ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 001-35081
Kinder Morgan, Inc.
(Exact name of registrant as specified in its charter)
Delaware
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
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically 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). Yes ☑ 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,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☑ 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ☐ No ☑
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 2021 was approximately $36,152,128,132. As of February 4, 2022, the registrant had 2,267,484,557 shares of Class P common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022, are incorporated into PART III, as specifically set forth in PART III.
Kinder Morgan Energy Partners, L.P. and its majority-owned and/or controlled subsidiaries
CIG
=
Colorado Interstate Gas Company, L.L.C.
CPGPL
=
Cheyenne Plains Gas Pipeline Company, L.L.C.
KMTP
=
Kinder Morgan Texas Pipeline LLC
EagleHawk
=
EagleHawk Field Services LLC
MEP
=
Midcontinent Express Pipeline LLC
Elba Express
=
Elba Express Company, L.L.C.
NGPL
=
Natural Gas Pipeline Company of America LLC and certain affiliates
EIG
=
EIG Global Energy Partners
ELC
=
Elba Liquefaction Company, L.L.C.
PHP
=
Permian Highway Pipeline LLC
EPNG
=
El Paso Natural Gas Company, L.L.C.
Ruby
=
Ruby Pipeline Holding Company, L.L.C.
FEP
=
Fayetteville Express Pipeline LLC
SFPP
=
SFPP, L.P.
Hiland
=
Hiland Partners, LP
SLNG
=
Southern LNG Company, L.L.C.
KinderHawk
=
KinderHawk Field Services LLC
SNG
=
Southern Natural Gas Company, L.L.C.
Kinetrex
=
Kinetrex Energy
TGP
=
Tennessee Gas Pipeline Company, L.L.C.
KMBT
=
Kinder Morgan Bulk Terminals, Inc.
TMEP
=
Trans Mountain Expansion Project
KMI
=
Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries
TMPL
=
Trans Mountain Pipeline System
Trans Mountain
=
Trans Mountain Pipeline ULC
KML
=
Kinder Morgan Canada Limited and its majority-owned and/or controlled subsidiaries
WIC
=
Wyoming Interstate Company, L.L.C.
KMLP
=
Kinder Morgan Louisiana Pipeline LLC
WYCO
=
WYCO Development 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
GAAP
=
United States Generally Accepted Accounting Principles
AFUDC
=
allowance for funds used during construction
Bbl
=
barrels
LIBOR
=
London Interbank Offered Rate
BBtu
=
billion British Thermal Units
LLC
=
limited liability company
Bcf
=
billion cubic feet
LNG
=
liquefied natural gas
CERCLA
=
Comprehensive Environmental Response, Compensation and Liability Act
MBbl
=
thousand barrels
MMBbl
=
million barrels
C$
=
Canadian dollars
MMtons
=
million tons
CO2
=
carbon dioxide or our CO2 business segment
NEB
=
Canadian National Energy Board
COVID-19
=
Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturn
NGL
=
natural gas liquids
NYMEX
=
New York Mercantile Exchange
CPUC
=
California Public Utilities Commission
NYSE
=
New York Stock Exchange
DCF
=
distributable cash flow
OTC
=
over-the-counter
DD&A
=
depreciation, depletion and amortization
PHMSA
=
United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
Dth
=
dekatherms
EBDA
=
earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments
ROU
=
Right-of-Use
RNG
=
renewable natural gas
EBITDA
=
earnings before interest, income taxes, depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments
SEC
=
United States Securities and Exchange Commission
U.S.
=
United States of America
EPA
=
United States Environmental Protection Agency
WTI
=
West Texas Intermediate
FASB
=
Financial Accounting Standards Board
FERC
=
Federal Energy Regulatory Commission
1
Information Regarding Forward-Looking Statements
This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “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, and our anticipated dividends and capital projects, including expected completion timing and benefits of those projects.
Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results may differ materially from those expressed in our forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or accurately predict. Specific factors that could cause actual results to differ from those in our forward-looking statements include:
•changes in supply of and demand for natural gas, NGL, refined petroleum products, oil, renewable fuels, CO2, electricity, petroleum coke, steel and other bulk materials and chemicals and certain agricultural products in North America;
•economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;
•competition from other pipelines, terminals or other forms of transportation, or from emerging technologies such as CO2 capture and sequestration;
•changes in our tariff rates required by the FERC, the CPUC or another regulatory agency;
•the timing and success of our business development efforts, including our ability to renew long-term customer contracts at economically attractive rates;
•our ability to safely operate and maintain our existing assets and to access or construct new assets including pipelines, terminals, gas processing, gas storage and NGL fractionation capacity;
•our ability to attract and retain key management and operations personnel;
•difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;
•shut-downs or cutbacks at major refineries, petrochemical or chemical plants, natural gas processing plants, ports, utilities, military bases or other businesses that use our services or provide services or products to us;
•changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in North Dakota, Ohio, Oklahoma, Pennsylvania and Texas, and the U.S. Rocky Mountains;
•changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may increase our compliance costs, restrict our ability to provide or reduce demand for our services, or otherwise adversely affect our business;
•interruptions of operations at our facilities due to natural disasters, damage by third parties, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes;
•compromise of our IT systems, operational systems or sensitive data as a result of errors, malfunctions, hacking events or coordinated cyber attacks;
•the uncertainty inherent in estimating future oil, natural gas, and CO2 production or reserves;
•issues, delays or stoppage associated with new construction or expansion projects;
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•regulatory, environmental, political, grass roots opposition, legal, operational and geological uncertainties that could affect our ability to complete our expansion projects on time and on budget or at all;
•our ability to acquire new businesses and assets and integrate those operations into our existing operations, and make cost-saving changes in operations, particularly if we undertake multiple acquisitions in a relatively short period of time, as well as our ability to expand our facilities;
•the ability of our customers and other counterparties to perform under their contracts with us including as a result of our customers’ financial distress or bankruptcy;
•changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;
•changes in tax laws;
•our ability to access external sources of financing in sufficient amounts and on acceptable terms to the extent needed to fund acquisitions of operating businesses and assets and expansions of our facilities;
•our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at a competitive disadvantage compared to our competitors that have less debt, or have other adverse consequences;
•our ability to obtain insurance coverage without significant levels of self-retention of risk;
•natural disasters, sabotage, terrorism (including cyber attacks) or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits;
•possible changes in our and our subsidiaries’ credit ratings;
•conditions in the capital and credit markets, inflation and fluctuations in interest rates;
•political and economic instability of the oil producing nations of the world;
•national, international, regional and local economic, competitive and regulatory conditions and developments, including the effects of any enactment of import or export duties, tariffs or similar measures;
•our ability to achieve cost savings and revenue growth;
•the extent of our success in developing and producing CO2 and oil and gas reserves, including the risks inherent in development drilling, well completion and other development activities;
•engineering and mechanical or technological difficulties that we may experience with operational equipment, in well completions and work-overs, and in drilling new wells;
•unfavorable results of litigation and the outcome of contingencies referred to in Note 18 “Litigation and Environmental” to our consolidated financial statements; and
•the long-term demand for our assets and services and the future impact on our business of the global economic consequences of the COVID-19 pandemic.
The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events or results expressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any forward-looking statements.
Additional discussion of factors that may affect our forward-looking statements appear elsewhere in this report, including in Item 1A “Risk Factors,” Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Energy Commodity Market Risk.” When
3
considering forward-looking statements, you should keep in mind the factors described in this section and the other sections referenced above. 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.
PART I
Items 1 and 2. Business and Properties.
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 143 terminals. Our pipelines transport natural gas, renewable fuels, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, biodiesel, renewable fuels, metals and petroleum coke.
4
General Development of Business
Recent Developments
The following is a listing of significant developments and updates related to our major projects and financing transactions. “Capital Scope” is estimated for our share of the described project which may include portions not yet completed.
Asset or project
Description
Activity
Approx. Capital Scope (KMI Share)
Placed in service, acquisitions or divestitures
NGPL
We and Brookfield Infrastructure Partners L.P. (Brookfield) sold a combined 25% interest in NGPL to ArcLight Capital Partners, LLC and we and Brookfield each now own a 37.5% interest.
Completed in March 2021.
n/a
Stagecoach assets
Acquired Stagecoach Gas Services LLC and its subsidiaries, a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP. Assets include 4 natural gas storage facilities and a network of natural gas transportation pipelines in the northeast region of the U.S.
Acquired in July and November 2021.
$1,258 million
Kinetrex
Acquired Kinetrex from an affiliate of Parallel49 Equity. Kinetrex is a supplier of LNG in the Midwest and a producer and supplier of RNG.
Acquired in August 2021.
$318 million
KMLP Acadiana Expansion
Expansion project provides 945,000 Dth/d of capacity to serve Train 6 at Cheniere’s Sabine pass LNG terminal. Project supported by long-term contracts.
Expansion project increases southbound capacity on NGPL’s Gulf Coast System by approximately 300,000 Dth/d serving Corpus Christi Liquefaction. Subscribed under a long-term firm transportation contract.
Full project placed in service March 2021.
$101 million
Other Announcements
Natural Gas Pipelines
TGP East 300 Upgrade
Expansion project involves upgrading compression facilities upstream on TGP’s system in order to provide 115,000 Dth/d of capacity to Con Edison’s distribution system in Westchester County, New York. Supported by a long-term contract with Con Edison.
Expected in-service date is November 2023, pending receipt of all required permits.
$246 million
CO2 - Energy Transition Ventures
RNG facilities
Construction of three additional landfill-based RNG facilities for Kinetrex in order to provide approximately 3.5 Bcf of RNG a year. Supported by a long-term contract.
First facility expected to be in service by September 2022 and final facility by January 2023.
$146 million
Financings
During 2021, we issued $1,550 million of new senior notes and repaid $2.4 billion of maturing senior notes. In addition, we entered into a new $3.5 billion revolving credit facility, maturing August 2026, which may be used for working capital and other general corporate purposes and amended our existing revolving credit facility, maturing November 2023, to reduce the capacity to $500 million.
Narrative Description of Business
Business Strategy
Our business strategy is to:
•focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure and energy transition of growing markets within North America or served by U.S. exports;
•increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;
5
•exercise discipline in capital allocation and in evaluating expansion projects and acquisition opportunities;
•leverage economies of scale from acquisitions and asset expansions that fit within our strategy; and
•maintain a strong financial profile and enhance and return value to our stockholders.
It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under Item 1A. “Risk Factors” below and at the beginning of this report in “Information Regarding Forward-Looking Statements,” there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.
We regularly consider and enter into discussions regarding potential acquisitions and divestitures, and we are currently contemplating potential transactions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, and, as applicable, receipt of fairness opinions, and approval of our board of directors. While there are currently no unannounced purchase or sale agreements for the acquisition or sale of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.
Business Segments
For financial information on our reportable business segments, see Note 16 “Reportable Segments” to our consolidated financial statements.
Natural Gas Pipelines
Our Natural Gas Pipelines business segment includes interstate and intrastate pipelines, underground storage facilities and our LNG liquefaction and terminal facilities, and includes both FERC regulated and non-FERC regulated assets.
Our primary businesses in this segment consist of natural gas transportation, storage, sales, gathering, processing and treating, and various LNG services. Within this segment are: (i) approximately 45,000 miles of wholly owned natural gas pipelines and (ii) our equity interests in entities that have approximately 27,000 miles of natural gas pipelines, along with associated storage and supply lines for these transportation networks, which are strategically located throughout the North American natural gas pipeline grid. Our transportation network provides access to the major natural gas supply areas and consumers in the western U.S., Louisiana, Texas, Northeast, Rocky Mountain, Midwest and Southeastern regions. Our LNG terminal facilities also serve natural gas market areas in the southeast. The following tables summarize our significant Natural Gas Pipelines business segment assets, as of December 31, 2021. The design capacity represents transmission, gathering, regasification or liquefaction capacity, depending on the nature of the asset.
Asset (KMI ownership shown if not 100%)
Miles of Pipeline
Design (Bcf/d) [(MBbl/d)] Capacity
Storage (Bcf) [Processing (Bcf/d)] Capacity
Supply and Market Region
East Region
TGP(a)
11,755
12.23
76
Marcellus, Utica, Gulf Coast, Haynesville and Eagle Ford shale supply basins; Northeast, Southeast, Gulf Coast and U.S.-Mexico border markets
NGPL (37.5%)
9,105
7.84
288
Chicago and other Midwest markets and all central U.S. supply basins; north to south deliveries, including deliveries to LNG facilities and to the U.S.-Mexico border markets
KMLP
140
3.89
—
Columbia Gulf, ANR Pipeline Company and various other pipeline interconnects; Cheniere Sabine Pass LNG and industrial markets
Stagecoach Gas Services LLC
185
3.22
41
Marcellus, Appalachia; Northeast markets
SNG (50%)(a)
6,925
4.44
66
Basins in Texas, Oklahoma, Louisiana, Mississippi and Alabama; Southeast markets
Florida Gas Transmission (Citrus) (50%)
5,365
4.04
—
Texas to Florida; basins along Louisiana and Texas Gulf Coast, Mobile Bay and offshore Gulf of Mexico
MEP (50%)
515
1.81
—
Oklahoma and north Texas supply with interconnects to Transco, Columbia Gulf, SNG and various other pipelines
6
Asset (KMI ownership shown if not 100%)
Miles of Pipeline
Design (Bcf/d) [(MBbl/d)] Capacity
Storage (Bcf) [Processing (Bcf/d)] Capacity
Supply and Market Region
Elba Express
190
1.10
—
South Carolina to Georgia; connects to SNG, Transco, SLNG, ELC and Dominion Energy Carolina Gas Transmission
FEP (50%)
185
2.00
—
Arkansas to Mississippi; connects to NGPL, Trunkline Gas Company, Texas Gas Transmission and ANR Pipeline Company
Gulf LNG Holdings (50%)
5
1.50
7
Near Pascagoula, Mississippi; connects to four interstate pipelines and a natural gas processing plant
SLNG
—
1.76
12
Located on Elba Island in Georgia; connects to Elba Express, SNG, ELC and Dominion Energy Carolina Gas Transmission
ELC (51%)
—
0.35
—
Located on Elba Island; connects to Elba Express delivering to SLNG for LNG storage and ship loading.
West Region
EPNG/Mojave
10,715
6.39
44
Permian, San Juan and Anadarko Basins; interconnects and demand locations in California, Arizona, New Mexico, Texas, Oklahoma and Mexico
CIG(b)
4,295
6.00
38
Rocky Mountain and Anadarko Basins; interconnects and demand locations in Colorado, Wyoming, Utah, Montana, Kansas, Oklahoma and Texas
WIC
850
3.61
—
Rocky Mountain Basins; interconnects and demand locations in Colorado, Utah and Wyoming
Ruby (50%)(c)
685
1.53
—
Rocky Mountain Basins; interconnects and demand locations in Utah, Nevada, Oregon and California
CPGPL
415
1.20
—
Rocky Mountain Basins; interconnects and demand locations in Colorado and Kansas
TransColorado
310
0.80
—
San Juan, Permian, Paradox and Piceance Basins; interconnects and demand locations in Colorado and New Mexico
Sierrita (35%)
60
0.52
—
Connects with EPNG near Tucson, Arizona, to the U.S.-Mexico international border crossing near Sasabe, Arizona to supply a third-party natural gas pipeline in Mexico
Young Gas Storage (47.5%)
15
—
6
Located in Morgan County, Colorado in the Denver Julesburg Basin; capacity is committed to CIG and Colorado Springs Utilities
Keystone Gas Storage
15
—
6
Located in the Permian Basin near the Waha natural gas trading hub in West Texas
Midstream
KM Texas and Tejas pipelines(d)
5,925
8.30
136 [0.52]
Texas Gulf Coast supply and markets
Mier-Monterrey pipeline(d)
90
0.65
—
Starr County, Texas to Monterrey, Mexico; connects to CENEGAS national system and multiple power plants in Monterrey
KM North Texas pipeline(d)
80
0.33
—
Interconnect from NGPL; connects to a 1,750-megawatt Forney, Texas, power plant and a 1,000-megawatt Paris, Texas, power plant
Gulf Coast Express pipeline (34%)
530
2.00
—
Permian Basin to the Agua Dulce, Texas area
PHP (27%)
430
2.10
—
Permian Basin to the Texas Gulf Coast and Mexico markets
Eagle Ford shale, Woodbine and Eaglebine formations
7
Asset (KMI ownership shown if not 100%)
Miles of Pipeline
Design (Bcf/d) [(MBbl/d)] Capacity
Storage (Bcf) [Processing (Bcf/d)] Capacity
Supply and Market Region
Webb/Duval gas gathering system (91%)
145
0.15
—
South Texas
Camino Real
75
0.15
—
South Texas, Eagle Ford shale formation
EagleHawk (25%)
530
1.20
—
South Texas, Eagle Ford shale formation
KM Altamont
1,545
0.10
[0.1]
Utah, Uinta Basin
Red Cedar (49%)
900
0.33
—
La Plata County, Colorado, Ignacio Blanco Field
Rocky Mountain
Fort Union (50%)
315
1.25
—
Powder River Basin (Wyoming)
Bighorn (51%)
265
0.60
—
Powder River Basin (Wyoming)
KinderHawk
535
2.35
—
Northwest Louisiana, Haynesville and Bossier shale formations
North Texas
545
0.14
—
North Barnett Shale Combo
KM Treating
—
—
—
Odessa, Texas, other locations in Tyler and Victoria, Texas
Hiland - Williston - gas
2,175
0.62
[0.33]
Bakken/Three Forks shale formations - natural gas gathering and processing
Liberty pipeline (50%)
85
[140]
—
Y-grade pipeline from Houston Central complex to the Texas Gulf Coast
South Texas NGL pipelines(e)
340
[115]
—
Ethane and propane pipelines from Houston Central complex to the Texas Gulf Coast
Utopia pipeline (50%)
265
[50]
—
Harrison County, Ohio extending to Windsor, Ontario
Cypress pipeline (50%)
105
[56]
—
Mont Belvieu, Texas to Lake Charles, Louisiana
EagleHawk - Condensate (25%)(f)
400
[220]
—
South Texas, Eagle Ford shale formation
(a)Includes proportionate share of storage capacity from our Bear Creek Storage joint venture.
(b)Includes leased pipeline miles and proportionate share of design and storage capacity from our WYCO joint venture.
(c)We operate Ruby and own the common interest in Ruby. Pembina owns the remaining interest in Ruby in the form of a convertible preferred interest and has 50% voting rights. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby.
(d)Collectively referred to as Texas intrastate natural gas pipeline operations.
(e)Includes proportionate share of design capacity from our Liberty pipeline joint venture.
(f)Asset also has storage capacity of 60 MBbl.
Segment Competition
The market for natural gas infrastructure is highly competitive, and new pipelines, storage facilities, treating facilities, and facilities for related services are currently being built to serve demand for natural gas in the markets served by the pipelines in our Natural Gas Pipelines business segment. We compete with interstate and intrastate pipelines for connections to new markets and supplies and for transportation, processing, storage and treating services. We believe the principal elements of competition in our various markets are location, rates, terms of service, flexibility, availability of alternative forms of energy and reliability of service. From time to time, projects are proposed that compete with our existing assets. Whether or when any such projects would be built, or the extent of their impact on our operations or profitability is typically not known.
Shippers on our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including oil, coal, nuclear and renewables such as hydro, wind and solar power, along with other evolving forms of renewable energy. Several factors influence the demand for natural gas, including price changes, the availability of supply, other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels and weather.
8
Products Pipelines
Our Products Pipelines business segment consists of our refined petroleum products, crude oil and condensate pipelines, and associated terminals, our Southeast terminals, our condensate processing facility and our transmix processing facilities. The following summarizes the significant Products Pipelines business segment assets that we own and operate as of December 31, 2021:
Asset (KMI ownership shown if not 100%)
Miles of Pipeline
Number of Terminals (a) or locations
Terminal Capacity (MMBbl)
Supply and Market Region
Crude & Condensate
KM Crude & Condensate pipeline
266
5
2.6
Eagle Ford shale field in South Texas (Dewitt, Karnes and Gonzales Counties) to the Houston ship channel refining complex
Camino Real Gathering
68
1
0.1
South Texas, Eagle Ford shale formation
Hiland - Williston Basin - oil(b)
1,617
7
0.9
Bakken/Three Forks shale formations - crude oil gathering and transporting
Double H pipeline(b)
512
—
—
Bakken shale in Montana and North Dakota to Guernsey, Wyoming
Double Eagle pipeline (50%)
204
2
0.6
Live Oak County, Texas; Corpus Christi, Texas; Karnes County, Texas; and LaSalle County
KM Condensate Processing Facility (Splitter)
—
1
2.0
Houston Ship Channel, Galena Park, Texas
Southeast Refined Products
Products (SE) pipeline (51%)
3,186
—
—
Louisiana to Washington D.C.
Central Florida pipeline
206
2
2.5
Tampa to Orlando
Southeast Terminals
—
25
8.9
From Mississippi to Virginia, including Tennessee
Transmix Operations
—
5
0.6
Colton, California; Richmond, Virginia; Dorsey Junction, Maryland; St. Louis, Missouri; and Greensboro, North Carolina
West Coast Refined Products
Pacific (SFPP) (99.5%)
2,804
13
15.2
Six western states
Calnev
566
2
2.0
Colton, California to Las Vegas, Nevada; Mojave region
West Coast Terminals
44
8
9.9
Seattle, Portland, San Francisco and Los Angeles areas
(a)The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.
(b)Collectively referred to as Bakken Crude assets.
Segment Competition
Our Products Pipelines’ pipeline and terminal operations compete against proprietary pipelines and terminals owned and operated by major oil companies, other independent products pipelines and terminals, trucking and marine transportation firms (for short-haul movements of products). Our transmix operations compete with refineries owned by major oil companies and independent transmix facilities.
Terminals
Our Terminals business segment includes the operations of our refined petroleum product, chemical, renewable fuel and other liquid terminal facilities (other than those included in the Products Pipelines business segment) and all of our petroleum coke, metal and ores facilities. Our terminals are located primarily near large U.S. urban centers. We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, our Terminals’ marine operations include Jones Act-qualified product tankers that provide
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marine transportation of crude oil, condensate and refined petroleum products between U.S. ports. The following summarizes our Terminals business segment assets, as of December 31, 2021:
Number
Capacity (MMBbl)
Liquids terminals
50
79.9
Bulk terminals
28
—
Jones Act-qualified tankers
16
5.3
Segment Competition
We are one of the largest independent operators of liquids terminals in the U.S., based on barrels of liquids terminaling capacity. Our liquids terminals compete with other publicly or privately held independent liquids terminals and terminals owned by oil, chemical, pipeline and refining companies. Our bulk terminals compete with numerous independent terminal operators, terminals owned by producers and distributors of bulk commodities, stevedoring companies and other industrial companies opting not to outsource terminaling services. In some locations, competitors are smaller, independent operators with lower cost structures. Our Jones Act-qualified product tankers compete with other Jones Act-qualified vessel fleets.
CO2
Our CO2 business segment produces, transports and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. Our CO2 pipelines and related assets allow us to market a complete package of CO2 supply and transportation services to our customers. We hold ownership interests in several oil-producing fields and own a crude oil pipeline, all located in the Permian Basin region of West Texas. We also own and operate RNG and LNG facilities in Indiana associated with our acquisition of Kinetrex.
Source and Transportation Activities
CO2 Resource Interests
Our principal market for CO2 is for injection into mature oil fields in the Permian Basin. Our ownership of CO2 resources as of December 31, 2021 includes:
Ownership Interest
Compression Capacity (Bcf/d)
Location
McElmo Dome unit
45
%
1.5
Colorado
Doe Canyon Deep unit
87
%
0.2
Colorado
Bravo Dome unit(a)
11
%
0.3
New Mexico
(a)We do not operate this unit.
CO2 and Crude Oil Pipelines
The principal market for transportation on our CO2 pipelines is to customers, including ourselves, using CO2 for enhanced recovery operations in mature oil fields in the Permian Basin, where industry demand is expected to remain stable in the foreseeable future. The tariffs charged on (i) the Wink crude oil pipeline system are regulated by both the FERC and the Texas Railroad Commission; (ii) the Pecos Carbon Dioxide Pipeline are regulated by the Texas Railroad Commission; and (iii) the Cortez pipeline are based on a consent decree. Rates on our other CO2 pipelines are established by other means, including by contract.
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Our ownership of CO2 and crude oil pipelines as of December 31, 2021 includes:
Asset (KMI ownership shown if not 100%)
Miles of Pipeline
Transport Capacity (Bcf/d)
Supply and Market Region
CO2 pipelines
Cortez pipeline (53%)
569
1.5
McElmo Dome and Doe Canyon source fields to the Denver City, Texas hub
Central Basin pipeline
337
0.7
Cortez, Bravo, Sheep Mountain, Canyon Reef Carriers and Pecos pipelines
Bravo pipeline (13%)(a)
218
0.4
Bravo Dome to the Denver City, Texas hub
Canyon Reef Carriers pipeline (98%)
163
0.3
McCamey, Texas, to the SACROC, Sharon Ridge, Cogdell and Reinecke units
Centerline CO2 pipeline
113
0.3
between Denver City, Texas and Snyder, Texas
Eastern Shelf CO2 pipeline
98
0.1
between Snyder, Texas and Knox City, Texas
Pecos pipeline (95%)
25
0.1
McCamey, Texas, to Iraan, Texas, delivers to the Yates unit
(Bbls/d)
Crude oil pipeline
Wink pipeline
434
145,000
West Texas to Marathon’s refinery in El Paso, Texas
(a)We do not operate Bravo pipeline.
Oil, Gas, and RNG Producing Activities
Oil and Gas Producing Interests
Our ownership interests in oil and gas producing fields located in the Permian Basin of West Texas as of December 31, 2021 include the following:
Working Interest
KMI Gross Developed Acres
SACROC
97
%
49,156
Yates
50
%
9,576
Goldsmith Landreth San Andres
99
%
6,166
Katz Strawn
99
%
7,194
Reinecke
70
%
3,793
Sharon Ridge(a)
14
%
2,619
Tall Cotton
100
%
641
MidCross(a)
13
%
320
(a)We do not operate these fields.
Our oil and gas producing activities are not significant to KMI as a whole; therefore, we do not include the supplemental information on oil and gas producing activities under Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas.
Gas and Gasoline Plant Interests
Owned and operated gas plants in the Permian Basin of West Texas as of December 31, 2021 include:
Ownership Interest
Source
Snyder gas plant(a)
22
%
The SACROC unit and neighboring CO2 projects, specifically the Sharon Ridge and Cogdell units
Diamond M gas plant
51
%
Snyder gas plant
North Snyder gas plant
100
%
Snyder gas plant
(a)This is a working interest, in addition, we have a 28% net profits interest.
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RNG and LNG Facilities
Owned and operated RNG and LNG facilities as of December 31, 2021 include:
Storage (Bcf) [Production (Bcf)] Capacity
Product
Ownership Interest
Location
LNG Indy
2.0
LNG
100
%
Indiana
Indy High BTU
[0.8]
RNG
50
%
Indiana
Segment Competition
Our primary competitors for the sale of CO2 include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep Mountain CO2 resources. Our ownership interests in the Central Basin, Cortez and Bravo pipelines are in direct competition with other CO2 pipelines. We also compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO2 to the Denver City, Texas market area.
Major Customers
Our revenue is derived from a wide customer base.For each of the years ended December 31, 2021, 2020 and 2019, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.
Industry Regulation
Interstate Natural Gas Transportation and Storage Regulation
We operate our interstate natural gas pipeline and storage facilities subject to the jurisdiction of the FERC and the provisions of the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 (NGPA), and the Energy Policy Act of 2005 (the Energy Policy Act). These laws provide the FERC authority over the construction and operation of such facilities, including their modification, extension, enlargement and abandonment. The FERC also has authority over the rates charged and terms and conditions of services offered by interstate natural gas pipeline and storage companies. The FERC’s regulatory authority extends to establishing minimum and maximum rates for services and allows operators to discount or negotiate rates on a non-discriminatory basis. The rates, terms and conditions of service are set forth in posted tariffs approved by the FERC for each of our interstate natural gas pipeline and storage companies. Posted tariff rates are deemed just and reasonable and cannot be changed without FERC authorization following an evidentiary hearing or settlement. The FERC can initiate proceedings, on its own initiative or in response to a shipper complaint, that could result in a rate change or confirm existing rates. Negotiated rates provide certainty to the pipeline and the shipper of agreed-upon rates during the term of the transportation agreement, regardless of changes to the posted tariff rates. Negotiated rate agreements must be filed with FERC or included in the pipeline’s tariff in summary form.
FERC regulations also include a comprehensive framework for market transparency and nondiscrimination, as well as the FERC’s prohibition against market manipulation. Under the Energy Policy Act and related regulations, it is unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to engage in fraudulent conduct. FERC Standards of Conduct regulate, among other things, the manner in which interstate natural gas pipelines may interact with their marketing affiliates. FERC’s market oversight and transparency regulations require annual reports of purchases or sales of natural gas meeting certain thresholds and criteria and certain public postings of information on scheduled volumes.
FERC has authority to impose civil penalties for violations of these statutes and regulations of more than $1.3 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by FERC, we could be subject to substantial civil penalties and fines.
Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation
Some of our U.S. refined petroleum products and crude oil gathering and transmission pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we
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maintain our tariffs on file with the FERC. Those tariffs set forth the rates we charge for providing gathering or transportation services on our interstate common liquids carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common liquids carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint. Accordingly, certain of the SFPP pipelines’ rates have been subject to challenge with the FERC, as is more fully described in Note 18 “Litigation and Environmental” to our consolidated financial statements.
Petroleum products and crude oil pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. A petroleum products or crude oil pipeline must, as a general rule, utilize the indexing methodology to change its rates. Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates.
CPUC Rate Regulation
The intrastate common carrier operations of our West Coast Refined Products operations’ pipelines in California are subject to regulation by the CPUC under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of the West Coast Refined Products operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by complaint by interested parties or by independent action of the CPUC. A variety of factors can affect the rates of return permitted by the CPUC, and certain other issues similar to those which have arisen with respect to our FERC regulated rates also could arise with respect to its intrastate rates.
Railroad Commission of Texas (RCT) Rate Regulation
The intrastate operations of our crude oil and liquids pipelines and natural gas pipelines and storage facilities in Texas are subject to regulation with respect to such intrastate transportation by the RCT. The RCT has the authority to regulate our rates, though it generally has not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints.
Mexico - Energy Regulatory Commission
The Mier-Monterrey Pipeline has a natural gas transportation permit granted by the Energy Regulatory Commission of Mexico (the Commission) that defines the conditions for the pipeline to carry out activity and provide natural gas transportation service. This permit expires in 2026, subject to an additional renewal term.
This permit establishes certain restrictive conditions, including without limitation: (i) compliance with the general conditions for the provision of natural gas transportation service; (ii) compliance with certain safety measures, contingency plans, maintenance plans and the official standards of Mexico regarding safety; (iii) compliance with the technical and economic specifications of the natural gas transportation system authorized by the Commission; (iv) compliance with certain technical studies established by the Commission; and (v) compliance with a minimum contributed capital not entitled to withdrawal of at least the equivalent of 10% of the investment proposed in the project.
Mexico - National Agency for Industrial Safety and Environmental Protection (ASEA)
ASEA regulates environmental compliance and industrial and operational safety. The Mier-Monterrey Pipeline must satisfy and maintain ASEA’s requirements, including compliance with certain safety measures, contingency plans, maintenance plans and the official standards of Mexico regarding safety, including a Safety Administration Program.
Safety Regulation
We are also subject to safety regulations issued by PHMSA, including those requiring us to develop and maintain pipeline integrity management programs to evaluate areas along our pipelines and take additional measures to protect pipeline segments
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located in what are referred to as High Consequence Areas (HCAs), and Moderate Consequence Areas (MCAs), where a leak or rupture could potentially do the most harm.
In October 2019, PHMSA published a final rule, effective July 1, 2020, to (i) expand integrity management program requirements outside of HCAs (with some exceptions), and (ii) reconfirm maximum allowable operating pressure (MAOP) on certain pipelines in populated areas including HCAs. The MAOP reconfirmations must be completed by 2035.Changes in technology such as advances of in-line inspection tools, identification of additional integrity threats and changes to PHMSA regulations or interpretations can have a significant impact on costs to perform integrity assessments, testing and repairs. We plan to continue to assess and maintain the integrity of our existing and future pipelines as required by PHMSA regulations. We expect the costs to comply with PHMSA regulations, including integrity management program requirements, will be substantial. Such costs will vary depending on the number of repairs or upgrades determined to be necessary as a result of integrity testing. Assessments performed as part of our program could identify results that require significant and unanticipated capital and operating expenditures to address.We expect to increase expenditures in the future to comply with PHMSA regulations.
Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures.
From time to time, our pipelines or facilities may experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
We are also subject to the requirements of the Occupational Safety and Health Administration (OSHA) and other federal and state agencies that address employee health, including infectious diseases such as COVID-19, and safety. In general, we believe we are fulfilling the OSHA requirements and protecting the health and safety of our employees. Based on new or revised regulatory developments, we may be required to increase expenditures in the future to comply with higher industry and regulatory safety standards. However, there are no known new or revised regulations which will require a material increase in our expenditures.
State and Local Regulation
Certain of our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, and human health and safety.
Marine Operations
The operation of tankers and marine equipment create maritime obligations involving property, personnel and cargo under General Maritime Law. These obligations create a variety of risks including, among other things, the risk of collision, which may result in claims for personal injury, cargo, contract, pollution, third-party claims and property damages to vessels and facilities.
We are subject to the Jones Act and other federal laws that restrict maritime transportation (between U.S. departure and destination points) to vessels built and registered in the U.S. and owned and crewed by U.S. citizens. As a result, we monitor the foreign ownership of our common stock and under certain circumstances consistent with our certificate of incorporation, we have the right to redeem shares of our common stock owned by non-U.S. citizens. If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels. Furthermore, from time to time, legislation has been introduced unsuccessfully in the U.S. Congress to amend the Jones Act to ease or remove the requirement that vessels operating between U.S. ports be built and registered in the U.S. and owned and crewed by U.S. citizens. If the Jones Act were amended in such fashion, we could face competition from foreign-flagged vessels.
In addition, the U.S. Coast Guard and the American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for owners of
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vessels registered under foreign flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness.
The Merchant Marine Act of 1936 is a federal law that provides the U.S. Secretary of Transportation, upon proclamation by the U.S. President of a national emergency or a threat to the national security, the authority to requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our vessels were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, we would not be entitled to compensation for any consequential damages suffered as a result of such purchase or requisition.
Canadian Regulation
The Utopia Pipeline System, owned by a joint venture that we operate and in which we own a 50% interest, originates in Ohio and terminates in Windsor, Ontario, Canada and is therefore subject to U.S. regulation as described in this section and below under the heading “—Environmental Matters,” as well as similar regulations promulgated by Canadian authorities with respect to natural gas liquids pipelines.
Derivatives Regulation
We use energy commodity derivative contracts as part of our strategy to hedge our exposure to energy commodity market risk and other external risks in the ordinary course of business. The derivative contracts that we use include exchange-traded and OTC commodity financial instruments such as, futures and options contracts, fixed price swaps and basis swaps. The Dodd-Frank Act requires the U.S. Commodity Futures Trading Commission (CFTC) and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that market. In October 2020, the CFTC finalized one of the last remaining new rules pursuant to the Dodd-Frank Act that institutes broad new aggregate position limits for OTC swaps and futures and options traded on regulated exchanges. As finalized, these rules include exemptions for hedging positions, and while we cannot yet predict the full impact of the rules when they take effect in 2022 and 2023, we do not expect that the rules will have a material adverse effect on our business. We cannot predict how new leadership at the CFTC as a result of the change in the U.S. presidential administration may impact us.
Environmental Matters
Our business operations are subject to federal, state and local laws and regulations relating to environmental protection and human health and safety. For example, if an accidental leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, storage or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release or spill, pay for government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or a combination of these and other measures. Furthermore, new projects may require approvals and environmental analyses under federal and state laws, including the Clean Water Act, the National Environmental Policy Act and the Endangered Species Act, as well as Executive Orders focused on environmental justice considerations. The resulting costs and liabilities could materially and negatively affect our business, financial condition, results of operations and cash flows. In addition, emission controls required under federal and state environmental laws for both new and existing facilities could require significant capital expenditures at our facilities. In general, the cost of environmental control at facilities is increasing and limiting the return on capital projects and the number of capital projects that are viable.
Environmental and human health and safety laws and regulations are subject to change. The long-term trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health. There can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Several state and federal agencies have also increased their daily and maximum penalty amounts in recent years. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, as well as increased penalty amounts for inadvertent non-compliance, such as an unexpected pipeline leak, could have a material adverse effect on our business, financial position, results of operations and cash flows.
In accordance with GAAP, we record liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or
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previously disposed. We have accrued liabilities for reasonably estimable and probable environmental remediation obligations at various sites, including multi-party sites where the EPA or a similar state agency has identified us as one of the potentially responsible parties. The involvement of other financially responsible companies at these multi-party sites could affect our actual joint and several liability exposures for response costs as well as natural resource damages.
We believe that the ultimate resolution of these environmental matters will not have a material adverse effect on our business, financial position, results of operations or cash flows. However, it is possible that our ultimate liability with respect to these environmental matters could exceed the amounts accrued in an amount that could be material to our business, financial position, results of operations or cash flows in any particular reporting period. We have accrued an environmental reserve in the amount of $243 million as of December 31, 2021. For additional information related to environmental matters, see Note 18 “Litigation and Environmental” to our consolidated financial statements.
Hazardous and Non-Hazardous Waste
We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. From time to time, the EPA, as well as other U.S. federal and state regulators, consider the adoption of stricter disposal standards for non‑hazardous waste. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations or wastes from oil and gas facilities that are currently exempt as exploration and production waste, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.
Superfund
The CERCLA or the Superfund law, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, in addition to compensation for natural resource damages, if any. Although petroleum is excluded from CERCLA’s definition of a hazardous substance, in the course of our ordinary operations, we have and will generate materials that may fall within the definition of “hazardous substance.” By operation of law, if we are determined to be a potentially responsible person, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such materials are present, in addition to compensation for natural resource damages, if any.
Clean Air Act
Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state statutes and regulations. The EPA regulations under the Clean Air Act contain requirements for the monitoring, reporting, and control of greenhouse gas (GHG) emissions from stationary sources. For further information, see “—Climate Change” below.
Clean Water Act
Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of fills and pollutants into waters of the U.S. The discharge of fills and pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention of and response to oil spills. Spill prevention, control and countermeasure requirements of the Clean Water Act and some state laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release of oil.
EPA Revisions to Ozone National Ambient Air Quality Standard (NAAQS)
As required by the Clean Air Act, the EPA establishes National Ambient Air Quality Standards (NAAQS) for how much pollution is permissible, and the states then have to adopt rules so their air quality meets the NAAQS. In October 2015, the EPA published a rule lowering the ground level ozone NAAQS from 75 parts per billion (ppb) to a more stringent 70 ppb standard. This change triggered a process under which the EPA designated the areas of the country in or out of compliance with the 2015 standards. In December 2020, EPA completed a review of the ozone NAAQS and published a rule retaining the
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2015 standards. State rules implementing the NAAQS, including those existing or proposed in Colorado and New Mexico, require the installation of more stringent air pollution controls on newly-installed equipment and possibly require the retrofitting of existing KMI facilities with air pollution controls. These rules will have financial impacts to our Natural Gas Business Unit. Future state rules could have financial impacts on multiple business units.
Climate Change
Due to concern over climate change, numerous proposals to monitor and limit emissions of GHGs have been made and are likely to continue to be made at the federal, state and local levels of government. Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of GHGs. Various laws and regulations exist or are under development to regulate the emission of such GHGs, including the EPA programs to report GHG emissions and state actions to develop statewide or regional programs. The U.S. Congress has in the past considered legislation to reduce emissions of GHGs. Climate-related laws and regulation could lead to reduced demand for hydrocarbon products that are deemed to contribute to GHGs, which in turn could adversely affect demand for our products and services.
Beginning in 2009, EPA published several findings and rulemakings under the Clean Air Act requiring the permitting and reporting of certain GHGs, including CO2 and methane. Our facilities are subject to these requirements. Operational and/or regulatory changes could require additional facilities to comply with requirements for reducing, reporting and permitting GHG emissions. In November 2021, EPA published preamble language for a proposed new rule to regulate GHGs from new and existing sources in the oil and natural gas sector. The proposal would require states to limit methane emissions consistent with the EPA proposed “Emission Guidelines” which are meant be presumptive standards for the states to follow. These standards include increased monitoring requirements and require installation of pollution control equipment on a wide variety of equipment including compressor engines, pneumatic controllers and tanks. The EPA proposal did not include draft rule language so the total cost to comply with the proposed rule is difficult to predict. However, if the rule is finalized in a similar format to what is proposed, we expect significant increases in capital and operating expenditures to comply with this EPA regulation.
At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs, such as through establishment of GHG reduction targets or regional GHG “cap and trade” programs. It is possible that sources such as our gas-fueled compressors and processing plants could become subject to these state GHG reduction regulations. Various states are also proposing or have implemented stricter regulations for reporting, monitoring or reduction of GHGs that go beyond the requirements of the EPA. Compliance with state rules could require additional expenditures, above and beyond those spent to comply with the November 2021 proposed EPA GHG rules for new and existing sources.
Because our operations, including the compressor stations and processing plants, emit various types of GHGs, primarily methane and CO2, such new legislation or regulation could increase the costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we or our subsidiaries could be required to incur capital expenditures for installing new monitoring equipment or emission controls on the facilities, acquire and surrender allowances for the GHG emissions, pay taxes related to the GHG emissions and administer and manage a more comprehensive GHG emissions program. We are not able at this time to estimate such increased costs; however, as is the case with similarly situated companies in our industry, they could be significant to us. While we may be able to include some or all of such increased costs in the rates charged by our or our subsidiaries’ pipelines, recovery of costs is uncertain in all cases and may depend on events beyond their control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations. Any of the foregoing could have an adverse effect on our business, financial position, results of operations and prospects.
Many climate models indicate that global warming is likely to result in rising sea levels, increased intensity of hurricanes and tropical storms, and increased frequency of extreme precipitation and flooding. We may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions. However, the timing, severity and location of these climate change impacts are not known with certainty and, these impacts are expected to manifest themselves over varying time horizons.
Because the combustion of natural gas produces lower GHG emissions per unit of energy than competing fossil fuels, cap-and-trade legislation or EPA regulatory initiatives to reduce GHGs could stimulate demand for natural gas by increasing the relative cost of competing fuels such as coal and oil. In addition, we anticipate that GHG regulations will increase demand for carbon sequestration technologies, such as the techniques we have successfully demonstrated in our enhanced oil recovery
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operations within our CO2 business segment. However, these potential positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels. Although we currently cannot predict the magnitude and direction of these impacts, GHG regulations could have material adverse effects on our business, financial position, results of operations or cash flows.
Department of Homeland Security
The Department of Homeland Security, referred to in this report as the DHS, has regulatory authority over security at certain high-risk chemical facilities. The DHS has promulgated the Chemical Facility Anti-Terrorism Standards and required all high-risk chemical and industrial facilities, including oil and gas facilities, to comply with the regulatory requirements of these standards. This process includes completing security vulnerability assessments, developing site security plans, and implementing protective measures necessary to meet DHS-defined, risk-based performance standards. The DHS has not provided final notice to all facilities that it determines to be high risk and subject to the rule; therefore, neither the extent to which our facilities may be subject to coverage by the rules nor the associated costs to comply can currently be determined, but it is possible that such costs could be substantial.
In response to ongoing cybersecurity threats affecting the pipeline industry the DHS’s Transportation Safety Administration issued two new security directives in 2021, which require critical pipeline owners to comply with mandatory reporting measures, designate a cybersecurity coordinator, provide vulnerability assessments, and ensure compliance with certain cybersecurity requirements. Compliance with these directives is consuming significant resources, and we may be required to expend significant additional resources to continue to enhance our information security measures, to comply with regulations, and/or to investigate and remediate information security vulnerabilities.
Human Capital
In managing our human capital resources, we use a strategic approach to building a diverse, inclusive, and respectful workplace. Our human resources department provides expertise and tools to attract, develop, and retain diverse talent and support our employees’ career and development goals. Our leadership teams have plans in place to enhance diversity and equality of opportunity in hiring, development, and promotions. We value our employees’ opinions and encourage them to engage with management and ask questions on topics such as our goals, challenges, and employee concerns.
We employed 10,529 full-time personnel at December 31, 2021, including approximately 910 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 2022 and 2024. We consider relations with our employees to be good.
We value the safety of our workforce and integrate a culture of safety, emergency preparedness, and environmental responsibility through our operations management system (OMS). Our OMS conforms to common industry standards and establishes a framework that helps us: (i) provide employees and contractors with a safe work environment; (ii) comply with laws, rules, regulations, policies, and procedures; and (iii) identify opportunities to improve. Although our ultimate target is zero incidents, we also have three non-zero employee safety performance targets. The first is to outperform the annual industry average total recordable incident rate (TRIR). The second is to outperform our own three-year TRIR average. The third is a longer-term target to improve our company-wide employee TRIR from 1.0 in the baseline year 2019 to 0.7 by 2024. Our 2021 company-wide TRIR was 1.8 and 0.7, including and excluding COVID-19 cases, respectively. We seek to constantly improve our contractor TRIR performance through initiatives to address recent incident trends and new best practices.
Our board of directors’ nominating and governance committee is responsible for planning for succession in the senior management ranks of the Company, including the office of chief executive officer. The chief executive officer shall report to the Committee, generally at the time of the regularly scheduled third quarter board of directors meeting in each year, regarding the processes in place to identify talent within and outside the Company to succeed to senior management positions and the information developed during the current calendar year pursuant to those processes. As part of our annual succession planning process, we identify minority and female candidates to include in the plan for senior positions. Management reviews its succession plan, including a discussion on development opportunities for potential successors, with the nominating and governance committee of our board of directors annually.
We consider employee diversity an asset and support equal opportunity employment. We take affirmative steps to employ and advance in employment all persons without regard to their race/ethnicity; sex; sexual orientation; gender, including gender identity and expression; veteran status; disability; or other protected categories, and base employment decisions solely on valid job requirements. We are committed to a harassment free workplace, supported with online and face-to-face workplace
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harassment and discrimination prevention training for our employees. Employees and supervisors review our harassment and discrimination prevention policy every two years as part of our policy renewal training.
Our employees are an integral part of our success, and we value their career development. We encourage and support professional development and learning for our employees by offering workforce training, tuition reimbursement, leadership and other development programs. These programs help improve recruitment, development, and retention. We support our employees’ ongoing career goals and development through several programs. These programs help maximize our employees’ potential and give them the skills they need to further enhance their careers.
Our compensation program is linked to long and short-term strategic financial and operational objectives, including environmental, safety, and compliance targets. Compensation includes competitive base salaries in the markets in which we operate and competitive benefits, including retirement plans, opportunities for annual bonuses, and, for eligible employees, long-term incentives and an employee stock purchase plan.
Properties and Rights-of-Way
We believe that we generally have satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties or the use of such properties in our businesses. Our terminals, storage facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, offices and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state or local government land.
We generally do not own the land on which our pipelines are constructed. Instead, we obtain and maintain rights to construct and operate the pipelines on other people’s land generally under agreements that are perpetual or provide for renewal rights. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of a majority of the interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense. Permits also have been obtained from railroad companies to run along or cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased by the Company.
Financial Information about Geographic Areas
For geographic information concerning our assets and operations, see Note 16 “Reportable Segments” to our consolidated financial statements.
Available Information
We make available free of charge on or through our internet website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on or connected to our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
Item 1A. Risk Factors.
You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.
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Risks Related to Operating our Business
The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.
The COVID-19 pandemic and the efforts to control it resulted in a significant decline in global economic activity and significant disruption of global supply chains in 2020. The resulting downturn in economic activity negatively impacted global demand and prices for crude oil, natural gas, NGL, refined petroleum products, CO2, steel, chemicals and other products that we handle in our pipelines, terminals, shipping vessels and other facilities. The sustainability of the economic recovery observed in 2021 remains unclear as inflationary pressures have increased in the U.S. and globally and efforts to combat the virus have been complicated by new variants.
As the pandemic and responses to it continue, we may experience further disruptions to commodities markets, supply chains and the health, availability and efficiency of our workforce, which could adversely affect our ability to conduct our business and operations and limit our ability to execute on our business plan. There are still too many variables and uncertainties regarding COVID-19 — including the pace and efficacy of vaccination efforts, the duration and severity of possible resurgences or additional variants, the duration and extent of any travel restrictions and business closures imposed in affected countries and market reactions to the announcement of any such restrictions and closures — to reasonably predict the potential impact of COVID-19 on our business and operations. COVID-19 may materially adversely affect our business, results of operations, financial condition and cash flows. Even after the COVID-19 pandemic has subsided, we may experience materially adverse impacts to our business due to residual impacts from measures taken to combat the virus. Further, adverse impacts from the pandemic may have the effect of heightening many of the other risks we face.
Our businesses are dependent on the supply of and demand for the products that we handle.
Our pipelines, terminals and other assets and facilities, including the availability of expansion opportunities, depend in part on continued production of natural gas, crude oil and other products in the geographic areas that they serve. Our business also depends in part on the levels of demand for natural gas, crude oil, NGL, refined petroleum products, CO2, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand. For example, without additions to crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may reduce or shut down production during times of lower product prices or higher production costs to the extent they become uneconomic. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our pipelines and related facilities may not be able to maintain existing volumes of throughput.
Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Additionally, demand for such products can decline due to situations over which we have no control, such as the COVID-19 pandemic and various measures that federal, state and local authorities have implemented in response to the virus or its economic consequences.
In addition to economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as declining or sustained low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets. Also, sustained lower demand for hydrocarbons, or changes in the regulatory environment or applicable governmental policies, including in relation to climate change or other environmental concerns, may have a negative impact on the supply of crude oil and other products. In recent years, a number of initiatives and regulatory changes relating to reducing GHG emissions have been undertaken by federal, state and municipal governments and crude oil and gas industry participants. In addition, public concern about the potential risks posed by climate change has resulted in increased demand for energy efficiency and a transition to energy provided from renewable energy sources, rather than fossil fuels, fuel-efficient alternatives such as hybrid and electric vehicles, and pursuit of other technologies to reduce GHG emissions, such as carbon capture and sequestration. We may see an intensification of these trends if and to the extent that the Biden presidential administration succeeds in enacting its energy and environmental policies.
These factors could result in not only increased costs for producers of hydrocarbons but also an overall decrease in the demand for hydrocarbons. Each of the foregoing could negatively impact our business directly as well as our shippers and other customers, which in turn could negatively impact our prospects for new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts or the ability of our customers and shippers to honor their contractual commitments. Furthermore, such unfavorable conditions may compound the adverse effects of larger disruptions such as COVID-19. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the productsor services we provide or otherwise fulfill their obligations to us” below.
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We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the production of and/or demand for the products we handle. In addition, irrespective of supply of or demand for products we handle, implementation of new regulations or changes to existing regulations affecting the energy industry could have a material adverse effect on us.
We face competition from other pipelines and terminals, as well as other forms of transportation and storage.
Competition is a factor affecting our existing businesses and our ability to secure new project opportunities. Any current or future pipeline system or other form of transportation (such as barge, rail or truck) that delivers the products we handle into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities or other factors. Likewise, competing terminals or other storage options may become more attractive to our customers. To the extent that competitors offer the markets we serve more desirable transportation or storage options, or customers opt to construct their own facilities for services previously provided by us, this could result in unused capacity on our pipelines and in our terminals. We also could experience competition for the supply of the products we handle from both existing and proposed pipeline systems; for example, several pipelines access many of the same areas of supply as our pipeline systems and transport to destinations not served by us. If capacity on our assets remains unused, our ability to re-contract for expiring capacity at favorable rates or otherwise retain existing customers could be impaired. In addition, to the extent that companies pursuing development of carbon capture and sequestration technology are successful, they could compete with us for customers who purchase CO2 for use in enhanced oil recovery operations.
The volatility of crude oil, NGL and natural gas prices could adversely affect our CO2 business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.
The revenues, cash flows, profitability and future growth of some of our businesses (and the carrying values of certain of their respective assets, which include related goodwill) depend to a large degree on prevailing crude oil, NGL and natural gas prices.
Prices for crude oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for crude oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) domestic and global economic conditions; (iii) the activities of the OPEC and other countries that are significant producers of crude oil (OPEC+); (iv) governmental regulation; (v) political instability in crude oil producing countries; (vi) the foreign supply of and demand for crude oil and natural gas; (vii) the price of foreign imports; (viii) the proximity and availability of storage and transportation infrastructure and processing and treating facilities; and (ix) the availability and prices of alternative fuel sources. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. We are also subject, indirectly, to volatility of commodity prices, through many of our customers’ direct exposure to such volatility. Please read “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.”
In 2020, the impact of COVID-19, combined with a dispute regarding production levels among OPEC+ countries, caused crude oil prices to reach historic lows in April 2020. While global oil demand and prices improved later in 2020 and through 2021 from the low levels experienced in early 2020, the announcement of a newly discovered variant of COVID-19 in late November 2021 resulted in a sharp, unexpected and temporary decline in the price of crude oil. If prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.
Sharp declines in the prices of crude oil, NGL or natural gas (such as we experienced in the first half of 2020) or a prolonged unfavorable price environment, may result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell crude oil, NGL, or natural gas, and could have a material adverse effect on the carrying value (which includes assigned goodwill) of our CO2 business segment’s proved reserves, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and certain assets within our Products Pipelines business segment. For example, following the commodity price declines we experienced during the first half of 2020, we recorded a combined $1.950 billion of non-cash impairments associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units, primarily for impairments of goodwill and assets owned in these businesses. See Note 4 “Losses and Gains on Impairments, Divestitures and Other Write-downs” and Note 8 “Goodwill” to our consolidated financial statements for more information.
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In recent decades, there have been periods worldwide of both overproduction and underproduction of hydrocarbons, and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The cycles of excess or short supply of crude oil or natural gas have placed pressures on prices and resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. These fluctuations impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk.”
Commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our operations.
There are a variety of hazards and operating risks inherent to the transportation and storage of the products we handle, such as leaks; releases; the breakdown, underperformance or failure of equipment, facilities, information systems or processes; damage to our pipelines caused by third-party construction; the compromise of information and control systems; spills at terminals and hubs; spills associated with the loading and unloading of harmful substances at rail facilities; adverse sea conditions (including storms and rising sea levels) and releases or spills from our shipping vessels or vessels loaded at our marine terminals; operator error; labor disputes/work stoppages; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries on which our assets depend; and catastrophic events or natural disasters such as fires, floods, explosions, earthquakes, acts of terrorists and saboteurs, cyber security breaches, and other similar events, many of which are beyond our control. Additional risks to our vessels include capsizing, grounding and navigation errors.
The occurrence of any of these risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution, significant reputational damage, impairment or suspension of operations, fines or other regulatory penalties, and revocation of regulatory approvals or imposition of new requirements, any of which also could result in substantial financial losses, including lost revenue and cash flow to the extent that an incident causes an interruption of service. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. In addition, the consequences of any operational incident (including as a result of adverse sea conditions) at one of our marine terminals may be even more significant as a result of the complexities involved in addressing leaks and releases occurring in the ocean or along coastlines and/or the repair of marine terminals.
Our operating results may be adversely affected by unfavorable economic and market conditions.
Unfavorable conditions such as a general slowdown of the global or U.S. economy, uncertainty and volatility in the financial markets, or inflation and rising interest rates, could materially adversely affect our operating results. For example, as described above, COVID-19 resulted in a global economic downturn in 2020. The slowdown resulting from the pandemic affected numerous industries, including the crude oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. While global economic activity largely rebounded in 2021, we could experience similar or compounded adverse impacts as a result of other global events affecting economic conditions. Also, economic conditions in the wake of the pandemic have included inflationary pressure, which could result in higher operating expenses and project costs for us, as well as higher interest rates.
In addition, uncertain or changing economic conditions within one or more geographic regions may affect our operating results within the affected regions. Sustained unfavorable commodity prices, volatility in commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers, which could impair their ability to meet their obligations to us. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” In addition, decreases in the prices of crude oil, NGL and natural gas are likely to have a negative impact on our operating results and cash flow. See “—The volatility of crude oil, NGL and natural gas prices could adversely affect our CO2 business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.”
If economic and market conditions (including volatility in commodity markets) globally, in the U.S. or in other key markets become more volatile or deteriorate, we may experience material impacts on our business, financial condition and results of operations.
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Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.
We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers. Many of our counterparties finance their activities through cash flow from operations or debt or equity financing, and some of them may be highly leveraged and may not be able to access additional capital to sustain their operations in the future. Our counterparties are subject to their own operating, market, financial and regulatory risks, and some have experienced, are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. For example, in 2020, the global economic slowdown caused by COVID-19, and the coinciding extreme drop in crude oil prices, which was exacerbated by the effects of the pandemic, significantly impacted the financial condition of many companies, particularly exploration and production companies, including some of our customers or counterparties. Further, the security that is permitted to be obtained from such customers may be limited, including by FERC regulation. While certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, the parent’s credit ratings may have no bearing on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us. See Note 2 “Summary of Significant Accounting Policies—Allowance for Credit Losses” in our consolidated financial statements.
Furthermore, financially distressed customers might be forced to reduce or curtail their future use of our products and services, which also could have a material adverse effect on our results of operations, financial condition, and cash flows.
We cannot provide any assurance that such customers and key counterparties will not become financially distressed or that such financially distressed customers or counterparties will not default on their obligations to us or file for bankruptcy protection. If one of such customers or counterparties files for bankruptcy protection, we likely would be unable to collect all, or even a significant portion of, amounts owed to us. Similarly, our contracts with such customers may be renegotiated at lower rates or terminated altogether. Significant customer and other counterparty defaults and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash flows.
We are subject to reputational risks and risks relating to public opinion.
Our business, operations or financial condition generally may be negatively impacted as a result of negative public opinion. Public opinion may be influenced by negative portrayals of the industry in which we operate as well as opposition to development projects. In addition, market events specific to us could result in the deterioration of our reputation with key stakeholders.
Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, regulatory and legal risks, among others, must all be managed effectively to safeguard our reputation. Our reputation and public opinion could also be impacted by the actions and activities of other companies operating in the energy industry, particularly other energy infrastructure providers, over which we have no control. In particular, our reputation could be impacted by negative publicity related to pipeline incidents or unpopular expansion projects and due to opposition to development of hydrocarbons and energy infrastructure, particularly projects involving resources that are considered to increase GHG emissions and contribute to climate change. Negative impacts from a compromised reputation or changes in public opinion (including with respect to the production, transportation and use of hydrocarbons generally) could include increased regulatory oversight, delays in obtaining, or challenges to, regulatory approvals with respect to growth projects, blockades, project cancellations, difficulty securing financing, revenue loss, reduction in customer base, and decreased value of our securities and our business.
The future success of our oil and gas development and production operations depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable.
The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves, revenues and cash flows of the oil and gas producing assets within our CO2 business segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.
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The development of crude oil and gas properties involves risks that may result in a total loss of investment.
The business of developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Acquisition and development decisions generally are based on subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions, may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.
Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.
We engage in hedging arrangements to reduce our direct exposure to fluctuations in the prices of crude oil, natural gas and NGL, including differentials between regional markets. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for crude oil, natural gas and NGL. Furthermore, our hedging arrangements cannot hedge against any decrease in the volumes of products we handle. See “—Our businesses are dependent on the supply of and demand for the products that we handle.”
The markets for instruments we use to hedge our commodity price exposure generally reflect then-prevailing conditions in the underlying commodity markets. As our existing hedges expire, we will seek to replace them with new hedging arrangements. To the extent then-existing underlying market conditions are unfavorable, new hedging arrangements available to us will reflect such unfavorable conditions, limiting our ability to hedge our exposure to unfavorable commodity prices.
The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those consolidated financial statements. In addition, it may not be possible for us to engage in hedging transactions that completely eliminate our exposure to commodity prices; therefore, our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For more information about our hedging activities, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—Hedging Activities” and Note 14 “Risk Management” to our consolidated financial statements.
A breach of information security or failure of one or more key information technology (IT) or operational (OT) systems, or those of third parties, may adversely affect our business, results of operations or business reputation.
Our business is dependent upon our operational systems to process a large amount of data and complex transactions. Some of the operational systems we use are owned or operated by independent third-party vendors. The various uses of these IT systems, networks and services include, but are not limited to, controlling our pipelines and terminals with industrial control systems, collecting and storing information and data, processing transactions, and handling other processing necessary to manage our business.
While we have implemented and maintain a cybersecurity program designed to protect our IT, OT and data systems from attacks, we can provide no assurance that our cybersecurity program will be effective. As a result of the COVID-19 pandemic and our subsequent continuation of hybrid office-and-remote-working arrangements with some of our employees, remote access to our networks and systems has increased substantially. While we have taken additional steps to secure our networks and systems, we may be more vulnerable to a successful cyber-attack or information security incident when significant numbers of our employees are working remotely. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. The risk of a disruption or breach of our operational systems,
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or the compromise of the data processed in connection with our operations, through an act of terrorism or cyber sabotage event has increased as attempted attacks have advanced in sophistication and number around the world.
If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to perform critical functions, which could adversely affect our business and results of operations. A significant failure, compromise, breach or interruption in our systems, which may result from problems such as ransomware, malware, computer viruses, hacking attempts or third-party error or malfeasance, could result in a disruption of our operations, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. Efforts by us and our vendors to develop, implement and maintain security measures, including malware and anti-virus software and controls, may not be successful in preventing these events from occurring, and any network and information systems-related events could require us to expend significant resources to remedy such event. In the future, we may be required to expend significant additional resources to continue to enhance our information security measures, to comply with regulations, and/or to investigate and remediate information security vulnerabilities.
Attacks, including acts of terrorism or cyber sabotage, or the threat of such attacks, may adversely affect our business or reputation.
The U.S. government has issued public warnings that indicate that pipelines and other infrastructure assets might be specific targets of terrorist organizations or “cyber sabotage” events. For example, in May 2021, a ransomware attack on a major U.S. refined products pipeline forced the operator to temporarily shut down the pipeline, resulting in disruption of fuel supplies along the East Coast. Potential targets include our pipeline systems, terminals, processing plants or operating systems. The occurrence of an attack could cause a substantial decrease in revenues and cash flows, increased costs to respond or other financial loss, damage to our reputation, increased regulation or litigation or inaccurate information reported from our operations. There is no assurance that adequate cyber sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition or could harm our business reputation.
Hurricanes, earthquakes, flooding and other natural disasters, as well as subsidence and coastal erosion and climate-related physical risks, could have an adverse effect on our business, financial condition and results of operations.
Some of our pipelines, terminals and other assets are located in, and our shipping vessels operate in, areas that are susceptible to hurricanes, earthquakes, flooding and other natural disasters or could be impacted by subsidence and coastal erosion. These natural disasters and phenomena could potentially damage or destroy our assets and disrupt the supply of the products we transport. Many climate models indicate that global warming is likely to result in rising sea levels, increased intensity of weather, and increased frequency of extreme precipitation and flooding. These climate-related changes could result in damage to physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions. In addition, we may experience increased insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather. Natural disasters and phenomena can similarly affect the facilities of our customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected, perhaps materially. See Items 1 and 2 “Business and Properties—Narrative Description of Business—Environmental Matters.”
Our insurance policies do not cover all losses, costs or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.
Our insurance program may not cover all operational risks and costs and may not provide sufficient coverage in the event of a claim. We do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations.
Changes in the insurance markets subsequent to certain hurricanes and natural disasters have made it more difficult and more expensive to obtain certain types of coverage. The occurrence of an event that is not fully covered by insurance, or failure by one or more of our insurers to honor its coverage commitments for an insured event, could have a material adverse effect on our business, financial condition and results of operations. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover our assets. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. There is no assurance that our insurers will renew their insurance coverage on
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acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.
Expanding our existing assets and constructing new assets is part of our growth strategy. Our ability to begin and complete construction on expansion and new-build projects may be inhibited by difficulties in obtaining, or our inability to obtain, permits and rights-of-way, as well as public opposition, increases in costs of construction materials, cost overruns, inclement weather and other delays. Should we pursue expansion of or construction of new projects through joint ventures with others, we will share control of and any benefits from those projects.
We regularly undertake major construction projects to expand our existing assets and to construct new assets. New growth projects generally will be subject to, among other things, the receipt of regulatory approvals, feasibility and cost analyses, funding availability and industry, market and demand conditions. If we pursue joint ventures with third parties, those parties may share approval rights over major decisions, and may act in their own interests. Their views may differ from our own or our views of the interests of the venture which could result in operational delays or impasses, which in turn could affect the financial expectations of and our expected benefits from the venture. A variety of factors outside of our control, such as difficulties in obtaining permits and rights-of-way or other regulatory approvals, have caused, and may continue to cause, delays in or cancellations of our construction projects. Regulatory authorities may modify their permitting policies in ways that disadvantage our construction projects, such as the FERC’s consideration of changes to its Certificate Policy Statement. Such factors can be exacerbated by public opposition to our projects. See “—We are subject to reputational risks and risks relating to public opinion.” For example, changing public attitudes toward pipelines bearing fossil fuels may impede our ability to secure rights-of-way or governmental reviews and authorizations on a timely basis or at all. Inclement weather, natural disasters and delays in performance by third-party contractors have also resulted in, and may continue to result in, increased costs or delays in construction. In addition, inflationary pressure that emerged during the economic recovery following the COVID-19 pandemic is likely to increase our costs for construction materials. Significant increases in costs of construction materials, cost overruns or delays, or our inability to obtain a required permit or right-of-way, could have a material adverse effect on our return on investment, results of operations and cash flows, and could result in project cancellations or limit our ability to pursue other growth opportunities.
Substantially all of the land on which our pipelines are located is owned by third parties. If we are unable to procure and maintain access to land owned by third parties, our revenue and operating costs, and our ability to complete construction projects, could be adversely affected.
We must obtain and maintain the rights to construct and operate pipelines on other owners’ land, including private landowners, railroads, public utilities and others. While our interstate natural gas pipelines in the U.S. have federal eminent domain authority, the availability of eminent domain authority for our other pipelines varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas, CO2, or crude oil—and the laws of the particular state. In any case, we must compensate landowners for the use of their property, and in eminent domain actions, such compensation may be determined by a court. If we are unable to obtain rights-of-way on acceptable terms, our ability to complete construction projects on time, on budget, or at all, could be adversely affected. In addition, we are subject to the possibility of increased costs under our rights-of-way or rental agreements with landowners, primarily through renewals of expiring agreements and rental increases. If we were to lose these rights, our operations could be disrupted or we could be required to relocate the affected pipelines, which could cause a substantial decrease in our revenues and cash flows and a substantial increase in our costs.
The acquisition of additional businesses and assets is part of our growth strategy. We may experience difficulties completing acquisitions or integrating new businesses and properties, and we may be unable to achieve the benefits we expect from any future acquisitions.
Part of our business strategy includes acquiring additional businesses and assets. We evaluate and pursue assets and businesses that we believe will complement or expand our operations in accordance with our growth strategy. We cannot provide any assurance that we will be able to complete acquisitions in the future or achieve the desired results from any acquisitions we do complete. Any acquired business or assets will be subject to many of the same risks as our existing businesses and may not achieve the levels of performance that we anticipate.
If we do not successfully integrate acquisitions, we may not realize anticipated operating advantages and cost savings. Integration of acquired companies or assets involves a number of risks, including (i) the loss of key customers of the acquired business; (ii) demands on management related to the increase in our size; (iii) the diversion of management’s attention from the
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management of daily operations; (iv) difficulties in implementing or unanticipated costs of accounting, budgeting, reporting, internal controls and other systems; and (v) difficulties in the retention and assimilation of necessary employees.
We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately. Successful integration of each acquisition will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.
Our business requires the retention and recruitment of a skilled workforce, and difficulties recruiting and retaining our workforce could result in a failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible and have significant institutional knowledge that must be transferred to other employees. If we are unable to (i) retain current employees; (ii) successfully complete the knowledge transfer; and/or (iii) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.
If we are unable to retain our executive officers, our ability to execute our business strategy, including our growth strategy, may be hindered.
Our success depends in part on the performance of and our ability to retain our executive officers, particularly Richard D. Kinder, our Executive Chairman and one of our founders, Steve Kean, our Chief Executive Officer, and Kim Dang, our President. Along with the other members of our senior management, Messrs. Kinder and Kean and Ms. Dang have been responsible for developing and executing our growth strategy. If we are not successful in retaining Mr. Kinder, Mr. Kean, Ms. Dang or our other executive officers, or replacing them, our business, financial condition or results of operations could be adversely affected. We do not maintain key personnel insurance.
Risks Related to Financing Our Business
Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.
As of December 31, 2021, we had approximately $32.4 billion of consolidated debt (excluding debt fair value adjustments). Additionally, we and substantially all of our wholly owned U.S. subsidiaries are parties to a cross guarantee agreement under which each party to the agreement unconditionally guarantees the indebtedness of each other party, which means that we are liable for the debt of each of such subsidiaries. This level of consolidated debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth, or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.
Our ability to service our consolidated debt, and our ability to meet our consolidated leverage targets, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our consolidated cash flow is not sufficient to service our consolidated debt, and any future indebtedness that we incur, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may also take such actions to reduce our indebtedness if we determine that our earnings (or consolidated EBITDA, as calculated in accordance with our revolving credit facility) may not be sufficient to meet our consolidated leverage targets or to comply with consolidated leverage ratios required under certain of our debt agreements. We may not be able to effect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 9 “Debt” to our consolidated financial statements.
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Our business, financial condition and operating results may be affected adversely by increased costs of capital or a reduction in the availability of credit.
Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings (which would have a corresponding impact on the credit ratings of our subsidiaries that are party to the cross guarantee agreement) could cause our cost of doing business to increase by limiting our access to capital, including our ability to refinance maturities of existing indebtedness on similar terms, which could in turn reduce our cash flows and limit our ability to pursue acquisition or expansion opportunities. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions. Although the ratings from credit agencies are not recommendations to buy, sell or hold our securities, our credit ratings will generally affect the market value of our and our subsidiaries’ debt securities and the terms available to us for future issuances of debt securities.
Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect our business, financial condition and results of operations.
Our and our customers’ access to capital could be affected by evolving financial institutions’ policies concerning businesses linked to fossil fuels.
Our and our customers’ access to capital could be affected by financial institutions’ evolving policies concerning businesses linked to fossil fuels. Public opinion toward industries linked to fossil fuels continues to evolve. Concerns about the potential effects of climate change have caused some to direct their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in such companies. Ultimately, this could make it more difficult for our customers to secure funding for exploration and production activities or for us to secure funding for growth projects, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects.
Our large amount of variable rate debt makes us vulnerable to increases in interest rates.
As of January 4, 2022, approximately $2.1 billion of our approximately $32.4 billion of consolidated debt (excluding debt fair value adjustments) was subject to variable interest rates, either as short-term or long-term variable-rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. Variable-to-fixed interest rate swap agreements covering an additional $5.1 billion of our consolidated debt will expire at the end of 2022. Should interest rates increase, the amount of cash required to service variable-rate debt would increase, as would our costs to refinance maturities of existing indebtedness, and our earnings and cash flows could be adversely affected.
For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”
Acquisitions and growth capital expenditures may require access to external capital. Limitations on our access to external financing sources could impair our ability to grow.
We have limited amounts of internally generated cash flows to fund acquisitions and growth capital expenditures. If our internally generated cash flows are not sufficient to fund one or more capital projects or acquisitions, we may have to rely on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund our acquisitions and growth capital expenditures. Limitations on our access to external financing sources, whether due to tightened capital markets, more expensive capital or otherwise, could impair our ability to execute our growth strategy.
Our debt instruments may limit our financial flexibility and increase our financing costs.
The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that may be beneficial to us. Some of the agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more limiting restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.
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Risks Related to Regulation
The FERC or state public utility commissions, such as the CPUC, may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC, state public utility commissions or our customers could initiate proceedings or file complaints challenging the tariff rates charged by our pipelines, which could have an adverse impact on us.
The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC or state public utility commissions to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact on our operating results.
Our existing rates may also be challenged by complaint. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators that seek substantial refunds for alleged overcharges during the years in question and prospective reductions in the tariff rates. Further, the FERC may continue to initiate investigations to determine whether interstate natural gas pipelines have over-collected on rates charged to shippers. We may face challenges, similar to those described in Note 18 “Litigation and Environmental” to our consolidated financial statements, to the rates we charge on our pipelines. Any successful challenge to our rates could materially adversely affect our future earnings, cash flows and financial condition.
New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows and operations.
Our assets and operations are subject to regulation and oversight by federal, state and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these authorities, have the potential to adversely affect our profitability. Additional regulatory burdens and uncertainties will be created if and to the extent that more stringent energy and environmental policies are enacted. For example, on November 15, 2021, the EPA published a proposed rule containing standards of performance for GHG emissions, in the form of methane limitations, and volatile organic compound emissions for new, modified, and reconstructed crude oil and natural gas sources, including the production, processing, transmission and storage segments. This proposal, if finalized, and other regulatory initiatives may affect our assets and operations directly or indirectly, such as by increasing the costs associated with the production of natural gas and liquids that we transport. In addition, on January 27, 2021, the President issued an executive order directing, among other matters, the reevaluation of the leasing program for federally managed lands and the “pause” of new oil and natural gas leases on public lands pending completion of the review. In July 2021, a federal district court granted a nationwide preliminary injunction against enforcement of the “pause.” The Biden Administration has appealed the injunction. On November 26, 2021, the Department of the Interior issued a report in response to the President’s executive order calling for an increase in royalty payments for new oil and gas leases on federal lands. These and other initiatives of the presidential administration may affect our assets and operations directly or indirectly, such as by preventing or delaying the exploration for and production of natural gas and liquids that we transport.
Regulation affects almost every part of our business and extends to such matters as (i) federal, state and local taxation; (ii) rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the contracts for service entered into with our customers; (v) the certification and construction of new facilities; (vi) the integrity, safety and security of facilities and operations; (vii) the acquisition of other businesses; (viii) the acquisition, extension, disposition or abandonment of services or facilities; (ix) reporting and information posting requirements; (x) the maintenance of accounts and records; and (xi) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.
Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines and potential loss of government contracts. Furthermore, new laws or regulations or policy changes sometimes arise from unexpected sources. New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to our income, operations, assets or another aspect of our business could have a material adverse impact on our earnings, cash flow, financial condition and results of operations. For more information, see Items 1 and 2 “Business and Properties—Narrative Description of Business—Industry Regulation.”
Environmental, health and safety laws and regulations could expose us to significant costs and liabilities.
Our operations are subject to federal, state and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety. Such laws and regulations
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affect many aspects of our past, present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals. Liability under such laws and regulations may be incurred without regard to fault under CERCLA, the Resource Conservation and Recovery Act, the Federal Clean Water Act, the Oil Pollution Act or analogous state laws as a result of the presence or release of hydrocarbons and other hazardous substances into or through the environment, and these laws may require response actions and remediation and may impose liability for natural resource and other damages. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us.
Failure to comply with these laws and regulations including required permits and other approvals also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could harm our business, financial position, results of operations and prospects. For example, if a leak, release or spill of liquid petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, shipping vessels or storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our earnings and cash flows.
We own and/or operate numerous properties and equipment that have been used for many years in connection with our business activities. While we believe we have utilized operating, handling and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties and equipment owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws in the U.S. such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.
Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. For example, the Federal Clean Air Act and other similar federal and state laws are subject to periodic review and amendment, which could result in more stringent emission control requirements obligating us to make significant capital expenditures at our facilities. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Items 1 and 2“Business and Properties—Narrative Description of Business—Environmental Matters.”
Increased regulatory requirements relating to the integrity of our pipelines may require us to incur significant capital and operating expense outlays to comply.
We are subject to extensive laws and regulations related to pipeline safety and integrity at the federal and state levels. There are, for example, regulations issued by the U.S. Department of Transportation (U.S. DOT) for pipeline companies in the areas of operations, testing, education, training and communication. We expect the costs of compliance with these regulations, including integrity management rules, will be substantial. The majority of compliance costs relate to pipeline integrity testing and repairs. Technological advances in in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipeline determined to be located in HCAs or MCAs can have a significant impact on integrity testing and repair costs. We plan to continue our integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the U.S. DOT rules. Repairs or upgrades deemed necessary to address results of these tests and/or ensure the continued safe and reliable operation of our pipeline could cause us to incur significant and unanticipated capital and operating expenditures.
Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating
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restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.
Climate-related risk and related regulation could result in significantly increased operating and capital costs for us and could reduce demand for our products and services.
Various laws and regulations exist or are under development that seek to regulate the emission of GHGs such as methane and CO2, including the EPA programs to control GHG emissions and state actions to develop statewide or regional programs. Existing EPA regulations require us to report GHG emissions in the U.S. from sources such as our larger natural gas compressor stations, fractionated NGL, and production of naturally occurring CO2 (for example, from our McElmo Dome CO2 field), even when such production is not emitted to the atmosphere. Proposed approaches to further address GHG emissions include establishing GHG “cap and trade” programs, a fee on methane emissions from petroleum and natural gas systems, increased efficiency standards, participation in international climate agreements, issuance of executive orders by the U.S. presidential administration and incentives or mandates for pollution reduction, use of renewable energy sources, or use of alternative fuels with lower carbon content. For more information about climate change regulation, see Items 1 and 2 “Business and Properties—Narrative Description of Business—Environmental Matters—Climate Change.”
Adoption of any such laws or regulations could increase our costs to operate and maintain our facilities and could require us to install new emission controls on our facilities, acquire allowances for our GHG emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program, and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Such laws or regulations could also lead to reduced demand for hydrocarbon products that are deemed to contribute to GHGs, or restrictions on their use, which in turn could adversely affect demand for our products and services.
Finally, many climate models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could result in damage to our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions.
Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows.
Increased regulation of exploration and production activities, including activity on public lands and hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, as well as reductions in production from existing wells, which could adversely impact the volumes of natural gas transported on our natural gas pipelines and our own oil and gas development and production activities.
We gather, process or transport crude oil, natural gas or NGL from several areas, including lands that are federally managed. Policy and regulatory initiatives or legislation by Congress may decrease access to federally managed lands and increase the regulatory burdens associated with using these lands to produce crude oil or natural gas.
The use of hydraulic fracturing is prevalent in areas where we have operations. Oil and gas development and production activities are subject to numerous federal, state and local laws and regulations relating to environmental quality and pollution control. The oil and gas industry is increasingly relying on supplies of hydrocarbons from unconventional sources, such as shale, tight sands and coal bed methane. The extraction of hydrocarbons from these sources frequently requires hydraulic fracturing. Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by oil and gas exploration and production operators in the completion of certain oil and gas wells. There have been initiatives at the federal and state levels to regulate or otherwise restrict the use of certain hydraulic fracturing activities. Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of crude oil, natural gas or NGL and, in turn, adversely affect our revenues, cash flows and results of operations by decreasing the volumes of these commodities that we handle.
In addition, many states are promulgating stricter requirements related not only to well development but also to compressor stations and other facilities in the oil and gas industry sector. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, these activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities and location,
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emissions into the environment, water discharges, transportation of hazardous materials, and storage and disposition of wastes. In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. These laws and regulations may adversely affect our oil and gas development and production activities.
The Jones Act includes restrictions on ownership by non-U.S. citizens of our U.S. point to point maritime shipping vessels, and failure to comply with the Jones Act, or changes to or a repeal of the Jones Act, could limit our ability to operate our vessels in the U.S. coastwise trade, result in the forfeiture of our vessels or otherwise adversely impact our earnings, cash flows and operations.
We are subject to the Jones Act, which generally restricts U.S. point-to-point maritime shipping to vessels operating under the U.S. flag, built in the U.S., owned and operated by U.S.-organized companies that are controlled and at least 75% owned by U.S. citizens and crewed by predominately U.S. citizens. Our business would be adversely affected if we fail to comply with the Jones Act provisions on coastwise trade. If we do not comply with any of these requirements, we would be prohibited from operating our vessels in the U.S. coastwise trade and, under certain circumstances, we could be deemed to have undertaken an unapproved transfer to non-U.S. citizens that could result in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of vessels. Our business could be adversely affected if the Jones Act were to be modified or repealed so as to permit foreign competition that is not subject to the same U.S. government imposed burdens.
Proposed changes to U.S. federal, state, and local tax laws, if enacted, could have a material adverse effect on our business and profitability.
New or revised U.S. federal, state, or local tax legislation may be enacted in the future, and such legislation could materially impact our current or future tax planning and effective tax rates. For example, President Biden and Congress have set forth proposals that would, if enacted, make significant changes to U.S. federal income tax laws applicable to domestic corporations. Such proposals include, but are not limited to, (i) an increase in the U.S. federal income tax rate applicable to corporations and (ii) a minimum book income tax applicable to certain large corporations. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income or other tax laws could materially and adversely affect our business, cash flows, and future profitability.
Risks Related to Ownership of Our Capital Stock
The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.
We disclose in this report and elsewhere the expected cash dividends on our common stock. These reflect our current judgment, but as with any estimate, they may be affected by inaccurate assumptions and other risks and uncertainties, many of which are beyond our control. See “Information Regarding Forward-Looking Statements” at the beginning of this report. If our board of directors elects to pay dividends at the anticipated level and that action would leave us with insufficient cash to take timely advantage of growth opportunities (including through acquisitions), to meet any large unanticipated liquidity requirements, to fund our operations, to maintain our leverage metrics or otherwise to address properly our business prospects, our business could be harmed.
Conversely, a decision to address such needs might lead to the payment of dividends below the anticipated levels. As events present themselves or become reasonably foreseeable, our board of directors, which determines our business strategy and our dividends, may decide to address those matters by reducing our anticipated dividends. Alternatively, because nothing in our governing documents or credit agreements prohibits us from borrowing to pay dividends, we could choose to incur debt to enable us to pay our anticipated dividends. This would add to our substantial debt discussed above under “—Risks Related to Financing Our Business—Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.”
Our certificate of incorporation restricts the ownership of our common stock by non-U.S. citizens within the meaning of the Jones Act. These restrictions may affect the liquidity of our common stock and may result in non-U.S. citizens being required to sell their shares at a loss.
The Jones Act requires, among other things, that at least 75% of our common stock be owned at all times by U.S. citizens, as defined under the Jones Act, in order for us to own and operate vessels in the U.S. coastwise trade. As a safeguard to help us maintain our status as a U.S. citizen, our certificate of incorporation provides that, if the number of shares of our common stock owned by non-U.S. citizens exceeds 22%, we have the ability to redeem shares owned by non-U.S. citizens to reduce the
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percentage of shares owned by non-U.S. citizens to 22%. These redemption provisions may adversely impact the marketability of our common stock, particularly in markets outside of the U.S. Further, those stockholders would not have control over the timing of such redemption, and may be subject to redemption at a time when the market price or timing of the redemption is disadvantageous. In addition, the redemption provisions might have the effect of impeding or discouraging a merger, tender offer or proxy contest by a non-U.S. citizen, even if it were favorable to the interests of some or all of our stockholders.
Item 1B. Unresolved Staff Comments.
None.
Item 3. Legal Proceedings.
See Note 18 “Litigation and Environmental” to our consolidated financial statements.
Item 4. Mine Safety Disclosures.
We no longer 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. We have 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 year ended December 31, 2021.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
As of February 4, 2022, we had 10,236 holders of our Class P common stock, which does not include beneficial owners whose shares are held by a nominee, such as a broker or bank.
For information on our equity compensation plans, see Note 10 “Share-based Compensation and Employee Benefits—Share-based Compensation” to our consolidated financial statements.
Item 6. [Reserved]
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto. We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 “Business and Properties—Narrative Description of Business—Business Strategy;” (ii) a description of developments during 2021, found in Items 1 and 2 “Business and Properties—General Development of Business—Recent Developments;” (iii) a description of risk factors affecting us and our business, found in Item 1A“Risk Factors;” and (iv) a discussion of forward-looking statements, found in “Information Regarding Forward-Looking Statements” at the beginning of this report.
A comparative discussion of our 2020 to 2019 operating results can be found in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on February 5, 2021.
General
Business Segments
As an energy infrastructure owner and operator in multiple facets of the various U.S. energy industries and markets, we examine a number of variables and factors on a routine basis to evaluate our current performance and our prospects for the future. We have four business segments as further described below.
Natural Gas Pipelines
This segment owns and operates (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas gathering systems and processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG regasification, liquefaction and storage facilities.
With respect to our interstate natural gas pipelines, related storage facilities and LNG terminals, the revenues from these assets are primarily received under long-term fixed contracts. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. These long-term contracts are typically structured with a fixed fee reserving the right to transport or store natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity. Similarly, our Texas Intrastate natural gas pipeline operations, currently derives approximately 84% of its sales and transport margins from long-term transport and sales contracts. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, 2021, the remaining weighted average contract life of our natural gas transportation contracts held by assets we own and have equity interests in (including intrastate pipelines’ sales portfolio) was approximatelysix years. Our LNG regasification and liquefaction and associated storage contracts are subscribed under long-term agreements with a weighted average remaining contract life of approximately 12 years.
Our midstream assets provide natural gas gathering and processing services. These assets are mostly fee-based and the revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into its base components, are affected by the volumes of natural gas made available to our systems. Such volumes are impacted by producer rig count and drilling activity. In addition to fee-based arrangements, some of which may include minimum volume commitments, we also provide some services based on percent-of-proceeds, percent-
34
of-index and keep-whole contracts. Our service contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices.
Products Pipelines
This segment owns and operates refined petroleum products, crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, crude oil and condensate to various markets. This segment also owns and/or operates associated product terminals and petroleum pipeline transmix facilities.
The profitability of our refined petroleum products pipeline transportation business generally is driven by the volume of refined petroleum products that we transport and the prices we receive for our services. We also have 49 liquids terminals in this business segment that store fuels and offer blending services for ethanol and biodiesel. The transportation and storage volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored. Demand for refined petroleum products tends to track in large measure demographic and economic growth, and, with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable. Because of that, we seek to own refined petroleum products pipelines and terminals located in, or that transport to, stable or growing markets and population centers. The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index and a FERC index rate.
Our crude, condensate and refined petroleum products transportation services are primarily provided pursuant to (i) either FERC or state tariffs and (ii) long-term contracts that normally contain minimum volume commitments. As a result of these contracts, our settlement volumes are generally not sensitive to changing market conditions in the shorter term; however, the revenues and earnings we realize from our pipelines and terminals are affected by the volumes of crude oil, refined petroleum products and condensate available to our pipeline systems, which are impacted by the level of oil and gas drilling activity and product demand in the respective regions that we serve. Our petroleum condensate processing facility splits condensate into its various components, such as light and heavy naphtha, under a long-term fee-based agreement with a major integrated oil company.
Terminals
This segment owns and operates (i) liquids and bulk terminal facilities located throughout the U.S. that store and handle various commodities including gasoline, diesel fuel, chemicals, renewable fuels, metals and petroleum coke; and (ii) Jones Act-qualified tankers.
The factors impacting our Terminals business segment generally differ between liquid and bulk terminals, and in the case of a bulk terminal, the type of product being handled or stored. Our liquids terminals business generally has long-term contracts that require the customer to pay regardless of whether they use the capacity. Thus, similar to our natural gas pipelines business, our liquids terminals business is less sensitive to short-term changes in supply and demand. Therefore, the extent to which changes in these variables affect our terminals business in the near term is a function of the remaining length of the underlying service contracts(which on a weighted average basis is approximately three years), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time.
As with our refined petroleum products pipelines transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. While we handle and store a large variety of products in our bulk terminals, the primary products are petroleum coke, metals and ores. In addition, the majority of our contracts for this business contain minimum volume guarantees and/or service exclusivity arrangements under which customers are required to utilize our terminals for all or a specified percentage of their handling and storage needs. The profitability of our minimum volume contracts is generally unaffected by short-term variation in economic conditions; however, to the extent we expect volumes above the minimum and/or have contracts which are volume-based, we can be sensitive to changing market conditions. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. In addition, weather-related events, including hurricanes, may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.
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In addition to liquid and bulk terminals, we also own Jones Act-qualified tankers in our Terminals business segment. As of December 31, 2021, we have 16 Jones Act-qualified tankers that operate in the marine transportation of crude oil, condensate and refined products in the U.S. and are primarily operating pursuant to fixed price term charters with major integrated oil companies, major refiners and the U.S. Military Sealift Command.
CO2
This segment (i) manages the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium to increase recovery and production of crude oil from mature oil fields; (ii) owns interests in and/or operates oil fields and gasoline processing plants in West Texas; (iii) owns and operates a crude oil pipeline system in West Texas; and (iv) owns and operates RNG and LNG facilities in Indiana associated with our acquisition of Kinetrex discussed below.
The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2021, had a remaining average contract life of approximately eight years. CO2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed. Our current sales contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price. Beginning in 2022, due to the floor price associated with a significant sales contract no longer being a component of the pricing formula, only a small percentage of our sales contracts will be based on a fixed fee or floor price. Our success in this portion of the CO2 business segment can be impacted by the demand for CO2. In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. The revenues we receive from our crude oil and NGL sales are affected by the prices we realize from the sale of these products. Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil. The realized weighted average crude oil price per barrel, with the hedges allocated to oil, was $52.71 per barrel in 2021 and $53.78 per barrel in 2020. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $68.47 per barrel in 2021 and $38.32 per barrel in 2020.
Also, see Note 15 “Revenue Recognition” to our consolidated financial statements for more information about the types of contracts and revenues recognized for each of our segments.
Stagecoach Acquisition
On July 9, 2021 and November 24, 2021, we completed the acquisitions of Stagecoach Gas Services LLC and its subsidiaries (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,258 million, including purchase price adjustments 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. The acquired assets are included in our Natural Gas Pipelines business segment.
Kinetrex Acquisition
On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Kinetrex is a supplier of LNG in the Midwest and a producer and supplier of RNG under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets are included as part of our new Energy Transition Ventures group within our CO2 business segment.
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 $412 million for our proportionate share of the interests sold. 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 year ended December 31, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.
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February 2021 Winter Storm
Our earnings for 2021 reflect impacts of the February 2021 winter storm that affected Texas, which are largely nonrecurring. See “—Segment Earnings Results” below.
2022 Dividends and Discretionary Capital
We expect to declare dividends of $1.11 per share for 2022, a 3% increase from the 2021 declared dividends of $1.08 per share. We also expect to invest $1.3 billion in expansion projects and contributions to joint ventures, or discretionary capital expenditures during 2022.
The expectations for 2022 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. Please read our Item 1A “Risk Factors” below and “Information Regarding Forward-Looking Statements” at the beginning of this report for more information. Furthermore, we plan to provide updates to these 2022 expectations when we believe previously disclosed expectations no longer have a reasonable basis.
Critical Accounting Estimates
Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
Critical accounting estimates and assumptions involve material levels of subjectivity and complex judgement to account for highly uncertain matters or matters with a high susceptibility to change, and could result in a material impact to our financial statements. Examples of certain areas that require more judgment relative to others when preparing our consolidated financial statements and related disclosures include our use of estimates in determining: (i) revenue recognition; (ii) income taxes; (iii) the economic useful lives of our assets and related depletion rates; (iv) the fair values used in (a) assigning the purchase price of a business acquisition, (b) calculations of possible asset and equity investment impairment charges, (c) calculation for the annual goodwill impairment test (or interim tests if triggered), and (d) recording derivative contract assets and liabilities; (v) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (vi) provisions for credit losses; (vii) computation of the gain or loss, if any, on assets sold in whole or in part; and (viii) exposures under contractual indemnifications.
For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” to our consolidated financial statements and the following discussion for further information regarding critical estimates and assumptions used in the preparation of our financial statements.
Acquisition Method of Accounting
For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired is recorded to goodwill. Determining the fair value of these items requires management’s judgment and/or the utilization of independent valuation specialists and involves the use of significant estimates and assumptions. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements.
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Impairments
In addition to our annual testing of impairment for goodwill, we evaluate impairment of our long-lived assets when a triggering event occurs. Management applies judgment in determining whether there is an impairment indicator. Fair value calculated for the purpose of testing our long-lived assets, including intangible assets, goodwill and equity method investments for impairment involves the use of significant estimates and assumptions regarding the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The estimates and assumptions can be affected by a variety of factors, including external factors such as industry and economic trends, and internal factors such as changes in our business strategy and our internal forecasts. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates.
For more information on our impairments and significant estimates and assumptions used in our impairment evaluations, see Note 4 “Losses and Gains on Impairments, Divestitures and Other Write-downs.”
Hedging Activities
All of our derivative contracts are recorded at estimated fair value. We utilize published prices, broker quotes, and estimates of market prices to estimate the fair value of these contracts; however, actual amounts could vary materially from estimated fair values as a result of changes in market prices. In addition, changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. For more information on our hedging activities, see Note 14 “Risk Management” to our consolidated financial statements.
Environmental Matters
With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Our accrual of environmental liabilities often coincides either with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our probable environmental liabilities, if necessary or appropriate, following quarterly reviews of potential environmental issues and claims that could impact our assets or operations. In recording and adjusting environmental liabilities, we consider the effect of environmental compliance, pending legal actions against us, and potential third party liability claims. For more information on environmental matters, see Part I, Items 1 and 2 “Business and Properties—Narrative Description of Business—Environmental Matters.” For more information on our environmental disclosures, see Note 18 “Litigation and Environmental” to our consolidated financial statements.
Legal and Regulatory Matters
Many of our operations are regulated by various U.S. regulatory bodies, and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on legal proceedings, see Note 18 “Litigation and Environmental” to our consolidated financial statements.
Employee Benefit Plans
We reflect an asset or liability for our pension and other postretirement benefit (OPEB) plans based on their overfunded or underfunded status. As of December 31, 2021, our pension plans were underfunded by$427 million, and our OPEB plans were overfunded by $125 million. Our pension and OPEB obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We utilize a full yield curve approach to estimate the service and interest cost components of net periodic benefit cost (credit) for our pension and OPEB plans, which applies the specific spot rates along the yield curve used in determining the benefit obligation to the underlying projected cash flows. The selection of these assumptions is further discussed in Note 10 “Share-based Compensation and Employee Benefits” to our consolidated financial statements.
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Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and OPEB can be, and have been revised in subsequent periods. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants. As of December 31, 2021, we had deferred net losses of approximately $319 million in pre-tax accumulated other comprehensive loss related to our pension and OPEB plans.
The following sensitivity analysis shows the estimated impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and OPEB plans for the year ended December 31, 2021:
Pension Benefits
OPEB
Net benefit cost (income)
Change in funded status(a)
Net benefit cost (income)
Change in funded status(a)
(In millions)
One percent increase in:
Discount rates
$
(11)
$
223
$
1
$
18
Expected return on plan assets
(21)
—
(4)
—
Rate of compensation increase
3
(13)
—
—
One percent decrease in:
Discount rates
13
(266)
—
(20)
Expected return on plan assets
21
—
4
—
Rate of compensation increase
(3)
12
—
—
(a)Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.
Income Taxes
We make significant judgments and estimates in determining our provision for income taxes, including our assessment of our income tax positions given the uncertainties involved in the interpretation and application of complex tax laws and regulations in various taxing jurisdictions. Numerous and complex judgments and assumptions are inherent in the estimation of future taxable income when determining a valuation allowance, including factors such as future operating conditions and the apportionment of income by state. For more information, see Note 5 “Income Taxes” to our consolidated financial statements.
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 16, “Reportable Segments”) and Net 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 years ended December 31, 2021 and 2020 present Segment EBDA and Net 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.
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Non-GAAP Financial Measures
Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net 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 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 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 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 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 earnings per share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.
DCF
DCF is calculated by adjusting Net 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 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 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.
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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 income attributable to Kinder Morgan, Inc. In prior periods Net income was considered the comparable GAAP measure and has been updated to Net 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 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 December 31, 2021, by subtracting the following amounts from our debt balance of $33,320 million: (i) cash and cash equivalents of $1,140 million; (ii) debt fair value adjustments of $902 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $64 million for which we have entered into currency swaps. Net Debt is a non-GAAP financial measure that management believes 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.
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Consolidated Earnings Results (GAAP)
The following tables summarize the key components of our consolidated earnings results.
Year Ended December 31,
2021
2020
Earnings increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines
$
3,815
$
3,483
$
332
10
%
Products Pipelines
1,064
977
87
9
%
Terminals
908
1,045
(137)
(13)
%
CO2
760
(292)
1,052
360
%
Total segment EBDA
6,547
5,213
1,334
26
%
DD&A
(2,135)
(2,164)
29
1
%
Amortization of excess cost of equity investments
(78)
(140)
62
44
%
General and administrative and corporate charges
(623)
(653)
30
5
%
Interest, net
(1,492)
(1,595)
103
6
%
Income before income taxes
2,219
661
1,558
236
%
Income tax expense
(369)
(481)
112
23
%
Net income
1,850
180
1,670
928
%
Net income attributable to noncontrolling interests
(66)
(61)
(5)
(8)
%
Net income attributable to Kinder Morgan, Inc.
$
1,784
$
119
$
1,665
1399
%
(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.
Year Ended December 31, 2021 vs. 2020
Net income attributable to Kinder Morgan, Inc. increased $1,665 million in 2021 compared to 2020. The increase primarily resulted from (i) $1,092 million of earnings related to the February 2021 winter storm, and therefore largely nonrecurring, mostly impacting the higher earnings from our Natural Gas Pipelines and CO2 business segments; and (ii) a decrease of $342 million in impairments in 2021 as compared to 2020 primarily reflecting the $1,600 million pre-tax non-cash asset impairment loss related to South Texas gathering and processing assets within our Natural Gas Pipeline segment in 2021 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 were partially offset by associated tax benefits. The increase was also impacted by higher earnings from our Products Pipelines business segment, lower interest expense and amortization of excess cost of equity investments partially offset by lower earnings from our Terminals business segment.
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Certain Items Affecting Consolidated Earnings Results
Year Ended December 31,
2021
2020
GAAP
Certain Items
Adjusted
GAAP
Certain Items
Adjusted
Adjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines
$
3,815
$
1,648
$
5,463
$
3,483
$
983
$
4,466
$
997
Products Pipelines
1,064
53
1,117
977
50
1,027
90
Terminals
908
42
950
1,045
(55)
990
(40)
CO2
760
(6)
754
(292)
944
652
102
Total Segment EBDA(a)
6,547
1,737
8,284
5,213
1,922
7,135
1,149
DD&A and amortization of excess cost of equity investments
(2,213)
—
(2,213)
(2,304)
—
(2,304)
91
General and administrative and corporate charges(a)
(623)
—
(623)
(653)
92
(561)
(62)
Interest, net(a)
(1,492)
(26)
(1,518)
(1,595)
(15)
(1,610)
92
Income before income taxes
2,219
1,711
3,930
661
1,999
2,660
1,270
Income tax expense(b)
(369)
(491)
(860)
(481)
(107)
(588)
(272)
Net income
1,850
1,220
3,070
180
1,892
2,072
998
Net income attributable to noncontrolling interests(a)
(66)
—
(66)
(61)
—
(61)
(5)
Net income attributable to Kinder Morgan, Inc.
$
1,784
$
1,220
$
3,004
$
119
$
1,892
$
2,011
$
993
(a)For a more detailed discussion of these 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 $993 million from the prior year resulting from earnings increases of $1,046 million from our Natural Gas Pipelines business segment’s Midstream region and $67 million from our CO2 business segment’s oil and gas producing activities (both primarily related to the February 2021 winter storm, and therefore largely nonrecurring), higher earnings from our Products Pipelines business segment and lower amortization of excess cost of equity investments and interest expense partially offset by higher general and administrative and corporate charges expense and lower earnings from our Terminals business segment. See “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
43
Non-GAAP Financial Measures
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF
Year Ended December 31,
2021
2020
(In millions)
Net income attributable to Kinder Morgan Inc. (GAAP)
$
1,784
$
119
Total Certain Items
1,220
1,892
Adjusted Earnings(a)
3,004
2,011
DD&A and amortization of excess cost of equity investments for DCF(b)
2,481
2,671
Income tax expense for DCF(a)(b)
943
670
Cash taxes(b)
(69)
(68)
Sustaining capital expenditures(b)
(864)
(658)
Other items(c)
(35)
(29)
DCF
$
5,460
$
4,597
Adjusted Segment EBDA to Adjusted EBITDA to DCF
Year Ended December 31,
2021
2020
(In millions, except per share amounts)
Natural Gas Pipelines
$
5,463
$
4,466
Products Pipelines
1,117
1,027
Terminals
950
990
CO2
754
652
Adjusted Segment EBDA(a)
8,284
7,135
General and administrative and corporate charges(a)
(623)
(561)
Joint venture DD&A and income tax expense(a)(b)
351
449
Net income attributable to noncontrolling interests(a)
(66)
(61)
Adjusted EBITDA
7,946
6,962
Interest, net(a)
(1,518)
(1,610)
Cash taxes(b)
(69)
(68)
Sustaining capital expenditures(b)
(864)
(658)
Other items(c)
(35)
(29)
DCF
$
5,460
$
4,597
Adjusted Earnings per share
$
1.32
$
0.88
Weighted average shares outstanding for dividends(d)
2,278
2,276
DCF per share
$
2.40
$
2.02
Declared dividends per share
$
1.08
$
1.05
(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net 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 pension contributions and non-cash pension expense and non-cash compensation associated with our restricted stock program.
(d)Includes restricted stock awards that participate in dividends.
44
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA
Year Ended December 31,
2021
2020
(In millions)
Net income attributable to Kinder Morgan, Inc. (GAAP)(a)
$
1,784
$
119
Certain Items:
Fair value amortization
(19)
(21)
Legal, environmental and taxes other than income tax reserves
160
26
Change in fair value of derivative contracts(b)
19
(5)
Loss on impairments, divestitures and other write-downs, net(c)
1,535
327
Loss on impairments of goodwill(d)
—
1,600
Restricted stock accelerated vesting and severance
—
52
COVID-19 costs
—
15
Income tax Certain Items
(491)
(107)
Other
16
5
Total Certain Items(e)
1,220
1,892
DD&A and amortization of excess cost of equity investments
2,213
2,304
Income tax expense(f)
860
588
Joint venture DD&A and income tax expense(f)(g)
351
449
Interest, net(f)
1,518
1,610
Adjusted EBITDA
$
7,946
$
6,962
(a)In prior periods, Net income was considered the comparable GAAP measure and has been updated to Net 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)2021 amount includes (i) 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 lower expectations regarding the volumes and rates associated with re-contracting; (ii) a write-down of $117 million, reported within “Earnings from equity investments” on the accompanying consolidated statement of income, on a long-term subordinated note receivable from an equity investee, Ruby; and (iii) a pre-tax non-cash impairment of $20 million related to our Wilmington terminal resulting from certain commercial contract terminations and lower expectations regarding the volumes and rates associated with re-contracting, partially offset by a pre-tax gain of $206 million, reported within “Other, net” on the accompanying consolidated statement of income, associated with the sale of a partial interest in our equity investment in NGPL Holdings. 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 partially offset by a $55 million pre-tax gain on sale of terminal assets. Except as otherwise noted above, these amounts are reported within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of income.
(d)2020 amount includes non-cash impairments of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-Regulated and our CO2 reporting units, respectively.
(e)2021 and 2020 amounts include $124 million and $(4) million, respectively, reported within “Earnings from equity investments” on our accompanying consolidated statements of income.
(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 table included in “—Supplemental Information” below.
45
Supplemental Information
Year Ended December 31,
2021
2020
(In millions)
DD&A (GAAP)
$
2,135
$
2,164
Amortization of excess cost of equity investments (GAAP)
78
140
DD&A and amortization of excess cost of equity investments
2,213
2,304
Joint venture DD&A
268
367
DD&A and amortization of excess cost of equity investments for DCF
$
2,481
$
2,671
Income tax expense (GAAP)
$
369
$
481
Certain Items
491
107
Income tax expense(a)
860
588
Unconsolidated joint venture income tax expense(a)(b)
83
82
Income tax expense for DCF(a)
$
943
$
670
Additional joint venture information
Unconsolidated joint venture DD&A
$
312
$
407
Less: Consolidated joint venture partners’ DD&A
44
40
Joint venture DD&A
268
367
Unconsolidated joint venture income tax expense(a)(b)
83
82
Joint venture DD&A and income tax expense(a)
$
351
$
449
Unconsolidated joint venture cash taxes(b)
$
(60)
$
(62)
Unconsolidated joint venture sustaining capital expenditures
$
(116)
$
(120)
Less: Consolidated joint venture partners’ sustaining capital expenditures
(9)
(6)
Joint venture sustaining capital expenditures
$
(107)
$
(114)
(a)Amounts are adjusted for Certain Items.
(b)Amounts are associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments.
46
Segment Earnings Results
Natural Gas Pipelines
Year Ended December 31,
2021
2020
(In millions, except operating statistics)
Revenues
$
11,709
$
7,259
Operating expenses
(7,000)
(3,457)
Loss on impairments and divestitures, net
(1,599)
(1,010)
Other income
2
1
Earnings from equity investments
487
679
Other, net
216
11
Segment EBDA
3,815
3,483
Certain Items(a)
1,648
983
Adjusted Segment EBDA
$
5,463
$
4,466
Change from prior period
Increase/(Decrease)
Adjusted Segment EBDA
$
997
Volumetric data(b)
Transport volumes (BBtu/d)
38,577
38,330
Sales volumes (BBtu/d)
2,473
2,353
Gathering volumes (BBtu/d)
2,749
3,039
NGLs (MBbl/d)
29
27
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $1,648 million and $983 million for 2021 and 2020, respectively. 2021 amount includes a pre-tax non-cash asset impairment loss of $1,600 million resulting from lower expectations regarding the volumes and rates associated with re-contracting related to our South Texas gathering and processing assets, a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $99 million related to litigation reserves partially offset by a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings. 2020 amount includes a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit and a decrease in revenues of $15 million related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales partially offset by an increase in revenues of $19 million resulting from amortization of regulatory liabilities including amounts recognized through earnings from equity investments.
Other
(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented. Volumes for acquired pipelines are included for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.
Below are the changes in Adjusted Segment EBDA between 2021 and 2020:
Year Ended December 31, 2021 versus Year Ended December 31, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Midstream
$
1,046
93
%
East Region
24
1
%
West Region
(73)
(7)
%
Total Natural Gas Pipelines
$
997
22
%
47
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 years of 2021 and 2020:
•$1,046 million (93%) increase in Midstream was primarily due to (i) higher commodity prices driving higher sales margins resulting in increases of $882 million on our Texas intrastate natural gas pipeline operations and $90 million on our South Texas assets primarily as a result of the February 2021 winter storm; (ii) $62 million of higher equity earnings due to PHP being placed in service in January 2021; (iii) higher earnings on Kinder Morgan Altamont LLC primarily due to higher commodity prices and volumes; and (iv) higher volumes on our Hiland Midstream assets partially offset by the impacts of lower volumes on KinderHawk and certain purchase contract obligations 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;
•$24 million (1%) increase in the East Region was primarily due to (i) a $61 million increase resulting from our July 2021 acquisition of the Stagecoach assets; (ii) higher earnings from TGP primarily due to weather-driven increases in reservation and park and loan revenues; and (iii) increased earnings from ELC resulting from the liquefaction units of the Elba Liquefaction project being fully operational as of August 2020, partially offset by lower earnings on FEP driven by lower revenues resulting from contract expirations; and
•$73 million (7%) decrease in the West Region was primarily due to lower earnings from WIC and CIG driven by lower revenues due to contract expirations, lower earnings from EPNG driven by lower park and loan revenues and lower equity earnings from Ruby.
Products Pipelines
Year Ended December 31,
2021
2020
(In millions, except operating statistics)
Revenues
$
2,245
$
1,721
Operating expenses
(1,239)
(779)
Loss on impairments and divestitures, net
—
(21)
Earnings from equity investments
57
55
Other, net
1
1
Segment EBDA
1,064
977
Certain Items(a)
53
50
Adjusted Segment EBDA
$
1,117
$
1,027
Change from prior period
Increase/(Decrease)
Adjusted Segment EBDA
$
90
Volumetric data(b)
Gasoline(c)
987
897
Diesel fuel
390
375
Jet fuel
223
179
Total refined product volumes
1,600
1,451
Crude and condensate
498
552
Total delivery volumes (MBbl/d)
2,098
2,003
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $53 million and $50 million in the 2021 and 2020 periods, respectively. 2021 amount includes increases in expense of $30 million and $23 million related to a litigation reserve and an environmental reserve adjustment, respectively. 2020 amount includes a $46 million unfavorable rate case reserve adjustment and a $21 million non-cash loss on impairment of our Belton Terminal partially offset by 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.
48
Below are the changes in Adjusted Segment EBDA between 2021 and 2020:
Year Ended December 31, 2021 versus Year Ended December 31, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
West Coast Refined Products
$
59
13
%
Southeast Refined Products
38
17
%
Crude and Condensate
(7)
(2)
%
Total Products Pipelines
$
90
9
%
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 years of 2021 and 2020:
•$59 million (13%) increase in West Coast Refined Products was primarily due to increased revenues on Pacific operations (SFPP), and to a lesser extent, on Calnev and West Coast terminals driven by the continued recovery of volumes in 2021 compared to 2020 which was impacted by COVID-19, partially offset by higher operating expenses primarily as a result of higher integrity management spending;
•$38 million (17%) increase in Southeast Refined Products was primarily due to higher 2021 earnings at our Transmix processing operations primarily due to higher prices and first quarter 2020 unfavorable inventory adjustments, and increased revenues from our South East Terminals resulting from higher volumes driven by continued recovery of volumes from 2020; and
•$7 million (2%) decrease in Crude and Condensate was primarily due to decreased earnings from the Bakken Crude assets and KM Condensate Processing Facility (Splitter) partially offset by increased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC). The Bakken Crude assets’ decreased earnings was driven by lower volumes, contracts renewed at lower average rates, and contract expirations partially offset by lower field operating expenses. Splitter’s decreased earnings was primarily driven by higher field maintenance expenses. KMCC’s increased earnings was primarily due to higher deficiency revenues and lower field operating expenses partially offset by contract expirations. Bakken Crude assets’ and KMCC’s changes were also impacted by first quarter 2020 unfavorable inventory valuation adjustments. In addition, increased marketing activities within KMCC have resulted in increases in revenues with corresponding increases in cost of sales.
49
Terminals
Year Ended December 31,
2021
2020
(In millions, except operating statistics)
Revenues
$
1,715
$
1,722
Operating expenses
(793)
(762)
(Loss) gain on impairments and divestitures, net
(36)
49
Other income
4
1
Earnings from equity investments
15
22
Other, net
3
13
Segment EBDA
908
1,045
Certain Items(a)
42
(55)
Adjusted Segment EBDA
$
950
$
990
Change from prior period
Increase/(Decrease)
Adjusted Segment EBDA
$
(40)
Volumetric data(b)
Liquids leasable capacity (MMBbl)
79.9
79.7
Liquids utilization %(c)
93.0
%
95.3
%
Bulk transload tonnage (MMtons)
51.7
48.0
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $42 million and $(55) million for 2021 and 2020, respectively. 2021 amount primarily resulted from pre-tax non-cash impairment losses of $20 million related to our Wilmington terminal resulting from certain commercial contract terminations and lower expectations regarding the volumes and rates associated with re-contracting and $14 million related to the reclassification of an asset to held for sale. 2020 amount related to a gain on sale of our Staten Island terminal.
Other
(b)Volumes for assets sold are excluded for all periods presented.
(c)The ratio of our tankage capacity in service to tankage capacity available for service.
Below are the changes in Adjusted Segment EBDA between 2021 and 2020:
Year Ended December 31, 2021 versus Year Ended December 31, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Marine operations
$
(50)
(25)
%
Northeast
10
10
%
Mid Atlantic
8
14
%
All others (including intrasegment eliminations)
(8)
(1)
%
Total Terminals
$
(40)
(4)
%
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 years of 2021 and 2020:
•$50 million (25%) decrease in Marine operations was primarily due to lower fleet utilization and average charter rates;
•$10 million (10%) increase in the Northeast terminals was primarily driven by increased revenues associated with higher throughput levels and associated ancillary fees; and
•$8 million (14%) increase in the Mid Atlantic terminals was primarily due to higher coal volumes at our Pier IX facility.
50
CO2
Year Ended December 31,
2021
2020
(In millions, except operating statistics)
Revenues
$
1,009
$
1,038
Operating expenses
(289)
(404)
Gain (loss) on impairments and divestitures, net
8
(950)
Earnings from equity investments
32
24
Segment EBDA
760
(292)
Certain Items(a)
(6)
944
Adjusted Segment EBDA
$
754
$
652
Change from prior period
Increase/(Decrease)
Adjusted Segment EBDA
$
102
Volumetric data
SACROC oil production
19.9
21.8
Yates oil production
6.6
6.6
Katz and Goldsmith oil production
2.2
2.8
Tall Cotton oil production
1.0
1.7
Total oil production, net (MBbl/d)(b)
29.7
32.9
NGL sales volumes, net (MBbl/d)(b)
9.4
9.5
CO2 sales volumes, net (Bcf/d)
0.4
0.4
Realized weighted average oil price ($ per Bbl)
$
52.71
$
53.78
Realized weighted average NGL price ($ per Bbl)
$
25.39
$
17.95
Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $(6) million and $944 million for 2021 and 2020, respectively. 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.
Below are the changes in Adjusted Segment EBDA between 2021 and 2020:
Year Ended December 31, 2021 versus Year Ended December 31, 2020
Adjusted Segment EBDA increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities
$
67
15
%
Source and Transportation activities
27
13
%
Subtotal
94
14
%
Energy Transition Ventures
8
n/a
Total CO2
$
102
16
%
n/a - not applicable
51
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 years of 2021 and 2020:
•$67 million (15%) increase in Oil and Gas Producing activities was primarily due to lower operating expenses of $143 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 and higher realized NGL prices which increased revenues by $42 million, partially offset by decreased revenues of (i) $50 million resulting from lower crude oil volumes, driven in part, by the curtailed oil production and (ii) $27 million related to lower realized crude oil prices, and increased operating expenses due to the impact of a settlement of $38 million for a terminated affiliate purchase contract with Source and Transportation activities; and
•$27 million (13%) increase in Source and Transportation activities primarily due to a settlement of $38 million for a terminated affiliate sales contract with Oil and Gas Producing activities which resulted in an increase in revenues partially offset by a decrease in revenues of $17 million related to lower CO2 sales volumes.
We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of December 31, 2021.
2022
2023
2024
2025
Crude Oil(a)
Price ($ per Bbl)
$
57.92
$
55.57
$
54.92
$
55.28
Volume (MBbl/d)
21.80
15.00
8.90
4.65
NGLs
Price ($ per Bbl)
$
48.43
Volume (MBbl/d)
2.94
Midland-to-Cushing Basis Spread
Price ($ per Bbl)
$
0.52
Volume (MBbl/d)
21.50
(a)Includes West Texas Intermediate hedges.
DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests
Year Ended December 31,
2021
2020
(In millions)
DD&A (GAAP)
$
(2,135)
$
(2,164)
General and administrative (GAAP)
$
(655)
$
(648)
Corporate benefit (charges)
32
(5)
Certain Items(a)
—
92
General and administrative and corporate charges(b)
$
(623)
$
(561)
Interest, net (GAAP)
$
(1,492)
$
(1,595)
Certain Items(c)
(26)
(15)
Interest, net(b)
$
(1,518)
$
(1,610)
Net income attributable to noncontrolling interests (GAAP)
$
(66)
$
(61)
Certain Items
—
—
Net income attributable to noncontrolling interests(b)
$
(66)
$
(61)
Certain Items
(a)2020 amount includes $52 million for restricted stock accelerated vesting and severance expense, an increase in expense of $23 million associated with a non-cash fair value adjustment and the dividend on the Pembina common stock and $15 million related to costs incurred associated with COVID-19 mitigation.
52
(b)Amounts are adjusted for Certain Items.
(c)2021 and 2020 amounts include decreases in interest expense of $19 million and $21 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and a decrease of $15 million and an increase of $8 million in interest expense, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt.
General and administrative expenses and corporate charges adjusted for Certain Items increased $62 million in 2021 when compared to 2020 primarily due to lower capitalized costs of $48 million reflecting reduced capital spending primarily by our Natural Gas Pipelines business segment, higher benefit-related costs of $34 million and non-recurring cost savings realized in the 2020 period as a result of the global pandemic of $33 million, partially offset by $41 million of cost savings in the 2021 period associated with organizational efficiency efforts, and lower pension costs of $17 million.
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 decreased $92 million in 2021 when compared to 2020 primarily due to lower long-term debt balances, lower LIBOR rates, and lower 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 December 31, 2021 and 2020, approximately 21% 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. The percentage at December 31, 2021 excludes $4,860 million of variable-to-fixed interest rate derivative contracts which became effective January 4, 2022 and hedge our exposure through 2022. For more information on our interest rate swaps, see Note 14 “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.
Income Taxes
Year Ended December 31, 2021 versus Year Ended December 31, 2020
Our income tax expense for the year ended December 31, 2021 is approximately $369 million, as compared with income tax expense of $481 million for the same period of 2020. The $112 million decrease in income tax expense is due primarily to (i) the lack of tax benefit on the impairment of non-tax-deductible goodwill in 2020; (ii) higher dividend-received deductions in 2021; (iii) the 2021 Enhanced Oil Recovery Credit; and (iv) the release in 2021 of a valuation allowance related to our investment in NGPL. These decreases are partially offset by (i) higher pretax book income in 2021 as a result of the February 2021 winter storm, the 2020 impairment of certain CO2 assets and the 2020 demand destruction from the COVID-19 pandemic; and (ii) the refund of alternative minimum tax sequestration credits in 2020.
Liquidity and Capital Resources
General
As of December 31, 2021, we had $1,140 million of “Cash and cash equivalents,” a decrease of $44 million from December 31, 2020. Additionally, as of December 31, 2021, we had borrowing capacity of approximately $3.9 billion under our credit facilities (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 facilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.
We have consistently generated substantial cash flow from operations, providing a source of funds of $5,708 million and $4,550 million in 2021 and 2020, respectively. The year-to-year 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; 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 fourth quarter of 2021, consistent with previous quarters in 2021. The total of the dividends declared for 2021 of $1.08 represents a 3% increase over total dividends
53
declared for 2020. We expect to fully fund our dividend payments as well as our discretionary spending for 2022 without funding from the capital markets with additional flexibility to engage in share repurchases on an opportunistic basis.
On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 and amended our existing facility (the “Existing Facility”) to reduce the borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder (together, the “Credit Facilities”).
Short-term Liquidity
As of December 31, 2021, our principal sources of short-term liquidity are (i) cash from operations; (ii) our combined $4.0 billion of Credit Facilities and associated commercial paper program; and (iii) cash and cash equivalents. The loan commitments under our revolving Credit Facilities can be used for working capital and other general corporate purposes, and as a backup to our commercial paper program. Commercial paper borrowings reduce borrowings allowed under our Credit Facilities and letters of credit reduce borrowings allowed under our New Credit Facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our Credit Facilities and have consistently generated strong cash flows from operations.
As of December 31, 2021, our $2,646 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 $1,992 million and $1,871 million as of December 31, 2021 and 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 $121 million unfavorable change from year-end 2020 was primarily due to: (i) a $104 million increase in accounts payable, net of change in accounts receivable; (ii) an increase of approximately $88 million in senior notes that mature in the next twelve months; and (iii) a net unfavorable short-term fair value adjustment of $80 million on derivative contract assets and liabilities in 2021, offset partially by a $214 million increase in inventories, primarily storage gas and product inventories, and a decrease of $23 million in accrued contingencies. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities (discussed below in “—Long-term Financing” and “—Capital Expenditures”).
We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of our wholly owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of our wholly owned subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the consolidated group. We place no material restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to KMI other than restrictions that may be contained in agreements governing the indebtedness of those entities.
Credit Ratings and Capital Market Liquidity
We believe that our capital structure will continue to allow us to achieve our business objectives. We expect that our short-term liquidity needs will be met primarily through retained cash from operations or short-term borrowings. Generally, we anticipate re-financing maturing long-term debt obligations in the debt capital markets and are therefore subject to certain market conditions which could result in higher costs or negatively affect our and/or our subsidiaries’ credit ratings. A decrease in our credit ratings could negatively impact our borrowing costs and could limit our access to capital.
As of December 31, 2021, our short-term corporate debt ratings were A-2, Prime-2 and F2 at Standard and Poor’s, Moody’s Investor Services and Fitch Ratings, Inc., respectively.
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The following table represents KMI’s and KMP’s senior unsecured debt ratings as of December 31, 2021.
Rating agency
Senior debt rating
Outlook
Standard and Poor’s
BBB
Stable
Moody’s Investor Services
Baa2
Stable
Fitch Ratings, Inc.
BBB
Stable
Long-term Financing
Our equity consists of Class P common stock with a par value of $0.01 per share. We do not expect to need to access the equity capital markets to fund our discretionary capital investments for the foreseeable future. See also “—Dividends and Stock Buy-back Program” below for additional discussion related to our dividends and stock buy-back program.
From time to time, we issue long-term debt securities, often referred to as senior notes. All of our senior notes issued to date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium. In addition, from time to time, our subsidiaries issue long-term debt securities. Furthermore, we and almost all of our direct and indirect wholly owned domestic subsidiaries are parties to a cross guaranty wherein we each guarantee each other’s debt. See “—Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries. As of December 31, 2021 and 2020, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $29,772 million and $30,838 million, respectively.
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.
On October 26, 2021, we issued in a registered offering two series of senior notes consisting of $500 million aggregate principal amount of 1.75% senior notes due 2026 and $300 million aggregate principal amount of 3.60% senior notes due 2051, as a reopening of the 3.60% series discussed above, and received combined net proceeds of $796 million.
On January 18, 2022, we repaid $260 million of maturing 8.625% notes.
We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping a portion of the fixed rate interest payments for variable rate interest payments and through the issuance of commercial paper or credit facility borrowings.
For additional information about our outstanding senior notes and debt-related transactions in 2021, see Note 9 “Debt” to our consolidated financial statements. For information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”
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. The balance of our allowance for credit losses as of December 31, 2021 and 2020, was $1 million and $26 million, respectively, reflected in “Other current assets” on our consolidated balance sheets, which includes reserves for counterparty bankruptcies recorded during the year ended December 31, 2020.
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
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discretionary capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement and are not deducted in calculating DCF (see “—Results of Operations—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to 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 which maintain throughput or capacity. The distinction between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.
Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital expenditure is classified as maintenance/sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are.
Our capital expenditures for the year ended December 31, 2021, and the amount we expect to spend for 2022 to sustain our assets and grow our business are as follows:
2021
Expected 2022
(In millions)
Sustaining capital expenditures(a)(b)
$
864
$
865
Discretionary capital investments(b)(c)(d)
2,278
1,319
(a)2021 and Expected 2022 amounts include $107 million and $120 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.”
(b)2021 combined sustaining and discretionary amounts include $78 million due to increases in accrued capital expenditures and contractor retainage and net changes in other.
(c)2021 amount includes $138 million of our contributions to certain unconsolidated joint ventures for capital investments and $1,538 million for our acquisitions of Stagecoach and Kinetrex.
(d)Amounts include our actual or estimated contributions to certain unconsolidated joint ventures, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.
Off Balance Sheet Arrangements
We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 13 “Commitments and Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 7 “Investments” to our consolidated financial statements.
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Contractual Obligations and Commercial Commitments
The table below provides a summary of our material cash requirements.
Payments due by period
Total
Less than 1 year
1-3 years
3-5 years
More than 5 years
(In millions)
Contractual obligations:
Debt borrowings-principal payments(a)
$
32,418
$
2,646
$
5,175
$
2,669
$
21,928
Interest payments(b)
21,171
1,646
2,932
2,601
13,992
Lease obligations(c)
411
57
94
67
193
Pension and OPEB plans(d)
604
57
33
30
484
Transportation, volume and storage agreements(e)
629
162
238
152
77
Other obligations(f)
392
86
122
61
123
Total
$
55,625
$
4,654
$
8,594
$
5,580
$
36,797
Other commercial commitments:
Standby letters of credit(g)
$
150
$
77
$
73
$
—
$
—
Capital expenditures(h)
$
209
$
209
$
—
$
—
$
—
(a)See Note 9 “Debt” to our consolidated financial statements.
(b)Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect at December 31, 2021.
(c)Represents commitments pursuant to the terms of operating lease agreements as of December 31, 2021.
(d)Represents the amount by which the benefit obligations exceeded the fair value of plan assets at year-end for pension and OPEB plans whose accumulated postretirement benefit obligations exceeded the fair value of plan assets. The payments by period include expected contributions in 2022 and estimated benefit payments for underfunded plans in the other years.
(e)Primarily represents transportation agreements of $289 million, NGL volume agreements of $203 million and storage agreements for capacity of $99 million.
(f)Primarily includes (i) rights-of-way obligations; and (ii) environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we willperform remediation activities. These environmental liabilities are included within “Other current liabilities” and “Other long-term liabilities and deferred credits” in our consolidated balance sheet as of December 31, 2021.
(g)The $150 million in letters of credit outstanding as of December 31, 2021 consisted of the following (i) $50 million under six letters of credit for insurance purposes; (ii) a $46 million letter of credit supporting our International Marine Terminals Partnership Plaquemines Bond; (iii) a $24 million letter of credit supporting our Kinder Morgan Operating LLC “B” tax-exempt bonds; and (iv) a combined $30 million in thirty letters of credit supporting environmental and other obligations of us and our subsidiaries.
(h)Represents commitments for the purchase of plant, property and equipment as of December 31, 2021.
Cash Flows
Operating Activities
Cash provided by operating activities increased $1,158 million in 2021 compared to 2020 primarily due to:
•a $1,264 million increase in cash largely related to the February 2021 winter storm. This change in cash is after adjusting the $1,670 million increase in net income by $406 million for the combined effects of the period-to-period net changes in non-cash items including the following: (i) losses 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 “—General”); (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 $106 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 payments for litigation matters in the 2021 period compared with the 2020 period.
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Investing Activities
Cash used in investing activities increased $1,394 million in 2021 compared to 2020 primarily due to:
•a $1,531 million increase in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,227 million and $311 million of net cash used for the Stagecoach and the Kinetrex acquisitions, respectively, in the 2021 period. See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information regarding these two acquisitions; and
•a $663 million decrease in cash received from the sales of property, plant and equipment, investments, and other net assets, net of removal costs, primarily due to, among other things, the $412 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 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information regarding these two transactions; partially offset by,
•a $426 million decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and
•a $348 million decrease in cash used for contributions to equity investees driven primarily by lower contributions to PHP and SNG in the 2021 period compared with the 2020 period.
Financing Activities
Cash used in financing activities increased $827 million in 2021 compared to 2020 primarily due to:
•a $766 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. See Note 9 “Debt” to our consolidated financial statements for further information regarding our debt activity; and
•an $81 million increase in dividend payments to our shareholders.
Dividends and Stock Buy-back Program
The table below reflects the declaration of dividends of $1.08 per share for 2021:
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
September 30, 2021
0.27
October 20, 2021
November 1, 2021
November 15, 2021
December 31, 2021
0.27
January 19, 2022
January 31, 2022
February 15, 2022
We expect to continue to return additional value to our shareholders in 2022 through our previously announced dividend increase. We plan to increase our dividend by 3% to $1.11 per common share in 2022. Based on our 2022 expectations, we also expect to have up to $750 million available to invest in attractive opportunities, including share repurchases. Any potential repurchases in 2022 would be under our $2 billion stock buy-back program approved by our board of directors in July 2017. Since December 2017, in total, we have repurchased approximately 32 million shares of our Class P common stock under the program at an average price of approximately $17.71 per share for approximately $575 million. For information on our equity buy-back program and our equity distribution agreement, see Note 11 “Stockholders’ Equity” to our consolidated financial statements.
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.” 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 will 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 (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 the Obligated Group, 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 10.12 to this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among KMI and certain of its subsidiaries, with schedules updated as of December 31, 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 December 31, 2021 and 2020, the Obligated Group had $31,608 million and $32,563 million, respectively, of Guaranteed Notes outstanding.
Summarized combined balance sheet and income statement information for the Obligated Group follows:
December 31,
Summarized Combined Balance Sheet Information
2021
2020
(In millions)
Current assets
$
3,556
$
2,957
Current assets - affiliates
1,233
1,151
Noncurrent assets
61,754
61,783
Noncurrent assets - affiliates
508
616
Total Assets
$
67,051
$
66,507
Current liabilities
$
5,413
$
4,528
Current liabilities - affiliates
1,332
1,209
Noncurrent liabilities
32,310
33,907
Noncurrent liabilities - affiliates
1,047
1,078
Total Liabilities
40,102
40,722
Redeemable noncontrolling interest
—
728
Kinder Morgan, Inc.’s stockholders’ equity
26,949
25,057
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity
$
67,051
$
66,507
Summarized Combined Income Statement Information
Year Ended December 31, 2021
(In millions)
Revenues
$
15,307
Operating income
2,541
Net income
1,489
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Recent Accounting Pronouncements
Please refer to Note 19 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.” Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in energy commodity prices or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in energy commodity prices or interest rates and the timing of transactions.
Energy Commodity Market Risk
We are exposed to energy commodity market risk and other external risks in the ordinary course of business. However, we manage these risks by executing a hedging strategy that seeks to protect us financially against adverse price movements and serves to minimize potential losses. Our strategy involves the use of certain energy commodity derivative contracts to reduce and minimize the risks associated with unfavorable changes in the market price of crude oil, natural gas and NGL. The derivative contracts that we use include exchange-traded and OTC commodity financial instruments, including, but not limited to, futures and options contracts, fixed price swaps and basis swaps. We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but which value is uncertain.
Our hedging strategy involves entering into a financial position intended to offset our physical position, or anticipated position, in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil, natural gas and NGL, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby in whole or in part offsetting any change in prices, either positive or negative. Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows which helps us to undertake further capital improvement projects, attain budget results and meet dividend targets.
Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While it is our policy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.
The credit ratings of the primary parties from whom we transact in energy commodity derivative contracts (based on contract market values) are as follows (credit ratings per Standard & Poor’s Rating Service):
Credit Rating
ING
A+
Macquarie
A+
JP Morgan
A+
Bank of Nova Scotia
A+
Bank of America
A-
We measure the risk of price changes in the derivative instrument portfolios utilizing a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. Because we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities, both in the sensitivity analysis model and in reality, the change in the market value of the derivative contracts’ portfolio is offset largely by changes in the value of the underlying
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physical transactions. A hypothetical 10% movement in the underlying commodity prices would have the following effect on the associated derivative contracts’ estimated fair value:
As of December 31,
Commodity derivative
2021
2020
(In millions)
Crude oil
$
135
$
81
Natural gas
36
12
NGL
8
7
Total
$
179
$
100
Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the crude oil, natural gas and NGL portfolios of derivative contracts assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.
Interest Rate Risk
In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.
For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Generally, there is not an obligation to prepay fixed rate debt prior to maturity and, as a result, changes in fair value should not have a significant impact on the fixed rate debt. We are generally subject to interest rate risk upon refinancing maturing debt. Below are our debt balances, including debt fair value adjustments, and sensitivity to interest rates:
December 31, 2021
December 31, 2020
Carrying value
Estimated fair value(a)
Carrying value
Estimated fair value(a)
(In millions)
Fixed rate debt(b)
$
33,006
$
37,459
$
34,376
$
39,306
Variable rate debt
$
314
$
316
$
313
$
316
Notional principal amount of variable-to-fixed interest rate swap agreements(c)
(490)
(2,750)
Notional principal amount of fixed-to-variable interest rate swap agreements(d)
7,100
7,625
Debt balances subject to variable interest rates(e)
$
6,924
$
5,188
(a)Fair values were determined using Level 2 inputs.
(b)A hypothetical 10% change in the average interest rates applicable to such debt as of December 31, 2021 and 2020, would result in changes of approximately $749 million and $1,541 million, respectively, in the estimated fair values of these instruments.
(c)December 31, 2021 amount excludes $4.9 billion of variable-to-fixed interest rate swap agreements that became effective January 4, 2022 and expire December 31, 2022. December 31, 2020 amount includes $2.5 billion of variable-to-fixed interest rate swap agreements that expired during 2021.
(d)December 31, 2020 amount includes $900 million of fixed-to-variable interest rate swap agreements that expired during 2021.
(e)A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 47 and 49 basis points, respectively, in 2021 and 2020) when applied to our outstanding balance of variable rate debt as of December 31, 2021 and 2020, including adjustments for the notional swap amounts described in the table above, would result in changes of approximately $32 million (or $10 million with the inclusion of the variable-to-fixed interest rate swap agreements described in note (c) above) and $25 million, respectively, in our 2021 and 2020 annual income before income taxes.
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Fixed-to-variable interest rate swap agreements are entered into for the purpose of converting a portion of the underlying cash flows related to long-term fixed rate debt securities into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. Since the fair value of fixed rate debt varies with changes in the market rate of interest, swap agreements are entered into to receive a fixed and pay a variable rate of interest. Such swap agreements result in future cash flows that vary with the market rate of interest, and therefore hedge against changes in the fair value of the fixed rate debt due to market rate changes.
As presented in the table above, we monitor the mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time, may alter that mix by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements. As of December 31, 2021, including debt converted to variable rates through the use of interest rate swaps but excluding our debt fair value adjustments, approximately 21% of our debt balances were subject to variable interest rates. The percentage at December 31, 2021 excludes $4,860 million of variable-to-fixed interest rate derivative contracts which became effective January 4, 2022 and hedge our exposure through 2022.
For more information on our interest rate risk management and on our interest rate swap agreements, see Note 14 “Risk Management” to our consolidated financial statements.
LIBOR Phase Out
Amounts drawn under our revolving credit facility may bear interest rates in relation to U.S. Dollar LIBOR (USD LIBOR), depending on our selection of repayment options, and certain of our outstanding interest rate swap agreements have a floating interest rate in relation to one-month LIBOR or three-month LIBOR. In July 2017, the Financial Conduct Authority in the U.K. announced a desire to phase out LIBOR as a benchmark by the end of 2021. The Alternative Reference Rates Committee, a steering committee consisting of large U.S. financial institutions convened by the U.S. Federal Reserve Board and the Federal Reserve Bank of New York, has recommended replacing LIBOR with the Secured Overnight Financing Rate (SOFR), an index supported by short-term Treasury repurchase agreements. On November 30, 2020, ICE Benchmark Administration (IBA), the administrator of USD LIBOR announced that it does not intend to cease publication of the remaining USD LIBOR tenors until June 30, 2023, providing additional time for existing contracts that are dependent on LIBOR to mature.
The agreements governing our Credit Facilities include customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available. The International Swaps and Derivatives Association has developed provisions for SOFR-based fall-back rates to apply upon permanent cessation of LIBOR and has published a protocol to enable market participants to include the new provisions in existing swap agreements. See also Note 19 “Recent Accounting Pronouncements” to our consolidated financial statements for accounting pronouncements related to the LIBOR phase out.
We currently do not expect the transition from LIBOR to have a material impact on us.
Foreign Currency Risk
As of December 31, 2021, we had a notional principal amount of $1,358 million of cross-currency swap agreements that effectively convert all of our fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates. These swaps eliminate the foreign currency risk associated with our foreign currency denominated debt.
Item 8. Financial Statements and Supplementary Data.
The information required in this Item 8 is in this report as set forth in the “Index to Financial Statements” on page 69.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
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Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 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 or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an assessment of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that our internal control over financial reporting was effective as of December 31, 2021.
The effectiveness of our internal control over financial reporting as of December 31, 2021, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report, which appears herein.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth quarter of 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
Not Applicable.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.
Item 11. Executive Compensation.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.
63
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.
Item 14. Principal Accounting Fees and Services.
The information required by this item is incorporated by reference from KMI’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which shall be filed no later than April 30, 2022.
64
PART IV
Item 15. Exhibits, Financial Statement Schedules.
(a)(1) Financial Statements and (2) Financial Statement Schedules
See “Index to Financial Statements” set forth on Page69.
Certain instruments with respect to long-term debt of KMI and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of KMI and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec. #229.601. KMI hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request.
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Income for the years ended December 31, 2021, 2020, and 2019; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2021, 2020, and 2019; (iii) our Consolidated Balance Sheets as of December 31, 2021 and 2020; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020, and 2019; (v) our Consolidated Statements of Stockholders’ Equity as of and for the years ended December 31, 2021, 2020, and 2019; and (vi) the notes to our Consolidated Financial Statements.
104
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.
_______
*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Stockholders of Kinder Morgan, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Kinder Morgan, Inc. and its subsidiaries (the “Company”) as of December 31, 2021 and 2020,and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of itsoperations and itscash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework(2013)issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
70
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Impairment of the South Texas Gathering and Processing Long-lived Assets
As described in Notes 2 and 4 to the consolidated financial statements, during the second quarter of 2021, the Company recognized a non-cash, long-lived asset impairment of $1,600 million related to the Company’s South Texas gathering and processing long-lived assets. Management evaluates long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To determine if a long-lived asset is recoverable, management compares the asset’s estimated undiscounted future cash flows to its carrying value. To compute the estimated undiscounted future cash flows, management used the forecast of expected revenues, adjusted for upcoming contract expirations. If the carrying value of a long-lived asset is in excess of estimated undiscounted future cash flows, management typically uses discounted cash flow analyses to calculate the fair value of the long-lived asset to determine the impairment required. The significant assumptions made in calculating the fair value include estimates of future cash flows and discount rates.
The principal considerations for our determination that performing procedures relating to the impairment of the South Texas gathering and processing long-lived assets is a critical audit matter are (i) the significant judgment by management when determining the fair value of the South Texas gathering and processing long-lived assets; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, analyses, and the significant assumptions related to future cash flows and discount rates used by management in determining the fair value of the South Texas gathering and processing long-lived assets; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s impairment assessment of the South Texas gathering and processing long-lived assets, including controls over the determination of the fair value of the long-lived assets. These procedures also included, among others (i) testing management’s process for determining the fair value of the South Texas gathering and processing long-lived assets; (ii) evaluating the appropriateness of the discounted cash flow analyses; (iii) testing the completeness and accuracy of the underlying data used by management in the discounted cash flow analyses; and (iv) evaluating the reasonableness of significant assumptions used by management related to future cash flows and discount rates. Evaluating management’s significant assumptions related to future cash flows involved evaluating whether the assumptions used were reasonable considering the current and past performance of the South Texas gathering and processing long-lived assets. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of the discount rate significant assumption.
Acquisitions of Stagecoach Gas Services LLC and its Subsidiaries - Fair Value of Assets Acquired
As described in Note 3 to the consolidated financial statements, the Company completed the acquisitions of Stagecoach Gas Services LLC and its subsidiaries (Stagecoach) in 2021 for approximately $1,258 million. These acquisitions resulted in the recognition of $1,187 million of property, plant and equipment. For acquired businesses, the Company recognizes the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Management determined the fair value utilizing valuation methodologies including discounted cash flows and the cost approach. Determining the fair value of these items requires management judgment and the utilization of an independent valuation specialist and involves the use of significant estimates and assumptions. The significant assumptions made in performing these valuations include the discount rate, future revenues and replacement costs.
The principal considerations for our determination that performing procedures relating to the fair value of assets acquired in the Stagecoach acquisitions is a critical audit matter are (i) the significant judgment by management, including the use of an independent valuation specialist, when determining the fair value of the assets acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, analyses, and the significant assumptions related to the discount rate, future revenues, and replacement costs used by management and its independent valuation specialist in determining the fair value of the assets acquired; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
71
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s determination of the fair value of the assets acquired. These procedures also included, among others (i) reading the purchase agreement; (ii) testing management’s process for determining the fair value of the assets acquired; (iii) evaluating the appropriateness of the discounted cash flow analyses and the cost approach; (iv) testing the completeness and accuracy of the underlying data used by management and its independent valuation specialist in the discounted cash flow analyses and the cost approach; (v) assessing the qualifications of the independent valuation specialist used by management and understanding the Company’s relationship with its independent valuation specialist; (vi) evaluating the reasonableness of significant assumptions used by management and its independent valuation specialist related to the discount rate, future revenues and replacement costs; and (vii) evaluating the independent valuation specialist’s results. Evaluating management’s significant assumptions related to future revenues involved evaluating whether the assumptions used were reasonable considering the current and past performance of Stagecoach. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the discounted cash flow analyses and the cost approach and evaluating the reasonableness of the fair value of the assets acquired, including the evaluation of the reasonableness of the replacement costs and the discount rate significant assumptions.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 7, 2022
We have served as the Company’s auditor since 1997.
72
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
Year Ended December 31,
2021
2020
2019
Revenues
Services
$
7,757
$
7,618
$
8,198
Commodity sales
8,714
3,891
4,811
Other
139
191
200
Total Revenues
16,610
11,700
13,209
Operating Costs, Expenses and Other
Costs of sales
6,493
2,545
3,263
Operations and maintenance
2,368
2,475
2,591
Depreciation, depletion and amortization
2,135
2,164
2,411
General and administrative
655
648
590
Taxes, other than income taxes
426
378
426
Loss (gain) on impairments and divestitures, net (Note 4)
1,624
1,932
(942)
Other income, net
(7)
(2)
(3)
Total Operating Costs, Expenses and Other
13,694
10,140
8,336
Operating Income
2,916
1,560
4,873
Other Income (Expense)
Earnings from equity investments
591
780
101
Amortization of excess cost of equity investments
(78)
(140)
(83)
Interest, net
(1,492)
(1,595)
(1,801)
Other, net (Note 3)
282
56
75
Total Other Expense
(697)
(899)
(1,708)
Income Before Income Taxes
2,219
661
3,165
Income Tax Expense
(369)
(481)
(926)
Net Income
1,850
180
2,239
Net Income Attributable to Noncontrolling Interests
(66)
(61)
(49)
Net Income Attributable to Kinder Morgan, Inc.
$
1,784
$
119
$
2,190
Class P Common Stock
Basic and Diluted Earnings Per Share
$
0.78
$
0.05
$
0.96
Basic and Diluted Weighted Average Shares Outstanding
2,266
2,263
2,264
The accompanying notes are an integral part of these consolidated financial statements.
73
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
Year Ended December 31,
2021
2020
2019
Net income
$
1,850
$
180
$
2,239
Other comprehensive (loss) income, net of tax
Net unrealized (loss) gain from derivative instruments (net of taxes of $131, $(75), and $52, respectively)
(432)
249
(177)
Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $(83), $78, and $(2), respectively)
273
(255)
6
Foreign currency translation adjustments (net of taxes of $—, $—, and $(27), respectively)
—
—
108
Benefit plan adjustments (net of taxes of $(47), $19, and $(23), respectively)
155
(68)
77
Total other comprehensive (loss) income
(4)
(74)
14
Comprehensive income
1,846
106
2,253
Comprehensive income attributable to noncontrolling interests
(66)
(61)
(66)
Comprehensive income attributable to KMI
$
1,780
$
45
$
2,187
The accompanying notes are an integral part of these consolidated financial statements.
74
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)
December 31,
2021
2020
ASSETS
Current assets
Cash and cash equivalents
$
1,140
$
1,184
Restricted deposits
7
25
Accounts receivable
1,611
1,293
Fair value of derivative contracts
220
185
Inventories
562
348
Other current assets
289
168
Total current assets
3,829
3,203
Property, plant and equipment, net
35,653
35,836
Investments
7,578
7,917
Goodwill
19,914
19,851
Other intangibles, net
1,678
2,453
Deferred income taxes
115
536
Deferred charges and other assets
1,649
2,177
Total Assets
$
70,416
$
71,973
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt
$
2,646
$
2,558
Accounts payable
1,259
837
Accrued interest
504
525
Accrued taxes
270
267
Accrued contingencies
284
307
Other current liabilities
858
580
Total current liabilities
5,821
5,074
Long-term liabilities and deferred credits
Long-term debt
Outstanding
29,772
30,838
Debt fair value adjustments
902
1,293
Total long-term debt
30,674
32,131
Other long-term liabilities and deferred credits
2,000
2,202
Total long-term liabilities and deferred credits
32,674
34,333
Total Liabilities
38,495
39,407
Commitments and contingencies (Notes 9, 13, 17 and 18)
Redeemable Noncontrolling Interest (Note 2)
—
728
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,267,391,527 and 2,264,257,336 shares, respectively, issued and outstanding
23
23
Additional paid-in capital
41,806
41,756
Accumulated deficit
(10,595)
(9,936)
Accumulated other comprehensive loss
(411)
(407)
Total Kinder Morgan, Inc.’s stockholders’ equity
30,823
31,436
Noncontrolling interests
1,098
402
Total Stockholders’ Equity
31,921
31,838
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity
$
70,416
$
71,973
The accompanying notes are an integral part of these consolidated financial statements.
75
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
Year Ended December 31,
2021
2020
2019
Cash Flows From Operating Activities
Net income
$
1,850
$
180
$
2,239
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization
2,135
2,164
2,411
Deferred income taxes
355
345
717
Amortization of excess cost of equity investments
78
140
83
Loss (gain) on impairments and divestitures, net (Note 4)
1,624
1,932
(942)
Gain on sale of interest in equity investment (Note 3)
(206)
—
—
Earnings from equity investments
(591)
(780)
(101)
Distributions of equity investment earnings
720
633
590
Pension (contributions) net of noncash pension benefit expenses
(39)
(90)
14
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable
(265)
88
98
Inventories
(202)
16
4
Other current assets
(109)
49
100
Accounts payable
387
(19)
(198)
Accrued interest, net of interest rate swaps
(17)
(51)
(43)
Accrued taxes
2
(93)
(142)
Other current liabilities
146
(81)
(46)
Rate reparations, refunds and other litigation reserve adjustments
(57)
40
(4)
Other, net
(103)
77
(32)
Net Cash Provided by Operating Activities
5,708
4,550
4,748
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired
(1,547)
(16)
(79)
Capital expenditures
(1,281)
(1,707)
(2,270)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs
406
1,069
82
Proceeds from the KML and U.S. Cochin Sale, net of cash disposed (Note 3)
—
—
1,527
Contributions to investments
(38)
(386)
(1,299)
Distributions from equity investments in excess of cumulative earnings
163
154
333
Other, net
(8)
(25)
(8)
Net Cash Used in Investing Activities
(2,305)
(911)
(1,714)
Cash Flows From Financing Activities
Issuances of debt
5,959
3,888
8,036
Payments of debt
(6,831)
(3,996)
(11,224)
Debt issue costs
(27)
(25)
(10)
Cash dividends - common shares (Note 11)
(2,443)
(2,362)
(2,163)
Repurchases of common shares
—
(50)
(2)
Contributions from investment partner and noncontrolling interests
4
14
151
Distributions to investment partner
(82)
(79)
(11)
Distribution to noncontrolling interests - KML distribution of the TMPL Sale proceeds
—
—
(879)
Distributions to noncontrolling interests - other
(20)
(15)
(55)
Other, net
(25)
(13)
(28)
Net Cash Used in Financing Activities
(3,465)
(2,638)
(6,185)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits
—
(1)
29
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Deposits
(62)
1,000
(3,122)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period
1,209
209
3,331
Cash, Cash Equivalents, and Restricted Deposits, end of period
$
1,147
$
1,209
$
209
76
KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
Year Ended December 31,
2021
2020
2019
Cash and Cash Equivalents, beginning of period
$
1,184
$
185
$
3,280
Restricted Deposits, beginning of period
25
24
51
Cash, Cash Equivalents, and Restricted Deposits, beginning of period
1,209
209
3,331
Cash and Cash Equivalents, end of period
1,140
1,184
185
Restricted Deposits, end of period
7
25
24
Cash, Cash Equivalents, and Restricted Deposits, end of period
1,147
1,209
209
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Deposits
$
(62)
$
1,000
$
(3,122)
Noncash Investing and Financing Activities
Increase in property, plant and equipment from both accruals and contractor retainage
$
74
ROU assets and operating lease obligations recognized (Note 17)
59
$
20
$
399
Marketable securities obtained as consideration for divestiture (Note 3)
—
—
892
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)
1,529
1,661
1,860
Cash paid during the period for income taxes, net
10
227
372
The accompanying notes are an integral part of these consolidated financial statements.
77
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In millions)
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, 2018
2,262
$
23
$
41,701
$
(7,716)
$
(330)
$
33,678
$
853
$
34,531
Impact of adoption of ASU
(4)
(4)
(4)
Balance at January 1, 2019
2,262
23
41,701
(7,720)
(330)
33,674
853
34,527
Repurchases of shares
(2)
(2)
(2)
Restricted shares
3
46
46
46
Net income
2,190
2,190
49
2,239
Distributions
—
(55)
(55)
Contributions
—
3
3
Dividends
(2,163)
(2,163)
(2,163)
Sale of interest in KML
68
68
(503)
(435)
Other
—
1
1
Other comprehensive loss
(71)
(71)
(4)
(75)
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
3
61
61
61
Net income
119
119
61
180
Distributions
—
(15)
(15)
Contributions
—
11
11
Dividends
(2,362)
(2,362)
(2,362)
Other
—
1
1
Other comprehensive loss
(74)
(74)
(74)
Balance at December 31, 2020
2,264
23
41,756
(9,936)
(407)
31,436
402
31,838
Restricted shares
3
50
50
50
Net income
1,784
1,784
66
1,850
Distributions
—
(20)
(20)
Contributions
—
4
4
Dividends
(2,443)
(2,443)
(2,443)
Reclassification of redeemable noncontrolling interest
—
646
646
Other comprehensive loss
(4)
(4)
(4)
Balance at December 31, 2021
2,267
$
23
$
41,806
$
(10,595)
$
(411)
$
30,823
$
1,098
$
31,921
The accompanying notes are an integral part of these consolidated financial statements.
78
KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
General
We are one of the largest energy infrastructure companies in North America and unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, metals and petroleum coke.
2.
Summary of Significant Accounting Policies
Basis of Presentation
Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
Use of Estimates
Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including those related to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
Certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.
Cash Equivalents and Restricted Deposits
We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.
Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive insurance subsidiary and cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions.
Allowance for Credit Losses
We evaluate our financial assets measured at amortized cost and off-balance sheet credit exposures for expected credit losses over the contractual term of the asset or exposure. We consider available information relevant to assessing the collectability of cash flows including the expected risk of credit loss even if that risk is remote. We measure expected credit losses on a collective (pool) basis when similar risk characteristics exist, and we reflect the expected credit losses on the amortized cost basis of the financial asset as of the reporting date.
Our financial instruments primarily consist of our accounts receivable from customers, notes receivable from affiliates, and contingent liabilities such as proportional guarantees of debt obligations of certain equity investees. We utilized historical analysis of credit losses experienced over the previous five years along with current conditions and reasonable and supportable forecasts of future conditions in our evaluation of collectability of our financial assets. Our allowance for credit losses includes
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an evaluation of estimated impacts resulting from the economic effects of COVID-19, which we estimate could have a more significant impact to certain subset or pools of customers.
Our allowance for credit losses as of December 31, 2021 and 2020 was $1 million and $26 million, respectively, and is included in “Other current assets” in our accompanying consolidated balance sheets.
Inventories
Our inventories consist of materials and supplies and products such as NGL, crude oil, condensate, refined petroleum products, transmix and natural gas. We report products inventory at the lower of weighted-average cost or net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.
Property, Plant and Equipment, net
Capitalization, Depreciation and Depletion and Disposals
We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred.
For the majority of our assets, we compute depreciation using either the straight-line method based on estimated economic lives or the composite depreciation method, which applies a single depreciation rate for a group of assets. We apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.092% to 33.3% excluding certain short-lived assets such as vehicles. For FERC-regulated entities, the FERC-accepted composite depreciation rate is applied to the total cost of the composite group until the net book value equals the salvage value. For other entities, depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract term for assets on leased or customer property and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When these assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. Subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.
Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method, costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.
We engage in enhanced recovery techniques in which CO2 is injected into certain producing oil reservoirs. In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs.
A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our liquids and bulk terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset. For our pipeline system assets under the composite method of depreciation, we charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. Gains and losses are booked for FERC-approved operating unit sales and land sales and are recorded to income or expense accounts in accordance with regulatory accounting guidelines.
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Asset Retirement Obligations
We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.
We have various other obligations throughout our businesses to remove facilities and equipment on rights-of-way and other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and certain liquids and bulk terminal facilities. An asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.
Long-lived Asset Impairments
We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable. We recognize impairment losses when the estimated fair value is less than its carrying amount.
In addition to our annual goodwill impairment test, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because the impairment test for long-lived assets held in use is based on estimated undiscounted cash flows, there may be instances where an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group. If the carrying value of a long-lived asset or asset group is in excess of estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required (step 2).
We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes.
Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on estimated future oil and gas production volumes. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.
Refer to Note 4 for further information.
Equity Method of Accounting and Basis Differences
We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. The carrying values of these investments are impacted by our share of investee income or loss, distributions, amortization or accretion of basis differences and other-than-temporary impairments.
The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized.
We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized the loss is recorded as a reduction in equity earnings.
Goodwill
Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least
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annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit, and an impairment exists and is recorded for the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.
We evaluate goodwill for impairment on May 31 of each year. For purposes of our May 31, 2021 evaluation, we grouped our businesses into 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. With our August 20, 2021 acquisition of Kinetrex Energy, we expanded our reporting units to include the Energy Transition Ventures reporting unit (see Note 3). We also evaluate goodwill for impairment to the extent events or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstance an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.
A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit.
Refer to Note 8 for further information.
Other Intangibles
Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, and technology-based assets. As of December 31, 2021 and 2020, the gross carrying amounts of these intangible assets was $3,036 million and $4,074 million, respectively, and the accumulated amortization was $1,358 million and $1,621 million, respectively, resulting in net carrying amounts of $1,678 million and $2,453 million, respectively.
Our intangible assets primarily relate to customer contracts or other relationships for the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline, and other refined petroleum products, petroleum coke, metals and ores, the gathering of natural gas and the production and supply of RNG. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.
We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effect of obsolescence, new technology, and competition.
For the years ended December 31, 2021, 2020 and 2019, the amortization expense on our intangibles totaled $237 million, $212 million and $214 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2022 – 2026) is approximately $242 million, $177 million, $153 million, $147 million, and $144 million, respectively. As of December 31, 2021, the weighted average amortization period for our intangible assets was approximately ten years.
Revenue Recognition
The majority of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers; however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases or ASC 815, Derivatives and Hedging Activities.
Revenue from Contracts with Customers
We review our contracts with customers using the following steps to recognize revenue based on the transfer of goods or services to customers and in amounts that reflect the consideration the company expects to receive for those goods or services. The steps include: (i) identify the contract; (ii) identify the performance obligations of the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and then (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.
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Our customer sales contracts primarily include natural gas sales, NGL sales, crude oil sales, CO2 sales, and transmix sales contracts, as described below. Generally, for the majority of these contracts: (i) each unit (Mcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied.
Our customer services contracts primarily include transportation service, storage service, gathering and processing service, and terminaling service contracts, as described below. Generally, for the majority of these contracts: (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights).
Firm Services
Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows:
•Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation) continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time.
•Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e.,
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breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods.
Non-Firm Services
Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period).
Contract Balances
Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations. We reassess amounts recorded as contract assets or liabilities upon contract modification.
Refer to Note 15 for further information.
Cost of Sales
Cost of sales primarily includes the cost to purchase energy commodities sold, including natural gas, crude oil, NGL and other refined petroleum products, adjusted for the effects of our energy commodity hedging activities, as applicable. Costs of our crude oil, gas and CO2 producing activities, such as those in our CO2 business segment, are not accounted for as costs of sales.
Operations and Maintenance
Operations and maintenance include costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO2 producing activities included within operations and maintenance totaled $180 million, $319 million and $382 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Environmental Matters
We capitalize or expense, as appropriate, environmental expenditures. We capitalize certain environmental expenditures required to obtain rights-of-way, regulatory approvals or permitting as part of the construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our accrual of these environmental liabilities coincides with either our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination.
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We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.
Leases
We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 49 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, were reflected based on contractual lease payments as outlined within the lease agreement and exclude CPI adjustments. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately, while for the remainder of our agreements we have elected the practical expedient to account for lease and non-lease components as a single lease component. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, are reassessed when agreements are modified.
Refer to Note 17 for further information.
Share-based Compensation
We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our Class P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in shares of our Class P common stock.
Pensions and Other Postretirement Benefits
We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.
Deferred Financing Costs
We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.
Redeemable Noncontrolling Interest
Through December 14, 2021, redeemable noncontrolling interest represented the interest in one of our consolidated subsidiaries, ELC, that was not owned by us, which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary and redeem its cumulative contributions, net of distributions it had received through date of the amended operating agreement. Distributions paid to EIG prior to that date were recorded as a reduction to the “Redeemable Noncontrolling Interest” balance. On December 14, 2021, the ownership agreement was modified such that EIG’s interest is no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to
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redeemable noncontrolling interest was $58 million, $54 million and $11 million for the years ended December 31, 2021, 2020 and 2019, respectively, and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statements of income.
Noncontrolling Interests
Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us. In our accompanying consolidated income statements, the noncontrolling interest in the net income of our less than wholly owned consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net Income Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”
Income Taxes
Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.
Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance for the amount that is, more likely than not, to not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached.
In determining the deferred income tax asset and liability balances attributable to our investments, we apply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments, including KMI’s investment in its wholly-owned subsidiary, KMP.
Risk Management Activities
We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of commodities including crude oil, natural gas, and NGL. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations. We also enter into cross-currency swap agreements to manage our foreign currency risk with certain debt obligations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. For certain physical forward commodity derivatives contracts, we apply the normal purchase/normal sale exception, whereby the revenues and expenses associated with such transactions are recognized during the period when the commodities are physically delivered or received.
For qualifying accounting hedges, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. When we designate a derivative contract as a cash flow accounting hedge, the entire change in fair value of the derivative that is included in the assessment of hedge effectiveness is deferred in “Accumulated other comprehensive loss” and reclassified into earnings in the period in which the hedged item affects earnings. When we designate a derivative contract as a fair value accounting hedge, the entire change in fair value of the derivative is recorded as an adjustment to the item being hedged. The gain or loss from any mismatch in the hedging relationship is recognized currently in earnings. When we designate a derivative contract as a net investment accounting hedge, the entire change in fair value of the derivative is reflected in the Foreign currency translation adjustments section of Other comprehensive (loss) income on our consolidated statements of comprehensive income.
For derivative instruments that are not designated as accounting hedges, or for which we have not elected the normal purchase/normal sales exception, changes in fair value are recognized currently in earnings.
Fair Value
The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair
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value. We assign each fair value measurement to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. Recognized valuation techniques utilize inputs such as contractual prices, quoted market prices or rates, and discount factors. These inputs may be either readily observable or corroborated by market data.
Regulatory Assets and Liabilities
Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or returned to customers through the ratemaking process. In instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount. We include the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.
The following table summarizes our regulatory asset and liability balances as of December 31, 2021 and 2020:
December 31,
2021
2020
(In millions)
Current regulatory assets
$
66
$
25
Non-current regulatory assets
220
231
Total regulatory assets(a)
$
286
$
256
Current regulatory liabilities
$
32
$
26
Non-current regulatory liabilities
163
169
Total regulatory liabilities(b)
$
195
$
195
(a)Regulatory assets as of December 31, 2021 include (i) $121 million of unamortized losses on disposal of assets; (ii) $47 million income tax gross up on equity AFUDC; and (iii) $118 million of other assets including amounts related to fuel tracker arrangements. Approximately $155 million of the regulatory assets, with a weighted average remaining recovery period of 10 years, are recoverable without earning a return, including the income tax gross up on equity AFUDC for which there is an offsetting deferred income tax balance for FERC rate base purposes; therefore, it does not earn a return.
(b)Regulatory liabilities as of December 31, 2021 are comprised of customer prepayments to be credited to shippers or other over-collections that are expected to be returned to shippers or netted against under-collections over time. Approximately $107 million of the $163 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 16 years, while the remaining $56 million is not subject to a defined period.
Earnings per Share
We calculate earnings per share using the two-class method. Earnings were allocated to Class P common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.
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The following table sets forth the allocation of net income available to shareholders of Class P common stock and participating securities:
Year Ended December 31,
2021
2020
2019
(In millions, except per share amounts)
Net Income Available to Stockholders
$
1,784
$
119
$
2,190
Participating securities:
Less: Net Income Allocated to Restricted stock awards(a)
(14)
(13)
(12)
Net Income Allocated to Class P Stockholders
$
1,770
$
106
$
2,178
Basic Weighted Average Shares Outstanding
2,266
2,263
2,264
Basic Earnings Per Share
$
0.78
$
0.05
$
0.96
(a)As of December 31, 2021, there were approximately 13 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:
Year Ended December 31,
2021
2020
2019
(In millions on a weighted average basis)
Unvested restricted stock awards
13
13
13
Convertible trust preferred securities
3
3
3
3.
Acquisitions and Divestitures
Business Combinations
For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of these items requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions.
As of December 31, 2021, our allocation of the purchase price for significant acquisitions completed during the year ended December 31, 2021 are detailed below:
Assignment of Purchase Price
Ref
Date
Acquisition
Purchase price
Current assets
Property, plant & equipment
Deferred charges & other
Goodwill
Current liabilities
Long-term liabilities
(In millions)
(1)
8/21
Kinetrex
$
318
$
18
$
49
$
262
$
63
$
(6)
$
(68)
(2)
7/21
Stagecoach Gas Services LLC
1,258
53
1,187
24
—
(6)
—
(1) Kinetrex
On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex from an affiliate of Parallel49 Equity for $318 million, including purchase price adjustments for working capital. Deferred charges and other within the preliminary purchase price allocation includes $63 million related to an equity investment and $199 million related to a customer relationship with an amortization period of approximately 10 years. Kinetrex is a supplier of LNG in the Midwest and a producer and supplier of RNG under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.
88
(2) Stagecoach Gas Services LLC
On July 9, 2021 and November 24, 2021, we completed the acquisitions of Stagecoach Gas Services LLC and its subsidiaries (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,258 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary purchase price allocation relates to customer contracts with a weighted average amortization period of less than 2 years. The determination of fair value utilized valuation methodologies including discounted cash flows and the cost approach. The significant assumptions made in performing these valuations include a discount rate of approximately 12%, future revenues and replacement costs. To compute estimated future cash flows for Stagecoach, transportation and storage revenue forecasts were developed based on projected demand and future rates for services in the Northeast market areas.
Pro Forma Information
Pro forma consolidated income statement information that gives effect to the above acquisitions as if they had occurred as of January 1, 2021 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of operations.
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 $412 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 year ended December 31, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.
Sale of U.S. Portion of Cochin Pipeline System and KML
On December 16, 2019, we closed on two cross-conditional transactions resulting in the sale of the U.S. portion of the Cochin Pipeline system and all the outstanding equity of KML, including our 70% interest, to Pembina Pipeline Corporation (Pembina) (together, the “KML and U.S. Cochin Sale”). We recognized a pre-tax net gain of $1,296 million from these transactions within “Loss (gain) on impairments and divestitures, net” on our accompanying consolidated statement of income during the year ended December 31, 2019. We received cash proceeds of $1,553 million net of a working capital adjustment, for the U.S. portion of the Cochin Pipeline system which was used to pay down debt. KML common shareholders received 0.3068 shares of Pembina common equity for each share of KML common equity. For our 70% interest in KML, we received approximately 25 million shares of Pembina common equity, with a pre-tax fair value on the transaction date of approximately $892 million. The Pembina common shares were sold on January 9, 2020, and we received proceeds of approximately $907 million ($764 million after tax).
Sale of Trans Mountain Pipeline System and Its Expansion Project
On January 3, 2019, KML distributed the net proceeds from the sale of TMPL, the TMEP, and the Puget Sound pipeline system in 2018 to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70% portion of the net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used to repay our outstanding commercial paper borrowings of $0.4 billion and in February 2019, to pay down approximately $1.3 billion of maturing long-term debt.
4. Losses and Gains on Impairments, Divestitures and Other Write-downs
During the years ended December 31, 2021, 2020, and 2019, we recorded net pre-tax losses of $1,535 million, losses of $1,922 million and gains of $285 million, respectively, reflecting net losses on impairments of goodwill, long-lived assets, intangible and other assets and certain equity investments, and net losses and gains on divestitures of assets and equity investments. The year ended December 31, 2021 amount primarily includes pre-tax long-lived asset impairments of $1,634 million. The year ended December 31, 2020 amount primarily includes pre-tax goodwill and long-lived asset impairment losses of $1,600 million and $376 million, respectively, and the year ended December 31, 2019 amount primarily
89
includes a net pre-tax gain of $1,296 million related to the KML and U.S. Cochin Sale (see Note 3) and impairment losses of $1,014 million as further described below.
We recognized the following non-cash pre-tax losses (gains) on impairments and divestitures on assets and equity investments during the years ended December 31, 2021, 2020, and 2019:
Year Ended December 31,
2021
2020
2019
(In millions)
Natural Gas Pipelines
Impairments of long-lived assets(a)
$
1,600
$
—
$
290
Impairment of goodwill(b)
—
1,000
—
Gain on sale of interest in NGPL Holdings(c)
(206)
—
—
Loss on write-down of related party note receivable(d)
117
—
—
(Gains) losses on divestitures of long-lived assets and other write-downs(e)
(1)
10
(967)
Impairment of equity investments(f)
—
—
650
Products Pipelines
Impairments of long-lived assets
—
21
—
Terminals
Impairments of long-lived assets
34
5
—
Losses (gains) on divestitures of long-lived assets(g)
2
(54)
(335)
Gain on sale of equity investment interests
—
(10)
—
CO2
Impairment of goodwill(b)
—
600
—
Impairments of long-lived assets(h)
—
350
74
(Gains) losses on divestitures of long-lived assets
(8)
—
2
Other (gains) losses on divestitures of long-lived assets
(3)
—
1
Pre-tax losses on impairments, divestitures and other write-downs, net
$
1,535
$
1,922
$
(285)
(a)2021 amount represents non-cash impairments associated with our South Texas gathering and processing assets. 2019 amount represents non-cash impairments associated with certain gathering and processing assets in Oklahoma and northern Texas.
(b)2020 amount represent non-cash goodwill impairments associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units (see “—Impairments—Goodwill” below).
(c)See Note 3.
(d)See “—Other Write-downs” below for a further discussion.
(e)2019 amount includes a $957 million gain related to the sale of the Cochin Pipeline system.
(f)2019 amount represents the non-cash impairment of our investment in Ruby which is included in “Earnings from equity investments” on our accompanying consolidated statements of income for the year ended December 31, 2019.
(g)2020 amount includes a $55 million gain related to the sale of our Staten Island terminal. 2019 amount includes a $339 million gain related to the sale of KML.
(h)2020 and 2019 amounts represent impairments of oil and gas properties.
Impairments
Long-lived Assets
During the second quarter 2021, we evaluated our South Texas gathering and processing assets within our Natural Gas Pipeline business segment for impairment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. To compute the estimated undiscounted future cash flows we used the forecast of expected revenues adjusted for upcoming contract expirations. This analysis indicated that 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. The significant assumptions made in calculating fair value include estimates of future cash flows and discount rates. We applied an approximate 8.5% discount rate, a Level 3 input, which we believed represented the estimated weighted average cost of capital of a theoretical market participant. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the year ended December 31, 2021.
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During the first half of 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 year ended December 31, 2020.
As of March 31, 2020, for our CO2 assets, the computation of estimated undiscounted future cash flows included the following:
•To compute estimated future cash flows for our oil and gas producing properties, we used our reserve engineer specialists to estimate future oil and gas production volumes. These estimates of future oil and gas production volumes are based upon historical performance along with adjustments for expected crude oil and natural gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on a March 31, 2020 NYMEX forward curve adjusted for the impact of our existing sales contracts to determine the applicable net crude oil and NGL pricing for each property. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.
•To compute estimated future cash flows for our CO2 source and transportation assets, throughput and production volume forecasts were developed based on projected demand for our CO2 services based upon management’s projections of the availability of CO2 supply and the future demand for CO2 for use in enhanced oil recovery projects. The CO2 pricing assumption was a function of the March 31, 2020 NYMEX forward curve adjusted for the impact of existing sales contracts to determine the applicable net CO2 pricing. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.
For certain oil and gas properties that failed the first step, we used a discounted cash flow analysis to estimate fair value. We applied a 10.5% discount rate, which we believe represented the estimated weighted average cost of capital of a theoretical market participant. Based on step two of our long-lived assets impairment test, we recognized $350 million of impairments on those oil and gas producing properties where the total carrying value exceeded its total estimated fair market value as of March 31, 2020.
Our largest impairment for the year ended December 31, 2019 was a $650 million non-cash impairment to our investment in Ruby in our Natural Gas Pipelines business segment. The impairment of our investment was considered from our subordinated ownership position and driven by reduced cash flow estimates identified during the period which resulted from (i) increased Canadian gas supplies and competition from other natural gas pipelines and (ii) upcoming contract expirations. These conditions were determined to be other than temporary. We utilized a discounted cash flow analysis.
Additional impairments totaling $290 million were recognized during the year ended December 31, 2019 on long-lived assets within our Natural Gas Pipelines business segment and were driven by continued reduced drilling activity in Oklahoma and northern Texas demonstrated in the fourth quarter. The reduced estimate triggered an impairment analysis as we determined that our carrying value may no longer be recoverable. The assets failed step 1 of our evaluation. Step 2 involved using the income approach to calculate the fair value of the asset group and comparing it to the carrying value. The impairment that we recorded represented the difference between the fair and carrying values.
Goodwill
The fair value estimates used in our 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 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.
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.
91
During the first quarter of 2020, we conducted interim impairment tests of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the second quarter 2020, we conducted our annual impairment test of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 and Natural Gas Pipelines business segments during the year ended December 31, 2020 as shown in the table above.
•Our May 31, 2020 goodwill impairment tests of the Products Pipelines, Products Pipelines Terminals, Natural Gas Pipelines Regulated and CO2 reporting units indicated that their fair values exceeded their carrying values. The results of our impairment analyses for our Products Pipelines, Terminals and CO2 reporting units, determined that each of the three reporting unit’s fair value was in excess of carrying value by less than 10%. For the Products Pipelines and Terminals reporting units, we used the market approach with assumptions similar to those described below for the Natural Gas Pipelines Non-Regulated reporting unit. For our May 31, 2020 goodwill impairment test of the CO2 reporting unit we used the income approach with assumptions similar to those used for its March 31, 2020 goodwill impairment test.
•In regards to our Natural Gas Pipelines Non-Regulated reporting unit, while no impairment was required as of March 31, 2020, it experienced a sharp decline in customer demand for its services during the second quarter of 2020. This represented a timing lag from the initial economic decline impacts resulting from the severe downturn in the upstream energy industry, including our CO2 business, whereby oil and gas producing companies accelerated their shut down of wells and reduced production during the second quarter which consequently adversely impacted the demand for our midstream services. In addition, continued diminished (i) current and expected future commodity pricing and (ii) peer group market capitalization values provided further indicators that an impairment of goodwill had occurred for this reporting unit during the second quarter.
Our May 31, 2020 goodwill impairment test for the Natural Gas Pipelines Non-Regulated reporting unit utilized a weighted average of a market approach (25%) and income approach (75%) to estimate its fair value. We gave higher weighting to the income approach as we believe it was more representative of the value that would be received from a market participant.
The market approach was based on enterprise value (EV) to estimated 2020 EBITDA multiples for a selected number of peer group midstream companies with comparable operations and economic characteristics. We estimated the median EV to EBITDA multiple to be approximately 10x without consideration of any control premium. The income approach we used to determine fair value included an analysis of estimated discounted cash flows based on 6.5 years of projections and application of an exit multiple based on management’s expectations of a discount rate and exit multiple that would be applied by a theoretical market participant and for market transactions of comparable assets. We applied an approximate 8% discount rate to the undiscounted cash flow amounts which represents our estimate of the weighted average cost of capital of a theoretical market participant. The discounted cash flows included various assumptions on forecasted commodity throughput volumes and contract prices for each underlying asset within the reporting unit. The fair value based on a weighting of the market and income approaches resulted in an implied EV to 2020 EBITDA multiple valuation of approximately 11x. Management believes this is a reasonable estimate of fair value based on comparable sales transactions and the fact that it implies a reasonable control premium.
The results of the Natural Gas Pipelines Non-Regulated reporting unit goodwill impairment analysis was a partial impairment of goodwill of approximately $1,000 million as of May 31, 2020.
•For our March 31, 2020 interim goodwill impairment test of the CO2 reporting unit, we applied an income approach to evaluate its fair value based on the present value of its cash flows that it is expected to generate in the future. Due to the uncertainty and volatility in market conditions within its peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.
In determining the fair value for our CO2 reporting unit, we applied a 9.25% discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents our estimate of the weighted average cost of capital of a theoretical market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO2 reporting unit of approximately $600 million as of March 31, 2020.
The fair value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.
92
Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.
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.
For additional information regarding changes in our goodwill, see Note 8.
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 for the year ended December 31, 2021. 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 LNG exporting facility that could significantly increase the demand for its services.
5.
Income Taxes
The components of “Income Before Income Taxes” are as follows:
Year Ended December 31,
2021
2020
2019
(In millions)
U.S.
$
2,217
$
663
$
2,482
Foreign
2
(2)
683
Total Income Before Income Taxes
$
2,219
$
661
$
3,165
93
Components of the income tax provision applicable for federal, foreign and state taxes are as follows:
Year Ended December 31,
2021
2020
2019
(In millions)
Current tax expense (benefit)
Federal
$
—
$
(20)
$
(2)
State
11
9
10
Foreign(a)
3
147
201
Total
14
136
209
Deferred tax expense (benefit)
Federal
334
440
682
State
21
49
66
Foreign(a)
—
(144)
(31)
Total
355
345
717
Total tax provision
$
369
$
481
$
926
(a)Our Canadian income tax (benefit) expense was $(1) million, $(4) million and $165 million for the years ended December 31, 2021, 2020 and 2019, respectively.
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
Year Ended December 31,
2021
2020
2019
(In millions, except percentages)
Federal income tax
$
466
21.0
%
$
139
21.0
%
$
665
21.0
%
Increase (decrease) as a result of:
Taxes on foreign earnings, net of federal benefit
2
0.1
%
2
0.3
%
139
4.4
%
Net effects of noncontrolling interests
(14)
(0.6)
%
(13)
(2.0)
%
(10)
(0.3)
%
State income tax, net of federal benefit
50
2.2
%
52
7.9
%
68
2.1
%
Dividend received deduction
(46)
(2.1)
%
(27)
(4.1)
%
(39)
(1.1)
%
Release of valuation allowance
(38)
(1.7)
%
—
—
%
—
—
%
Nondeductible goodwill
—
—
%
336
50.8
%
108
3.4
%
General business credit
(36)
(1.6)
%
—
—
%
—
—
%
Federal refunds
—
—
%
(20.0)
(3.0)
%
—
—
%
Other
(15)
(0.7)
%
12
1.9
%
(5)
(0.2)
%
Total
$
369
16.6
%
$
481
72.8
%
$
926
29.3
%
94
Deferred tax assets and liabilities result from the following:
December 31,
2021
2020
(In millions)
Deferred tax assets
Employee benefits
$
154
$
224
Net operating loss carryforwards
1,476
1,484
Tax credit carryforwards
301
257
Other
229
242
Valuation allowances
(93)
(138)
Total deferred tax assets
2,067
2,069
Deferred tax liabilities
Property, plant and equipment
166
414
Investments
1,769
1,084
Other
17
35
Total deferred tax liabilities
1,952
1,533
Net deferred tax assets
$
115
$
536
Deferred Tax Assets and Valuation Allowances
We have deferred tax assets of $1,476 million related to net operating loss carryovers, $301 million related to general business and foreign tax credits, and $93 million of valuation allowances related to these deferred tax assets as of December 31, 2021. As of December 31, 2020, we had deferred tax assets of $1,484 million related to net operating loss carryovers, $257 million related to general business and foreign tax credits, and $100 million of valuation allowances related to these deferred tax assets. We expect to generate taxable income and begin to utilize federal net operating loss carryforwards and tax credits in 2024.
We decreased our valuation allowances related to net operating loss and tax credits in 2021 by $7 million, primarily due to $5 million of statute expirations for federal and state net operating losses and foreign tax credits and $2 million of currency fluctuations on foreign net operating losses. We also released the $38 million of valuation allowances related to our investment in NGPL upon the sale of a partial interest in NGPL.
Expiration Periods for Deferred Tax Assets:As of December 31, 2021, we have U.S. federal net operating loss carryforwards of $2.7 billion that will be carried forward indefinitely and $3.2 billion that will expire from 2022 - 2037; state losses of $4 billion which will expire from 2022 - 2040; and foreign losses of $77 million which will be carried forward indefinitely. We also have $287 million of general business credits which will expire from 2026 - 2031; and approximately $14 million of foreign tax credits, which will expire from 2022 - 2027. Use of a portion of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations. If certain substantial changes in our ownership occur, there would be an annual limitation on the amount of carryforwards that could be utilized.
Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.
Our gross unrecognized tax benefit balances, excluding immaterial amounts of interest and penalties, were $21 million, $18 million and $16 million as of December 31, 2021, 2020 and 2019, respectively. Reductions based on settlements with taxing authorities were $0 million for each of the years ended December 31, 2021 and 2020 and $21 million for the year ended December 31, 2019, respectively. All of the $21 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will not have any material change during the next year, primarily due to releases from statute expirations, offset by additions for state filing positions taken in prior years.
95
We are subject to taxation and have tax years open to examination for the periods 2017 - 2021 in the U.S., which include net operating loss utilization from earlier years, 2003 - 2021 in various states and 2008 - 2021 in various foreign jurisdictions.
6. Property, Plant and Equipment, net
Classes and Depreciation
As of December 31, 2021 and 2020, our property, plant and equipment, net consisted of the following:
December 31,
2021
2020
(In millions)
Pipelines (Natural gas, liquids, crude oil and CO2)
$
20,254
$
20,339
Equipment (Natural gas, liquids, crude oil, CO2, and terminals)
26,511
26,142
Other(a)
5,356
5,188
Accumulated depreciation, depletion and amortization
(18,792)
(17,818)
33,329
33,851
Land and land rights-of-way
1,718
1,403
Construction work in process
606
582
Property, plant and equipment, net
$
35,653
$
35,836
(a)Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment.
As of December 31, 2021 and 2020, property, plant and equipment, net included $12,277 million and $12,160 million, respectively, of assets which were regulated by the FERC. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $1,873 million, $1,928 million and $2,176 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Asset Retirement Obligations
As of December 31, 2021 and 2020, we recognized asset retirement obligations in the aggregate amount of $196 million and $214 million, respectively, of which $4 million were classified as current for both periods. The majority of our asset retirement obligations are associated with our CO2 business segment, where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors.
96
7. Investments
Our investments primarily consist of equity investments where we hold significant influence over investee actions and for which we apply the equity method of accounting. The following table provides details on our investments as of December 31, 2021 and 2020, and our earnings (loss) from these respective investments for the years ended December 31, 2021, 2020 and 2019:
Ownership Interest
Equity Investments
Earnings (Loss) from Equity Investments
December 31,
December 31,
Year Ended December 31,
2021
2021
2020
2021
2020
2019
(In millions)
Citrus Corporation
50%
$
1,768
$
1,849
$
151
$
165
$
157
SNG
50%
1,514
1,532
128
129
140
PHP
26.67%
647
632
63
—
—
Gulf Coast Express Pipeline LLC
34%
618
638
86
90
37
NGPL Holdings(a)
37.5%
604
803
94
116
81
MEP
50%
388
416
(17)
(6)
15
Gulf LNG
50%
347
361
22
19
17
Products (SE) Pipe Line Corporation
51.17%
346
357
48
43
58
Utopia Holding LLC
50%
328
329
20
20
20
EagleHawk
25%
266
275
8
17
17
Watco Companies, LLC
(b)
75
70
9
16
19
Cortez Pipeline Company
52.98%
28
25
29
24
35
FEP
50%
—
16
—
70
59
Ruby(c)
(d)
—
1
(116)
15
(609)
All others
649
613
66
62
55
Total investments
$
7,578
$
7,917
$
591
$
780
$
101
Amortization of excess cost
$
(78)
$
(140)
$
(83)
(a)Our investment in NPGL Holdings includes a related party promissory note receivable from NGPL Holdings with quarterly interest payments at 6.75%. On March 8, 2021, we and Brookfield completed the sale of a combined 25% interest in our joint venture, NGPL Holdings, to ArcLight including a transfer of $125 million in principal amount of our related party promissory note receivable (see Note 3). We and Brookfield now each hold a 37.5% interest in NGPL Holdings. The outstanding principal amount of our related party promissory note receivable at December 31, 2021 and 2020 was $375 million and $500 million, respectively. For the years ended December 31, 2021, 2020 and 2019, we recognized $27 million, $34 million and $8 million, respectively, of interest within “Earnings from equity investments” on our accompanying consolidated statements of income.
(b)We hold a preferred equity investment in Watco Companies, LLC (Watco). We own 50,000 Class B preferred shares and pursuant to the terms of the investment, receive priority, cumulative cash and stock distributions from the preferred shares at a rate of 3.00% per quarter. We do not hold any voting powers, but the class does provide us certain approval rights, including the right to appoint one of the members to Watco’s board of managers. During the fourth quarter of 2020, we sold our Preferred A and common equity investment in Watco, and recognized a pre-tax gain of $10 million within “Other, net” on our accompanying consolidated statement of income for the year ended December 31, 2020.
(c)The loss from our investment in Ruby for the year ended December 31, 2021 includes a non-cash impairment charge of $117 million related to a write-down of our subordinated note receivable from Ruby driven by the impairment by Ruby of its assets, and the year ended December 31, 2019 loss includes a non-cash impairment charge of $650 million (pre-tax) related to our investment (see Note 4).
(d)We operate Ruby and own the common interest in Ruby, the sole owner of the Ruby Pipeline natural gas transmission system. Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby.
97
Summarized combined financial information for our significant equity investments (listed or described above) is reported below (amounts represent 100% of investee financial information):
Year Ended December 31,
Income Statement
2021(a)
2020
2019
(In millions)
Revenues
$
5,426
$
5,076
$
4,906
Costs and expenses
6,083
4,249
3,508
Net (loss) income
$
(657)
$
827
$
1,398
December 31,
Balance Sheet
2021
2020
(In millions)
Current assets
$
1,235
$
1,013
Non-current assets
22,749
25,069
Current liabilities
1,778
1,787
Non-current liabilities
9,931
9,734
Partners’/owners’ equity
12,275
14,561
(a)2021 amounts include a non-cash impairment charge of $2.2 billion recorded by Ruby.
8. Goodwill
Changes in the amounts of our goodwill for each of the years ended December 31, 2021 and 2020 are summarized by reporting unit as follows:
Natural Gas Pipelines Regulated
Natural Gas Pipelines Non-Regulated
CO2
Products Pipelines
Products Pipelines Terminals
Terminals
Energy Transition Ventures
Total
(In millions)
Gross goodwill
$
15,892
$
4,940
$
1,528
$
2,575
$
221
$
1,481
$
—
$
26,637
Accumulated impairment losses
(1,643)
(1,597)
—
(1,197)
(70)
(679)
—
(5,186)
December 31, 2019
14,249
3,343
1,528
1,378
151
802
—
21,451
Impairments(a)
—
(1,000)
(600)
—
—
—
—
(1,600)
December 31, 2020
14,249
2,343
928
1,378
151
802
—
19,851
Acquisition of Kinetrex
—
—
—
—
—
—
63
63
December 31, 2021
14,249
2,343
928
1,378
151
802
63
19,914
Gross goodwill
15,892
4,940
1,528
2,575
221
1,481
63
26,700
Accumulated impairment losses
(1,643)
(2,597)
(600)
(1,197)
(70)
(679)
—
(6,786)
December 31, 2021
$
14,249
$
2,343
$
928
$
1,378
$
151
$
802
$
63
$
19,914
(a)See Note 4 “Losses and Gains on Impairments, Divestitures and Other Write-downs—Goodwill Impairments” for further information regarding our goodwill impairments.
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9. Debt
The following table provides detail on the principal amount of our outstanding debt balances:
December 31,
2021
2020
(In millions)
Credit facility and commercial paper borrowings(a)
$
—
$
—
Corporate senior notes(b)
5.00%, due February 2021
—
750
3.50%, due March 2021(c)
—
750
5.80%, due March 2021
—
400
5.00%, due October 2021
—
500
4.15%, due March 2022
375
375
1.50%, due March 2022(d)
853
917
3.95%, due September 2022
1,000
1,000
3.15%, due January 2023
1,000
1,000
Floating rate, due January 2023(e)
250
250
3.45%, due February 2023
625
625
3.50%, due September 2023
600
600
5.625%, due November 2023
750
750
4.15%, due February 2024
650
650
4.30%, due May 2024
600
600
4.25%, due September 2024
650
650
4.30%, due June 2025
1,500
1,500
1.75%, due November 2026(f)
500
—
6.70%, due February 2027
7
7
2.25%, due March 2027(d)
569
611
6.67%, due November 2027
7
7
4.30%, due March 2028
1,250
1,250
7.25%, due March 2028
32
32
6.95%, due June 2028
31
31
8.05%, due October 2030
234
234
2.00%, due February 2031
750
750
7.40%, due March 2031
300
300
7.80%, due August 2031
537
537
7.75%, due January 2032
1,005
1,005
7.75%, due March 2032
300
300
7.30%, due August 2033
500
500
5.30%, due December 2034
750
750
5.80%, due March 2035
500
500
7.75%, due October 2035
1
1
6.40%, due January 2036
36
36
6.50%, due February 2037
400
400
7.42%, due February 2037
47
47
6.95%, due January 2038
1,175
1,175
6.50%, due September 2039
600
600
6.55%, due September 2040
400
400
7.50%, due November 2040
375
375
6.375%, due March 2041
600
600
5.625%, due September 2041
375
375
5.00%, due August 2042
625
625
4.70%, due November 2042
475
475
5.00%, due March 2043
700
700
5.50%, due March 2044
750
750
5.40%, due September 2044
550
550
5.55%, due June 2045
1,750
1,750
5.05%, due February 2046
800
800
5.20%, due March 2048
750
750
3.25%, due August 2050
500
500
3.60%, due February 2051(f)(g)
1,050
—
7.45%, due March 2098
26
26
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(continued)
December 31,
2021
2020
TGP senior notes(b)
7.00%, due March 2027
300
300
7.00%, due October 2028
400
400
2.90%, due March 2030
1,000
1,000
8.375%, due June 2032
240
240
7.625%, due April 2037
300
300
EPNG senior notes(b)
8.625%, due January 2022(h)
260
260
7.50%, due November 2026
200
200
8.375%, due June 2032
300
300
CIG senior notes(b)
4.15%, due August 2026
375
375
6.85%, due June 2037
100
100
EPC Building, LLC, promissory note, 3.967%, due January 2021 through December 2035
364
380
Trust I Preferred Securities, 4.75%, due March 2028(i)
221
221
Other miscellaneous debt(j)
248
254
Total debt – KMI and Subsidiaries
32,418
33,396
Less: Current portion of debt(k)
2,646
2,558
Total long-term debt – KMI and Subsidiaries(l)
$
29,772
$
30,838
(a)See “—Current portion of debt” below for further details regarding our outstanding credit facilities and commercial paper borrowings.
(b)Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.
(c)On January 4, 2021, we repaid our $750 million senior corporate notes.
(d)Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2021 exchange rate of 1.1370 U.S. dollars per Euro and at the December 31, 2020 exchange rate of 1.2216 U.S. dollars per Euro. As of December 31, 2021 and 2020, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in increases to our debt balance of $38 million and $102 million, respectively, related to the 1.50% series and increases of $26 million and $68 million, respectively, related to the 2.25% series. The cumulative increase in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “Other long-term liabilities and deferred credits” on our 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 14 “Risk Management—Foreign Currency Risk Management”).
(e)As of December 31, 2021, we had outstanding, an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge.
(f)On October 26, 2021, we issued in a registered offering two series of senior notes consisting of $500 million aggregate principal amount of 1.75% senior notes due 2026 and $300 million aggregate principal amount of 3.60% senior notes due 2051 as a reopening of the 3.60% series (see (g) following) and received combined net proceeds of $796 million. These notes are guaranteed through the cross guarantee agreement discussed below.
(g)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 below.
(h)On January 18, 2022, we repaid these senior notes.
(i)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2021, had 4.4 million of 4.75% trust convertible preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend or loan. The Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75% and carry a liquidation value of $50 per security plus accrued and unpaid distributions. The Trust I Preferred Securities outstanding as of December 31, 2021 are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; and (ii) $25.18 in cash without interest. We have the right to redeem these Trust I Preferred Securities at any time.
(j)Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2061.
(k)Amounts include KMI outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months. See “—Current Portion of Debt” below.
(l)Excludes our “Debt fair value adjustments” which, as of December 31, 2021 and 2020, increased our combined debt balances by $902 million and $1,293 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see “—Debt Fair Value Adjustments” below.
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Current Portion of Debt
The following table details the components of our “Current portion of debt” reported on our consolidated balance sheets:
December 31,
2021
2020
(In millions)
$3.5 billion credit facility due August 20, 2026(a)
$
—
$
—
$500 million credit facility due November 16, 2023(a)
—
—
Commercial paper notes(a)
—
—
Current portion of senior notes
5.00%, due February 2021
—
750
3.50%, due March 2021
—
750
5.80%, due March 2021
—
400
5.00%, due October 2021
—
500
8.625%, due January 2022(b)
260
—
4.15%, due March 2022
375
—
1.50%, due March 2022(c)
853
—
3.95% due September 2022
1,000
—
Trust I Preferred Securities, 4.75% due March 2028(d)
111
111
Current portion of other debt
47
47
Total current portion of debt
$
2,646
$
2,558
(a)On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following.
(b)On January 18, 2022, we repaid these senior notes.
(c)Denominated in Euros.
(d)Reflects the portion of cash consideration payable if all the outstanding securities as of the end of the reporting period were converted by the holders.
We and substantially all of our wholly owned domestic subsidiaries are a party to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement.
Credit Facility and Restrictive Covenants
On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 with a syndicate of lenders, which can be increased by up to $1.0 billion if certain conditions, including the receipt of additional lender commitments, are met. Borrowings under the New Credit Facility may be used for working capital and other general corporate purposes. On the same date, we also entered into a first amendment (the “Amendment”) to our existing Revolving Credit Agreement, dated as of November 16, 2018 (as amended prior to the Amendment, the “Existing Credit Facility”). The Amendment provides for certain amendments to the Existing Credit Facility to, among other things, reduce the Existing Credit Facility’s borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder. The combined credit facilities continue to support our $4 billion commercial paper program.
As of December 31, 2021, we had borrowing capacity of approximately $3.9 billion under our credit facilities. We also continue to maintain a $4 billion commercial paper program through the private placement of short-term notes. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.
Depending on the type of loan request, our credit facility borrowings under our credit facilities bear interest at either (i) LIBOR adjusted for a eurocurrency funding reserve plus an applicable margin ranging from 1.000% to 1.750% (for our New Credit Facility) or to 2.000% (for our Existing Credit Facility) per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; or (3) LIBOR for a one-month eurodollar loan adjusted for a
101
eurocurrency funding reserve, plus 1%, plus, in each case, an applicable margin ranging from 0.100% to 0.750% (for our New Credit Facility) or to 1.000% (for our Existing Credit Facility) per annum based on our credit rating. Standby fees for the unused portion of the credit facility will be calculated at a rate ranging from 0.100% to 0.250% (for our New Credit Facility) or to 0.300% (for our Existing Credit Facility). The New Credit Facility also includes customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available.
Our credit facility contains financial and various other covenants that apply to us and our subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (as defined in the credit facility) of 5.50 to 1.00, for any four-fiscal-quarter period. Other negative covenants include restrictions on our and certain of our subsidiaries’ ability to incur debt, grant liens, make fundamental changes or engage in certain transactions with affiliates, or in the case of certain material subsidiaries, permit restrictions on dividends, distributions or making or prepayments of loans to us or any guarantor. Our credit facility also restricts our ability to make certain restricted payments if an event of default (as defined in the credit facility) has occurred and is continuing or would occur and be continuing.
As of December 31, 2021, we had no borrowings outstanding under our credit facility, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilities as of December 31, 2021 was approximately $3.9 billion. As of December 31, 2021, we were in compliance with all required covenants.
Maturities of Debt
The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2021, are summarized as follows:
Year
Total
(In millions)
2022
$
2,646
2023
3,250
2024
1,925
2025
1,567
2026
1,102
Thereafter
21,928
Total
$
32,418
Debt Fair Value Adjustments
The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets:
December 31,
2021
2020
(In millions)
Purchase accounting debt fair value adjustments
$
498
$
546
Carrying value adjustment to hedged debt
376
702
Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a)
223
240
Unamortized debt discounts, net
(71)
(76)
Unamortized debt issuance costs
(124)
(119)
Total debt fair value adjustments
$
902
$
1,293
(a)As of December 31, 2021, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 13 years.
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Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances is disclosed below:
December 31, 2021
December 31, 2020
Carrying value
Estimated fair value
Carrying value
Estimated fair value
(In millions)
Total debt
$
33,320
$
37,775
$
34,689
$
39,622
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2021 and 2020.
Interest Rates, Interest Rate Swaps and Contingent Debt
The weighted average interest rate on all of our borrowings was 4.67% during 2021 and 4.86% during 2020. Information on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13“Commitments and Contingent Liabilities—Contingent Debt”).
10. Share-based Compensation and Employee Benefits
Share-based Compensation
Class P Common Stock
Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors
We have a Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors, in which our eligible non-employee directors participate. The plan recognizes that the compensation paid to each eligible non-employee director is fixed by our board of directors, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each eligible non-employee director may elect to receive shares of Class P common stock. Each election will be generally at or around the first board of directors meeting in January of each calendar year and will be effective for the entire calendar year. An eligible director may make a new election each calendar year. The total number of shares of Class P common stock authorized under the plan is 1,190,000. During 2021, 2020 and 2019, we made restricted Class P common stock grants to our non-employee directors of 49,890, 14,570 and 23,100, respectively. These grants were valued at time of issuance at $0.8 million, $0.3 million and $0.4 million, respectively. All of the restricted stock awards made to non-employee directors vest during a 6-month period.
Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan
The Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan is an equity awards plan available to eligible employees. The total number of shares of Class P common stock authorized under the plan is 63,000,000. The following table sets forth a summary of activity and related balances of our restricted stock awards excluding that issued to non-employee directors:
Shares
Weighted Average Grant Date Fair Value per Share
(In thousands, except per share amounts)
Outstanding at December 31, 2020
12,682
$
17.79
Granted
4,705
17.44
Vested
(4,463)
17.89
Forfeited
(307)
17.47
Outstanding at December 31, 2021
12,617
$
17.63
103
The following table sets forth additional information related to our restricted stock awards excluding that issued to non-employee directors:
Year Ended December 31,
2021
2020
2019
(In millions, except per share amounts)
Weighted average grant date fair value per share
$
17.44
$
15.10
$
20.46
Intrinsic value of awards vested during the year
77
59
87
Restricted stock awards made to employees have vesting periods ranging from 1 year up to 10 years. Following is a summary of the future vesting of our outstanding restricted stock awards:
Year
Vesting of Restricted Shares
(In thousands)
2022
2,832
2023
5,552
2024
3,662
2025
513
2026
58
Total Outstanding
12,617
During 2021, 2020 and 2019, we recorded $59 million, $73 million and $62 million, respectively, in expense related to restricted stock awards and capitalized approximately $9 million, $11 million and $12 million, respectively. We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements. At December 31, 2021, unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $112 million with a weighted average remaining amortization period of 1.98 years.
Pension and Other Postretirement Benefit (OPEB) Plans
Savings Plan
We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain collectively bargained participants receive Company contributions in accordance with collective bargaining agreements. A participant becomes fully vested in Company contributions after two years and may take a distribution upon termination of employment or retirement. The total cost for our savings plan was approximately $48 million, $53 million, and $50 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Pension Plans
Our pension plans are defined benefit plans that cover substantially all of our U.S. employees and provide benefits under a cash balance formula. A participant in the cash balance formula accrues benefits through contribution credits based on a combination of age and years of service, multiplied by eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years and may take a lump sum or annuity distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees accrue benefits through career pay or final pay formulas.
OPEB Plans
We and certain of our subsidiaries provide OPEB benefits, including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. These plans provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits.
104
Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2021 and 2020:
Pension Benefits
OPEB
2021
2020
2021
2020
(In millions)
Change in benefit obligation:
Benefit obligation at beginning of period
$
2,844
$
2,696
$
299
$
333
Service cost
53
59
1
1
Interest cost
45
71
4
8
Actuarial (gain) loss
(80)
198
(21)
(17)
Benefits paid
(204)
(180)
(28)
(29)
Participant contributions
—
—
1
2
Medicare Part D subsidy receipts
—
—
1
1
Benefit obligation at end of period
2,658
2,844
257
299
Change in plan assets:
Fair value of plan assets at beginning of period
2,199
2,076
361
333
Actual return on plan assets
180
178
40
47
Employer contributions
56
125
7
7
Participant contributions
—
—
1
2
Medicare Part D subsidy receipts
—
—
1
1
Benefits paid
(204)
(180)
(28)
(29)
Fair value of plan assets at end of period
2,231
2,199
382
361
Funded status - net (liability) asset at December 31,
$
(427)
$
(645)
$
125
$
62
The 2021 net actuarial gain for the pension plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligation as of December 31, 2021, partially offset by changes made to the assumptions used to determine at what age and in what form benefits commence. The 2021 net actuarial gain for the OPEB plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligations as of December 31, 2021 and changes in the claims cost assumptions. The 2020 net actuarial loss for the pension plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligation as of December 31, 2020. The 2020 net actuarial gain for the OPEB plans was primarily due to changes in the claims cost and trend assumptions, partially offset by a decrease in the weighted average discount rate used to determine the benefit obligations as of December 31, 2020.
Components of Funded Status. The following table details the amounts recognized in our balance sheets at December 31, 2021 and 2020 related to our pension and OPEB plans:
Pension Benefits
OPEB
2021
2020
2021
2020
(In millions)
Non-current benefit asset(a)
$
—
$
—
$
302
$
269
Current benefit liability
—
—
(18)
(19)
Non-current benefit liability
(427)
(645)
(159)
(188)
Funded status - net (liability) asset at December 31,
$
(427)
$
(645)
$
125
$
62
(a)2021 and 2020 OPEB amounts include $54 million and $46 million, respectively, of non-current benefit assets related to a plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and for which we have recorded an offsetting related party deferred credit.
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Components of Accumulated Other Comprehensive (Loss) Income. The following table details the amounts of pre-tax accumulated other comprehensive (loss) income at December 31, 2021 and 2020 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets:
Pension Benefits
OPEB
2021
2020
2021
2020
(In millions)
Unrecognized net actuarial (loss) gain
$
(495)
$
(674)
$
176
$
153
Unrecognized prior service (cost) credit
(2)
(2)
6
9
Accumulated other comprehensive (loss) income
$
(497)
$
(676)
$
182
$
162
Our accumulated benefit obligation for our pension plans was $2,608 million and $2,804 million at December 31, 2021 and 2020, respectively.
Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $219 million and $255 million at December 31, 2021 and 2020, respectively. The fair value of these plans’ assets was approximately $42 million and $48 million at December 31, 2021 and 2020, respectively.
Plan Assets. The investment policies and strategies are established by our plan’s fiduciary committee for the assets of each of the pension and OPEB plans, which are responsible for investment decisions and management oversight of the plans. The stated philosophy of the fiduciary committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (i) meet or exceed plan actuarial earnings assumptions over the long term and (ii) provide a reasonable return on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the fiduciary committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the fiduciary committee has adopted a strategy of using multiple asset classes.
As of December 31, 2021, the allowable range for asset allocations in effect for our pension plan were 42% to 52% equities, 37% to 47% fixed income securities, 2% to 12% real estate and 0% to 10% company securities (KMI Class P common stock and/or debt securities). As of December 31, 2021, the allowable range for asset allocations in effect for our OPEB plans were 0% to 22% cash, 46% to 68% equities and 25% to 50% fixed income securities.
Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used for assets measured at fair value.
•Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are cash, equities and exchange traded mutual funds. These investments are valued at the closing price reported on the active market on which the individual securities are traded.
•Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices.
•Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as reported by the issuers are determined based on the fair value of the underlying securities as of the valuation date and include common/collective trust funds, private investment funds and limited partnerships. The plan assets measured at NAV are not categorized within the fair value hierarchy described above, but are separately identified in the following tables.
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Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 2021 and 2020:
Pension Assets
2021
2020
Level 1
Level 2
Total
Level 1
Level 2
Total
(In millions)
Measured within fair value hierarchy
Cash
$
11
$
—
$
11
$
—
$
—
$
—
Short-term investment funds
—
25
25
—
77
77
Equities(a)
153
—
153
249
—
249
Fixed income securities(b)
—
566
566
—
425
425
Derivatives
—
—
—
—
11
11
Subtotal
$
164
$
591
755
$
249
$
513
762
Measured at NAV(c)
Common/collective trusts(d)
1,389
1,184
Private investment funds(e)
39
208
Private limited partnerships(f)
48
45
Subtotal
1,476
1,437
Total plan assets fair value
$
2,231
$
2,199
(a)Plan assets include $97 million and $83 million of KMI Class P common stock for 2021 and 2020, respectively.
(b)Plan assets include $1 million of KMI debt securities for 2020.
(c)Plan assets which used NAV as a practical expedient to measure fair value.
(d)Common/collective trust funds were invested in approximately 83% equities and 17% fixed income securities in 2021 and 71% equities and 29% fixed income securities in 2020.
(e)Private investment funds were invested in 100% fixed income securities in 2021 and approximately 29% equities and 71% fixed income securities in 2020.
(f)Includes assets invested in real estate, venture and buyout funds.
OPEB Assets
2021
2020
Level 1
Level 2
Total
Level 1
Level 2
Total
(In millions)
Measured within fair value hierarchy
Short-term investment funds
$
—
$
3
$
3
$
—
$
5
$
5
Measured at NAV(a)
Common/collective trusts(b)
379
356
Total plan assets fair value
$
382
$
361
(a)Plan assets which used NAV as a practical expedient to measure fair value.
(b)Common/collective trust funds were invested in approximately 63% equities and 37% fixed income securities for 2021 and 65% equities and 35% fixed income securities for 2020.
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Expected Payment of Future Benefits and Employer Contributions. As of December 31, 2021, we expect to make the following benefit payments under our plans:
Fiscal year
Pension Benefits
OPEB(a)
(In millions)
2022
$
212
$
28
2023
210
26
2024
204
24
2025
199
22
2026
194
21
2027 - 2031
864
84
(a)Includes a reduction of approximately $1 million in each of the years 2022 through 2026 and approximately $4 million in aggregate for the period 2027 - 2031 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
In 2022, we expect to contribute approximately $50 million to our pension plans and $7 million, net of anticipated subsidies, to our OPEB plans.
Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation and net benefit costs of our pension and OPEB plans for 2021, 2020 and 2019:
Pension Benefits
OPEB
2021
2020
2019
2021
2020
2019
(In millions)
Assumptions related to benefit obligations:
Discount rate
2.74
%
2.27
%
3.17
%
2.56
%
2.08
%
3.03
%
Rate of compensation increase
3.50
%
3.50
%
3.50
%
n/a
n/a
n/a
Interest crediting rate
3.01
%
2.57
%
3.71
%
n/a
n/a
n/a
Assumptions related to benefit costs:
Discount rate for benefit obligations
2.27
%
3.17
%
4.26
%
2.08
%
3.03
%
4.16
%
Discount rate for interest on benefit obligations
1.60
%
2.71
%
3.89
%
1.46
%
2.63
%
3.83
%
Discount rate for service cost
2.33
%
3.24
%
4.28
%
2.70
%
3.48
%
4.51
%
Discount rate for interest on service cost
1.70
%
2.80
%
3.93
%
2.63
%
3.39
%
4.46
%
Expected return on plan assets(a)
6.25
%
6.75
%
7.25
%
5.75
%
6.50
%
6.50
%
Rate of compensation increase
3.50
%
3.50
%
3.50
%
n/a
n/a
n/a
Interest crediting rate
2.57
%
3.71
%
3.90
%
n/a
n/a
n/a
(a)The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes (UBIT), we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on UBIT rates of 27% for each of 2021, 2020 and 2019.
We utilize a full yield curve approach in the estimation of the service and interest cost components of net periodic benefit cost (credit) for our retirement benefit plans by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class.
Actuarial estimates for our OPEB plans assume an annual increase in the per capita cost of covered health care benefits; the initial annual rate of increase is 5.63% which gradually decreases to 4.00% by the year 2046.
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Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows:
Pension Benefits
OPEB
2021
2020
2019
2021
2020
2019
(In millions)
Components of net benefit cost (credit):
Service cost
$
53
$
59
$
53
$
1
$
1
$
1
Interest cost
45
71
96
4
8
12
Expected return on assets
(133)
(137)
(129)
(16)
(16)
(16)
Amortization of prior service cost (credit)
—
1
—
(5)
(5)
(4)
Amortization of net actuarial loss (gain)
52
40
54
(17)
(13)
(11)
Net benefit cost (credit)
17
34
74
(33)
(25)
(18)
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net (gain) loss arising during period
(127)
157
(42)
(40)
(43)
(17)
Amortization or settlement recognition of net actuarial (loss) gain
(52)
(40)
(54)
17
13
11
Amortization of prior service (cost) credit
—
(1)
—
3
3
2
Total recognized in total other comprehensive (income) loss(a)
(179)
116
(96)
(20)
(27)
(4)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss
$
(162)
$
150
$
(22)
$
(53)
$
(52)
$
(22)
(a)Excludes $3 million and $2 million for the years ended December 31, 2021 and 2020, respectively, associated with other plans.
Multiemployer Plans
We participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans were approximately $8 million, $6 million and $8 million for the years ended December 31, 2021, 2020 and 2019, respectively. We consider the overall multi-employer pension plan liability exposure to be immaterial in relation to the value of its total consolidated assets and net income.
11.
Stockholders’ Equity
Class P Common Stock
On July 19, 2017, our board of directors approved a $2 billion share buy-back program that began in December 2017. During the year ended December 31, 2021, we did not repurchase any shares. During the years ended December 31, 2020 and 2019, we repurchased approximately 4.0 million and 0.1 million, respectively, of our shares for approximately $50 million and $2 million, respectively. Since December 2017, in total, we have repurchased approximately 32 million of our shares under the program at an average price of approximately $17.71 per share for approximately $575 million.
On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares having an aggregate offering price of up to $5.0 billion from
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time to time during the term of this agreement. During the years ended December 31, 2021, 2020 and 2019 we did not issue any shares under this agreement.
Dividends
The following table provides information about our per share dividends:
Year Ended December 31,
2021
2020
2019
Per share cash dividend declared for the period
$
1.08
$
1.05
$
1.00
Per share cash dividend paid in the period
1.0725
1.0375
0.95
On January 19, 2022, our board of directors declared a cash dividend of $0.27 per share for the quarterly period ended December 31, 2021, which is payable on February 15, 2022 to shareholders of record as of January 31, 2022.
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 at December 31, 2018
$
164
$
(91)
$
(403)
$
(330)
Other comprehensive (loss) gain before reclassifications
(177)
—
77
(100)
Losses reclassified from accumulated other comprehensive loss(a)
6
91
—
97
Net current-period change in accumulated other comprehensive income (loss)
(171)
91
77
(3)
Balance at December 31, 2019
(7)
—
(326)
(333)
Other comprehensive gain (loss) before reclassifications
249
—
(68)
181
Gains reclassified from accumulated other comprehensive loss
(255)
—
—
(255)
Net current-period change in accumulated other comprehensive loss
(6)
—
(68)
(74)
Balance at December 31, 2020
(13)
—
(394)
(407)
Other comprehensive (loss) gain before reclassifications
(432)
—
155
(277)
Losses reclassified from accumulated other comprehensive loss
273
—
—
273
Net current-period change in accumulated other comprehensive loss
(159)
—
155
(4)
Balance at December 31, 2021
$
(172)
$
—
$
(239)
$
(411)
(a)Amount for foreign currency translation adjustments reflect the deferred losses recognized in income during the year ended December 31, 2019 related to the sale of KML.
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Noncontrolling Interests
KML Distributions
In accordance with its dividend policy, KML, our former indirect subsidiary, paid cash dividends to the public during the year ended December 31, 2019 of $17 million and $22 million, on its restricted voting shares and preferred shares, respectively.
On January 3, 2019, KML distributed approximately $0.9 billion of the net proceeds from the TMPL Sale to its public held restricted voting shareholders as a return of capital.
12. Related Party Transactions
Affiliate Balances
We have transactions with affiliates which consist of (i) unconsolidated affiliates in which we hold an investment accounted for under the equity method of accounting (see Note 7 for additional information related to these investments); and (ii) external partners of our joint ventures we consolidate, and for periods prior to the sale of KML, our proportional method joint ventures, for which we include our proportionate share of activity in our financial statements.
The following tables summarize our affiliate balance sheet balances and income statement activity, other than amounts reported within our “Investments” balances and “Earnings from equity investments” activity:
December 31,
2021
2020
(In millions)
Balance sheet location
Accounts receivable
$
38
$
41
Other current assets
4
6
Deferred charges and other assets
—
109
$
42
$
156
Current portion of debt
$
6
$
6
Accounts payable
21
25
Other current liabilities
4
4
Long-term debt
148
154
Other long-term liabilities and deferred credits
56
48
$
235
$
237
Year Ended December 31,
2021
2020
2019
(In millions)
Income statement location
Revenues
$
164
$
206
$
269
Operating Costs, Expenses and Other
Costs of sales
$
145
$
116
$
75
Other operating expenses
52
119
132
13. Commitments and Contingent Liabilities
Rights-Of-Way Obligations
Our rights-of-way obligations primarily consist of non-lease agreements that existed at the time of Topic 842 adoption, at which time we elected a practical expedient which allowed us to continue our historical treatment. Our future minimum rental commitments related to our rights-of-way obligations were $149 million as of December 31, 2021.
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Contingent Debt
Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote.
As of December 31, 2021 and 2020, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $170 million and $217 million, respectively. December 31, 2021 and 2020 amounts are represented by our proportional share of the debt obligations of one and three equity investees, respectively. Under such guarantees we are severally liable for our percentage ownership share of these equity investees’ debt issued in the event of their non-performance. The contingent debt obligations balances as of December 31, 2021 and 2020 included $120 million and $122 million, respectively, for 100% guaranteed debt obligations for a subsidiary of our equity investee, Cortez Pipeline Company.
Guarantees and Indemnifications
We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.
While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are also circumstances where the amount and duration are unlimited. Currently, we are not subject to any material requirements to perform under quantifiable arrangements other than as described above. We are unable to estimate a maximum exposure for our other guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.
See Note 18 for a description of matters that we have identified as contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or indemnification agreements.
14. Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.
112
Energy Commodity Price Risk Management
As of December 31, 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
(18.4)
MMBbl
Crude oil basis
(6.5)
MMBbl
Natural gas fixed price
(54.2)
Bcf
Natural gas basis
(43.9)
Bcf
NGL fixed price
(0.7)
MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price
(1.0)
MMBbl
Crude oil basis
(9.1)
MMBbl
Natural gas fixed price
(13.2)
Bcf
Natural gas basis
(38.5)
Bcf
NGL fixed price
(1.4)
MMBbl
As of December 31, 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.
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 December 31, 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(b)
5,100
Mark-to-Market
December 2022
(a)The principal amount of hedged senior notes consisted of $750 million included in “Current portion of debt” and $6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.
(b)Of this notional amount, $4,860 million became effective January 4, 2022.
During the year ended December 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 rates through February 2028. In addition, we entered into variable-to-fixed interest rate swap agreements with a combined notional principal amount of $5,100 million. These agreements were not designated as accounting hedges and effectively fixed our LIBOR exposure for a portion of our fixed-to-variable interest rate swaps for 2022.
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 December 31, 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 all of our Euro-denominated debt.
113
Impact of Derivative Contracts on Our Consolidated Financial Statements
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:
Fair Value of Derivative Contracts
Derivatives Asset
Derivatives Liability
December 31,
December 31,
2021
2020
2021
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)
$
61
$
42
$
(141)
$
(33)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
3
33
(94)
(8)
Subtotal
64
75
(235)
(41)
Interest rate contracts
Fair value of derivative contracts/(Other current liabilities)
101
119
(3)
(3)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
284
575
(15)
(7)
Subtotal
385
694
(18)
(10)
Foreign currency contracts
Fair value of derivative contracts/(Other current liabilities)
35
—
(3)
(6)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
6
138
—
—
Subtotal
41
138
(3)
(6)
Total
490
907
(256)
(57)
Derivatives not designated as
hedging instruments
Energy commodity derivative contracts
Fair value of derivative contracts/(Other current liabilities)
11
24
(31)
(21)
Deferred charges and other assets/(Other long-term liabilities and deferred credits)
1
—
(6)
—
Subtotal
12
24
(37)
(21)
Interest rate contracts
Fair value of derivative contracts/(Other current liabilities)
12
—
—
—
Total
24
24
(37)
(21)
Total derivatives
$
514
$
931
$
(293)
$
(78)
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.
114
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 December 31, 2021
Energy commodity derivative contracts(a)
$
56
$
20
$
—
$
76
$
(53)
$
(20)
$
3
Interest rate contracts
—
397
—
397
(9)
—
388
Foreign currency contracts
—
41
—
41
(3)
—
38
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 December 31, 2021
Energy commodity derivative contracts(a)
$
(15)
$
(257)
$
—
$
(272)
$
53
$
—
$
(219)
Interest rate contracts
—
(18)
—
(18)
9
—
(9)
Foreign currency contracts
—
(3)
—
(3)
3
—
—
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 income and comprehensive income:
Derivatives in fair value hedging relationships
Location
Gain/(loss) recognized in income on derivatives and related hedged item
Year Ended December 31,
2021
2020
2019
(In millions)
Interest rate contracts
Interest, net
$
(322)
$
335
$
340
Hedged fixed rate debt(a)
Interest, net
$
326
$
(343)
$
(353)
(a)As of December 31, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $376 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheets.
115
Derivatives in cash flow hedging relationships
Gain/(loss) recognized in OCI on derivative(a)
Location
Gain/(loss) reclassified from Accumulated OCI into income(b)
Year Ended
Year Ended
December 31,
December 31,
2021
2020
2019
2021
2020
2019
(In millions)
(In millions)
Energy commodity derivative
contracts
$
(475)
$
240
$
(168)
Revenues—Commodity sales
$
(271)
$
222
$
16
Costs of sales
20
(14)
5
Interest rate contracts(c)
5
(8)
(1)
Earnings from equity
investments(c)
—
—
2
Foreign currency contracts
(93)
92
(60)
Other, net
(105)
125
(31)
Total
$
(563)
$
324
$
(229)
Total
$
(356)
$
333
$
(8)
(a)We expect to reclassify an approximately $58 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 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 years ended December 31, 2021, 2020 and 2019, we recognized gains of $41 million, no gains and gains of $12 million, respectively, 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 in net investment hedging relationships
Gain/(loss) recognized in OCI on derivative
Location
Gain/(loss) reclassified from Accumulated OCI into income(a)
Year Ended
Year Ended
December 31,
December 31,
2021
2020
2019
2021
2020
2019
(In millions)
(In millions)
Foreign currency contracts
$
—
$
—
$
(8)
Loss (gain) on impairments and divestitures, net
$
—
$
—
$
83
Total
$
—
$
—
$
(8)
Total
$
—
$
—
$
83
(a)During the year ended December 31, 2019, we recognized an $83 million gain related to the KML and U.S. Cochin Sale. See Note 3.
Derivatives not designated as accounting hedges
Location
Gain/(Loss) recognized in income on derivatives
Year Ended December 31,
2021
2020
2019
(In millions)
Energy commodity derivative contracts
Revenues—Commodity sales
$
(652)
$
(1)
$
33
Costs of sales
152
25
(7)
Earnings from equity investments(b)
(5)
—
3
Interest rate contracts
Interest, net
12
—
—
Total(a)
$
(493)
$
24
$
29
(a)The years ended December 31, 2021, 2020 and 2019 include approximate losses of $479 million, $11 million and $8 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.
(b)Amounts represent our share of an equity investee’s income (loss).
Credit Risks
In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2021 and 2020, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2021, we had cash margins of $14 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our
116
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 sheets. The balance at December 31, 2021 represents the initial margin requirements of $6 million, offset by counterparty variation margin requirements of $20 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 December 31, 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 $155 million of additional collateral.
15. Revenue Recognition
Nature of Revenue by Segment
Natural Gas Pipelines Segment
We provide various types of natural gas transportation and storage services, natural gas and NGL sales contracts, and various types of gathering and processing services for producers, including receiving, compressing, transporting and re-delivering quantities of natural gas and/or NGLs made available to us by producers to a specified delivery location.
Natural Gas Transportation and Storage Contracts
The natural gas we receive under our transportation and storage contracts remains under the control of our customers. Under firm service contracts, the customer generally pays a two-part transaction price that includes (i) a fixed take-or-pay reservation fee and (ii) a fee-based per-unit rate for quantities of natural gas actually transported or injected into/withdrawn from storage. Under non-firm service contracts, generally described as interruptible service, the customer pays a transaction price on a fee-based per-unit rate for the quantities actually transported or injected into/withdrawn from storage.
Natural Gas and NGL Sales Contracts
Our sales and purchases of natural gas and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales. These customer contracts generally provide for the customer to nominate a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.
Gathering and Processing Contracts
We provide various types of gathering and processing services for producers, including receiving, processing, compressing, transporting and re-delivering quantities of natural gas made available to us by producers to a specified delivery location. This integrated service can be firm if subject to a minimum volume commitment or acreage dedication or non-firm when offered on an as requested, non-guaranteed basis. In our gathering contracts we generally promise to provide the contracted integrated services each day over the life of the contract. The customer pays a transaction price typically based on a per-unit rate for the quantities actually gathered and/or processed, including amounts attributable to deficiency quantities associated with minimum volume contracts.
Products Pipelines Segment
We provide crude oil and refined petroleum transportation and storage services on a firm or non-firm basis. For our firm transportation service, the customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it flows volumes into our pipeline. The customer pays a transaction price typically based on a per-unit rate for quantities transported, including amounts attributable to deficiency quantities. Our firm storage service generally includes a fixed take-or-pay monthly reservation fee for the portion of storage capacity reserved by the customer and a per-unit rate for actual quantities injected into/withdrawn from storage. Under the non-firm transportation and storage service the customer typically pays a per-unit rate for actual quantities of product injected into/withdrawn from storage and/or transported.
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We sell transmix, crude oil or other commodity products. The customer’s contracts generally include a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.
Terminals Segment
We provide various types of liquid tank and bulk terminal services. These services are generally comprised of inbound, storage and outbound handling of customer products.
Liquids Tank Services
Firm Storage and Handling Contracts: We have liquids tank storage and handling service contracts that include a promised tank storage capacity provision and prepaid volume throughput of the stored product. In these contracts, the customers have fixed take-or-pay monthly obligation which generally include a per-unit rate for any quantities we handle at the request of the customer in excess of the prepaid volume throughput amount and also typically include per-unit rates for additional, ancillary services that may be periodically requested by the customer.
Firm Handling Contracts: For our firm handling service contracts, we typically promise to handle on a stand-ready basis throughput volumes up to the customer’s minimum volume commitment amount. The customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it used the handling service. The customer pays a transaction price typically based on a per-unit rate for volumes handled, including amounts attributable to deficiency quantities.
Bulk Services
Our bulk storage and handling contracts generally include inbound handling of our customers’ dry bulk material product (e.g. petcoke, metals, ores) into our storage facility and outbound handling of these products from our storage facility. These services are provided on both a firm basis, including amounts attributable to deficiency quantities, and non-firm basis where the customer pays a transaction price typically based on a per-unit rate for quantities handled on an as requested, non-guaranteed basis.
CO2 Segment
Our crude oil, NGL, CO2 and natural gas production customer sales contracts typically include a specified quantity and quality of commodity product to be delivered and sold to the customer at a specified delivery point. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.
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Disaggregation of Revenues
The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:
Year Ended December 31, 2021
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
3,402
$
259
$
751
$
1
$
(2)
$
4,411
Fee-based services
746
949
375
45
(1)
2,114
Total services
4,148
1,208
1,126
46
(3)
6,525
Commodity sales
Natural gas sales
6,463
—
—
32
(15)
6,480
Product sales
1,260
845
24
1,070
(50)
3,149
Total commodity sales
7,723
845
24
1,102
(65)
9,629
Total revenues from contracts with customers
11,871
2,053
1,150
1,148
(68)
16,154
Other revenues(c)
Leasing services(d)
473
172
565
56
—
1,266
Derivatives adjustments on commodity sales
(700)
(1)
—
(222)
—
(923)
Other
65
21
—
27
—
113
Total other revenues
(162)
192
565
(139)
—
456
Total revenues
$
11,709
$
2,245
$
1,715
$
1,009
$
(68)
$
16,610
Year Ended December 31, 2020
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
3,345
$
271
$
756
$
1
$
(3)
$
4,370
Fee-based services
714
905
395
42
—
2,056
Total services
4,059
1,176
1,151
43
(3)
6,426
Commodity sales
Natural gas sales
2,038
—
—
1
(7)
2,032
Product sales
562
358
14
735
(30)
1,639
Total commodity sales
2,600
358
14
736
(37)
3,671
Total revenues from contracts with customers
6,659
1,534
1,165
779
(40)
10,097
Other revenues(c)
Leasing services(d)
466
166
557
47
—
1,236
Derivatives adjustments on commodity sales
18
—
—
203
—
221
Other
116
21
—
9
—
146
Total other revenues
600
187
557
259
—
1,603
Total revenues
$
7,259
$
1,721
$
1,722
$
1,038
$
(40)
$
11,700
119
Year Ended December 31, 2019
Natural Gas Pipelines
Products Pipelines
Terminals
CO2
Corporate and Eliminations
Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)
$
3,549
$
319
$
1,012
$
1
$
(4)
$
4,877
Fee-based services
780
1,016
560
60
—
2,416
Total services
4,329
1,335
1,572
61
(4)
7,293
Commodity sales
Natural gas sales
2,603
—
—
1
(9)
2,595
Product sales
805
289
20
1,111
(33)
2,192
Total commodity sales
3,408
289
20
1,112
(42)
4,787
Total revenues from contracts with customers
7,737
1,624
1,592
1,173
(46)
12,080
Other revenues(c)
Leasing services(d)
273
182
442
54
—
951
Derivatives adjustments on commodity sales
70
—
—
(21)
—
49
Other
90
25
—
13
1
129
Total other revenues
433
207
442
46
1
1,129
Total revenues
$
8,170
$
1,831
$
2,034
$
1,219
$
(45)
$
13,209
(a)Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c)).
(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 indexed-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 14 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 December 31, 2021 and 2020, our contract asset balances were $39 million and $20 million, respectively. Of the contract asset balance at December 31, 2020, $18 million was transferred to accounts receivable during the year ended December 31. 2021. As of December 31, 2021 and 2020, our contract liability balances were $212 million and $239 million, respectively. Of the contract liability balance at December 31, 2020, $83 million was recognized as revenue during the year ended December 31, 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 December 31, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods:
Year
Estimated Revenue
(In millions)
2022
$
4,324
2023
3,418
2024
2,857
2025
2,382
2026
2,108
Thereafter
12,618
Total
$
27,707
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.
16. Reportable Segments
Our reportable business segments are:
•Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG regasification, liquefaction and storage facilities;
•Products Pipelines—the ownership and operation of refined petroleum products, crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, crude oil and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;
•Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada (prior to the sale of KML in December 2019) that store and handle various commodities including gasoline, diesel fuel, chemicals, renewable fuels, metals and petroleum coke; and (ii) Jones Act-qualified tankers;
•CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 as a flooding medium to increase recovery and production of crude oil from mature oil fields; (ii) ownership interests in and/or operation of oil fields and gasoline processing plants in West Texas; (iii) the ownership and operation of a crude oil pipeline system in West Texas; and (iv) the ownership and operation of RNG and LNG facilities in Indiana associated with our acquisition of Kinetrex (see Note 3).
We evaluate performance principally based on each segment’s EBDA, which excludes general and administrative expenses and corporate charges, interest expense, net, and income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision makers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and services and marketing strategies.
We consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our reporting segments. We account for intersegment sales at market prices, while we account for asset transfers at book value.
During 2021, 2020 and 2019, we did not have revenues from any single external customer that exceeded 10% of our consolidated revenues.
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Financial information by segment follows:
Year Ended December 31,
2021
2020
2019
(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers
$
11,644
$
7,222
$
8,128
Intersegment revenues
65
37
42
Products Pipelines
2,245
1,721
1,831
Terminals
Revenues from external customers
1,712
1,719
2,031
Intersegment revenues
3
3
3
CO2
1,009
1,038
1,219
Corporate and intersegment eliminations
(68)
(40)
(45)
Total consolidated revenues
$
16,610
$
11,700
$
13,209
Year Ended December 31,
2021
2020
2019
(In millions)
Operating expenses(a)
Natural Gas Pipelines
$
7,000
$
3,457
$
4,213
Products Pipelines
1,239
779
684
Terminals
793
762
888
CO2
289
404
496
Corporate and intersegment eliminations
(34)
(4)
(1)
Total consolidated operating expenses
$
9,287
$
5,398
$
6,280
Year Ended December 31,
2021
2020
2019
(In millions)
Other expense (income)(b)
Natural Gas Pipelines
$
1,597
$
1,009
$
(680)
Products Pipelines
—
21
—
Terminals
32
(50)
(342)
CO2
(8)
950
77
Kinder Morgan Canada
—
—
2
Corporate
(4)
—
(2)
Total consolidated other expense (income)
$
1,617
$
1,930
$
(945)
Year Ended December 31,
2021
2020
2019
(In millions)
DD&A
Natural Gas Pipelines
$
1,099
$
1,062
$
1,005
Products Pipelines
335
347
338
Terminals
440
438
494
CO2
236
291
548
Corporate
25
26
26
Total consolidated DD&A
$
2,135
$
2,164
$
2,411
122
Year Ended December 31,
2021
2020
2019
(In millions)
Earnings (loss) from equity investments and amortization of excess cost of equity investments, including loss on impairments of equity investments
Natural Gas Pipelines
$
435
$
551
$
(101)
Products Pipelines
34
45
63
Terminals
15
22
23
CO2
29
22
33
Total consolidated equity earnings
$
513
$
640
$
18
Year Ended December 31,
2021
2020
2019
(In millions)
Other, net-income (expense)
Natural Gas Pipelines
$
216
$
11
$
53
Products Pipelines
1
1
6
Terminals
3
13
(5)
Corporate
62
31
21
Total consolidated other, net-income (expense)
$
282
$
56
$
75
Year Ended December 31,
2021
2020
2019
(In millions)
Segment EBDA(c)
Natural Gas Pipelines
$
3,815
$
3,483
$
4,661
Products Pipelines
1,064
977
1,225
Terminals
908
1,045
1,506
CO2
760
(292)
681
Kinder Morgan Canada
—
—
(2)
Total Segment EBDA
6,547
5,213
8,071
DD&A
(2,135)
(2,164)
(2,411)
Amortization of excess cost of equity investments
(78)
(140)
(83)
General and administrative and corporate charges
(623)
(653)
(611)
Interest, net
(1,492)
(1,595)
(1,801)
Income tax expense
(369)
(481)
(926)
Total consolidated net income
$
1,850
$
180
$
2,239
Year Ended December 31,
2021
2020
2019
(In millions)
Capital expenditures
Natural Gas Pipelines
$
570
$
945
$
1,377
Products Pipelines
122
122
175
Terminals
332
433
347
CO2
230
186
349
Corporate
27
21
22
Total consolidated capital expenditures
$
1,281
$
1,707
$
2,270
123
December 31,
2021
2020
(In millions)
Investments
Natural Gas Pipelines
$
6,887
$
7,262
Products Pipelines
465
494
Terminals
137
136
CO2
89
25
Total consolidated investments
$
7,578
$
7,917
December 31,
2021
2020
(In millions)
Other intangibles, net
Natural Gas Pipelines
$
557
$
1,418
Products Pipelines
868
961
Terminals
51
64
CO2
202
10
Total consolidated other intangibles, net
$
1,678
$
2,453
December 31,
2021
2020
(In millions)
Assets
Natural Gas Pipelines
$
47,746
$
48,597
Products Pipelines
9,088
9,182
Terminals
8,513
8,639
CO2
2,843
2,478
Corporate assets(d)
2,226
3,077
Total consolidated assets
$
70,416
$
71,973
(a)Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)Includes loss (gain) on impairments and divestitures, net and other income, net.
(c)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss (gain) on impairments and divestitures, net and other income, net.
(d)Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy balances) not allocated to our reportable segments.
We do not attribute interest and debt expense to any of our reportable business segments.
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Following is geographic information regarding the revenues and long-lived assets of our business:
Year Ended December 31,
2021
2020
2019
(In millions)
Revenues from external customers
U.S.
$
16,479
$
11,625
$
12,833
Canada
—
—
300
Mexico and other foreign
131
75
76
Total consolidated revenues from external customers
$
16,610
$
11,700
$
13,209
December 31,
2021
2020
2019
(In millions)
Long-term assets, excluding goodwill and other intangibles
U.S.
$
44,916
$
46,384
$
46,709
Canada
1
1
1
Mexico and other foreign
78
81
82
Total consolidated long-lived assets
$
44,995
$
46,466
$
46,792
17. Leases
Following are components of our lease cost:
Year Ended December 31,
2021
2020
2019
(In millions)
Operating leases
$
60
$
55
$
136
Short-term and variable leases
109
101
92
Total lease cost(a)
$
169
$
156
$
228
(a)2021, 2020 and 2019 amounts include $32 million, $25 million and $46 million of capitalized lease costs, respectively.
Other information related to our operating leases are as follows:
Year Ended December 31,
2021
2020
2019
(In millions, except lease term and discount rate)
Operating cash flows from operating leases
$
(137)
$
(131)
$
(182)
Investing cash flows from operating leases
(32)
(25)
(46)
ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion
59
20
102
Amortization of ROU assets
47
46
75
Removal of ROU assets and liabilities associated with the KML and U.S. Cochin Sale
(394)
Weighted average remaining lease term
10.39 years
11.56 years
13.40 years
Weighted average discount rate
3.95
%
4.27
%
4.31
%
125
Amounts recognized in the accompanying consolidated balance sheet are as follows:
December 31,
Lease Activity
Balance sheet location
2021
2020
(In millions)
ROU assets
Deferred charges and other assets
$
315
$
303
Short-term lease liability
Other current liabilities
45
40
Long-term lease liability
Other long-term liabilities and deferred credits
270
263
Finance lease assets
Property, plant and equipment, net
1
1
Finance lease liabilities
Long-term debt—Outstanding
1
1
Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2021 are as follows:
Year
Commitment
(In millions)
2022
$
57
2023
51
2024
43
2025
36
2026
31
Thereafter
193
Total lease payments
411
Less: Interest
(96)
Present value of lease liabilities
$
315
Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.
18. 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 North, Oregon, and West Line Settlement in Docket No. IS22-100 (NOW Settlement) on January 14, 2022. The NOW Settlement will become final and effective on the date it is no longer subject to rehearing at the FERC, which is expected to be February 14, 2022. The amounts SFPP agreed to pay pursuant to the NOW Settlement were fully accrued on or before December 31, 2021. Together with the East Line Settlement (which the FERC approved previously on December 31, 2020 in Docket No. IS21-138), the NOW Settlement resolves all remaining disputes before the FERC (including Docket Nos. OR11-13, OR11-16, OR11-18, OR14-35, OR14-36, OR19-21, OR19-33, and OR19-37) and establishes a moratorium with settling shippers that prohibits the filing of a protest or complaint against SFPP’s FERC rates until February 1, 2025.
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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 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. In response to the foregoing lawsuit, Eni S.p.A. filed counterclaims under the terminal use agreement and claims under a parent direct agreement with Gulf LNG Energy (Port), LLC.The foregoing claims asserted by Eni S.p.A seek unspecified damages.On January 4, 2022, the trial court entered a decision granting Eni S.p.A’s motion for summary judgment on the claims asserted by GLNG under the Guarantee Agreement.GLNG will file an interlocutory appeal of the decision.Pending resolution of GLNG’s appeal, the foregoing counterclaims and other claims asserted by Eni S.p.A under the terminal use agreement and parent direct agreement remain pending in the trial court.
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. Eni USA’s second arbitration 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, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the second 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 pursuing the second arbitration, including the breach of contract and negligent misrepresentation claims therein. On October 4, 2021, the U.S. Supreme Court denied Eni USA’s petition for writ of certiorari. Consequently, Eni USA remains permanently enjoined from pursuing the second arbitration and the claims asserted therein.
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 an Award on the merits of all claims submitted to the tribunal and denied all of ALSS’s claims with prejudice. On November 23, 2021, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award.
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
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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 $276 million. We deny and are vigorously defending against these claims.
Freeport LNG Winter Storm Litigation
On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed suit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. We believe that our declaration of force majeure is valid and are vigorously defending 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 December 31, 2021 and 2020, our total reserve for legal matters was $231 million and $273 million, respectively.
Environmental Matters
We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to 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 to be more than $2.8 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
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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 in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately 20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a PRP within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG is conducting environmental assessments of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines. 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. and EPEC Oil Company Liquidating Trust (collectively EPEC) are identified as PRPs 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 in New Jersey. EPEC entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. EPEC is part of a joint defense group of approximately 44 cooperating parties which is directing and funding the AOC work required by the EPA. We have established a reserve for the anticipated cost of compliance with these two AOCs. On March 4, 2016, the EPA issued a Record of Decision (ROD) for the lower eight miles of the Site. At that time the cleanup plan in the ROD was estimated to cost $1.7 billion. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC, 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, 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 lower eight mile ROD. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the EPA concerning the upper nine miles. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the upper nine mile ROD. Until the ongoing discussions with the EPA conclude, 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 of the Site, 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
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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 U.S. District Court ordered the case to be remanded to the state district court for Plaquemines Parish. The defendants appealed that decision. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing. On August 5, 2021, the Fifth Circuit remanded the case to the U.S. District Court to determine whether there is federal officer jurisdiction. The case remains effectively stayed pending a ruling by the U.S. District Court on the federal officer issue. 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 these cases.
Products Pipeline Incident, Walnut Creek, California
On November 20, 2020, SFPP identified an issue on its Line Section 16 (LS-16) which transports petroleum products in California from Concord to San Jose. We shut down the pipeline and notified the appropriate regulatory agencies of a “threatened release” of gasoline. We investigated the issue over the next several days and on November 24, 2020, identified a crack in the pipeline and notified the regulatory agencies of a “confirmed release”. The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on November 26, 2020. We reported the estimated volume of gasoline released to be 8.1 Bbl. On December 2, 2020, complaints of gasoline odors were reported along the LS-16 pipeline corridor in Walnut Creek. A unified response was implemented by us along with the U.S. EPA, the California Office of Spill Prevention and Response, the California Fire Marshall, and the San Francisco Regional Water Quality Control Board. On December 8, 2020, we reported an updated estimated spill volume of up to 1,000 Bbl.
On October 28, 2021, we were informed by the California Attorney General it was contemplating criminal charges against us asserting the November 2020 discharge of gasoline affected waters of the State of California, and there was a failure to make timely notices of this discharge to appropriate state agencies. On December 16, 2021, we entered into a plea agreement with
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the State of California to resolve misdemeanor charges of the unintentional, non-negligent discharge of gasoline resulting from the release and the claimed failure to provide timely notices of the discharge to appropriate state agencies. Under the plea agreement, SFPP agreed to plead no-contest to two misdemeanors and to pay approximately $2.5 million in fines, penalties, restitution, environmental improvement project funding, and for enforcement training in the State of California, and to be placed on informal, unsupervised probation for a term of 18 months.
Since the November 2020 release, we have cooperated fully with federal and state agencies and have worked diligently to remediate the affected areas. We anticipate civil enforcement actions by federal and state agencies arising from the November 2020 release as well as ongoing monitoring and, where necessary, remediation under the oversight of the San Francisco Regional Water Quality Control Board until site conditions demonstrate no further actions are required. We do not anticipate the costs to resolve those enforcement matters, including the costs to monitor and further remediate the site, will have a material adverse impact to our business.
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 December 31, 2021 and 2020, we have accrued a total reserve for environmental liabilities in the amount of $243 million and $250 million, respectively. In addition, as of December 31, 2021 and 2020, we have recorded a receivable of $12 million for expected cost recoveries that have been deemed probable.
19.
Recent Accounting Pronouncements
Accounting Standards Updates
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 SOFR. 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.
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 was effective January 1, 2022. We adopted ASU No. 2020-06 with no material impact to our financial statements.
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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 was effective January 1, 2022. We adopted ASU No. 2021-05 with no material impact to our financial statements.
Item 16. Form 10-K Summary.
Not Applicable.
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SIGNATURES
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
/s/ David P. Michels
David P. Michels Vice President and Chief Financial Officer
Date:
February 7, 2022
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
Signature
Title
Date
/s/ DAVID P. MICHELS
Vice President and Chief Financial Officer (principal financial officer and principal accounting officer)
February 7, 2022
David P. Michels
/s/ STEVEN J. KEAN
Chief Executive Officer (principal executive officer); Director
