, in Marine operations were primarily due to lower fleet utilization and average charter rates.
47
CO2
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(In millions, except operating statistics)
Revenues
$
243
$
232
$
472
$
541
Operating expenses
(98)
(91)
(49)
(213)
Loss on impairments and divestitures, net
(3)
—
(3)
(950)
Earnings from equity investments
8
5
16
13
Segment EBDA
150
146
436
(609)
Certain Items(a)
1
10
6
940
Adjusted Segment EBDA
$
151
$
156
$
442
$
331
Change from prior period
Increase/(Decrease)
Adjusted Segment EBDA
$
(5)
$
111
Volumetric data
SACROC oil production
20.2
22.0
19.8
22.6
Yates oil production
6.7
6.7
6.4
6.9
Katz and Goldsmith oil production
2.2
2.5
2.4
2.9
Tall Cotton oil production
1.0
1.8
1.0
2.1
Total oil production, net (MBbl/d)(b)
30.1
33.0
29.6
34.5
NGL sales volumes, net (MBbl/d)(b)
9.5
9.4
9.1
9.6
CO2 sales volumes, net (Bcf/d)
0.4
0.4
0.4
0.5
Realized weighted average oil price ($ per Bbl)
$
52.50
$
50.31
$
51.79
$
52.56
Realized weighted average NGL price ($ per Bbl)
$
22.58
$
15.84
$
21.42
$
17.84
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $1 million and $6 million for the three and six months ended June 30, 2021, respectively, and $10 million and $940 million for the three and six months ended June 30, 2020, respectively. Six month 2020 amount primarily resulted from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on our oil and gas producing assets
Other
(b)Net of royalties and outside working interests.
48
Below are the changes in Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:
Three Months Ended June 30, 2021 versus Three Months Ended June 30, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities
$
(8)
(7)
%
Source and Transportation activities
3
6
%
Total CO2
$
(5)
(3)
%
Six Months Ended June 30, 2021 versus Six Months Ended June 30, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities
$
115
53
%
Source and Transportation activities
(4)
(4)
%
Total CO2
$
111
34
%
The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and six-month periods ended June 30, 2021 and 2020:
•$8 million (7%) decrease and $115 million (53%) increase, respectively, in Oil and Gas Producing activities. The second quarter decrease was primarily due to higher operating and other expenses of $8 million and lower revenues of $12 million due to lower crude oil volumes partially offset by higher realized crude oil and NGL prices that resulted in increased revenues of $15 million. The year-to-date increase was primarily due to lower operating expenses of $156 million driven by a benefit in the 2021 period realized from returning power to the grid by curtailing oil production during the February 2021 winter storm, partially offset by lower volumes resulting in decreased revenues of $37 million, driven in part, by the curtailed oil production and lower realized crude oil prices which decreased revenues by $8 million; and
•$3 million (6%) increase and $4 million (4%) decrease, respectively, in Source and Transportation activities. The second quarter increase was primarily due to an increase in equity earnings offset by a decrease in revenues related to lower CO2 sales prices. The year-to-date decrease was primarily due to a decrease in revenues of $17 million related to lower CO2 sales volumes partially offset by lower operating expenses of $7 million and an increase in equity earnings.
49
We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of June 30, 2021.
Remaining 2021
2022
2023
2024
2025
Crude Oil(a)
Price ($ per Bbl)
$
50.38
$
52.68
$
49.86
$
47.76
$
49.95
Volume (MBbl/d)
25.70
16.20
9.25
3.80
1.40
NGLs
Price ($ per Bbl)
$
33.81
$
48.06
Volume (MBbl/d)
5.70
1.36
Midland-to-Cushing Basis Spread
Price ($ per Bbl)
$
0.26
$
0.73
Volume (MBbl/d)
24.55
10.25
(a)Includes West Texas Intermediate hedges.
DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests
Three Months Ended June 30,
Earnings increase/(decrease)
2021
2020
(In millions, except percentages)
DD&A (GAAP)
$
(528)
$
(532)
$
4
1
%
General and administrative (GAAP)
$
(160)
$
(155)
$
(5)
(3)
%
Corporate benefit (charges)
10
(2)
12
600
%
Certain Items(a)
—
—
—
—
%
General and administrative and corporate charges(b)
$
(150)
$
(157)
$
7
4
%
Interest, net (GAAP)
$
(377)
$
(395)
$
18
5
%
Certain Items(c)
(3)
(1)
(2)
(200)
%
Interest, net(b)
$
(380)
$
(396)
$
16
4
%
Net income attributable to noncontrolling interests (GAAP)
$
(17)
$
(13)
$
(4)
(31)
%
Certain Items(d)
—
—
—
—
%
Net income attributable to noncontrolling interests(b)
$
(17)
$
(13)
$
(4)
(31)
%
50
Six Months Ended June 30,
Earnings increase/(decrease)
2021
2020
(In millions, except percentages)
DD&A (GAAP)
$
(1,069)
$
(1,097)
$
28
3
%
General and administrative (GAAP)
$
(316)
$
(308)
$
(8)
(3)
%
Corporate benefit (charges)
18
(14)
32
229
%
Certain Items(a)
—
25
(25)
(100)
%
General and administrative and corporate charges(b)
$
(298)
$
(297)
$
(1)
—
%
Interest, net (GAAP)
$
(754)
$
(831)
$
77
9
%
Certain Items(c)
(9)
—
(9)
—
%
Interest, net(b)
$
(763)
$
(831)
$
68
8
%
Net income attributable to noncontrolling interests (GAAP)
$
(33)
$
(28)
$
(5)
(18)
%
Certain Items(d)
—
—
—
—
%
Net income attributable to noncontrolling interests(b)
$
(33)
$
(28)
$
(5)
(18)
%
Certain items
(a)Six month 2020 amount includes an increase in expense of $23 million associated with the non-cash fair value adjustment of and the dividend accrual prior to the sale of our investment in Pembina common stock.
(b)Amounts are adjusted for Certain Items.
(c)Three and six month 2021 amounts include decreases in interest expense of $4 million and $8 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and six month 2020 amounts include (i) decreases in interest expense of $4 million and $12 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases in expense of $3 million and $14 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt.
(d)Three and six months ended June 30, 2021 and 2020 amounts each include less than $1 million of noncontrolling interests associated with Certain Items.
General and administrative expenses and corporate charges adjusted for Certain Items decreased $7 million for the three months ended June 30, 2021 and increased $1 million for the six months ended June 30, 2021, when compared with the respective prior year periods primarily due to $12 million and $24 million, respectively, of cost savings associated with organizational efficiency efforts and lower pension costs of $6 million and $10 million, respectively, partially offset by lower capitalized costs of $7 million and $23 million, respectively, reflecting reduced capital spending primarily by our Natural Gas Pipelines business segment and higher benefit-related costs of $4 million and $6 million, respectively.
In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense, net adjusted for Certain Items for the three and six months ended June 30, 2021 when compared with the respective prior year periods decreased $16 million and $68 million, respectively, primarily due to lower weighted average long-term debt balances and lower LIBOR and long-term interest rates, partially offset by lower capitalized interest.
We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of June 30, 2021 and December 31, 2020, approximately 14% and 16%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.
Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us.
51
Income Taxes
Our tax benefit for the three months ended June 30, 2021 was approximately $237 million as compared with $104 million of expense for the same period of 2020. The $341 million decrease in tax expense was due to the prior year disallowance of a tax benefit for the non-tax deductible goodwill impairment.
Our tax expense for the six months ended June 30, 2021 was approximately $114 million as compared with $164 million for the same period of 2020. The $50 million decrease in tax expense was due primarily to the prior year disallowance of a tax benefit for the non-tax deductible goodwill impairment and the current year release of the valuation allowance on our investment in NGPL Holdings, offset by federal and state taxes on higher pre-tax book income in the 2021 period and the refund of alternative minimum tax sequestration credits in the 2020 period.
Liquidity and Capital Resources
General
As of June 30, 2021, we had $1,365 million of “Cash and cash equivalents,” an increase of $181 million from December 31, 2020. As of June 30, 2021, our “Restricted deposits” included $506 million held in escrow for the repayment of senior notes and accrued interest made on July 1, 2021. We also used $1.2 billion of cash on hand to complete the acquisition on July 9, 2021 of subsidiaries of Stagecoach. Additionally, as of June 30, 2021, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
We have consistently generated substantial cash flows from operations, providing a source of funds of $3,311 million and $2,232 million in the first six months of 2021 and 2020, respectively. The period-to-period increase is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our growth capital expenditures. We believe our current cash on hand, our cash flows from operations, and our borrowing capacity under our revolving credit facility are more than adequate to allow us to manage our cash requirements, including maturing debt, through 2021; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt.
Our board of directors declared a quarterly dividend of $0.27 per share for the second quarter of 2021, consistent with the dividend declared for the previous quarter. We expect to fully fund our dividend payments as well as our discretionary spending for 2021 without funding from the capital markets.
On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million which were used to repay maturing senior notes.
Short-term Liquidity
As of June 30, 2021, our principal sources of short-term liquidity are (i) cash from operations; (ii) our $4.0 billion revolving credit facility and associated commercial paper program; and (iii) cash and cash equivalents. The loan commitments under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Letters of credit and commercial paper borrowings reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations. We do not anticipate any significant limitations from the impacts of COVID-19 with respect to our ability to access funding through our credit facility.
As of June 30, 2021, our $2,183 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. We intend to fund our debt, as it becomes due, primarily through cash on hand, credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2020 was $2,558 million.
We had working capital (defined as current assets less current liabilities) deficits of $776 million and $1,871 million as of June 30, 2021 and December 31, 2020, respectively. From time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $1,095 million favorable change from year-end 2020 was primarily due to (i) a decrease of approximately $375 million in senior notes that mature in the next twelve months; (ii) a $604
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million increase in restricted deposits primarily related to cash held in escrow for $506 million in senior notes and accrued interest that were repaid on July 1, 2021; (iii) a $181 million increase in cash and cash equivalents; and (iv) a $75 million decrease in accrued contingencies, partially offset by a $176 million increase in current regulatory liabilities and a net unfavorable short-term fair value adjustment of $164 million on derivative contract assets and liabilities in 2021. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.
Counterparty Creditworthiness
Some of our customers or other counterparties may experience severe financial problems that may have a significant impact on their creditworthiness. These financial problems may arise from our current global economic conditions, continued volatility of commodity prices, or otherwise. In such situations, we utilize, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these counterparties. While we believe we have taken reasonable measures to protect against counterparty credit risk, we cannot provide assurance that one or more of our customers or other counterparties will not become financially distressed and will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. The balance of our allowance for credit losses as of June 30, 2021 and December 31, 2020, was $2 million and $26 million, respectively, reflected in “Other current assets” on our consolidated balance sheets.
Capital Expenditures
We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as discretionary capital expenditures). Expansion capital expenditures are those expenditures that increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “Results of Operations—Overview—Non-GAAP Financial Measures—DCF”). With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e., production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those that maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.
Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital expenditure is classified as a maintenance/sustaining or as an expansion capital expenditure is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are.
Our capital expenditures for the six months ended June 30, 2021, and the amount we expect to spend for the remainder of 2021 to sustain and grow our businesses are as follows:
Six Months Ended June 30, 2021
2021 Remaining
Total 2021
(In millions)
Sustaining capital expenditures(a)(b)
$
317
$
557
$
874
Discretionary capital investments(b)(c)(d)
302
1,683
1,985
(a)Six months ended June 30, 2021, 2021 Remaining, and Total 2021 amounts include $49 million, $60 million, and $109 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “Non-GAAP Financial Measures—Supplemental Information.”
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(b)Six months ended June 30, 2021 amount excludes $45 million due to decreases in accrued capital expenditures and contractor retainage and net changes in other.
(c)Six months ended June 30, 2021 amount includes $70 million of our contributions to certain unconsolidated joint ventures for capital investments. Both 2021 Remaining and Total 2021 amounts include $1.2 billion for our acquisition of subsidiaries of Stagecoach.
(d)Amounts include our actual or estimated contributions to certain equity investees, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.
Off Balance Sheet Arrangements
There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2020 in our 2020 Form 10-K.
Commitments for the purchase of property, plant and equipment as of June 30, 2021 and December 31, 2020 were $227 million and $141 million, respectively. The increase of $86 million was primarily driven by capital commitments related to our Terminals and Natural Gas Pipelines business segments.
Cash Flows
Operating Activities
Cash provided by operating activities increased $1,079 million in the six months ended June 30, 2021 compared to the respective 2020 period primarily due to:
•a $1,178 million increase in cash after adjusting the $1,600 million increase in net income by $422 million for the combined effects of the period-to-period net changes in non-cash items including the following: (i) loss from impairments and divestitures, net (see discussion above in “—Results of Operations”); (ii) gain from the sale of a partial interest in our equity investment in NGPL Holdings (see discussion above in “—Results of Operations”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; and (v) earnings from equity investments (including a non-cash write-down of a related party note receivable from Ruby); partially offset by,
•a $99 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by a net unfavorable change in the timing of accounts receivable collections and trade payable payments in the 2021 period compared to the 2020 period. The decrease was also driven by payments for litigation matters in the 2021 period.
Investing Activities
Cash used in investing activities decreased $130 million for the six months ended June 30, 2021 compared to the respective 2020 period primarily attributable to:
•a $418 million decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and
•a $199 million decrease in cash used for contributions to equity investees driven by lower contributions to Permian Highway Pipeline and SNG in the 2021 period compared with the 2020 period; partially offset by,
•a $494 million decrease in cash primarily due to $413 million of net proceeds received from the sale of a partial interest in our equity investment in NGPL Holdings in the 2021 period, versus the $907 million of proceeds received from the sale of Pembina shares in the 2020 period. See Note 2 “Losses and Gains on Impairments, Divestitures and Other Write-downs” to our consolidated financial statements for further information regarding the transaction of the sale of an interest in NGPL Holdings.
Financing Activities
Cash used in financing activities increased $791 million for the six months ended June 30, 2021 compared to the respective 2020 period primarily attributable to:
•a $779 million net increase in cash used related to debt activity as a result of higher net debt payments in the 2021 period compared to the 2020 period.
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Dividends
We expect to declare dividends of $1.08 per share on our stock for 2021. The table below reflects our 2021 dividends declared:
Three months ended
Total quarterly dividend per share for the period
Date of declaration
Date of record
Date of dividend
March 31, 2021
$
0.27
April 21, 2021
April 30, 2021
May 17, 2021
June 30, 2021
0.27
July 21, 2021
August 2, 2021
August 16, 2021
The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 2020 Form 10-K. All of these matters will be taken into consideration by our board of directors in declaring dividends.
Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally are expected to be paid on or about the 15th day of each February, May, August and November.
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Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), 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 issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or subsidiary issuers are in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.
In lieu of providing separate financial statements for subsidiary issuers and guarantors, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X. Also, see Exhibit 10.1 to this report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of June 30, 2021.”
All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors, (referred to as “affiliates”) are presented separately in the accompanying supplemental summarized combined financial information.
Excluding fair value adjustments, as of June 30, 2021 and December 31, 2020, the Obligated Group had $31,369 million and $32,563 million, respectively, of Guaranteed Notes outstanding.
Summarized combined balance sheet and income statement information for the Obligated Group follows:
Summarized Combined Balance Sheet Information
June 30, 2021
December 31, 2020
(In millions)
Current assets
$
3,996
$
2,957
Current assets - affiliates
1,195
1,151
Noncurrent assets
59,088
61,783
Noncurrent assets - affiliates
507
616
Total Assets
$
64,786
$
66,507
Current liabilities
$
4,654
$
4,528
Current liabilities - affiliates
1,213
1,209
Noncurrent liabilities
32,887
33,907
Noncurrent liabilities - affiliates
945
1,078
Total Liabilities
39,699
40,722
Redeemable noncontrolling interest
683
728
Kinder Morgan, Inc.’s stockholders’ equity
24,404
25,057
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity
$
64,786
$
66,507
Summarized Combined Income Statement Information
Three Months Ended June 30, 2021
Six Months Ended June 30, 2021
(In millions)
Revenues
$
2,837
$
7,739
Operating (loss) income
(831)
998
Net (loss) income
(813)
564
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Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2020, in Item 7A in our 2020 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.
Item 4. Controls and Procedures.
As of June 30, 2021, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended June 30, 2021 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.
Item 1A. Risk Factors.
There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2020 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
The Company does not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. The Company has not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended June 30, 2021.
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Operations for the three and six months ended June 30, 2021 and 2020; (ii) our Consolidated Statements of Comprehensive (Loss) Income for the three and six months ended June 30, 2021 and 2020; (iii) our Consolidated Balance Sheets as of June 30, 2021 and December 31, 2020; (iv) our Consolidated Statements of Cash Flows for the six months ended June 30, 2021 and 2020; (v) our Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 2021 and 2020; and (vi) the notes to our Consolidated Financial Statements.
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Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
KINDER MORGAN, INC.
Registrant
Date:
July 23, 2021
By:
/s/ David P. Michels
David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)
