8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 13, 2019

The Williams Companies, Inc.

(Exact name of registrant as specified in its charter)

Delaware	1-4174	73-0569878
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

One Williams Center Tulsa, Oklahoma	74172-0172
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (918) 573-2000

NOT APPLICABLE

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

 Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Item 2.02. Results of Operations and Financial Condition

On February 13, 2019, The Williams Companies, Inc. (the "Company") issued a press release announcing its financial results for the quarter and year ended December 31, 2018. A copy of the press release and accompanying financial highlights and operating statistics and reconciliation schedules are furnished herewith as Exhibit 99.1 and Exhibit 99.2 and are incorporated herein in their entirety by reference.

The press release and accompanying financial highlights and operating statistics and reconciliation schedules are being furnished pursuant to Item 2.02, Results of Operations and Financial Condition. The information furnished is not deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

Item 9.01. Financial Statements and Exhibits

(a) None

(b) None

(c) None

(d) Exhibits.

Exhibit No.	Description
99.1	Press release of the Company dated February 13, 2019, publicly announcing the Company's financial results for the quarter and year ended December 31, 2018.
99.2	Non-GAAP Reconciliations, Financial Highlights, and Operating Statistics for the quarter and year ended December 31, 2018.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

			THE WILLIAMS COMPANIES, INC.
Dated:	February 13, 2019	By:	/s/ JOHN D. CHANDLER
			John D. Chandler
			Senior Vice President and Chief Financial Officer

EX-99.1

EXHIBIT 99.1

News Release Williams (NYSE: WMB) One Williams Center Tulsa, OK 74172 800-Williams www.williams.com

DATE: Feb. 13, 2019

MEDIA CONTACT:	INVESTOR CONTACTS:
Keith Isbell (918) 573-7308	John Porter (918) 573-0797	Paul Schroedter (918) 573-9673

Williams Reports Fourth-Quarter and Full-Year 2018 Financial Results

TULSA, Okla. – Williams (NYSE: WMB) today announced its financial results for the three and 12 months ended Dec. 31, 2018.

Highlights

• Net Income (Loss) Attributable to Williams Available to Common Stockholders of ($572) Million for 4Q 2018 and ($156) Million for Full-Year 2018 (impacted by certain asset impairments and gains as described in this press release)

• Net Income (Loss) Per Share of ($0.47) for 4Q 2018 and ($0.16) for Full-Year 2018

• 4Q 2018 Cash Flow From Operations of $962 Million; Up $104 Million over 4Q 2017

• 4Q 2018 Adjusted Income Per Share of $0.19; Full-Year 2018 Adjusted Income Per Share of $0.79

• 4Q 2018 Adjusted EBITDA of $1.197 Billion; Up $37 Million over 4Q 2017

• Full-Year 2018 Adjusted EBITDA of $4.638 Billion; Up $107 Million over Full-Year 2017

• 4Q 2018 DCF of $748 Million; Coverage Ratio is 1.82; Full-Year 2018 DCF of $2.872 Billion; Coverage Ratio is 1.69

• Consolidated Net Debt/ 2018 Adjusted EBITDA Leverage Ratio of 4.80x; Well Ahead of the Guided ~5x Ratio

• Placed Atlantic Sunrise Project into Full Service on Oct. 6, 2018; Placed Gulf Connector into Full Service on Jan. 4, 2019

• 4Q 2018 Northeast G&P EBITDA (both Modified and Adjusted) Up Approximately 30% and NE Gathering Volumes Up 13% over 4Q 2017

• Completed Asset Sales Totaling $1.3 Billion during 4Q 2018

CEO Perspective

Alan Armstrong, president and chief executive officer, made the following comments:

"Once again in 2018, our consistent natural gas-focused strategy delivered as expected with solid and predictable growth. In fact, our 2018 Adjusted EBITDA was a new record even in the face of asset sales totaling $4.6 billion over the past two and a half years that dramatically reduced commodity exposure and improved leverage metrics for WMB. Thanks to strong execution by our teams, we again delivered at the top end of the range for nearly all of our key guidance metrics for the year. Bringing the Atlantic Sunrise project online and dramatically increasing gathering volumes in our Northeast G&P segment were just a couple of the many achievements during the year.

"The quality and predictability of our cash flows, even in times of commodity swings, combined with the accelerating demand for natural gas, point to continued growth for us in 2019 as we enjoyed strong execution on all of our major projects in 2018 and the beginning of 2019."

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Armstrong added, "With the expected 15 percent compounded annual growth rate for gathered volumes in our Northeast G&P segment expected through 2021, Transco's continued string of expansion projects, our recently announced Bluestem Pipeline project, our joint venture in the Permian with Brazos Midstream, the growing Rocky Mountain Midstream in the DJ Basin and a growing list of deepwater discoveries, it's easy to see why Williams is poised for additional growth in 2019 and beyond. And, Williams is well-positioned for sustained growth as we continue to capitalize on significant opportunities to connect low-cost natural gas supplies to premier demand markets.

"The combined impact of strong business performance, capital discipline and our ongoing portfolio optimization efforts continues to improve our credit metrics. We finished 2018 with overall leverage of 4.80x, and we are very focused on further improvement in 2019.”

Williams Summary Financial Information	4Q					Full Year
Amounts in millions, except per-share amounts. Per share amounts are reported on a diluted basis. Net income (loss) amounts are attributable to The Williams Companies, Inc. available to common stockholders.	2018			2017		2018			2017
GAAP Measures
Cash Flow from Operations		$962			$858		$3,293			$3,089
Net income (loss)		($572	)		$1,687		($156	)		$2,174
Net income (loss) per share		($0.47	)		$2.03		($0.16	)		$2.62
Non-GAAP Measures (1)
Adjusted income		$230			$170		$775			$521
Adjusted income per share		$0.19			$0.20		$0.79			$0.63
Adjusted EBITDA		$1,197			$1,160		$4,638			$4,531
Distributable Cash Flow		$748			$629		$2,872			$2,580
Coverage Ratio	1.82			1.57		1.69			1.61
(1) Schedules reconciling adjusted income from continuing operations, adjusted EBITDA, Distributable Cash Flow and Coverage Ratio (non-GAAP measures) to the most comparable GAAP measure are available at www.williams.com and as an attachment to this news release.

Fourth-Quarter and Full-Year 2018 Financial Results

Williams reported unaudited fourth-quarter2018 net income (loss) attributable to Williams available to common stockholders of ($572) million, a decrease of $2.259 billion from fourth-quarter2017. The unfavorable change was driven primarily by a $1.849 billion impairment of certain gathering assets in the Barnett Shale, partially offset by gains totaling $833 million from the sale of the Four Corners Area ("FCA") business, the sale of certain gulf coast pipeline systems, and from the deconsolidation of certain former Permian Basin assets as part of the formation of a new joint venture with Brazos Midstream. Although our financial expectations for the Barnett assets have not materially changed over the next several years, the impairment was the result of reductions to our long-term estimate of revenues. Revenue estimates were lowered due to the forward curve for gas prices in this basin that have been impacted by the widening Permian basis differential. This resulted in moving the asset from its historical carrying value down to a current fair value. The impairment will reduce the book value for the assets and reduce future depreciation, but it does not impact guidance for our key financial metrics. Results also reflect the absence of a favorable fourth-quarter 2017 net impact of $1.147 billion, related to the tax provision benefit due to the Tax Cuts and Jobs Act of 2017 ("Tax Reform Act") partially offset by regulatory charges associated with the Tax Reform Act. The quarter benefited from a $111 million increase in service revenues in the Atlantic-Gulf segment driven by Transco expansion projects brought online in 2017 and 2018 and a $45 million improvement in service revenues in the Northeast G&P segment driven by higher gathering volumes compared to fourth-quarter 2017. Partially offsetting the improvements were a $39 million decrease in commodity margins due in part to the absence of results from the company's former FCA business sold on Oct. 1, 2018, and a decline in service revenues in the West segment driven by the sale of our FCA business, deconsolidation of our Jackalope interest as of June 2018, as well as the timing of recognizing minimum volume commitments (MVCs). 

For the year, Williams reported unaudited net income (loss) attributable to Williams available to common stockholders of ($156) million, a decrease of $2.330 billion versus full-year 2017. The unfavorable change was

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driven primarily by the previously described absence of the favorable fourth-quarter 2017 net benefit associated with the Tax Reform Act, $667 million of higher impairments of assets primarily reflecting the Barnett impairment in 2018 exceeding the impairment of certain gathering assets in the Mid-Continent region in 2017, $466 million of lower gains on the sale of assets and lower investing income where the gains from the sale of the Geismar olefins facility and the transaction involving certain interests in the Delaware Basin and Marcellus Shale in 2017 exceeded the gains on the sale of the FCA business, the sale of certain gulf coast pipeline systems, and from the deconsolidation of both our Jackalope interest and certain former Permian Basin assets in 2018. Results benefited from a $270 million increase in service revenues in the Atlantic-Gulf segment driven by Transco expansion projects brought online in 2017 and 2018 and a $104 million improvement in service revenues in the Northeast G&P segment driven by higher gathering volumes. Partially offsetting the improvements were $79 million lower commodity margins due primarily to the absence of results from our former Geismar olefins facility sold in July 2017, and a decline in service revenues in the West segment driven by the sale of our FCA business, deconsolidation of our Jackalope interest as of June 2018, and unfavorable changes in the recognition of deferred revenue driven by the adoption of a new accounting standard in 2018.

Cash Flow From Operations

Cash flow from operations (CFFO) for fourth-quarter2018 was $962 million, an increase of $104 million over fourth-quarter2017. Year-to-date, Williams’ CFFO totaled $3.293 billion compared with $3.089 billion for the prior year. The improvements compared to the prior year periods were driven by increased operating income (excluding impairments, gains and regulatory charges), due primarily to an increase in service revenues associated with Transco expansion projects placed in service in 2017 and 2018. The full-year improvement was partially offset by a decline in distributions from unconsolidated affiliates, primarily from deepwater Discovery Producer Services.

Adjusted Results

Williams reported fourth-quarter2018 Adjusted income of $230 million, a $60 million increase over fourth-quarter2017. For the year, Williams reported Adjusted income of $775 million, a $254 million improvement over 2017. Both the quarterly and full-year measures reflect the previously described changes in service revenues, partially offset by commodity margin declines. Changes in service revenues for the fourth-quarter and full-year periods were unfavorably impacted by $35 million and $100 million, respectively, reflecting the adoption of new revenue recognition standards in 2018. The improvements in both periods also reflect the benefit of less income allocated to noncontrolling interests following the completion of the WPZ Merger in third-quarter 2018. The full-year change was also impacted by lower equity earnings from Discovery attributable to Hadrian South production ending in fourth-quarter 2017. Adjusted income per share was $0.19. Although fourth-quarter 2018 adjusted income was $60 million higher than fourth-quarter 2017, the per share amount was slightly unfavorable by one cent due primarily to higher shares outstanding following completion of the WPZ merger. For the year, Adjusted income per share was $0.79, a 25 percent improvement over the full-year 2017 result of $0.63.

Williams reported fourth-quarter2018 Adjusted EBITDA of $1.197 billion, a $37 million increase from fourth-quarter2017. The improvement for fourth-quarter2018 over fourth-quarter2017 was driven primarily by the previously described increases in service revenues in the Atlantic-Gulf and Northeast G&P segments and a $23 million increase in proportional EBITDA of joint ventures due primarily to an increase in volumes in various Northeast G&P gathering systems. Partially offsetting the improvement were $39 million lower commodity margins primarily in the West segment. The year-over-year comparison was unfavorably impacted by $35 million from the adoption of new revenue recognition standards in 2018 and the absence of $27 million of Adjusted EBITDA from the company's former FCA business, sold Oct. 1, 2018.

For the year, Williams reported Adjusted EBITDA of $4.638 billion, an increase of $107 million over full-year 2017 results. The favorable change was driven by the previously described increases in Atlantic-Gulf and Northeast G&P segments. Partially offsetting the improvements was a $35 million decrease in proportional EBITDA from joint ventures driven by less production on the deepwater Discovery System attributable to Hadrian South production ending in fourth-quarter 2017. The year-over-year comparison was also unfavorably impacted by $100 million from the adoption of new revenue recognition standards in 2018, the absence of EBITDA earned by the former Geismar olefins plant of $72 million and the absence of fourth-quarter 2018 EBITDA earned by the company's former FCA business of $27 million.

Distributable Cash Flow

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For fourth-quarter2018, Williams generated $748 million in distributable cash flow (DCF) compared with $629 million in DCF for fourth-quarter2017. DCF was favorably impacted by the company's improvement in Adjusted EBITDA and lower maintenance capital spending, partially offset by higher net interest expense. Beginning with first-quarter 2018 results, Williams has discontinued the adjustment which removed the DCF associated with 2016 contract restructuring prepayments in the Barnett Shale and Mid-Continent region. For fourth-quarter2018, the coverage ratio is 1.82.

For the year, Williams generated $2.872 billion in DCF, a $292 million increase versus full-year 2017. DCF was favorably impacted by the company's improvement in Adjusted EBITDA and eliminating the adjustment in 2018 involving the removal of DCF associated with 2016 contract restructuring prepayments in the Barnett Shale and Mid-Continent region, partially offset by increased maintenance capital spending and higher net interest expense. For full-year 2018, the coverage ratio is 1.69.

Business Segment Results

Williams' operations following the Aug. 10, 2018, completion of Williams' acquisition of Williams Partners are comprised of the following reportable segments: Atlantic-Gulf, West, Northeast G&P and Other.

The below table reflects Modified and Adjusted EBITDA results for fourth-quarter2018 and full-year 2018, with comparisons to the previous year for each of the segments.

Williams	Modified and Adjusted EBITDA
Amounts in millions	4Q 2018								4Q 2017							Full-Year 2018								Full-Year 2017
	Modified EBITDA			Adjust.			Adjusted EBITDA		Modified EBITDA			Adjust.		Adjusted EBITDA		Modified EBITDA			Adjust.			Adjusted EBITDA		Modified EBITDA		Adjust.			Adjusted EBITDA
Atlantic-Gulf	605			(76		)	529		(96		)	529		433		2,023			(92		)	1,931		1,238		541			1,779
West	(906		)	1,264			358		286			195		481		308			1,269			1,577		412		1,256			1,668
Northeast G&P	300			4			304		231			7		238		1,086			4			1,090		819		140			959
Other*	20			(14		)	6		(103		)	111		8		(29		)	69			40		997		(872		)	125
Totals		$19			$1,178			$1,197		$318			$842		$1,160		$3,388			$1,250			$4,638		$3,466		$1,065			$4,531
Note: Williams uses Modified EBITDA for its segment reporting. Definitions of Modified EBITDA and Adjusted EBITDA and schedules reconciling to net income are included in this news release.
*In 2017, Other Modified EBITDA included a $1.095 billion gain on sale of the Company's former Geismar olefins plant, which was sold July 6, 2017.

Atlantic-Gulf

This segment includes Williams' interstate natural gas pipeline, Transco, and significant 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 entity), which is a proprietary floating production system, and the Bayou Ethane feedstock pipeline, as well as a 50 percent equity-method investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity) which is developing a pipeline project, and a 60 percent equity-method investment in Discovery.

The Atlantic-Gulf segment reported Modified EBITDA of $605 million for fourth-quarter2018, compared with ($96) million for fourth-quarter2017. Adjusted EBITDA increased by $96 million to $529 million for the same time period. Modified EBITDA results benefited from the absence of $493 million of non-cash regulatory charges at Transco in fourth-quarter 2017 associated with the Tax Reform Act and an $81 million gain on the sale of certain gulf coast pipeline systems in fourth-quarter 2018, which do not impact Adjusted EBITDA. The improvement in both measures reflects $111 million increased service revenues driven primarily by Transco expansion projects placed into service in 2017 and 2018.

For the year, the Atlantic-Gulf segment reported Modified EBITDA of $2.023 billion, an increase of $785 million over full-year 2017 results. Adjusted EBITDA increased $152 million to $1.931 billion. Modified EBITDA results benefited from the absence of the non-cash regulatory charges associated with the Tax Reform Act and an $81 million gain on the sale of certain gulf coast pipeline systems, which do not impact Adjusted EBITDA. The improvement in both measures reflects $270 million increased service revenues driven primarily by Transco

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expansion projects placed into service in 2017 and 2018. Partially offsetting the improvement was a $90 million decrease in proportional EBITDA from joint ventures due primarily to less production on the deepwater Discovery system attributable to Hadrian South production ending in fourth-quarter 2017.

West

This segment includes Williams' interstate natural gas pipeline, Northwest Pipeline, and natural gas gathering, processing, and treating operations in Colorado, and Wyoming, as well as 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 reporting segment also includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018), a 50 percent equity-method investment in Rocky Mountain Midstream (RMM) and a 15 percent equity-method investment in Brazos Permian II, LLC. Through third-quarter 2018, this segment also included natural gas gathering, processing, and treating operations in New Mexico and in Ignacio, Colorado, that were part of the company's FCA business, which was sold on Oct. 1, 2018.

The West segment reported Modified EBITDA of ($906) million for fourth-quarter2018, compared with $286 million for fourth-quarter2017. Adjusted EBITDA decreased by $123 million to $358 million. The unfavorable change in Modified EBITDA was driven primarily by a $1.849 billion impairment of certain gathering assets in the Barnett Shale, partially offset by a $591 million gain on the sale of the FCA business and the absence of $220 million of non-cash regulatory charges at Northwest Pipeline in fourth-quarter 2017 associated with the Tax Reform Act. Modified EBITDA was also unfavorably impacted by the timing of recognizing MVCs, which were recognized earlier throughout 2018 with the adoption of a new accounting standard. These items are not included in Adjusted EBITDA. The unfavorable change in both measures reflects a decrease in service revenues due primarily to the absence of the former FCA business, the deconsolidation of the company's interests in the Jackalope system, and lower volumes. Commodity margins also decreased $43 million due in part to the sale of the company's former FCA business and by lower NGL sale prices and volumes. Partially offsetting these decreases was a $14 million increase in proportional EBITDA from joint ventures due primarily to contributions from Jackalope and higher RMM and Overland Pass Pipeline volumes. The change in service revenues was unfavorably impacted by $35 million reflecting the adoption of new revenue-recognition standards in 2018.

For the year, the West segment reported Modified EBITDA of $308 million, a decrease of $104 million from full-year 2017 results. Adjusted EBITDA decreased by $91 million to $1.577 billion. The unfavorable change in Modified EBITDA was driven primarily by a $1.849 billion impairment of certain gathering assets in the Barnett Shale, partially offset by the absence of a $1.019 billion impairment of certain gathering assets in the Mid-Continent region and the absence of $220 million of non-cash regulatory charges at Northwest Pipeline, both in 2017, as well as the $591 million gain on the sale of the FCA business. These items are not included in Adjusted EBITDA. The unfavorable change in both measures was driven by a decrease in service revenues due primarily to the absence of results from the company's former FCA business, lower Northwest Pipeline rates and the deconsolidation of the company's interests in the Jackalope system. The change in service revenues was unfavorably impacted by $100 million reflecting the adoption of new revenue-recognition standards in 2018. Results also reflect $24 million of regulatory charges associated with Northwest Pipeline's approved rates related to the Tax Reform Act. Partially offsetting these decreases were $34 million increased commodity margins and lower operating and administrative costs.

Northeast G&P

This segment includes natural gas gathering and processing, compression and NGL fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, 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 an approximate average 66 percent equity-method investment in multiple gas gathering systems in the Marcellus Shale. Williams' natural gas gathering position is the largest in the entire Northeast region.

The Northeast G&P segment reported Modified EBITDA of $300 million for fourth-quarter2018, compared with $231 million for fourth-quarter2017. Adjusted EBITDA increased by $66 million to $304 million. The improvement

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in both measures was driven primarily by $45 million increased service revenues due to higher volumes at the Susquehanna, Ohio River and Utica systems and a $21 million increase in proportional EBITDA of joint ventures due primarily to higher volumes in Marcellus South and Blue Racer.

For the year, the Northeast G&P segment reported Modified EBITDA of $1.086 billion, an increase of $267 million over full-year 2017 results. Adjusted EBITDA increased by $131 million to $1.090 billion. Modified EBITDA results reflect the absence of a $121 million impairment of certain operations in 2017, which does not impact Adjusted EBITDA. Both measures benefited from $104 million increased service revenues due to higher volumes at the Susquehanna, Ohio River and Utica systems and a $40 million increase in proportional EBITDA of joint ventures due primarily to increased ownership in the Bradford gas gathering system and increased volumes in Marcellus South. Partially offsetting the improvements was an increase in operating and administrative costs.

Other Segment

Following Williams' completed acquisition of Williams Partners on Aug. 10, 2018, this segment now also includes the historical results of our former petchem services business.

The Other segment reported fourth-quarter2018 Modified EBITDA of $20 million, an increase of $123 million from fourth-quarter2017. Adjusted EBITDA decreased by $2 million to $6 million. The improvement in Modified EBITDA reflects the absence of certain 2017 charges associated with the Tax Reform Act, lower pension settlement charges, and a 2018 gain on the sale of certain gulf coast pipeline systems, all of which are excluded from Adjusted EBITDA.

For the year, Williams' Other segment reported Modified EBITDA of ($29) million, a decrease of $1.026 billion over the same 12-month reporting period in 2017. Adjusted EBITDA decreased by $85 million to $40 million. In addition to the items previously described, the unfavorable change in Modified EBITDA was driven primarily by the absence of a $1.095 billion gain on the sale of the company's former Geismar olefins plant in 2017, and costs related to the WPZ Merger, partially offset by lower net asset impairments. All of these impacts are excluded from Adjusted EBITDA. Both measures reflect the absence of results from the former Geismar olefins plant.

Today's Joint Announcement from Williams and Targa Resources

Earlier today, Williams and Targa Resources Corp. (NYSE: TRGP) (“Targa”) announced new natural gas liquids (“NGL”) agreements and NGL pipeline projects that will link the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. Williams will build a 188-mile NGL pipeline, called the “Bluestem Pipeline,” from its fractionator in Conway, Kansas, and the southern terminus of Overland Pass Pipeline to an interconnect with Targa’s Grand Prix NGL Pipeline (“Grand Prix”) in Kingfisher County, Oklahoma. Targa will construct a 110-mile extension of Grand Prix from southern Oklahoma into the Sooner Trend (oil field), Anadarko (basin), Canadian and Kingfisher (counties) (“STACK”) region of Central Oklahoma where it will connect with Williams’ new Bluestem Pipeline. To learn more about this announcement, please see today's joint news release from Williams and Targa.

Recent Accomplishments

Williams' Transco Pipeline recently delivered a record amount of natural gas on its Transco interstate gas pipeline. The nation's largest-volume natural gas transmission system, Transco delivered a record-breaking 15.68 million dekatherms (MMdt) on Jan. 21, 2019. The new peak-day mark surpasses the previous high that was set on Jan. 5, 2018. The Transco system, which stretches from South Texas to New York City, also established a new three-day market area delivery record, averaging 15.30 MMdt from Jan. 30 to Feb. 1, 2019. The natural gas delivery records were made possible thanks to additional firm transportation capacity created by multiple fully-contracted Transco expansions completed in 2018 and early 2019 (Gulf Connector, Atlantic Sunrise, and Garden State Phase II). Together, these expansions added more than 2.3 MMdt of firm transportation capacity to the existing pipeline system.

2019 Guidance

Current guidance for 2019, originally announced at Analyst Day on May 17, 2018, remains unchanged with the exception of Growth Capital Expenditures. Growth capital expenditure guidance has increased from prior guidance of $2.6 billion to a range of $2.7 billion to $2.9 billion primarily due to timing shifts from 2018 to 2019.

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Williams' Fourth-Quarter and Full-Year2018 Materials to be Posted Shortly; Q&A Webcast Scheduled for Tomorrow

Williams' fourth-quarter and full-year 2018 financial results package will be posted shortly at www.williams.com. The materials will include the analyst package. The Company’s fourth-quarter and full-year 2018 earnings conference call and webcast with analysts and investors is scheduled for Thursday, Feb. 14, 2019, at 9:30 a.m. Eastern Time (8:30 a.m. Central Time). A limited number of phone lines will be available at (800) 239-9838. International callers should dial (323) 794-2551. The conference ID is 3043497. A webcast link to the conference call is available at www.williams.com. A replay of the webcast will be available on the website for at least 90 days following the event.

Form 10-K

The company plans to file its 2018 Form 10-K with the Securities and Exchange Commission (SEC) next week. Once filed, the document will be available on both the SEC and Williams websites.

Non-GAAP Measures

This news release and accompanying materials may include certain financial measures – Adjusted EBITDA, adjusted income (“earnings”), adjusted earnings per share, distributable cash flow and dividend coverage ratio – that are non-GAAP financial measures as defined under the rules of the SEC.

Our segment performance measure, Modified EBITDA, is defined as net income (loss) before income (loss) from discontinued operations, income tax expense, net interest expense, equity earnings from equity-method investments, other net investing income, impairments of equity investments and goodwill, depreciation and amortization expense, and accretion expense associated with asset retirement obligations for nonregulated operations. We also add our proportional ownership share (based on ownership interest) of Modified EBITDA of equity-method investments.

Adjusted EBITDA further excludes items of income or loss that we characterize as unrepresentative of our ongoing operations. Management believes this measure provides investors meaningful insight into results from ongoing operations.

Distributable cash flow is defined as Adjusted EBITDA less maintenance capital expenditures, cash portion of net interest expense, income attributable to noncontrolling interests and cash income taxes, and certain other adjustments that management believes affects the comparability of results. Adjustments for maintenance capital expenditures and cash portion of interest expense include our proportionate share of these items of our equity-method investments. We also calculate the ratio of distributable cash flow to the total cash dividends paid (dividend coverage ratio). This measure reflects Williams’ distributable cash flow relative to its actual cash dividends paid.

This news release is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are accepted financial indicators used by investors to compare company performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of assets and the cash that the business is generating.

Neither Adjusted EBITDA, adjusted income, nor distributable cash flow are intended to represent cash flows for the period, nor are they presented as an alternative to net income or cash flow from operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles.

About Williams

Williams (NYSE: WMB) is a premier provider of large-scale infrastructure connecting U.S. natural gas and natural gas products to growing demand for cleaner fuel and feedstocks. Headquartered in Tulsa, Okla., Williams is an industry-leading, investment grade C-Corp with operations across the natural gas value chain including gathering, processing, interstate transportation and storage of natural gas and natural gas liquids. With major positions in top U.S. supply basins, Williams owns and operates more than 33,000 miles of pipelines system wide - including Transco, the nation’s largest volume and fastest growing pipeline - providing natural gas for clean-power

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generation, heating and industrial use. Williams’ operations handle approximately 30 percent of U.S. natural gas.www.williams.com

Forward-Looking Statements

The reports, filings, and other public announcements of The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical facts, included herein that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and may include, among others, statements regarding:

• Financial performance, including anticipated leverage and guidance for 2019;

• Levels of dividends to Williams stockholders;

• Future credit ratings of Williams and its affiliates;

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Expected in-service dates for capital projects;

• Financial condition and liquidity;

• Business strategy;

• Cash flow from operations or results of operations;

• Seasonality of certain business components;

• Natural gas and natural gas liquids prices, supply, and demand; and

• Demand for our services.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied herein. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

• Whether we are able to pay current and expected levels of dividends;

• Whether we will be able to effectively execute our financing plan;

• Availability of supplies, market demand, and volatility of prices;

• Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);

• The strength and financial resources of our competitors and the effects of competition;

• Whether we are able to successfully identify, evaluate and timely execute our capital projects and other investment opportunities;

• Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities, and to consummate asset sales on acceptable terms;

• Development and rate of adoption of alternative energy sources;

• The impact of operational and developmental hazards and unforeseen interruptions;

• The impact of existing and future laws and regulations (including but not limited to the Tax Cuts and Jobs Act of 2017), the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;

• Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

• Changes in maintenance and construction costs as well as our ability to obtain sufficient construction-related inputs including skilled labor;

• Changes in the current geopolitical situation;

• Our exposure to the credit risk of our customers and counterparties;

• Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally-recognized credit rating agencies and the availability and cost of capital;

• The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;

8

• Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;

• Acts of terrorism, cybersecurity incidents, and related disruptions;

• Additional risks described in our filings with the Securities and Exchange Commission (SEC).

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above may cause our intentions to change from those statements of intention set forth herein. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 22, 2018 and in Part II, Item 1A. Risk Factors in our Quarterly Reports on Form 10-Q.

###

9

Reconciliation of Income (Loss) Attributable to The Williams Companies, Inc. to Adjusted Income
(UNAUDITED)
	2017															2018
(Dollars in millions, except per-share amounts)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Income (loss) attributable to The Williams Companies, Inc. available to common stockholders	$	373		$	81		$	33		$	1,687		$	2,174		$	152		$	135		$	129		$	(572	)	$	(156	)
Income (loss) - diluted earnings (loss) per common share	$	.45		$	.10		$	.04		$	2.03		$	2.62		$	.18		$	.16		$	.13		$	(.47	)	$	(.16	)
Adjustments:
Northeast G&P
Share of impairment at equity-method investments	$	—		$	—		$	1		$	—		$	1		$	—		$	—		$	—		$	—		$	—
Impairment of certain assets	—			—			121			—			121			—			—			—			—			—
Ad valorem obligation timing adjustment	—			—			7			—			7			—			—			—			—			—
Settlement charge from pension early payout program	—			—			—			7			7			—			—			—			4			4
Organizational realignment-related costs	1			1			2			—			4			—			—			—			—			—
Total Northeast G&P adjustments	1			1			131			7			140			—			—			—			4			4
Atlantic-Gulf
Constitution Pipeline project development costs	2			6			4			4			16			2			1			1			—			4
Settlement charge from pension early payout program	—			—			—			15			15			—			—			—			7			7
Regulatory adjustments resulting from Tax Reform	—			—			—			493			493			11			(20		)	—			—			(9		)
Benefit of regulatory asset associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger	—			—			—			—			—			—			—			(3		)	—			(3		)
Share of regulatory charges resulting from Tax Reform for equity-method investments	—			—			—			11			11			2			—			—			—			2
Organizational realignment-related costs	1			2			2			1			6			—			—			—			—			—
Gain on sale of certain Gulf Coast pipeline assets	—			—			—			—			—			—			—			—			(81		)	(81		)
(Gain) loss on asset retirement	—			—			(5		)	5			—			—			—			(10		)	(2		)	(12		)
Total Atlantic-Gulf adjustments	3			8			1			529			541			15			(19		)	(12		)	(76		)	(92		)
West
Estimated minimum volume commitments	15			15			18			(48		)	—			—			—			—			—			—
Impairment of certain assets	—			—			1,021			9			1,030			—			—			—			1,849			1,849
Settlement charge from pension early payout program	—			—			—			13			13			—			—			—			6			6
Organizational realignment-related costs	2			3			2			1			8			—			—			—			—			—
Regulatory adjustments resulting from Tax Reform	—			—			—			220			220			(7		)	—			—			—			(7		)
Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger	—			—			—			—			—			—			—			12			—			12
Gain on sale of Four Corners assets	—			—			—			—			—			—			—			—			(591		)	(591		)
Gains from contract settlements and terminations	(13		)	(2		)	—			—			(15		)	—			—			—			—			—
Total West adjustments	4			16			1,041			195			1,256			(7		)	—			12			1,264			1,269
Other
(Gain) loss related to Canada disposition	(2		)	(1		)	4			5			6			—			—			—			—			—
Expenses associated with strategic asset monetizations	1			4			—			—			5			—			—			—			—			—
Geismar Incident adjustments	(9		)	2			8			(1		)	—			—			—			—			—			—
Gain on sale of Geismar Interest	—			—			(1,095		)	—			(1,095		)	—			—			—			—			—
Gain on sale of RGP Splitter	—			(12		)	—			—			(12		)	—			—			—			—			—
Accrual for loss contingency	9			—			—			—			9			—			—			—			—			—
Severance and related costs	9			4			5			4			22			—			—			—			—			—
ACMP Merger and transition costs	—			4			3			4			11			—			—			—			—			—
Expenses associated with Financial Repositioning	8			2			—			—			10			—			—			—			—			—
(Gain) loss on early retirement of debt	(30		)	—			3			—			(27		)	7			—			—			—			7
Impairment of certain assets	—			23			68			—			91			—			66			—			—			66
Expenses associated with strategic alternatives	1			3			5			—			9			—			—			—			—			—
Settlement charge from pension early payout program	—			—			—			36			36			—			—			—			5			5
Regulatory adjustments resulting from Tax Reform	—			—			—			63			63			—			1			—			—			1
Benefit of regulatory assets associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger	—			—			—			—			—			—			—			(45		)	—			(45		)
WPZ Merger costs	—			—			—			—			—			—			4			15			1			20
Gain on sale of certain Gulf Coast pipeline systems	—			—			—			—			—			—			—			—			(20		)	(20		)
Charitable contribution of preferred stock to Williams Foundation	—			—			—			—			—			—			—			35			—			35
Total Other adjustments	(13		)	29			(999		)	111			(872		)	7			71			5			(14		)	69
Adjustments included in Modified EBITDA	(5		)	54			174			842			1,065			15			52			5			1,178			1,250
Adjustments below Modified EBITDA
Gain on disposition of equity-method investment	(269		)	—			—			—			(269		)	—			—			—			—			—
Accelerated depreciation by equity-method investments	—			—			—			9			9			—			—			—			—			—
Change in depreciable life associated with organizational realignment	(7		)	—			—			—			(7		)	—			—			—			—			—
Gain on deconsolidation of Jackalope interest	—			—			—			—			—			—			(62		)	—			—			(62		)
Impairment of equity-method investments	—			—			—			—			—			—			—			—			32			32
Gain on deconsolidation of certain Permian assets	—			—			—			—			—			—			—			—			(141		)	(141		)
Allocation of adjustments to noncontrolling interests	77			(10		)	(28		)	(199		)	(160		)	(5		)	21			—			—			16
	(199		)	(10		)	(28		)	(190		)	(427		)	(5		)	(41		)	—			(109		)	(155		)
Total adjustments	(204		)	44			146			652			638			10			11			5			1,069			1,095
Less tax effect for above items	77			(17		)	(55		)	(246		)	(241		)	(3		)	(3		)	(1		)	(267		)	(274		)
Adjustments for tax-related items (1)	(127		)	—			—			(1,923		)	(2,050		)	—			—			110			—			110
Adjusted income available to common stockholders	$	119		$	108		$	124		$	170		$	521		$	159		$	143		$	243		$	230		$	775
Adjusted diluted earnings per common share (2)	$	.14		$	.13		$	.15		$	.20		$	.63		$	.19		$	.17		$	.24		$	.19		$	.79
Weighted-average shares - diluted (thousands)	826,476			828,575			829,368			829,607			828,518			830,197			830,107			1,026,504			1,212,822			976,097
(1) The first quarter of 2017 includes an unfavorable adjustment related to the release of a valuation allowance. The fourth quarter of 2017 includes an unfavorable adjustment to reverse the tax benefit associated with remeasuring our deferred tax balances at a lower corporate rate resulting from Tax Reform. The third quarter of 2018 reflects tax adjustments driven by the WPZ Merger, primarily a valuation allowance for foreign tax credits.
(2) The sum of earnings per share for the quarters may not equal the total earnings per share for the year due to changes in the weighted-average number of common shares outstanding.

10

Reconciliation of Distributable Cash Flow (DCF)
(UNAUDITED)
	2017															2018
(Dollars in millions, except coverage ratios)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
The Williams Companies, Inc.
Reconciliation of GAAP "Net Income (Loss)" to Non-GAAP "Modified EBITDA", "Adjusted EBITDA" and "Distributable cash flow"
Net income (loss)	$	569		$	193		$	125		$	1,622		$	2,509		$	270		$	269		$	200		$	(546	)	$	193
Provision (benefit) for income taxes	37			65			24			(2,100		)	(1,974		)	55			52			190			(159		)	138
Interest expense	280			271			267			265			1,083			273			275			270			294			1,112
Equity (earnings) losses	(107		)	(125		)	(115		)	(87		)	(434		)	(82		)	(92		)	(105		)	(117		)	(396		)
Impairment of equity-method investments	—			—			—			—			—			—			—			—			32			32
Other investing (income) loss - net	(272		)	(2		)	(4		)	(4		)	(282		)	(4		)	(68		)	(2		)	(145		)	(219		)
Proportional Modified EBITDA of equity-method investments	194			215			202			184			795			169			178			205			218			770
Depreciation and amortization expenses	442			433			433			428			1,736			431			434			425			435			1,725
Accretion for asset retirement obligations associated with nonregulated operations	7			9			7			10			33			8			10			8			7			33
Modified EBITDA	1,150			1,059			939			318			3,466			1,120			1,058			1,191			19			3,388
EBITDA adjustments	(5		)	54			174			842			1,065			15			52			5			1,178			1,250
Adjusted EBITDA	1,145			1,113			1,113			1,160			4,531			1,135			1,110			1,196			1,197			4,638
Maintenance capital expenditures (1)	(58		)	(105		)	(143		)	(165		)	(471		)	(110		)	(160		)	(138		)	(122		)	(530		)
Preferred dividends	—			—			—			—			—			—			—			—			(1		)	(1		)
Net interest expense - cash portion (2) (5)	(289		)	(280		)	(271		)	(271		)	(1,111		)	(276		)	(279		)	(274		)	(299		)	(1,128		)
Cash taxes	(5		)	(1		)	(11		)	(11		)	(28		)	(1		)	(10		)	(1		)	1			(11		)
Income attributable to noncontrolling interests (3)	(27		)	(32		)	(27		)	(27		)	(113		)	(25		)	(24		)	(19		)	(28		)	(96		)
WPZ restricted stock unit non-cash compensation	2			1			1			1			5			—			—			—			—			—
Amortization of deferred revenue associated with certain 2016 contract restructurings (4)	(58		)	(58		)	(59		)	(58		)	(233		)	—			—			—			—			—
Distributable cash flow (5)	$	710		$	638		$	603		$	629		$	2,580		$	723		$	637		$	764		$	748		$	2,872
Total cash distributed (6)	$	400		$	400		$	400		$	401		$	1,601		$	438		$	443		$	412		$	411		$	1,704
Coverage ratios:
Distributable cash flow divided by Total cash distributed (5)	1.78			1.60			1.51			1.57			1.61			1.65			1.44			1.85			1.82			1.69
Net income (loss) divided by Total cash distributed	1.42			0.48			0.31			4.04			1.57			0.62			0.61			0.49			(1.33		)	0.11
(1) Includes proportionate share of maintenance capital expenditures of equity investments.
(2) Includes proportionate share of interest expense of equity investments.
(3) Excludes allocable share of certain EBITDA adjustments.
(4) Beginning first quarter 2018, as a result of the extended deferred revenue amortization period under the new GAAP revenue standard, we have discontinued the adjustment associated with these 2016 contract restructuring payments. For each quarter of 2018, the adjustments would have been $32 million, $31 million, $32 million, and $33 million, respectively.
(5) The first, second, and third quarters of 2018 have been corrected to increase amounts reported as Net interest expense - cash portion by $3 million, $4 million, and $4 million, respectively.
(6) Includes cash dividends paid each quarter by WMB, as well as the public unitholders share of distributions declared by WPZ for the 2017 periods and the first two quarters of 2018.

11

Reconciliation of "Net Income (Loss)" to “Modified EBITDA” and Non-GAAP “Adjusted EBITDA”
(UNAUDITED)
	2017															2018
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Net income (loss)	$	569		$	193		$	125		$	1,622		$	2,509		$	270		$	269		$	200		$	(546	)	$	193
Provision (benefit) for income taxes	37			65			24			(2,100		)	(1,974		)	55			52			190			(159		)	138
Interest expense	280			271			267			265			1,083			273			275			270			294			1,112
Equity (earnings) losses	(107		)	(125		)	(115		)	(87		)	(434		)	(82		)	(92		)	(105		)	(117		)	(396		)
Impairment of equity-method investments	—			—			—			—			—			—			—			—			32			32
Other investing (income) loss - net	(272		)	(2		)	(4		)	(4		)	(282		)	(4		)	(68		)	(2		)	(145		)	(219		)
Proportional Modified EBITDA of equity-method investments	194			215			202			184			795			169			178			205			218			770
Depreciation and amortization expenses	442			433			433			428			1,736			431			434			425			435			1,725
Accretion expense associated with asset retirement obligations for nonregulated operations	7			9			7			10			33			8			10			8			7			33
Modified EBITDA	$	1,150		$	1,059		$	939		$	318		$	3,466		$	1,120		$	1,058		$	1,191		$	19		$	3,388
Northeast G&P	$	226		$	247		$	115		$	231		$	819		$	250		$	255		$	281		$	300		$	1,086
Atlantic-Gulf	450			454			430			(96		)	1,238			451			475			492			605			2,023
West	385			356			(615		)	286			412			413			389			412			(906		)	308
Other	89			2			1,009			(103		)	997			6			(61		)	6			20			(29		)
Total Modified EBITDA	$	1,150		$	1,059		$	939		$	318		$	3,466		$	1,120		$	1,058		$	1,191		$	19		$	3,388
Adjustments included in Modified EBITDA (1):
Northeast G&P	$	1		$	1		$	131		$	7		$	140		$	—		$	—		$	—		$	4		$	4
Atlantic-Gulf	3			8			1			529			541			15			(19		)	(12		)	(76		)	(92		)
West	4			16			1,041			195			1,256			(7		)	—			12			1,264			1,269
Other	(13		)	29			(999		)	111			(872		)	7			71			5			(14		)	69
Total Adjustments included in Modified EBITDA	$	(5	)	$	54		$	174		$	842		$	1,065		$	15		$	52		$	5		$	1,178		$	1,250
Adjusted EBITDA:
Northeast G&P	$	227		$	248		$	246		$	238		$	959		$	250		$	255		$	281		$	304		$	1,090
Atlantic-Gulf	453			462			431			433			1,779			466			456			480			529			1,931
West	389			372			426			481			1,668			406			389			424			358			1,577
Other	76			31			10			8			125			13			10			11			6			40
Total Adjusted EBITDA	$	1,145		$	1,113		$	1,113		$	1,160		$	4,531		$	1,135		$	1,110		$	1,196		$	1,197		$	4,638
(1) Adjustments by segment are detailed in the "Reconciliation of Income (Loss) Attributable to The Williams Companies, Inc. to Adjusted Income," which is also included in these materials.

12

EX-99.2

EXHIBIT 99.2

Non-GAAP Reconciliations,

Financial Highlights, and Operating Statistics

(UNAUDITED)

Final

December 31, 2018

Reconciliation of Income (Loss) Attributable to The Williams Companies, Inc. to Adjusted Income
(UNAUDITED)
	2017															2018
(Dollars in millions, except per-share amounts)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Income (loss) attributable to The Williams Companies, Inc. available to common stockholders	$	373		$	81		$	33		$	1,687		$	2,174		$	152		$	135		$	129		$	(572	)	$	(156	)
Income (loss) - diluted earnings (loss) per common share	$	.45		$	.10		$	.04		$	2.03		$	2.62		$	.18		$	.16		$	.13		$	(.47	)	$	(.16	)
Adjustments:
Northeast G&P
Share of impairment at equity-method investments	$	—		$	—		$	1		$	—		$	1		$	—		$	—		$	—		$	—		$	—
Impairment of certain assets	—			—			121			—			121			—			—			—			—			—
Ad valorem obligation timing adjustment	—			—			7			—			7			—			—			—			—			—
Settlement charge from pension early payout program	—			—			—			7			7			—			—			—			4			4
Organizational realignment-related costs	1			1			2			—			4			—			—			—			—			—
Total Northeast G&P adjustments	1			1			131			7			140			—			—			—			4			4
Atlantic-Gulf
Constitution Pipeline project development costs	2			6			4			4			16			2			1			1			—			4
Settlement charge from pension early payout program	—			—			—			15			15			—			—			—			7			7
Regulatory adjustments resulting from Tax Reform	—			—			—			493			493			11			(20		)	—			—			(9		)
Benefit of regulatory asset associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger	—			—			—			—			—			—			—			(3		)	—			(3		)
Share of regulatory charges resulting from Tax Reform for equity-method investments	—			—			—			11			11			2			—			—			—			2
Organizational realignment-related costs	1			2			2			1			6			—			—			—			—			—
Gain on sale of certain Gulf Coast pipeline assets	—			—			—			—			—			—			—			—			(81		)	(81		)
(Gain) loss on asset retirement	—			—			(5		)	5			—			—			—			(10		)	(2		)	(12		)
Total Atlantic-Gulf adjustments	3			8			1			529			541			15			(19		)	(12		)	(76		)	(92		)
West
Estimated minimum volume commitments	15			15			18			(48		)	—			—			—			—			—			—
Impairment of certain assets	—			—			1,021			9			1,030			—			—			—			1,849			1,849
Settlement charge from pension early payout program	—			—			—			13			13			—			—			—			6			6
Organizational realignment-related costs	2			3			2			1			8			—			—			—			—			—
Regulatory adjustments resulting from Tax Reform	—			—			—			220			220			(7		)	—			—			—			(7		)
Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger	—			—			—			—			—			—			—			12			—			12
Gain on sale of Four Corners assets	—			—			—			—			—			—			—			—			(591		)	(591		)
Gains from contract settlements and terminations	(13		)	(2		)	—			—			(15		)	—			—			—			—			—
Total West adjustments	4			16			1,041			195			1,256			(7		)	—			12			1,264			1,269
Other
(Gain) loss related to Canada disposition	(2		)	(1		)	4			5			6			—			—			—			—			—
Expenses associated with strategic asset monetizations	1			4			—			—			5			—			—			—			—			—
Geismar Incident adjustments	(9		)	2			8			(1		)	—			—			—			—			—			—
Gain on sale of Geismar Interest	—			—			(1,095		)	—			(1,095		)	—			—			—			—			—
Gain on sale of RGP Splitter	—			(12		)	—			—			(12		)	—			—			—			—			—
Accrual for loss contingency	9			—			—			—			9			—			—			—			—			—
Severance and related costs	9			4			5			4			22			—			—			—			—			—
ACMP Merger and transition costs	—			4			3			4			11			—			—			—			—			—
Expenses associated with Financial Repositioning	8			2			—			—			10			—			—			—			—			—
(Gain) loss on early retirement of debt	(30		)	—			3			—			(27		)	7			—			—			—			7
Impairment of certain assets	—			23			68			—			91			—			66			—			—			66
Expenses associated with strategic alternatives	1			3			5			—			9			—			—			—			—			—
Settlement charge from pension early payout program	—			—			—			36			36			—			—			—			5			5
Regulatory adjustments resulting from Tax Reform	—			—			—			63			63			—			1			—			—			1
Benefit of regulatory assets associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger	—			—			—			—			—			—			—			(45		)	—			(45		)
WPZ Merger costs	—			—			—			—			—			—			4			15			1			20
Gain on sale of certain Gulf Coast pipeline systems	—			—			—			—			—			—			—			—			(20		)	(20		)
Charitable contribution of preferred stock to Williams Foundation	—			—			—			—			—			—			—			35			—			35
Total Other adjustments	(13		)	29			(999		)	111			(872		)	7			71			5			(14		)	69
Adjustments included in Modified EBITDA	(5		)	54			174			842			1,065			15			52			5			1,178			1,250
Adjustments below Modified EBITDA
Gain on disposition of equity-method investment	(269		)	—			—			—			(269		)	—			—			—			—			—
Accelerated depreciation by equity-method investments	—			—			—			9			9			—			—			—			—			—
Change in depreciable life associated with organizational realignment	(7		)	—			—			—			(7		)	—			—			—			—			—
Gain on deconsolidation of Jackalope interest	—			—			—			—			—			—			(62		)	—			—			(62		)
Impairment of equity-method investments	—			—			—			—			—			—			—			—			32			32
Gain on deconsolidation of certain Permian assets	—			—			—			—			—			—			—			—			(141		)	(141		)
Allocation of adjustments to noncontrolling interests	77			(10		)	(28		)	(199		)	(160		)	(5		)	21			—			—			16
	(199		)	(10		)	(28		)	(190		)	(427		)	(5		)	(41		)	—			(109		)	(155		)
Total adjustments	(204		)	44			146			652			638			10			11			5			1,069			1,095
Less tax effect for above items	77			(17		)	(55		)	(246		)	(241		)	(3		)	(3		)	(1		)	(267		)	(274		)
Adjustments for tax-related items (1)	(127		)	—			—			(1,923		)	(2,050		)	—			—			110			—			110
Adjusted income available to common stockholders	$	119		$	108		$	124		$	170		$	521		$	159		$	143		$	243		$	230		$	775
Adjusted diluted earnings per common share (2)	$	.14		$	.13		$	.15		$	.20		$	.63		$	.19		$	.17		$	.24		$	.19		$	.79
Weighted-average shares - diluted (thousands)	826,476			828,575			829,368			829,607			828,518			830,197			830,107			1,026,504			1,212,822			976,097
(1) The first quarter of 2017 includes an unfavorable adjustment related to the release of a valuation allowance. The fourth quarter of 2017 includes an unfavorable adjustment to reverse the tax benefit associated with remeasuring our deferred tax balances at a lower corporate rate resulting from Tax Reform. The third quarter of 2018 reflects tax adjustments driven by the WPZ Merger, primarily a valuation allowance for foreign tax credits.
(2) The sum of earnings per share for the quarters may not equal the total earnings per share for the year due to changes in the weighted-average number of common shares outstanding.

1

Reconciliation of Distributable Cash Flow (DCF)
(UNAUDITED)
	2017															2018
(Dollars in millions, except coverage ratios)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
The Williams Companies, Inc.
Reconciliation of GAAP "Net Income (Loss)" to Non-GAAP "Modified EBITDA", "Adjusted EBITDA" and "Distributable cash flow"
Net income (loss)	$	569		$	193		$	125		$	1,622		$	2,509		$	270		$	269		$	200		$	(546	)	$	193
Provision (benefit) for income taxes	37			65			24			(2,100		)	(1,974		)	55			52			190			(159		)	138
Interest expense	280			271			267			265			1,083			273			275			270			294			1,112
Equity (earnings) losses	(107		)	(125		)	(115		)	(87		)	(434		)	(82		)	(92		)	(105		)	(117		)	(396		)
Impairment of equity-method investments	—			—			—			—			—			—			—			—			32			32
Other investing (income) loss - net	(272		)	(2		)	(4		)	(4		)	(282		)	(4		)	(68		)	(2		)	(145		)	(219		)
Proportional Modified EBITDA of equity-method investments	194			215			202			184			795			169			178			205			218			770
Depreciation and amortization expenses	442			433			433			428			1,736			431			434			425			435			1,725
Accretion for asset retirement obligations associated with nonregulated operations	7			9			7			10			33			8			10			8			7			33
Modified EBITDA	1,150			1,059			939			318			3,466			1,120			1,058			1,191			19			3,388
EBITDA adjustments	(5		)	54			174			842			1,065			15			52			5			1,178			1,250
Adjusted EBITDA	1,145			1,113			1,113			1,160			4,531			1,135			1,110			1,196			1,197			4,638
Maintenance capital expenditures (1)	(58		)	(105		)	(143		)	(165		)	(471		)	(110		)	(160		)	(138		)	(122		)	(530		)
Preferred dividends	—			—			—			—			—			—			—			—			(1		)	(1		)
Net interest expense - cash portion (2) (5)	(289		)	(280		)	(271		)	(271		)	(1,111		)	(276		)	(279		)	(274		)	(299		)	(1,128		)
Cash taxes	(5		)	(1		)	(11		)	(11		)	(28		)	(1		)	(10		)	(1		)	1			(11		)
Income attributable to noncontrolling interests (3)	(27		)	(32		)	(27		)	(27		)	(113		)	(25		)	(24		)	(19		)	(28		)	(96		)
WPZ restricted stock unit non-cash compensation	2			1			1			1			5			—			—			—			—			—
Amortization of deferred revenue associated with certain 2016 contract restructurings (4)	(58		)	(58		)	(59		)	(58		)	(233		)	—			—			—			—			—
Distributable cash flow (5)	$	710		$	638		$	603		$	629		$	2,580		$	723		$	637		$	764		$	748		$	2,872
Total cash distributed (6)	$	400		$	400		$	400		$	401		$	1,601		$	438		$	443		$	412		$	411		$	1,704
Coverage ratios:
Distributable cash flow divided by Total cash distributed (5)	1.78			1.60			1.51			1.57			1.61			1.65			1.44			1.85			1.82			1.69
Net income (loss) divided by Total cash distributed	1.42			0.48			0.31			4.04			1.57			0.62			0.61			0.49			(1.33		)	0.11
(1) Includes proportionate share of maintenance capital expenditures of equity investments.
(2) Includes proportionate share of interest expense of equity investments.
(3) Excludes allocable share of certain EBITDA adjustments.
(4) Beginning first quarter 2018, as a result of the extended deferred revenue amortization period under the new GAAP revenue standard, we have discontinued the adjustment associated with these 2016 contract restructuring payments. For each quarter of 2018, the adjustments would have been $32 million, $31 million, $32 million, and $33 million, respectively.
(5) The first, second, and third quarters of 2018 have been corrected to increase amounts reported as Net interest expense - cash portion by $3 million, $4 million, and $4 million, respectively.
(6) Includes cash dividends paid each quarter by WMB, as well as the public unitholders share of distributions declared by WPZ for the 2017 periods and the first two quarters of 2018.

2

Reconciliation of "Net Income (Loss)" to “Modified EBITDA” and Non-GAAP “Adjusted EBITDA”
(UNAUDITED)
	2017															2018
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Net income (loss)	$	569		$	193		$	125		$	1,622		$	2,509		$	270		$	269		$	200		$	(546	)	$	193
Provision (benefit) for income taxes	37			65			24			(2,100		)	(1,974		)	55			52			190			(159		)	138
Interest expense	280			271			267			265			1,083			273			275			270			294			1,112
Equity (earnings) losses	(107		)	(125		)	(115		)	(87		)	(434		)	(82		)	(92		)	(105		)	(117		)	(396		)
Impairment of equity-method investments	—			—			—			—			—			—			—			—			32			32
Other investing (income) loss - net	(272		)	(2		)	(4		)	(4		)	(282		)	(4		)	(68		)	(2		)	(145		)	(219		)
Proportional Modified EBITDA of equity-method investments	194			215			202			184			795			169			178			205			218			770
Depreciation and amortization expenses	442			433			433			428			1,736			431			434			425			435			1,725
Accretion expense associated with asset retirement obligations for nonregulated operations	7			9			7			10			33			8			10			8			7			33
Modified EBITDA	$	1,150		$	1,059		$	939		$	318		$	3,466		$	1,120		$	1,058		$	1,191		$	19		$	3,388
Northeast G&P	$	226		$	247		$	115		$	231		$	819		$	250		$	255		$	281		$	300		$	1,086
Atlantic-Gulf	450			454			430			(96		)	1,238			451			475			492			605			2,023
West	385			356			(615		)	286			412			413			389			412			(906		)	308
Other	89			2			1,009			(103		)	997			6			(61		)	6			20			(29		)
Total Modified EBITDA	$	1,150		$	1,059		$	939		$	318		$	3,466		$	1,120		$	1,058		$	1,191		$	19		$	3,388
Adjustments included in Modified EBITDA (1):
Northeast G&P	$	1		$	1		$	131		$	7		$	140		$	—		$	—		$	—		$	4		$	4
Atlantic-Gulf	3			8			1			529			541			15			(19		)	(12		)	(76		)	(92		)
West	4			16			1,041			195			1,256			(7		)	—			12			1,264			1,269
Other	(13		)	29			(999		)	111			(872		)	7			71			5			(14		)	69
Total Adjustments included in Modified EBITDA	$	(5	)	$	54		$	174		$	842		$	1,065		$	15		$	52		$	5		$	1,178		$	1,250
Adjusted EBITDA:
Northeast G&P	$	227		$	248		$	246		$	238		$	959		$	250		$	255		$	281		$	304		$	1,090
Atlantic-Gulf	453			462			431			433			1,779			466			456			480			529			1,931
West	389			372			426			481			1,668			406			389			424			358			1,577
Other	76			31			10			8			125			13			10			11			6			40
Total Adjusted EBITDA	$	1,145		$	1,113		$	1,113		$	1,160		$	4,531		$	1,135		$	1,110		$	1,196		$	1,197		$	4,638
(1) Adjustments by segment are detailed in the "Reconciliation of Income (Loss) Attributable to The Williams Companies, Inc. to Adjusted Income," which is also included in these materials.

3

Consolidated Statement of Operations
(UNAUDITED)
	2017															2018
(Dollars in millions, except per-share amounts)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Revenues:
Service revenues	$	1,261		$	1,282		$	1,310		$	1,459		$	5,312		$	1,351		$	1,340		$	1,371		$	1,440		$	5,502
Service revenues - commodity consideration	—			—			—			—			—			101			94			121			84			400
Product sales	727			642			581			769			2,719			636			657			811			680			2,784
Total revenues	1,988			1,924			1,891			2,228			8,031			2,088			2,091			2,303			2,204			8,686
Costs and expenses:
Product costs	579			537			504			680			2,300			613			636			790			668			2,707
Processing commodity expenses	—			—			—			—			—			35			26			30			46			137
Operating and maintenance expenses	371			392			403			410			1,576			357			388			389			373			1,507
Depreciation and amortization expenses	442			433			433			428			1,736			431			434			425			435			1,725
Selling, general, and administrative expenses	161			153			138			142			594			132			130			174			133			569
Impairment of certain assets	1			25			1,210			12			1,248			—			66			—			1,849			1,915
Gain on sale of certain assets	—			—			(1,095		)	—			(1,095		)	—			—			—			(692		)	(692		)
Regulatory charges resulting from Tax Reform	—			—			—			674			674			—			—			—			(17		)	(17		)
Other (income) expense - net	4			6			24			37			71			29			1			(6		)	43			67
Total costs and expenses	1,558			1,546			1,617			2,383			7,104			1,597			1,681			1,802			2,838			7,918
Operating income (loss)	430			378			274			(155		)	927			491			410			501			(634		)	768
Equity earnings (losses)	107			125			115			87			434			82			92			105			117			396
Impairment of equity-method investments	—			—			—			—			—			—			—			—			(32		)	(32		)
Other investing income (loss) - net	272			2			4			4			282			4			68			2			145			219
Interest incurred	(287		)	(280		)	(275		)	(274		)	(1,116		)	(282		)	(288		)	(286		)	(304		)	(1,160		)
Interest capitalized	7			9			8			9			33			9			13			16			10			48
Other income (expense) - net	77			24			23			(149		)	(25		)	21			26			52			(7		)	92
Income (loss) before income taxes	606			258			149			(478		)	535			325			321			390			(705		)	331
Provision (benefit) for income taxes	37			65			24			(2,100		)	(1,974		)	55			52			190			(159		)	138
Net income (loss)	569			193			125			1,622			2,509			270			269			200			(546		)	193
Less: Net income (loss) attributable to noncontrolling interests	196			112			92			(65		)	335			118			134			71			25			348
Net income (loss) attributable to The Williams Companies, Inc.	373			81			33			1,687			2,174			152			135			129			(571		)	(155		)
Preferred stock dividends	—			—			—			—			—			—			—			—			1			1
Net income (loss) available to common stockholders	$	373		$	81		$	33		$	1,687		$	2,174		$	152		$	135		$	129		$	(572	)	$	(156	)
Diluted earnings (loss) per common share:
Net income (loss) (1)	$	.45		$	.10		$	.04		$	2.03		$	2.62		$	.18		$	.16		$	.13		$	(.47	)	$	(.16	)
Weighted-average number of shares (thousands)	826,476			828,575			829,368			829,607			828,518			830,197			830,107			1,026,504			1,210,780			973,626
Common shares outstanding at end of period (thousands)	826,239			826,398			826,723			826,836			826,836			827,607			827,733			1,210,525			1,210,564			1,210,564
Market price per common share (end of period)	$	29.59		$	30.28		$	30.01		$	30.49		$	30.49		$	24.86		$	27.11		$	27.19		$	22.05		$	22.05
Cash dividends declared per share	$	.30		$	.30		$	.30		$	.30		$	1.20		$	.34		$	.34		$	.34		$	.34		$	1.36
(1) The sum of earnings (loss) per share for the quarters may not equal the total earnings (loss) per share for the year due to changes in the weighted-average number of common shares outstanding.

4

Northeast G&P
(UNAUDITED)
	2017											2018
(Dollars in millions)	1st Qtr		2nd Qtr		3rd Qtr			4th Qtr		Year		1st Qtr		2nd Qtr		3rd Qtr		4th Qtr		Year
Revenues:
Service revenues:
Nonregulated gathering and processing fee-based revenue	$	182	$	183	$	182		$	191	$	738	$	189	$	196	$	211	$	226	$	822
Other fee revenues	35		34		32			33		134		39		36		36		43		154
Nonregulated commodity consideration	—		—		—			—		—		4		4		6		6		20
Product sales:
NGL sales from gas processing	4		4		2			4		14		4		5		6		5		20
Marketing sales	64		48		59			106		277		89		65		57		35		246
Tracked product sales	—		—		—			—		—		5		5		6		5		21
Total revenues	285		269		275			334		1,163		330		311		322		320		1,283
Segment costs and expenses:
NGL cost of goods sold	4		1		2			1		8		4		5		6		5		20
Marketing cost of goods sold	65		48		59			106		278		90		65		57		36		248
Processing commodity expenses	—		—		—			—		—		2		2		3		2		9
Operating and administrative costs	86		88		99			103		376		85		91		96		108		380
Other segment costs and expenses	—		1		(1		)	10		10		2		1		4		5		12
Impairment of certain assets	1		1		121			1		124		—		—		—		—		—
Tracked cost of goods sold	—		—		—			—		—		5		7		6		3		21
Total segment costs and expenses	156		139		280			221		796		188		171		172		159		690
Proportional Modified EBITDA of equity-method investments	97		117		120			118		452		108		115		131		139		493
Modified EBITDA	226		247		115			231		819		250		255		281		300		1,086
Adjustments	1		1		131			7		140		—		—		—		4		4
Adjusted EBITDA	$	227	$	248	$	246		$	238	$	959	$	250	$	255	$	281	$	304	$	1,090
NGL margin	$	—	$	3	$	—		$	3	$	6	$	2	$	2	$	3	$	4	$	11
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day) - Consolidated (1)	3.32		3.28		3.28			3.37		3.31		3.38		3.45		3.67		4.02		3.63
Gathering volumes (Bcf per day) - Non-consolidated (2)	3.55		3.58		3.48			3.61		3.55		3.82		3.59		3.73		3.89		3.76
Plant inlet natural gas volumes (Bcf per day) (1)	0.39		0.40		0.45			0.50		0.43		0.49		0.55		0.52		0.52		0.52
Ethane equity sales (Mbbls/d)	2.32		2.34		1.71			0.98		1.83		1.33		3.17		2.74		2.80		2.52
Non-ethane equity sales (Mbbls/d)	1.09		1.13		1.17			0.90		1.07		0.79		1.09		1.49		1.28		1.16
NGL equity sales (Mbbls/d)	3.41		3.47		2.88			1.88		2.90		2.12		4.26		4.23		4.08		3.68
Ethane production (Mbbls/d)	17		22		17			22		20		23		27		26		20		24
Non-ethane production (Mbbls/d)	15		17		19			22		18		21		21		23		22		22
NGL production (Mbbls/d)	32		39		36			44		38		44		48		49		42		46
(1) Includes gathering volumes associated with Susquehanna Supply Hub, Ohio Valley Midstream, and Utica Supply Hub, all of which are consolidated.
(2) Includes 100% of the volumes associated with operated equity-method investments, including the Laurel Mountain Midstream partnership; and the Bradford Supply Hub and a portion of the Marcellus South Supply Hub within the Appalachia Midstream Services partnership. Volumes handled by Blue Racer Midstream (gathering and processing) and UEOM (processing only), which we do not operate, are not included.

5

Atlantic-Gulf
(UNAUDITED)
	2017														2018
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year		1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue	$	127		$	136		$	133		$	132		$	528	$	138		$	128		$	138		$	137		$	541
Regulated transportation revenue	354			358			380			408			1,500		413			406			411			508			1,738
Other fee revenues	34			34			31			33			132		32			34			34			34			134
Tracked service revenue	21			19			20			19			79		26			22			24			24			96
Nonregulated commodity consideration	—			—			—			—			—		15			12			18			14			59
Product sales:
NGL sales from gas processing	27			16			13			14			70		15			10			16			15			56
Marketing sales	90			75			66			81			312		45			57			67			53			222
Other sales	4			3			2			1			10		2			2			3			1			8
Tracked product sales	13			31			25			23			92		31			36			45			37			149
Total revenues	670			672			670			711			2,723		717			707			756			823			3,003
Segment costs and expenses:
NGL cost of goods sold	13			7			6			3			29		15			12			19			14			60
Marketing cost of goods sold	89			73			64			81			307		44			56			67			53			220
Other cost of goods sold	1			—			—			1			2		—			—			—			—			—
Tracked cost of goods sold	15			33			27			24			99		33			38			48			39			158
Processing commodity expenses	—			—			—			—			—		5			2			3			6			16
Operating and administrative costs	157			169			193			208			727		177			181			181			197			736
Other segment costs and expenses	(4		)	(3		)	(6		)	26			13		(2		)	(15		)	(29		)	14			(32		)
Gain on sale of certain assets	—			—			—			—			—		—			—			—			(81		)	(81		)
Regulatory charges resulting from Tax Reform	—			—			—			493			493		11			(20		)	—			—			(9		)
Tracked operating and administrative costs	21			19			20			19			79		26			22			24			23			95
Total segment costs and expenses	292			298			304			855			1,749		309			276			313			265			1,163
Proportional Modified EBITDA of equity-method investments	72			80			64			48			264		43			44			49			47			183
Modified EBITDA	450			454			430			(96		)	1,238		451			475			492			605			2,023
Adjustments	3			8			1			529			541		15			(19		)	(12		)	(76		)	(92		)
Adjusted EBITDA	$	453		$	462		$	431		$	433		$	1,779	$	466		$	456		$	480		$	529		$	1,931
NGL Margins	$	14		$	9		$	7		$	11		$	41	$	10		$	8		$	12		$	9		$	39
Statistics for Operated Assets
Gathering, Processing and Crude Oil Transportation
Gathering volumes (Bcf per day) - Consolidated (1)	0.32			0.29			0.31			0.30			0.31		0.29			0.23			0.26			0.24			0.26
Gathering volumes (Bcf per day) - Non-consolidated (2)	0.55			0.54			0.39			0.28			0.44		0.24			0.25			0.25			0.31			0.26
Plant inlet natural gas volumes (Bcf per day) - Consolidated (1)	0.56			0.57			0.52			0.54			0.55		0.54			0.43			0.51			0.53			0.50
Plant inlet natural gas volumes (Bcf per day) - Non-consolidated (2)	0.54			0.53			0.39			0.27			0.43		0.24			0.25			0.25			0.32			0.27
Crude transportation volumes (Mbbls/d)	131			135			137			136			134		142			132			147			140			140
Consolidated (1)
Ethane margin ($/gallon)	$	.02		$	.03		$	.04		$	.09		$	.04	$	.03		$	.16		$	.24		$	.14		$	.14
Non-ethane margin ($/gallon)	$	.42		$	.36		$	.53		$	.72		$	.47	$	.66		$	.74		$	.76		$	.58		$	.68
NGL margin ($/gallon)	$	.26		$	.23		$	.26		$	.46		$	.28	$	.40		$	.48		$	.51		$	.36		$	.43
Ethane equity sales (Mbbls/d)	6.09			3.74			4.29			2.36			4.11		2.82			1.91			3.05			2.98			2.69
Non-ethane equity sales (Mbbls/d)	8.64			5.82			3.50			3.42			5.33		3.87			2.35			3.14			3.21			3.14
NGL equity sales (Mbbls/d)	14.73			9.56			7.79			5.78			9.44		6.69			4.26			6.19			6.19			5.83
Ethane production (Mbbls/d)	14			14			13			14			14		12			12			15			16			14
Non-ethane production (Mbbls/d)	20			19			18			19			19		19			17			18			19			18
NGL production (Mbbls/d)	34			33			31			33			33		31			29			33			35			32
Non-consolidated (2)
NGL equity sales (Mbbls/d)	5			4			5			4			5		3			5			4			5			4
NGL production (Mbbls/d)	21			22			22			19			21		18			20			20			23			20
Transcontinental Gas Pipe Line
Throughput (Tbtu)	939.1			887.6			938.5			1,017.5			3,782.7		1,099.9			965.5			1,092.3			1,150.9			4,308.5
Avg. daily transportation volumes (Tbtu)	10.4			9.8			10.2			11.1			10.4		12.2			10.6			11.9			12.5			11.8
Avg. daily firm reserved capacity (Tbtu)	12.8			13.2			14.1			14.9			13.8		15.4			15.0			15.0			16.4			15.5
(1) Excludes volumes associated with equity-method investments that are not consolidated in our results.
(2) Includes 100% of the volumes associated with operated equity-method investments.

6

West
(UNAUDITED)
	2017													2018
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr		Year		1st Qtr			2nd Qtr		3rd Qtr		4th Qtr			Year
Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue	$	363		$	382		$	398		$	502	$	1,645	$	386		$	398	$	387	$	335		$	1,506
Regulated transportation revenue	117			112			113			118		460		109			104		106		110			429
Other fee revenues	38			33			33			37		141		36			32		40		41			149
Nonregulated commodity consideration	—			—			—			—		—		82			78		97		64			321
Tracked service revenues	—			—			—			—		—		—			1		—		—			1
Product sales:
NGL sales from gas processing	64			61			68			82		275		85			76		90		71			322
Olefin sales	1			—			—			—		1		—			—		—		—			—
Marketing sales	387			368			408			534		1,697		419			465		615		571			2,070
Other sales	4			5			9			20		38		10			9		16		3			38
Tracked product sales	—			1			—			1		2		16			10		11		(19		)	18
Total revenues	974			962			1,029			1,294		4,259		1,143			1,173		1,362		1,176			4,854
Segment costs and expenses:
NGL cost of goods sold	27			31			31			32		121		85			81		101		66			333
Marketing cost of goods sold	386			375			397			527		1,685		418			458		605		587			2,068
Other cost of goods sold	3			3			10			20		36		7			8		12		2			29
Tracked cost of goods sold	—			—			—			—		—		16			10		12		(20		)	18
Processing commodity expenses	—			—			—			—		—		30			20		26		40			116
Operating and administrative costs	210			216			203			201		830		193			215		200		166			774
Tracked operating and administrative costs	—			—			1			1		2		—			1		—		—			1
Other segment costs and expenses	(12		)	(2		)	(1		)	15		—		6			10		19		15			50
Impairment of certain assets	—			1			1,021			10		1,032		—			—		—		1,849			1,849
Gain on sale of certain assets	—			—			—			—		—		—			—		—		(591		)	(591		)
Regulatory charges resulting from Tax Reform	—			—			—			220		220		(7		)	—		—		—			(7		)
Total segment costs and expenses	614			624			1,662			1,026		3,926		748			803		975		2,114			4,640
Proportional Modified EBITDA of equity-method investments	25			18			18			18		79		18			19		25		32			94
Modified EBITDA	385			356			(615		)	286		412		413			389		412		(906		)	308
Adjustments	4			16			1,041			195		1,256		(7		)	—		12		1,264			1,269
Adjusted EBITDA	$	389		$	372		$	426		$	481	$	1,668	$	406		$	389	$	424	$	358		$	1,577
NGL margin	$	37		$	30		$	37		$	50	$	154	$	52		$	53	$	60	$	29		$	194
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day) - Consolidated (1)	4.23			4.40			4.62			4.86		4.53		4.58			4.60		4.48		3.44			4.27
Gathering volumes (Bcf per day) - Non-consolidated (2)	—			—			—			—		—		—			—		0.15		0.16			0.08
Plant inlet natural gas volumes (Bcf per day) - Consolidated (1)	1.99			2.01			2.11			2.17		2.07		2.16			2.12		2.11		1.75			2.04
Plant inlet natural gas volumes (Bcf per day) - Non-consolidated (2)	—			—			—			—		—		—			—		0.12		0.13			0.06
Ethane equity sales (Mbbls/d)	3.00			10.55			10.87			11.90		9.11		19.01			10.23		12.19		16.40			14.44
Non-ethane equity sales (Mbbls/d)	19.52			19.53			20.49			20.80		20.09		19.83			18.80		19.48		14.40			18.12
NGL equity sales (Mbbls/d)	22.52			30.08			31.36			32.70		29.20		38.84			29.03		31.67		30.80			32.56
Ethane margin ($/gallon)	$	.04		$	.00		$	.02		$	.02	$	.02	$	.01		$	.07	$	.18	$	.02		$	.06
Non-ethane margin ($/gallon)	$	.49		$	.40		$	.45		$	.61	$	.49	$	.69		$	.71	$	.69	$	.49		$	.65
NGL margin ($/gallon)	$	.43		$	.26		$	.30		$	.39	$	.34	$	.35		$	.48	$	.49	$	.24		$	.39
Ethane production (Mbbls/d)	8			18			19			26		18		31			26		28		31			29
Non-ethane production (Mbbls/d) - Consolidated (1)	55			57			62			63		59		62			61		59		45			56
Non-ethane production (Mbbls/d) - Jackalope equity-method investment - 100%	—			—			—			—		—		—			—		5		5			3
NGL production (Mbbls/d)	63			75			81			89		77		93			87		92		81			88
NGL Transportation volumes (Mbbls) (3)	18,338			20,558			21,015			21,424		81,335		21,263			21,334		22,105		23,049			87,751
Northwest Pipeline LLC
Throughput (Tbtu)	219.0			165.4			156.4			209.1		749.9		226.1			188.1		193.5		212.3			820.0
Avg. daily transportation volumes (Tbtu)	2.4			1.8			1.7			2.3		2.1		2.5			2.1		2.1		2.3			2.2
Avg. daily firm reserved capacity (Tbtu)	3.1			3.1			3.1			3.1		3.1		3.1			3.1		3.1		3.1			3.1
(1) Excludes volumes associated with equity-method investments that are not consolidated in our results.
(2) Includes 100% of the volumes associated with operated equity-method investments, including the Jackalope Gas Gathering System and Rocky Mountain Midstream.
(3) Includes 100% of the volumes associated with operated equity-method investments, including the Overland Pass Pipeline Company and Rocky Mountain Midstream.

7

Capital Expenditures and Investments
(UNAUDITED)
	2017															2018
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr		2nd Qtr		3rd Qtr		4th Qtr		Year
Capital expenditures:
Northeast G&P	$	58		$	81		$	173		$	101		$	413		$	114	$	104	$	114	$	139	$	471
Atlantic-Gulf	388			398			371			508			1,665			764		746		549		359		2,418
West	57			58			94			76			285			69		74		96		93		332
Other	8			8			6			14			36			10		9		10		6		35
Total (1)	$	511		$	545		$	644		$	699		$	2,399		$	957	$	933	$	769	$	597	$	3,256
Purchases of investments:
Northeast G&P	$	20		$	26		$	24		$	29		$	99		$	20	$	70	$	114	$	58	$	262
Atlantic-Gulf	—			1			—			—			1			1		—		5		—		6
West	32			—			—			—			32			—		—		593		271		864
Total	$	52		$	27		$	24		$	29		$	132		$	21	$	70	$	712	$	329	$	1,132
Summary:
Northeast G&P	$	78		$	107		$	197		$	130		$	512		$	134	$	174	$	228	$	197	$	733
Atlantic-Gulf	388			399			371			508			1,666			765		746		554		359		2,424
West	89			58			94			76			317			69		74		689		364		1,196
Other	8			8			6			14			36			10		9		10		6		35
Total	$	563		$	572		$	668		$	728		$	2,531		$	978	$	1,003	$	1,481	$	926	$	4,388
Capital expenditures incurred and purchases of investments:
Increases to property, plant, and equipment	$	569		$	591		$	666		$	836		$	2,662		$	934	$	930	$	618	$	539	$	3,021
Purchases of investments	52			27			24			29			132			21		70		712		329		1,132
Total	$	621		$	618		$	690		$	865		$	2,794		$	955	$	1,000	$	1,330	$	868	$	4,153
(1) Increases to property, plant, and equipment	$	569		$	591		$	666		$	836		$	2,662		$	934	$	930	$	618	$	539	$	3,021
Changes in related accounts payable and accrued liabilities	(58		)	(46		)	(22		)	(137		)	(263		)	23		3		151		58		235
Capital expenditures	$	511		$	545		$	644		$	699		$	2,399		$	957	$	933	$	769	$	597	$	3,256

8

Selected Financial Information
(UNAUDITED)
	2017												2018
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr
Selected financial information:
Cash and cash equivalents	$	639		$	1,918		$	1,172		$	899		$	1,292		$	275		$	42		$	168
Total assets	$	47,512		$	48,770		$	46,120		$	46,352		$	47,052		$	46,374		$	47,153		$	45,302
Capital structure:
Debt:
Commercial paper	$	—		$	—		$	—		$	—		$	—		$	—		$	823		$	—
Current	$	—		$	1,951		$	502		$	501		$	501		$	2		$	33		$	47
Noncurrent	$	21,825		$	21,325		$	20,567		$	20,434		$	21,379		$	21,313		$	21,409		$	22,367
Stockholders’ equity	$	8,444		$	8,306		$	8,109		$	9,656		$	9,473		$	9,345		$	15,610		$	14,660
Debt to debt-plus-stockholders’ equity ratio	72.1		%	73.7		%	72.2		%	68.4		%	69.8		%	69.5		%	58.8		%	60.5		%

9

Reconciliation of "Net Income (Loss)" to "Modified EBITDA", Non-GAAP "Adjusted EBITDA" and "Distributable Cash Flow"
	2019 Guidance
(Dollars in billions, except coverage ratios)	Low			Mid			High
Net income (loss)	$	1.050		$	1.200		$	1.350
Provision (benefit) for income taxes				0.400
Interest expense				1.225
Equity (earnings) losses				(0.450		)
Proportional Modified EBITDA of equity-method investments				0.825
Depreciation and amortization expenses and accretion expense associated with asset retirement obligations for nonregulated operations				1.800
Modified EBITDA	$	4.850		$	5.000		$	5.150
Total Adjustments included in Modified EBITDA				—
Adjusted EBITDA	$	4.850		$	5.000		$	5.150
Interest expense - net (1)				(1.235		)
Maintenance capital expenditures (2)	(0.675		)	(0.625		)	(0.575		)
Cash taxes - (Payment) Benefit				0.075
Income attributable to noncontrolling interests (NCI) and other				(0.115		)
Distributable cash flow (DCF)	$	2.900		$	3.100		$	3.300
Dividends paid				(1.850		)
Excess cash available after dividends & distributions	$	1.050		$	1.250		$	1.450
Dividend per share				$	1.52
Coverage ratio (3)	1.57x			1.68x			1.78x
(1) Includes proportionate share of interest expense of equity investments.
(2) Includes proportionate share of maintenance capital expenditures of equity investments.
(3) Distributable cash flow / Dividends paid.

10

Reconciliation of Income (Loss) Attributable to The Williams Companies, Inc. to Adjusted Income
	2019 Guidance
(Dollars in billions, except per-share amounts)	Low		Mid		High
Net income (loss)	$	1,050	$	1,200	$	1,350
Less: Net income (loss) attributable to noncontrolling interests	115		115		115
Net income (loss) attributable to The Williams Companies, Inc.	935		1,085		1,235
Adjustments:
Adjustments included in Modified EBITDA	—		—		—
Adjustments below Modified EBITDA	—		—		—
Total adjustments	—		—		—
Less tax effect for above items	—		—		—
Adjustments for tax related items	—		—		—
Adjusted income available to common stockholders	$	935	$	1,085	$	1,235
Adjusted diluted earnings per common share	$	0.77	$	0.89	$	1.01
Weighted-average shares - diluted (billions)	1,217		1,217		1,217

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