Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream business. Our operations are located in the United States.

Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.

As of December 31, 2019, our operations are presented within the following reportable segments: Atlantic-Gulf, Northeast G&P, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities as well as corporate activities are included in Other. Our reportable segments are comprised of the following businesses:


•	Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent equity-method investment in Constitution as of December 31, 2019.

•

Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent equity-method investment in Constitution as of December 31, 2019.


•	Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

•

Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).


•	West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, and a 15 percent equity-method investment in Brazos Permian II. West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), and our former 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), which was sold in April 2019,

•

West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, and a 15 percent equity-method investment in Brazos Permian II. West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were sold during the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), and our former 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), which was sold in April 2019,

and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements).


•	Other includes minor business activities that are not operating segments, as well as corporate operations. Other also includes our previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017.

•

Other includes minor business activities that are not operating segments, as well as corporate operations. Other also includes our previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017.

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report. Effective January 1, 2020, the composition of our reportable segments changed (see Part I, Item I Business Segments for further discussion).

Dividends

In December 2019, we paid a regular quarterly dividend of $0.38 per share. On January 28, 2020, our board of directors approved a regular quarterly dividend of $0.40 per share payable on March 30, 2020.

Overview

Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2019, increased $1.005 billion compared to the year ended December 31, 2018, reflecting:


•	A $1.451 billion decrease in Impairment of certain assets;


•	A $431 million increase in Service revenues primarily associated with Transco expansion projects, the consolidation of UEOM beginning March 2019, and growth in Northeast G&P volumes, partially offset by lower revenues from our Barnett Shale operations primarily associated with the reduced recognition of deferred revenue and the end of a contractual MVC period, as well as the absence of revenues from operations sold or deconsolidated during 2018;

•

A $431 million increase in Service revenues primarily associated with Transco expansion projects, the consolidation of UEOM beginning March 2019, and growth in Northeast G&P volumes, partially offset by lower revenues from our Barnett Shale operations primarily associated with the reduced recognition of deferred revenue and the end of a contractual MVC period, as well as the absence of revenues from operations sold or deconsolidated during 2018;


•	A $484 million decrease to Net income (loss) attributable to noncontrolling interests primarily due to the WPZ Merger in the third quarter of 2018, as well as the noncontrolling interests’ share of the 2019 Constitution impairment.

These favorable changes were partially offset by:


•	A $694 million decrease in the Gain on sale of certain assets and businesses primarily related to the sale of the Four Corners area business in the fourth quarter of 2018;


•	A $266 million decrease in Other investing income (loss) – net primarily due to the absence of 2018 gains on deconsolidations and 2019 impairments of equity-method investments, partially offset by a 2019 gain on the sale of our interest in Jackalope;


•	$138 million of lower commodity margins;


•	$74 million of higher net interest expense;


•	$58 million lower allowance for equity funds used during construction (AFUDC);


•	A $197 million increase in provision for income taxes driven by higher pre-tax income, partially offset by the absence of a 2018 charge to establish a valuation allowance on deferred tax assets that may not be realized following the WPZ merger.

Acquisition of UEOM

As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM. (See Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)

Northeast JV

Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion for a 35 percent ownership interest, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business. (See Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)

Sale of Jackalope

In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)

Constitution

Although Constitution received a certificate of public convenience and necessity from the FERC to construct and operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following extensive evaluation and discussion, recently determined that the underlying risk-adjusted return for this greenfield pipeline project has diminished in such a way that further development is no longer supported. (See Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements for further discussion.)

Expansion Project Updates

Significant expansion project updates for the period, including projects placed into service are described below. Ongoing major expansion projects are discussed later in Company Outlook.

Northeast G&P

Ohio River Supply Hub Expansion

We agreed to expand our services for certain customers to provide additional rich gas processing capacity in the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with these agreements, we have expanded the inlet processing capacity of our Oak Grove facility to 400 MMcf/d. We have also constructed a new NGL pipeline from Moundsville to the Harrison Hub fractionation facility to provide an additional outlet for NGLs. These expansions are supported by long-term, fee-based agreements and volumetric commitments.

Susquehanna Supply Hub Expansion

In November 2019, we completed a 500 MMcf/d expansion of the gathering systems in the Susquehanna Supply Hub to bring the capacity to approximately 4.3 Bcf/d.

Atlantic-Gulf

Rivervale South to Market

In August 2018, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New

Jersey. The project was placed into partial service in July 2019. The remaining portion of the project was placed into service in September 2019. The full project increased capacity by 190 Mdth/d.

Norphlet Project

In March 2016, we announced that we reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. We completed modifications to install an alternate delivery route to our Main Pass 261 Platform, as well as modifications to our onshore Mobile Bay processing facility. The project went in service early in July 2019, at which time we also purchased a 54-mile-long, 16-inch-diameter pipeline (the Norphlet Pipeline) for $200 million. This pipeline transports gas from the Appomattox development to our Main Pass 261 Platform.

Gateway

In December 2018, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company’s proposed interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations within New Jersey. The project was placed into service in December 2019 and increased capacity by 65 Mdth/d.

Gulf Connector

In January 2019, the Gulf Connector project was placed into service. This project expanded Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project increased capacity by 475 Mdth/d.

West

North Seattle Lateral Upgrade

In July 2018, we received approval from the FERC to expand delivery capabilities on Northwest Pipeline’s North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. The project was placed into service in November 2019. The project increased delivery capacity by approximately 159 Mdth/d.

Wamsutter Expansion

We have expanded our gathering and processing infrastructure in the Wamsutter region of Wyoming in order to meet our customers’ production plans. We have completed construction of new compressor stations and modifications to our processing facilities, which were placed into service throughout 2019. The expansion added approximately 20 miles of gathering pipelines and approximately 15,000 horsepower of compression.

Filing of Rate Case

On August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and were not subject to refund. In March 2019, the FERC accepted our motion to place the rates that were suspended by the September 2018 order into effect on March 1, 2019, subject to refund. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing, and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement. We anticipate FERC approval of the stipulation and agreement in the second quarter of 2020. As of December 31, 2019, we have provided a $189 million reserve for rate refunds related to increased rates collected since March 2019, which we believe is adequate for any refunds that may be required.

Commodity Prices

NGL per-unit margins were approximately 44 percent lower in 2019 compared to 2018 primarily due to a 31 percent and a 44 percent decrease in per-unit non-ethane and ethane sales prices, respectively, slightly offset by an approximate 10 percent decrease in per-unit natural gas feedstock prices.

NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

The potential impact of commodity prices on our business is further discussed in the following Company Outlook.

Company Outlook

Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders.

Our business plan for 2020 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs. Many of our producer customers are being impacted by extremely low natural gas and NGL prices, which are driving decreased drilling. We are responding by reducing the pace of our capital growth spending in our gathering and processing business and remaining committed to operating cost discipline.

In 2020, our operating results are expected to include increases from Transco’s recent expansion projects placed in-service and general rate settlement as previously discussed. We also expect an increase from a full year contribution from the Norphlet project, partially offset by lower deferred revenue amortization from Gulfstar, both in the Eastern Gulf region. Northeast results are expected to increase from higher gathering and processing volumes.We expect decreases in the West primarily due to lower deferred revenue amortization in the Barnett Shale and lower revenues from our Haynesville operations, partially offset by increased results from our DJ Basin and Eagle Ford operations. Additionally, we expect our recently implemented organizational realignment will benefit our expenses.

Our growth capital and investment expenditures in 2020 are expected to be in a range from $1.1 billion to $1.3 billion. Growth capital spending in 2020 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and our Bluestem NGL pipeline project in the Mid-Continent region. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

Potential risks and obstacles that could impact the execution of our plan include:


•	Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;


•	Counterparty credit and performance risk;


•	Unexpected significant increases in capital expenditures or delays in capital project execution;


•	Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;


•	Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;


•	General economic, financial markets, or further industry downturns, including increased interest rates;


•	Physical damages to facilities, including damage to offshore facilities by named windstorms;


•	Other risks set forth under Part I, Item 1A. Risk Factors in this report.

We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets which continue to serve key growth markets and supply basins in the United States.

Expansion Projects

Our ongoing major expansion projects include the following:

Atlantic-Gulf

Hillabee

In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completed in 2017 and it increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020, and together Phases I and II are expected to increase capacity by 1,025 Mdth/d.

Northeast Supply Enhancement

In May 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection remain pending, with each such agency having denied, without prejudice, Transco’s applications for such approvals. We have refiled our applications for those approvals and have addressed the technical issues identified by the agencies. We plan to place the project into service in the fall of 2021, assuming timely receipt of these remaining approvals. The project is expected to increase capacity by 400 Mdth/d.

Southeastern Trail

In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We plan to place the project into service in late 2020. The project is expected to increase capacity by 296 Mdth/d.

Leidy South

In July 2019, we filed an application with the FERC for approval of the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We plan to place the project into service as early as the fourth quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.

West

Project Bluestem

We are expanding our presence in the Mid-Continent region through building a 188-mile NGL pipeline from our fractionator near Conway, Kansas to an interconnect with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt. Belvieu pricing. As part of the project, the third-party intends to construct a 110-mile pipeline extension of their existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. Further, during the first quarter of 2019, we exercised an option to purchase a 20 percent equity interest in a Mt. Belvieu fractionation train developed by the third party. The pipeline and extension projects are expected to be placed into service during the first quarter of 2021.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

Pension and Postretirement Obligations

We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit obligations are shown in Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.



	Benefit Cost						Benefit Obligation
	One- Percentage- Point Increase			One- Percentage- Point Decrease			One- Percentage- Point Increase			One- Percentage- Point Decrease
	(Millions)
Pension benefits:
Discount rate	$	(2	)	$	4		$	(102	)	$	120
Expected long-term rate of return on plan assets	(12		)	12			—			—
Cash balance interest crediting rate	12			(10		)	71			(60		)
Other postretirement benefits:
Discount rate	1			2			(23		)	28
Expected long-term rate of return on plan assets	(2		)	2			—			—

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which include an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets. We develop our expectations using input from our third-party independent investment consultant. The forward-looking capital market projections start with current conditions of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections of normal inflation, growth, and interest rates to determine expected returns. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.

Our expected long-term rate of return on plan assets used for our pension plans was 5.26 percent in 2019. The 2019 actual return on plan assets for our pension plans was approximately 19.0 percent. The 10-year average rate of return on pension plan assets through December 2019 was approximately 8.1 percent. The expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation also impact the expected rates of return.

The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities.

The cash balance interest crediting rate assumption represents the average long-term rate by which the pension plans’ cash balance accounts are expected to grow. Interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate and is credited to the accounts quarterly. An increase in this rate causes the pension obligation and cost to increase.

Equity-Method Investments

We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. We also utilize a form of market approach to estimate the fair value of our investments. During 2019, we recognized impairments totaling $186 million related to our equity-method investments. (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2019. The results of operations by segment are discussed in further detail following this consolidated overview discussion.



	Year Ended December 31,
	2019			$ Change from 2018*	% Change from 2018*		2018			$ Change from 2017*	% Change from 2017*		2017
	(Millions)
Revenues:
Service revenues	$	5,933		+431	+8	%	$	5,502		+190	+4	%	$	5,312
Service revenues – commodity consideration	203			-197	-49	%	400			+400	NM		—
Product sales	2,065			-719	-26	%	2,784			+65	+2	%	2,719
Total revenues	8,201						8,686						8,031
Costs and expenses:
Product costs	1,961			+746	+28	%	2,707			-407	-18	%	2,300
Processing commodity expenses	105			+32	+23	%	137			-137	NM		—
Operating and maintenance expenses	1,468			+39	+3	%	1,507			+69	+4	%	1,576
Depreciation and amortization expenses	1,714			+11	+1	%	1,725			+11	+1	%	1,736
Selling, general, and administrative expenses	558			+11	+2	%	569			+25	+4	%	594
Impairment of certain assets	464			+1,451	+76	%	1,915			-667	-53	%	1,248
Gain on sale of certain assets and businesses	2			-694	NM		(692		)	-403	-37	%	(1,095		)
Regulatory charges resulting from Tax Reform	—			-17	-100	%	(17		)	+691	NM		674
Other (income) expense – net	8			+59	+88	%	67			+4	+6	%	71
Total costs and expenses	6,280						7,918						7,104
Operating income (loss)	1,921						768						927
Equity earnings (losses)	375			-21	-5	%	396			-38	-9	%	434
Other investing income (loss) – net	(79		)	-266	NM		187			-95	-34	%	282
Interest expense	(1,186		)	-74	-7	%	(1,112		)	-29	-3	%	(1,083		)
Other income (expense) – net	33			-59	-64	%	92			+117	NM		(25		)
Income (loss) from continuing operations before income taxes	1,064						331						535
Provision (benefit) for income taxes	335			-197	-143	%	138			-2,112	NM		(1,974		)
Income (loss) from continuing operations	729						193						2,509
Income (loss) from discontinued operations	(15		)	-15	NM		—			—	—	%	—
Net income (loss)	714						193						2,509
Less: Net income (loss) attributable to noncontrolling interests	(136		)	+484	NM		348			-13	-4	%	335
Net income (loss) attributable to The Williams Companies, Inc.	$	850					$	(155	)				$	2,174


*	+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

2019 vs. 2018

Service revenues increased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in service in 2019 and 2018, as well as the impact of the consolidation of UEOM, higher Northeast volumes at the Susquehanna Supply Hub and Ohio Valley Midstream regions, and higher gathering rates and volumes at the Utica Shale region. These increases are partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations, as well as lower revenue in the Barnett Shale associated with the end of a contractual MVC period and lower revenue at Gulfstar primarily associated with producer operational issues.

Service revenues – commodity consideration decreased due to lower NGL prices and lower volumes primarily due to the absence of our former Four Corners area operations. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, lower volumes from our equity NGL sales primarily reflecting the absence of our former Four Corners area operations, and lower system management gas sales, partially offset by higher marketing volumes. Marketing sales and system management gas sales are substantially offset in Product costs.

Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services reflecting the absence of our former Four Corners area operations and lower system management gas purchases, partially offset by higher volumes for marketing activities.

Processing commodity expenses decreased primarily due to lower production of equity NGLs primarily related to ethane rejection and the absence of our former Four Corners area operations, and lower prices for natural gas purchases associated with our NGL production*.*

Operating and maintenance expenses decreased primarily due to the absence of our former Four Corners area operations and lower contracted services at Transco primarily due to the timing of required engine overhauls and integrity testing. These decreases are partially offset by the impact of the consolidation of UEOM and by a $32 million charge for severance and related costs primarily associated with a voluntary separation program (VSP) in 2019.

Depreciation and amortization expenses decreased primarily due to the 2018 impairment of certain assets in the Barnett Shale region and the absence of assets disposed including our former Four Corners area operations, partially offset by new assets placed in service and by the impact of the consolidation of UEOM.

Selling, general, and administrative expenses decreased primarily due to the absences of a charitable contribution of preferred stock to the Williams Foundation, Inc. (see Note 16 – Stockholders' Equity of Notes to Consolidated Financial Statements) and fees associated with the WPZ Merger, partially offset by a $25 million charge for severance and related costs primarily associated with our 2019 VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.

Impairment of certain assets includes 2019 impairments of our Constitution development project, certain Eagle Ford Shale gathering assets, and certain assets that may no longer be in use or are surplus in nature. Asset impairments in 2018 included certain assets in the Barnett Shale region and certain idle pipelines (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Gain on sale of certain assets and businesses includes gains recognized on the sales of our Four Corners area and our Gulf Coast pipeline systems in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable changes to charges and credits to regulatory assets and liabilities, partially offset by the absence of a 2018 gain on asset retirement (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).

The favorable change in Operating income (loss) includes lower impairments of assets, an increase in Service revenues primarily associated with Transco projects placed in-service and higher volumes in the Northeast region, the favorable impact of acquiring the additional interest of UEOM, and higher Transco rates and favorable changes in the amortization of regulatory assets and liabilities. The change is also impacted favorably by the absence of a charitable contribution of preferred stock to the Williams Foundation, Inc., and the absence of fees associated with the WPZ Merger. These favorable changes were partially offset by the impact of asset divestitures and deconsolidations during 2018, including the related gains on sales. They were also partially offset by lower margins associated with our equity NGL production primarily associated with lower prices, higher depreciation expense associated with new assets placed in service, and charges for severance and related costs primarily associated with our VSP.

The unfavorable change in Equity earnings (losses) is primarily due to 2019 losses from our Brazos Permian II investment acquired in December 2018 of $14 million, the impact of the consolidation of UEOM during the first quarter of 2019 which reduced equity earnings by $9 million, and a $7 million unfavorable impact related to the April 2019 sale of our Jackalope investment. Additionally, equity earnings at Aux Sable decreased $9 million related to lower rates reflecting lower NGL prices. These decreases are partially offset by improved results at our Appalachia Midstream Investments of $20 million.

The unfavorable change in Other investing income (loss) – net includes higher impairments of equity-method investments, the absence of 2018 gains on the deconsolidations of our Delaware basin assets and Jackalope, and a 2019 loss on the deconsolidation of Constitution. These were partially offset by a 2019 gain on the disposition of Jackalope (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements).

Interest expense increased primarily due to an increase in financing obligations associated with Transco’s Atlantic Sunrise project and lower Interest capitalized related to construction projects that have been placed into service. (See Note 15 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)

The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a decrease in equity AFUDC associated with reduced capital expenditures on projects, partially offset by the absence of 2018 unfavorable settlement charges from our pension early payout program (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income attributable to The Williams Companies, Inc, partially offset by the absence of a charge to establish a $105 million valuation allowance, recorded in 2018, on certain deferred tax assets that may not be realized following the WPZ merger. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

The favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to our third- quarter 2018 acquisition of the publicly held interests in WPZ associated with the WPZ Merger, the impairment of Constitution project costs, and lower results at Gulfstar.

2018 vs. 2017

Service revenues increased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in-service in 2017 and 2018, as well as higher gathering volumes at the Susquehanna Supply Hub and Ohio River Supply Hub. These increases were partially offset by an unfavorable change in the rate of deferred revenue recognition resulting from implementing Accounting Standards Update 2014-09 “Revenue from Contracts with Customers” (ASC 606), reduced revenues from our Four Corners area operations that were sold in October 2018, a reduction of rates resulting from a Northwest Pipeline rate case settlement, and a decrease following the Jackalope deconsolidation.

Service revenues – commodity consideration increased as the result of implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods were not recast. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting

Policies of Notes to Consolidated Financial Statements.) Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

Product sales increased primarily due to higher marketing sales and higher system management gas sales, which are offset in Product costs*,* and higher sales from the production of our equity NGLs, reflecting higher NGL prices. These increases are partially offset by the absence of $269 million in olefins sales associated with our former olefins operations in 2017.

The increase in Product costs is primarily due to the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as higher marketing and system management gas purchases. This increase is partially offset by the absence of $147 million of olefin feedstock purchases due to the sale of our former olefins operations, as well as the absence of natural gas purchases associated with the production of equity NGLs, which are reported in Processing commodity expenses in conjunction with the 2018 implementation of ASC 606.

Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606*.*

Operating and maintenance expenses decreased primarily due to the absence of $80 million of costs associated with our former olefins and Four Corners area operations.

Depreciation and amortization expenses decreased primarily due to the absence of our former olefins and Four Corners area operations, partially offset by new assets placed in-service.

Selling, general, and administrative expenses decreased primarily due to the absence of severance-related, organizational realignment, and Financial Repositioning costs incurred in 2017, $25 million in reduced costs associated with our former olefins and Four Corners area operations, and cost containment efforts. These decreases are partially offset by a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. and fees associated with the WPZ Merger.

Impairment of certain assets includes 2018 impairments on certain assets in the Barnett Shale region and certain idle pipelines and 2017 impairments associated with certain assets in the Mid-Continent, Marcellus South, and Houston Ship Channel areas (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Gain on sale of certain assets and businesses includes gains recognized on the sales of our Four Corners area in October 2018, our Gulf Coast pipeline systems in December 2018 and our Geismar Interest in July 2017 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

Regulatory charges resulting from Tax Reform relates to the 2017 establishment of regulatory liabilities for the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).

The favorable change in Other (income) expense – net within Operating income (loss) includes the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger in 2018, substantially offset by the absence of gains from certain contract settlements and terminations in 2017, the absence of a gain on the sale of our RGP Splitter in 2017, and 2018 charges establishing a regulatory liability associated with a decrease in Northwest Pipeline's estimated deferred state income tax rate following the WPZ Merger (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).

Operating income (loss) changed unfavorably primarily due to higher impairments of assets, lower gains on sales of assets and businesses, and the absence of operating income associated with our former olefins and Four Corners area operations, partially offset by the absence of regulatory charges resulting from Tax Reform, higher Service revenues primarily from expansion projects, and higher NGL margins.

The unfavorable change in Equity earnings (losses) is primarily due to a decrease in volumes at Discovery, partially offset by improved results at our Appalachia Midstream Investments and the deconsolidation of our Jackalope interest, which is accounted for as an equity-method investment beginning in the second quarter of 2018.

Other investing income (loss) – net includes a 2017 gain on disposition of our investments in DBJV and Ranch Westex JV LLC, a 2018 impairment related to our investment in UEOM, and 2018 gains on the deconsolidations of certain Permian basin assets and of our interest in Jackalope. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)

Interest expense increased primarily due to an increase in other financing obligations associated with Transco's Dalton and Atlantic Sunrise projects, as well as expense related to the deemed financing component of certain contract liabilities resulting from our implementation of ASC 606 in 2018. This increase is partially offset by lower interest rates on our outstanding debt in 2018 and lower borrowings on our credit facilities in 2018.

Other income (expense) – net below Operating income (loss) changed favorably primarily due to a decrease in charges reducing regulatory assets related to deferred taxes on equity AFUDC resulting from Tax Reform, an increase in equity AFUDC, and a lower settlement charge from the pension early payout program. These favorable changes were partially offset by a decrease due to the absence of a net gain on early retirement of debt in 2017 and a loss on early retirement of debt in 2018. (See Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

Provision (benefit) for income taxes changed unfavorably primarily due to the absence of a $1.923 billion tax provision benefit associated with Tax Reform and releasing a $127 million valuation allowance in 2017. The unfavorable change also reflects a $105 million valuation allowance in 2018 associated with certain foreign tax credits. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily related to WPZ, reflective of both our acquisition of the publicly held interests in WPZ associated with the WPZ Merger and a fourth quarter 2017 net loss incurred by WPZ, partially offset by lower operating results at Gulfstar.

Year-Over-Year Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 20 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Atlantic-Gulf



	Year Ended December 31,
	2019			2018			2017
	(Millions)
Service revenues	$	2,861		$	2,509		$	2,239
Service revenues – commodity consideration	41			59			—
Product sales	288			435			484
Segment revenues	3,190			3,003			2,723

Product costs	(288		)	(438		)	(437		)
Processing commodity expenses	(16		)	(16		)	—
Other segment costs and expenses	(814		)	(799		)	(819		)
Impairment of certain assets	(354		)	—			—
Gain on sale of certain assets and businesses	—			81			—
Regulatory charges resulting from Tax Reform	—			9			(493		)
Proportional Modified EBITDA of equity-method investments	177			183			264
Atlantic-Gulf Modified EBITDA	$	1,895		$	2,023		$	1,238

Commodity margins	$	25		$	40		$	47

2019 vs. 2018

Atlantic-Gulf Modified EBITDA decreased primarily due to the impairment of Constitution, the absence of a 2018 Gain on sale of certain assets and businesses , and higher Other segment costs and expenses, partially offset by increased Service revenues related to expansion projects placed into service during 2018 and 2019.

Service revenues increased primarily due to a $403 million increase in Transco’s natural gas transportation revenues primarily driven by a $358 million increase related to expansion projects placed in service in 2018 and 2019, as well as higher revenue associated with Transco’s general rate case settlement and increased amounts for reimbursable power and storage expenses. Partially offsetting these increases were lower fee revenues of $62 million primarily due to producer operational issues and lower deferred revenue amortization at Gulfstar, as well as the sale of certain Gulf Coast pipeline assets in fourth-quarter 2018.

The net sum of Service revenues – commodity consideration*,* Product sales*,* Product costs*,* and Processing commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs decreased $16 million, consisting of a $26 million decrease associated with unfavorable net realized NGL sales prices, partially offset by a $10 million increase associated with higher sales volumes. The higher NGL volumes were primarily related to the absence of 2018 downtime to modify the Mobile Bay processing plant for the Norphlet project. Additionally, the decrease in Product sales includes a $93 million decrease in commodity marketing sales due to lower NGL prices and volumes and a $39 million decrease in system management gas sales. Marketing sales and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses increased primarily due a $56 million unfavorable change in equity AFUDC due to lower construction activity, a $32 million charge in 2019 for severance and related costs primarily associated with our 2019 VSP, a $21 million increase in reimbursable power and storage expenses, $16 million of expense in 2019 related to the reversal of expenditures previously capitalized, and the absence of a $12 million 2018 gain on asset retirements. These unfavorable changes were partially offset by $77 million of net favorable changes to charges and credits associated with regulatory assets and liabilities, which were significantly driven by the previously mentioned settlement in Transco’s general rate case, and a $46 million decrease in Transco’s contracted services compared to 2018 mainly due to the timing of required engine overhauls and integrity testing.

Impairment of certain assets includes the 2019 impairment of our Constitution development project (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Gain on sale of certain assets and businesses reflects an $81 million gain from the sale of our Gulf Coast pipeline system assets in fourth-quarter 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

2018 vs. 2017

Atlantic-Gulf Modified EBITDA increased primarily due to the absence of regulatory charges associated with the impact of Tax Reform at Transco, higher Service revenues, and a 2018 gain on the sale of certain assets; partially offset by lower Proportional Modified EBITDA of equity-method investments.

Service revenues increased primarily due to a $253 million increase in Transco’s natural gas transportation fee revenues primarily due to a $241 million increase associated with expansion projects placed in-service in 2017 and 2018.

Service revenues – commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we received in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

The decrease in Product sales includes:


•	A $90 million decrease in commodity marketing sales driven by a $149 million decrease in crude oil sales as this activity is now presented on a net basis within Product costs in conjunction with the adoption of ASC 606, partially offset by a $59 million increase in NGL marketing sales primarily reflecting 20 percent higher non-ethane prices;


•	A $14 million decrease in sales associated with the production of our equity NGLs, as further described below as part of our commodity margins;


•	A $57 million increase in system management gas sales. System management gas sales are offset in Product costs and therefore have little impact to Modified EBITDA.

Product costs slightly increased primarily due to a $59 million increase in system management gas purchases (substantially offset in Product sales) and the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services. This increase was partially offset by an $87 million decrease in marketing purchases (more than offset in Product sales) and the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.

Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606*.*

The net sum of Service revenues – commodity consideration*,* Product sales*,* Product costs*,* and Processing commodity expenses comprise our commodity margins.

Other segment costs and expenses decreased primarily due to a $17 million increase in Transco’s equity AFUDC as a result of higher construction activity in 2018.

Gain on sale of certain assets reflects an $81 million gain from the sale of our Gulf Coast pipeline system assets in fourth-quarter 2018, as previously mentioned.

The decrease in Regulatory charges resulting from Tax Reform reflects the absence of $493 million of regulatory charges in 2017 associated with the impact of Tax Reform at Transco (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).

The decrease in Proportional Modified EBITDA of equity-method investments is due to an $89 million decrease at Discovery, primarily related to a $76 million decrease associated with production ending on certain wells.

Northeast G&P



	Year Ended December 31,
	2019			2018			2017
	(Millions)
Service revenues	$	1,338		$	976		$	872
Service revenues – commodity consideration	12			20			—
Product sales	150			287			291
Segment revenues	1,500			1,283			1,163

Product costs	(152		)	(289		)	(286		)
Processing commodity expenses	(8		)	(9		)	—
Other segment costs and expenses	(470		)	(392		)	(386		)
Impairment of certain assets	(10		)	—			(124		)
Proportional Modified EBITDA of equity-method investments	454			493			452
Northeast G&P Modified EBITDA	$	1,314		$	1,086		$	819

Commodity margins	$	2		$	9		$	5

2019 vs. 2018

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues due to increased gathering volumes, as well as the $38 million favorable impact of acquiring the additional interest of UEOM, partially offset by 2019 impairments.

Service revenues increased primarily due to:


•	A $158 million increase associated with the consolidation of UEOM, as previously discussed;


•	A $102 million increase associated with higher gathering revenues at Susquehanna Supply Hub reflecting 18 percent higher gathering volumes due to increased production from customers and higher rates;


•	A $49 million increase at Ohio Valley Midstream primarily due to higher gathering, processing, and transportation volumes;


•	A $36 million increase in gathering revenues in the Utica Shale region due to higher rates and volumes from new wells;


•	A $14 million increase in compression revenues for services charged to an affiliate driven by higher volumes.

Product sales decreased primarily due to lower non-ethane volumes and prices within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.

Other segment costs and expenses increased primarily due to:


•	A $53 million increase associated with the consolidation of UEOM;


•	A $10 million increase related to transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV;


•	A $7 million charge in 2019 for severance and related costs primarily associated with our VSP.

Impairment of certain assets increased due to a $10 million write-down of other certain assets that may no longer be in use or are surplus in nature in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments decreased $59 million as a result of the consolidation of UEOM and $10 million due to unfavorable rates reflecting lower NGL prices at Aux Sable. This decrease was partially offset by a $29 million increase at Appalachia Midstream Investments, reflecting higher volumes due to increased customer production.

2018 vs. 2017

Northeast G&P Modified EBITDA increased primarily due to the absence of Impairment of certain assets in 2017, and higher Service revenues and Proportional Modified EBITDA of equity-method investments.

Service revenues increased due to:


•	A $65 million increase in gathering fee revenues at Susquehanna Supply Hub due to 13 percent higher gathering volumes reflecting increased customer production;


•	A $24 million increase at Ohio River Supply Hub reflecting higher gathering volumes due to increased customer production;


•	An $11 million increase in Utica gathering fee revenues reflecting higher rates and volumes.

Service revenues – commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Processing commodity expenses.

Product sales decreased primarily due to $31 million lower marketing sales, driven by lower non-ethane volumes and prices. The changes in marketing sales are offset by similar changes in marketing purchases, reflected above as Product costs. The decrease in Product sales is partially offset by $21 million in higher system management gas sales. System management gas sales are offset in Product costs and therefore have no impact on Modified EBITDA.

Impairment of certain assets reflects the absence of a $115 million impairment of certain gathering operations in the Marcellus South region in 2017.

Proportional Modified EBITDA of equity-method investments increased primarily due to a $33 million increase at Appalachia Midstream Investments reflecting our increased ownership acquired in late first-quarter 2017 and higher volumes. Improvements at Aux Sable and Caiman II also contributed to the increase.

West



	Year Ended December 31,
	2019			2018			2017
	(Millions)
Service revenues	$	1,813		$	2,085		$	2,246
Service revenues – commodity consideration	150			321			—
Product sales	1,797			2,448			2,013
Segment revenues	3,760			4,854			4,259

Product costs	(1,774		)	(2,448		)	(1,842		)
Processing commodity expenses	(79		)	(116		)	—
Other segment costs and expenses	(688		)	(825		)	(832		)
Impairment of certain assets	(100		)	(1,849		)	(1,032		)
Gain on sale of certain assets and businesses	(2		)	591			—
Regulatory charges resulting from Tax Reform	—			7			(220		)
Proportional Modified EBITDA of equity-method investments	115			94			79
West Modified EBITDA	$	1,232		$	308		$	412

Commodity margins	$	94		$	205		$	171

2019 vs. 2018

West Modified EBITDA increased primarily due to lower Impairment of certain assets and lower Other segment costs and expenses, partially offset by a lower gain on sale of certain assets in 2019, lower Service revenues, and lower commodity margins.

Service revenues decreased primarily due to:


•	A $218 million decrease associated with asset divestitures and deconsolidations during 2018 and 2019, including our former Four Corners area assets, certain Delaware basin assets that were contributed to our Brazos Permian II equity-method investment, and our Jackalope assets which were deconsolidated in second-quarter 2018 and subsequently sold in second-quarter 2019;


•	A $57 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues in the Barnett Shale region primarily associated with the expiration of a certain MVC agreement;


•	A $17 million decrease driven by lower gathering volumes primarily in the Mid-Continent, Barnett Shale, and Wamsutter regions, partially offset by higher gathering volumes primarily in the Haynesville Shale and Eagle Ford regions;


•	A $15 million decrease associated with lower processing rates primarily driven by lower commodity pricing in the Piceance region;


•	A $15 million decrease associated with lower gathering rates primarily in the Mid-Continent and Haynesville Shale regions;


•	A $17 million increase related to other MVC deficiency fee revenues;


•	A $13 million increase related to higher fractionation and storage fees;


•	An $8 million increase associated with the resolution of a prior period performance obligation.


•	A $98 million decrease associated with lower sales volumes, consisting of $54 million related to the absence of our former Four Corners area assets and $44 million due to 12 percent lower non-ethane volumes and 33 percent lower ethane sales volumes primarily due to higher ethane rejection in 2019, natural declines, less producer drilling activity, and more severe weather conditions in first-quarter 2019;

•

A $98 million decrease associated with lower sales volumes, consisting of $54 million related to the absence of our former Four Corners area assets and $44 million due to 12 percent lower non-ethane volumes and 33 percent lower ethane sales volumes primarily due to higher ethane rejection in 2019, natural declines, less producer drilling activity, and more severe weather conditions in first-quarter 2019;


•	A $66 million decrease associated with lower sales prices primarily due to 29 percent and 48 percent lower average net realized per-unit non-ethane and ethane sales prices, respectively;


•	A $37 million increase related to lower natural gas purchases associated with lower equity NGL production volumes and lower natural gas prices, including $9 million related to the absence of our former Four Corners area assets.

Additionally, the decrease in Product sales includes a $447 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher sales volumes, and a $36 million decrease related to the sale of other products. These decreases are substantially offset in Product costs*.* Marketing margins increased by $27 million primarily due to favorable changes in prices.

Other segment costs and expenses decreased primarily due to a $127 million reduction associated with the absences of our former Four Corners area assets and from the Jackalope deconsolidation in second-quarter 2018, the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger, $12 million favorable settlements in 2019, as well as $10 million lower ad valorem taxes. These decreases were partially offset by an unfavorable charge in 2019 for severance and related costs primarily associated with our VSP of $17 million.

Impairment of certain assets decreased primarily due to the absence of the $1,849 million Barnett impairment in 2018, partially offset by various 2019 impairments (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The decrease in Gain on sale of certain assets and businesses reflects the absence of the gain from the sale of our Four Corners area assets recorded in the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments increased primarily due to the additions of the RMM and Brazos Permian II equity-method investments in the second half of 2018, partially offset by the sale of our Jackalope investment in second-quarter 2019.

2018 vs. 2017

West Modified EBITDA decreased primarily due to the increase in Impairment of certain assets and lower Service revenues*.* These decreases were partially offset by the Gain on sale of certain assets and businesses in 2018, the absence of regulatory charges associated with the impact of Tax Reform, and higher NGL margins driven by higher NGL prices and lower realized natural gas prices, partially offset by lower NGL volumes.

Service revenues decreased primarily due to:

•

A $64 million decrease primarily associated with implementing the new revenue guidance under ASC 606 including a $118 million decrease related to lower amortization of deferred revenue associated with the up-front cash payments received in conjunction with the fourth quarter 2016 Barnett Shale and Mid-Continent contract restructurings, partially offset by a $54 million increase related to other deferred revenue amortization primarily in the Permian basin;


•	A $42 million decrease associated with the sale of our Four Corners area assets in October 2018;


•	A $30 million decrease at Northwest Pipeline primarily due to the reduction of its rates as a result of a rate case settlement that became effective January 1, 2018;


•	A $29 million decrease following the Jackalope deconsolidation in second-quarter 2018;


•	A $15 million decrease driven by lower gathering volumes primarily in the Eagle Ford Shale, Barnett Shale, and Mid-Continent regions, partially offset by higher volumes in the Niobrara (prior to the Jackalope deconsolidation), Piceance, and Permian regions;


•	A $21 million increase associated with higher gathering and processing rates in the Piceance region driven by higher NGL prices as well as higher average gathering and processing rates across most other areas, partially offset by lower contract rates primarily in the Haynesville Shale region.

Service revenues – commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.

The increase in Product sales includes:


•	A $373 million increase in marketing sales primarily due to increases in realized NGL prices including a 14 percent increase in average non-ethane per-unit sales prices and a 25 percent increase in ethane prices, in addition to a 15 percent increase in ethane volumes (more than offset by higher Product costs);


•	A $47 million increase in sales associated with the production of our equity NGLs, as further described below as part of our commodity margins;


•	An $18 million increase in system management gas sales due to a change in presentation in accordance with ASC 606, which are more than offset in Product costs and, therefore, have little impact on Modified EBITDA.

The increase in Product costs includes the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, a $381 million increase in marketing purchases (substantially offset in Product sales), a $19 million increase in system management gas purchases (substantially offset in Product sales), partially offset by the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.

Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606*.*

The net sum of Service revenues – commodity consideration*,* Product sales*,* Product costs*,* and Processing commodity expenses comprise our commodity margins. Our commodity margins increased primarily due to a $40 million increase in NGL product margins partially offset by an $8 million decrease in marketing margins. NGL margins are driven by $56 million in higher ethane and non-ethane per-unit prices, reflecting 19 percent higher realized non-ethane per-unit sales prices and 50 percent higher realized ethane per-unit sales prices. These increases were partially offset by $18 million in lower volumes primarily due to the sale of our Four Corners area assets in October 2018.

Other segment costs and expenses decreased primarily due to $57 million lower operating and maintenance and general and administrative costs. This reduction in costs is due primarily to the Four Corners area sale in October 2018, ongoing cost containment efforts, and the deconsolidation of our Jackalope interest in second-quarter 2018. These reductions are partially offset by a $24 million regulatory charge associated with Northwest Pipeline’s approved rates related to Tax Reform, the absence of a $15 million gain from contract settlements and terminations in 2017, and a $12

million charge for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger.

Impairment of certain assets increased primarily due to the $1.849 billion impairment of certain assets in the Barnett Shale region in 2018, partially offset by the absence of a $1.019 billion impairment of certain gathering operations in the Mid-Continent region in 2017 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Gain on sale of certain assets and businesses reflects a gain from the sale of our Four Corners area assets in fourth quarter 2018.

Regulatory charges resulting from Tax Reform decreased primarily due to the absence of the $220 million initial regulatory charge associated with the impact of Tax Reform at Northwest Pipeline in 2017 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments increased primarily due to the deconsolidation of our Jackalope interest, which is accounted for as an equity-method investment beginning in the second quarter of 2018.

Other



	Year Ended December 31,
	2019		2018			2017
	(Millions)
Other Modified EBITDA	$	6	$	(29	)	$	997

2019 vs. 2018

Other Modified EBITDA increased primarily due to:


•	The absence of the $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note 18 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements);


•	The absence of a $35 million charge in 2018 associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) (See Note 16 – Stockholders’ Equity of Notes to Consolidated Financial Statements);


•	The absence of $20 million in costs in 2018 associated with the WPZ Merger (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements);


•	An $8 million increase related to the absence of 2018 unfavorable Modified EBITDA associated with the results of certain of our former Gulf Coast area operations sold in 2018;


•	The absence of a $7 million loss on early retirement of debt in 2018 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).

These increases were partially offset by:


•	The absence of a $37 million benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger in 2018 and a subsequent unfavorable $12 million adjustment in the first quarter of 2019;


•	A $26 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;


•	The absence of a $20 million gain on the sale of certain assets and operations located in the Gulf Coast area in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

2018 vs. 2017

Modified EBITDA changed unfavorably primarily due to:


•	The absence of a $1.095 billion gain on the sale of our Geismar Interest in 2017 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements);


•	The absence of $54 million of Modified EBITDA associated with the results of our former Geismar Olefins and RGP Splitter plants subsequent to their sale in July 2017;


•	A $35 million charge in 2018 associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation), as previously mentioned;


•	A $34 million decrease due to the absence of a net gain on early retirement of debt in 2017 and a loss on early retirement of debt in 2018 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);


•	A $26 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;


•	$20 million in costs in 2018 associated with the WPZ Merger, as previously mentioned;


•	The absence of a $12 million gain on the sale of the Refinery Grade Propylene Splitter in 2017 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).

These decreases were partially offset by:

•

The absence of a $68 million impairment for a certain NGL pipeline asset in the third quarter of 2017 and a$23 million impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017, partially offset by a $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);


•	A $62 million favorable change for lower charges to reduce regulatory assets related to deferred taxes on AFUDC resulting from Tax Reform (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);


•	$40 million of lower costs, driven by the absence of expenses associated with severance and related costs, Financial Repositioning, and strategic alternative costs;


•	A $37 million increase associated with the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger, as previously mentioned;


•	A $30 million favorable change in the settlement charge expense related to the program to pay out certain deferred vested pension benefits of employees associated with former operations (see Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements);


•	A $20 million gain on the sale of certain assets and operations located in the Gulf Coast area, as previously mentioned.

Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

As previously discussed, we have continued to focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs. In 2019, we acquired the remaining outstanding ownership interests in UEOM for $728 million and subsequently formed a new partnership which includes UEOM and our Ohio Valley Midstream business. Our partner purchased a 35 percent ownership interest in the partnership for $1.3 billion. Also, during the second quarter of 2019 we sold our 50 percent ownership interest in Jackalope for $485 million. See also the following table of Sources (Uses) of Cash.

Outlook

As previously discussed in Company Outlook, our growth capital and investment expenditures in 2020 are currently expected to be in a range from $1.1 billion to $1.3 billion. Growth capital spending in 2020 includes Transco expansions, all of which are fully contracted with firm transportation agreements, and our Bluestem NGL pipeline project in the Mid-Continent region. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2020 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.

As of December 31, 2019, we have $2.121 billion of long-term debt maturing in 2020. Our potential sources of liquidity available to address these maturities include proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2020. Our potential material internal and external sources and uses of liquidity are as follows:





Sources:
	Cash and cash equivalents on hand
	Cash generated from operations
	Distributions from our equity-method investees
	Utilization of our credit facility and/or commercial paper program
	Cash proceeds from issuance of debt and/or equity securities
	Proceeds from asset monetizations
	Contributions from noncontrolling interests

Uses:
	Working capital requirements
	Capital and investment expenditures
	Quarterly dividends to our shareholders
	Debt service payments, including payments of long-term debt
	Distributions to noncontrolling interests

Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook*.*

As of December 31, 2019, we had a working capital deficit of $2.388 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:



Available Liquidity	December 31, 2019
	(Millions)
Cash and cash equivalents	$	289
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)	4,500
	$	4,789

(1)

In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of December 31, 2019. The highest amount outstanding under our commercial paper program and credit facility during 2019 was $1.226 billion. At December 31, 2019, we were in compliance with the financial covenants associated with our credit facility. See Note 15 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for additional information on our credit facility and commercial paper program.

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 12 percent from the previous quarterly cash dividends of $0.34 per share paid in each quarter of 2018, to $0.38 per share for the quarterly cash dividends paid in each quarter of 2019.

Registrations

In February 2018, we filed a shelf registration statement as a well-known seasoned issuer. In August 2018, we filed a prospectus supplement for the offer and sale from time to time of shares of our common stock having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at then-current prices. Such sales are to be made pursuant to an equity distribution agreement between us and certain entities who may act as sales agents or purchase for their own accounts as principals at a price agreed upon at the time of the sale.

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. See Note 6 – Investing Activities of Notes to Consolidated Financial Statements for our more significant equity-method investees.

Credit Ratings

The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:



Rating Agency	Outlook	Senior Unsecured Debt Rating
S&P Global Ratings	Stable	BBB
Moody’s Investors Service	Stable	Baa3
Fitch Ratings	Rating Watch Positive	BBB-

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria

for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.

Sources (Uses) of Cash

The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):



	Cash Flow	Year Ended December 31,
	Category	2019			2018			2017
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	3,693		$	3,293		$	3,089
Proceeds from sale of partial interest in consolidated subsidiary (see Note 3)	Financing	1,334			—			—
Proceeds from credit-facility borrowings	Financing	700			1,840			1,635
Proceeds from dispositions of equity-method investments (see Note 6)	Investing	485			—			200
Proceeds from long-term debt (see Note 15)	Financing	67			2,086			1,698
Contributions in aid of construction	Investing	52			411			426
Proceeds from issuance of common stock	Financing	10			15			2,131
Proceeds from sale of businesses, net of cash divested (see Note 3)	Investing	(2		)	1,296			2,067

Uses of cash and cash equivalents:
Capital expenditures	Investing	(2,109		)	(3,256		)	(2,399		)
Common dividends paid	Financing	(1,842		)	(1,386		)	(992		)
Payments on credit-facility borrowings	Financing	(860		)	(1,950		)	(2,140		)
Purchases of businesses, net of cash acquired (see Note 3)	Investing	(728		)	—			—
Purchases of and contributions to equity-method investments (see Note 6)	Investing	(453		)	(1,132		)	(132		)
Dividends and distributions paid to noncontrolling interests	Financing	(124		)	(591		)	(822		)
Payments of long-term debt (see Note 15)	Financing	(49		)	(1,254		)	(3,785		)
Payments of commercial paper – net	Financing	(4		)	(2		)	(93		)

Other sources / (uses) – net	Financing and Investing	(49		)	(101		)	(154		)
Increase (decrease) in cash and cash equivalents		$	121		$	(731	)	$	729

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Gain on disposition of equity-method investments, Impairment of equity-method investments, (Gain) on sale of certain assets and businesses, Impairment of certain assets, (Gain) loss on deconsolidation of businesses, and Regulatory charges resulting from Tax Reform.

Our Net cash provided (used) by operating activities in 2019 increased from 2018 primarily due to the net favorable changes in operating working capital in 2019, including the collection of Transco’s filed rates subject to refund and the receipt of an income tax refund, as well as higher operating income (excluding noncash items as previously discussed) in 2019, partially offset by the impact of decreased distributions from unconsolidated affiliates in 2019.

Our Net cash provided (used) by operating activities in 2018 increased from 2017 primarily due to higher operating income (excluding noncash items as previously discussed) in 2018, partially offset by the impact of decreased distributions from unconsolidated affiliates in 2018.

Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments

We have various other guarantees and commitments which are disclosed in Note 4 – Variable Interest Entities, Note 12 – Property, Plant, and Equipment, Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 19 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.

Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2019:



	2020		2021 - 2022		2023 - 2024		Thereafter		Total
					(Millions)
Long-term debt, including current portion: (1)
Principal	$	2,141	$	2,918	$	3,756	$	13,650	$	22,465
Interest	1,097		2,004		1,709		8,561		13,371
Operating leases	29		61		41		157		288
Purchase obligations (2)	890		647		245		290		2,072
Other obligations (3)(4)	3		5		—		—		8
Total	$	4,160	$	5,635	$	5,751	$	22,658	$	38,204


(1)	Includes any borrowings outstanding under credit facilities, but does not include any related variable-rate interest payments.


(2)	Includes:


•	Approximately $206 million in open property, plant, and equipment purchase orders;


•	An estimated $589 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2019 prices;


•	An estimated $193 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies third parties at their plants and is reflected in this table at a value calculated using December 31, 2019 prices. Any excess purchased volumes may be sold at comparable market prices;


•	An estimated $163 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies a third party for consumption at their plant and is reflected in this table at a value calculated using December 31, 2019 prices. Any excess purchased volumes may be sold at comparable market prices;

•

An estimated $149 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2019 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator near Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or sold at comparable prices in the Mont Belvieu market;


•	An estimated $129 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2019 prices.

In addition, we have not included certain natural gas life-of-lease contracts for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders, for the acquisition or construction of property, plant, and equipment or expected contributions to our jointly owned investments. (See Company Outlook — Expansion Projects.)

(3)

Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $68 million in 2019 and $93 million in 2018. In 2020, we expect to contribute approximately $19 million to these plans (see Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements). Tax-qualified pension plans are required to meet minimum contribution requirements. In the past, we have contributed amounts to our tax-qualified pension plans in excess of the minimum required contribution. These excess amounts can be used to offset future minimum contribution requirements. During 2019, we contributed $60 million to our tax-qualified pension plans. In addition to these contributions, a portion of the excess contributions was used to meet the minimum contribution requirements. During 2020, we expect to contribute approximately $10 million to our tax-qualified pension plans and use excess amounts to satisfy minimum contribution requirements, if needed. Additionally, estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations.


(4)	We have not included income tax liabilities in the table above. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of income taxes, including our contingent tax liability reserves.

Effects of Inflation

Our operations have historically not been materially affected by inflation. Approximately 49 percent of our gross property, plant, and equipment is comprised of our interstate natural gas pipeline assets. They are subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For our gathering and processing assets, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in crude oil and natural gas and related commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to certain of these price changes is reduced through the fee-based nature of certain of our services and the use of hedging instruments.

Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own (see Note 19 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $31 million, all of which are included in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2019. We will seek recovery of the accrued costs related to remediation activities by our interstate gas pipelines totaling approximately $4 million through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2019, we paid approximately $6 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $8 million in 2020 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2019, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design

and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule's implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.

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