Williams (NYSE: WMB) today announced its unaudited financial
results for the three and nine months ended Sept. 30, 2019.
Strong 3Q 2019 Results Compared with 3Q 2018
- Net Income attributable to Williams available to common
stockholders of $220 million – up $91 million or 71%; Year-to-Date
(YTD) up $308 million or 74%
- Net Income Per Share of $0.18 – up 38%; YTD is $0.60 – up
30%
- Adjusted Income Per Share of $0.26 – up 8%; YTD is $0.75 – up
23%
- Cash Flow From Operations of $858 million – up $112 million or
15%; YTD up 16%
- Adjusted EBITDA of $1.274 billion – up $78 million or 7%; YTD
up $290 million or 8%
- Distributable Cash Flow ("DCF") of $822 million – up $58
million or 8%; YTD up $345 million or 16%
- Dividend Coverage Ratio is 1.78x
- Debt (Net of Cash) to Adjusted EBITDA at Quarter End:
4.47x
Solid Execution Delivers Strong Results; Record Fee-Based
Revenue, Adjusted EBITDA and Gathering Volumes
- Northeast G&P segment up 23% in Modified EBITDA and 22% in
Adjusted EBITDA 3Q 2019 vs. 3Q 2018
- Northeast G&P gathering volumes up 17% 3Q 2019 vs. 3Q
2018
- Atlantic-Gulf segment up 22% in Modified EBITDA and 27% in
Adjusted EBITDA 3Q 2019 vs. 3Q 2018
- Reached settlement terms on Transco Rate Case, pending FERC
approval
- Placed Rivervale South to Market expansion project into full
service on Sept. 1, 2019; Transco expansion provides 190,000
dekatherms of firm natural gas service per day to meet growing
heating and power generation demand for northeastern consumers
- Received FERC approval authorizing Southeastern Trail expansion
project, a 296,375 dekatherms per day expansion designed to serve
Transco pipeline markets in the Mid-Atlantic and Southeastern U.S.
in time for the 2020/2021 winter heating season
- Filed application with FERC seeking authorization for Leidy
South project – 582,400 dekatherms per day expansion of Transco
pipeline system to connect Marcellus and Utica supplies with
markets along Atlantic Seaboard
- Commissioned Rocky Mountain Midstream (RMM) JV's second DJ
Basin processing plant, Keenesburg I, on schedule; adds 225 MMcf/d
processing capacity to RMM assets
CEO Perspective
Alan Armstrong, president and chief executive officer, made the
following comments:
"Our third-quarter 2019 results show why we're so confident in
the long-term sustainability of our business. Even in the current
challenging commodity environment, we once again delivered
year-over-year growth in our key financial metrics and remain on
track for our 2019 guidance. Compared to third-quarter 2018, our
Net Income increased by 71% and Cash Flow From Operations rose 15%
as our demand-driven, natural gas strategy continues to drive
earnings and steadily growing cash flows while maintaining strong
dividend coverage.
"Williams is helping meet growing clean energy demands as
highlighted by our Transco Pipeline system, which recently placed
our Rivervale South to Market project into service in New Jersey,
received approval from FERC for the Southeastern Trail expansion
project and filed application with the FERC seeking authorization
for the Leidy South project. Combined with other expansion projects
under construction or in various levels of permitting, we expect
Transco's system-design capacity to increase from its current 17.2
million dekatherms per day to more than 18 million dekatherms per
day in time for the 2020/2021 winter heating season. We also
completed and commissioned several key projects in the DJ and
Wamsutter basins during the quarter."
Armstrong added, "Natural gas is fundamentally important to
achieving both economic development and emissions reductions goals,
both in the United States and abroad. As we continue to focus on
connecting the best supplies to the best markets, natural gas
demand will continue to drive realized and future growth for our
business. And we will continue to run our business in an
environmentally responsible manner as evidenced by the fact that
since 2012, we've eliminated more than half of our methane
emissions from our gas processing plants and transmission
compressor stations."
Williams Summary Financial
Information
3Q
YTD
Amounts in millions, except ratios and
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.
2019
2018
2019
2018
GAAP Measures
Net Income
$220
$129
$724
$416
Net Income Per Share
$0.18
$0.13
$0.60
$0.46
Cash Flow From Operations
$858
$746
$2,702
$2,331
Non-GAAP Measures (1)
Adjusted EBITDA
$1,274
$1,196
$3,731
$3,441
Adjusted Income
$321
$243
$907
$545
Adjusted Income Per Share
$0.26
$0.24
$0.75
$0.61
Distributable Cash Flow
$822
$764
$2,469
$2,124
Dividend Coverage Ratio
1.78x
1.85x
1.79x
1.64x
Other
Debt-to-Adjusted EBITDA at Quarter End
(2)
4.47x
4.65x
Capital Investments (3)(4)
$849
$1,330
$2,068
$3,285
(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
(2)
Debt-to-Adjusted EBITDA ratio does not
represent leverage ratios measured for WMB credit agreement
compliance or leverage ratios as calculated by the major credit
ratings agencies. Debt is net of cash on hand, and Adjusted EBITDA
reflects the sum of the last four quarters.
(3)
Capital Investments includes increases to
property, plant, and equipment, purchases of businesses, net of
cash acquired, and purchases of and contributions to equity-method
investments.
(4)
YTD 2019 excludes $728 million (net of
cash acquired) for the purchase of the remaining 38% of UEO as this
amount was provided for at the close of the new Northeast JV by our
JV partners, CPPIB, in June 2019.
GAAP Measures
- Third-quarter 2019 Net Income benefited from increased service
revenues in the Atlantic-Gulf segment primarily from Transco
expansion projects and in the Northeast G&P segment driven by
growth in gathering volumes, partially offset by a decline in the
West segment results due to lower commodity margins, lower deferred
revenue recognition in the Barnett Shale associated with the end of
a contractual minimum volume commitment (MVC) period, and the
absence of the former Four Corners area business sold in
fourth-quarter 2018. The current year also benefited from reduced
operating and administrative expenses, including the absence of
costs associated with the WPZ merger, and a favorable change in the
provision for income taxes due primarily to the absence of 2018
valuation allowance charge on deferred tax assets that may not be
realized following the WPZ merger. The period was negatively
impacted by $114 million of impairments of equity-method
investments and the absence of a $45 million benefit recognized in
2018 related to adjusting regulatory assets associated with an
increase in Transco’s estimated deferred state income tax rate
following the WPZ merger. Net Income also reflects less income
attributable to noncontrolling interests driven by the WPZ merger
in third-quarter 2018.
- YTD 2019 Net Income benefited from increased service revenues
in the Atlantic-Gulf segment primarily from Transco expansion
projects and in the Northeast G&P segment driven by growth in
volumes, partially offset by a decline in West segment results due
to lower commodity margins and the absence of the former Four
Corners area business. Other drivers of the improvement include
reduced operating and administrative expenses, including the
absence of costs associated with the WPZ merger, a $122 million
gain on the sale of our 50% interest in Jackalope and the absence
of a $105 million valuation allowance charge on deferred tax assets
that may not be realized following the WPZ merger. These
improvements were partially offset by $186 million of impairments
of equity-method investments, the absence of a $62 million gain the
prior year associated with the deconsolidation of our Jackalope
interest, higher interest expense associated with financing
obligations for leased pipeline capacity, a decrease in the
allowance for equity funds used during construction (EAFUDC), and
the previously described absence of a $45 million benefit
recognized in 2018 related to adjusting regulatory assets. Asset
impairments in the current year were substantially offset by
similar levels of impairments in the prior year. Net income also
reflects less income attributable to noncontrolling interests
driven by the WPZ merger in third-quarter 2018.
- The increase in Cash Flow From Operations for third-quarter and
YTD 2019 periods was largely driven by the increased service
revenues in the Atlantic-Gulf and Northeast G&P segments and
the collection of Transco's filed rates subject to refund,
partially offset by the decline in West segment results. The YTD
2019 period also benefited from the receipt of an income tax
refund.
Non-GAAP Measures
- The increase in Adjusted EBITDA for third-quarter 2019 and YTD
2019 largely reflects the previously mentioned increased service
revenues in the Atlantic-Gulf and Northeast G&P segments,
partially offset by the decline in West segment results.
- Adjusted Income for both the quarter and YTD periods also
improved, driven by the higher Adjusted EBITDA and less income
attributable to noncontrolling interests, partially offset by
higher interest expense, lower EAFUDC, and an increased provision
for income taxes.
- Third-quarter and YTD 2019 DCF are higher, reflecting the
increased Adjusted EBITDA and lower maintenance capital, partially
offset by higher net interest expense. The YTD increase also
benefited from an income tax refund received in 2019.
Business Segment Results & Form 10-Q
Williams' operations are comprised of the following reportable
segments: Atlantic-Gulf, West, Northeast G&P and Other. For
additional information, please see the company's third-quarter
2019, Form 10-Q, which Williams expects to file this week with the
Securities and Exchange Commission (SEC). Once filed, the document
will be on the SEC and Williams websites.
Quarter-To-Date
Year-To-Date
Amounts in millions
Modified EBITDA
Adjusted EBITDA
Modified EBITDA
Adjusted EBITDA
3Q 2019
3Q 2018
Change
3Q 2019
3Q 2018
Change
2019
2018
Change
2019
2018
Change
Atlantic-Gulf
$599
$492
$107
$611
$480
$131
$1,683
$1,418
$265
$1,730
$1,402
$328
West
311
412
(101
)
313
424
(111
)
921
1,214
(293
)
1,015
1,219
(204
)
Northeast G&P
345
281
64
343
281
62
947
786
161
964
786
178
Other
(2
)
6
(8
)
7
11
(4
)
1
(49
)
50
22
34
(12
)
Totals
$1,253
$1,191
$62
$1,274
$1,196
$78
$3,552
$3,369
$183
$3,731
$3,441
$290
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.
Atlantic-Gulf
- Improvement in third-quarter and YTD 2019 Modified and Adjusted
EBITDA is driven by Transco expansion projects, including Atlantic
Sunrise (in service October 2018) and Gulf Connector (in service
early January 2019) and $44 million of adjustments related to
reaching settlement terms in the Transco Rate Case (pending FERC
approval). The $44 million includes reductions to the reserve
established against the filed rate we began collecting in March of
this year along with other related accounting entries.
Approximately $16 million of the $44 million relates specifically
to third-quarter 2019.
- Unfavorably impacting results was reduced EAFUDC due to lower
levels of construction activity.
West
- Lower third-quarter and YTD 2019 Modified and Adjusted EBITDA
reflect lower NGL margins (excluding Four Corners) driven by lower
NGL prices, the absence of EBITDA from our former Four Corners area
business, the sale of our Jackalope interest, the absence of
deferred revenue associated with our former Delaware basin assets
that were contributed for our Brazos Permian II interest in
December 2018, and lower deferred revenue recognition in the
Barnett Shale associated with the end of a contractual MVC
period.
- Modified EBITDA for the YTD 2019 period includes asset
impairment charges that are excluded from Adjusted EBITDA.
- Third-quarter and YTD 2019 results reflect higher gathering
volumes in the Eagle Ford and Haynesville. Eagle Ford gathering
volumes increased by 19% versus third-quarter 2018 and by 10% YTD
over the same reporting period in 2018. Haynesville gathering
volumes increased by 18% versus third-quarter 2018 and by 9% YTD
over the same reporting period in 2018.
Northeast G&P
- Improvement in Modified and Adjusted EBITDA for third-quarter
and YTD 2019 was driven by increased service revenues from the
Susquehanna Supply Hub, the Utica Shale region, and Ohio Valley, as
well as the acquisition of Utica East Ohio Midstream.
- Both third-quarter and YTD 2019 reflect a 17% increase in gross
gathering volumes, including 100% of operated equity-method
investments, over the same reporting periods in 2018.
Williams' Third-Quarter 2019 Materials to be Posted Shortly;
Q&A Webcast Scheduled for Tomorrow
Williams' third-quarter 2019 earnings presentation will be
posted at www.williams.com. The
company’s third-quarter 2019 earnings conference call and webcast
with analysts and investors is scheduled for Thursday, Oct. 31, at
9:30 a.m. Eastern Time (8:30 a.m. Central Time). A limited number
of phone lines will be available at (800) 367-2403. International
callers should dial (334) 777-6978. The conference ID is 1823519. 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.
Williams' Analyst Day Set for Dec. 5
Williams is scheduled to host its 2019 Analyst Day event Dec. 5,
2019. During the event, Williams' management will give in-depth
presentations covering all of the company's energy infrastructure
businesses. This year's Analyst Day meeting is scheduled to begin
at 8:15 a.m. Eastern Time (7:15 a.m. Central Time) and run
approximately four hours. Presentation slides along with a link to
the live video webcast will be accessible at www.williams.com the morning of Dec. 5. A replay
of the 2019 Analyst Day webcast will also be available on the
website for at least 90 days following the event.
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, Oklahoma, 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 30,000
miles of pipelines system wide – including Transco, the nation’s
largest volume and fastest growing pipeline – providing natural gas
for clean-power generation, heating and industrial use. Williams’
operations handle approximately 30% of U.S. natural gas.
www.williams.com
The Williams Companies,
Inc.
Consolidated Statement of
Income
(Unaudited)
Three Months Ended September
30,
Nine Months Ended September
30,
2019
2018
2019
2018
(Millions, except per-share
amounts)
Revenues:
Service revenues
$
1,495
$
1,371
$
4,424
$
4,062
Service revenues – commodity
consideration
38
121
158
316
Product sales
466
811
1,512
2,104
Total revenues
1,999
2,303
6,094
6,482
Costs and expenses:
Product costs
434
790
1,442
2,039
Processing commodity expenses
19
30
83
91
Operating and maintenance expenses
364
389
1,091
1,134
Depreciation and amortization expenses
435
425
1,275
1,290
Selling, general, and administrative
expenses
130
174
410
436
Impairment of certain assets
—
—
76
66
Other (income) expense – net
(11
)
(6
)
30
24
Total costs and expenses
1,371
1,802
4,407
5,080
Operating income (loss)
628
501
1,687
1,402
Equity earnings (losses)
93
105
260
279
Other investing income (loss) – net
(107
)
2
(54
)
74
Interest incurred
(303
)
(286
)
(915
)
(856
)
Interest capitalized
7
16
27
38
Other income (expense) – net
1
52
19
99
Income (loss) before income taxes
319
390
1,024
1,036
Provision (benefit) for income taxes
77
190
244
297
Net income (loss)
242
200
780
739
Less: Net income (loss) attributable to
noncontrolling interests
21
71
54
323
Net income (loss) attributable to The
Williams Companies, Inc.
221
129
726
416
Preferred stock dividends
1
—
2
—
Net income (loss) available to common
stockholders
$
220
$
129
$
724
$
416
Basic earnings (loss) per common
share:
Net income (loss)
$
.18
$
.13
$
.60
$
.47
Weighted-average shares (thousands)
1,212,270
1,023,587
1,211,938
893,706
Diluted earnings (loss) per common
share:
Net income (loss)
$
.18
$
.13
$
.60
$
.46
Weighted-average shares (thousands)
1,214,165
1,026,504
1,213,943
896,322
The Williams Companies,
Inc.
Consolidated Balance
Sheet
(Unaudited)
September 30, 2019
December 31, 2018
(Millions, except per-share
amounts)
ASSETS
Current assets:
Cash and cash equivalents
$
247
$
168
Trade accounts and other receivables (net
of allowance of $6 at September 30, 2019 and $9 at December 31,
2018)
875
992
Inventories
129
130
Other current assets and deferred
charges
183
174
Total current assets
1,434
1,464
Investments
6,228
7,821
Property, plant, and equipment
41,647
38,661
Accumulated depreciation and
amortization
(12,034
)
(11,157
)
Property, plant, and equipment – net
29,613
27,504
Intangible assets – net of accumulated
amortization
8,041
7,767
Regulatory assets, deferred charges, and
other
965
746
Total assets
$
46,281
$
45,302
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
$
602
$
662
Accrued liabilities
1,184
1,102
Long-term debt due within one year
1,538
47
Total current liabilities
3,324
1,811
Long-term debt
20,719
22,367
Deferred income tax liabilities
1,651
1,524
Regulatory liabilities, deferred income,
and other
3,728
3,603
Contingent liabilities
Equity:
Stockholders’ equity:
Preferred stock
35
35
Common stock ($1 par value; 1,470 million
shares authorized at September 30, 2019 and December 31, 2018;
1,247 million shares issued at September 30, 2019 and 1,245 million
shares issued at December 31, 2018)
1,247
1,245
Capital in excess of par value
24,310
24,693
Retained deficit
(10,664
)
(10,002
)
Accumulated other comprehensive income
(loss)
(266
)
(270
)
Treasury stock, at cost (35 million shares
of common stock)
(1,041
)
(1,041
)
Total stockholders’ equity
13,621
14,660
Noncontrolling interests in consolidated
subsidiaries
3,238
1,337
Total equity
16,859
15,997
Total liabilities and equity
$
46,281
$
45,302
The Williams Companies,
Inc.
Consolidated Statement of Cash
Flows
(Unaudited)
Nine Months Ended September
30,
2019
2018
(Millions)
OPERATING ACTIVITIES:
Net income (loss)
$
780
$
739
Adjustments to reconcile to net cash
provided (used) by operating activities:
Depreciation and amortization
1,275
1,290
Provision (benefit) for deferred income
taxes
268
351
Equity (earnings) losses
(260
)
(279
)
Distributions from unconsolidated
affiliates
458
507
Net (gain) loss on disposition of
equity-method investments
(122
)
—
Impairment of equity-method
investments
186
—
(Gain) loss on deconsolidation of
businesses
2
(62
)
Impairment of and net (gain) loss on sale
of certain assets
76
64
Amortization of stock-based awards
44
43
Cash provided (used) by changes in current
assets and liabilities:
Accounts and notes receivable
159
75
Inventories
7
(39
)
Other current assets and deferred
charges
(10
)
(44
)
Accounts payable
(76
)
(76
)
Accrued liabilities
76
(62
)
Other, including changes in noncurrent
assets and liabilities
(161
)
(176
)
Net cash provided (used) by operating
activities
2,702
2,331
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial
paper – net
(4
)
821
Proceeds from long-term debt
736
3,745
Payments of long-term debt
(904
)
(3,201
)
Proceeds from issuance of common stock
10
15
Proceeds from sale of partial interest in
consolidated subsidiary
1,330
—
Common dividends paid
(1,382
)
(974
)
Dividends and distributions paid to
noncontrolling interests
(86
)
(552
)
Contributions from noncontrolling
interests
32
13
Payments for debt issuance costs
—
(26
)
Other – net
(11
)
(46
)
Net cash provided (used) by financing
activities
(279
)
(205
)
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)
(1,705
)
(2,659
)
Dispositions – net
(32
)
(2
)
Contributions in aid of construction
25
395
Purchases of businesses, net of cash
acquired
(728
)
—
Proceeds from dispositions of
equity-method investments
485
—
Purchases of and contributions to
equity-method investments
(361
)
(803
)
Other – net
(28
)
86
Net cash provided (used) by investing
activities
(2,344
)
(2,983
)
Increase (decrease) in cash and cash
equivalents
79
(857
)
Cash and cash equivalents at beginning of
year
168
899
Cash and cash equivalents at end of
period
$
247
$
42
_____________
(1) Increases to property, plant, and
equipment
$
(1,707
)
$
(2,482
)
Changes in related accounts payable and
accrued liabilities
2
(177
)
Capital expenditures
$
(1,705
)
$
(2,659
)
Atlantic-Gulf
(UNAUDITED)
2018
2019
(Dollars in millions)
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
Year
1st Qtr
2nd Qtr
3rd Qtr
Year
Revenues:
Service revenues:
Nonregulated gathering & processing
fee-based revenue
$
138
$
128
$
138
$
137
$
541
$
128
$
119
$
117
$
364
Regulated transportation revenue
413
406
411
508
1,738
517
514
549
1,580
Other fee revenues
32
34
34
34
134
34
40
32
106
Tracked service revenue
26
22
24
24
96
30
25
33
88
Nonregulated commodity consideration
15
12
18
14
59
13
13
7
33
Product sales:
NGL sales from gas processing
15
10
16
15
56
12
12
6
30
Marketing sales
45
57
67
53
222
40
32
23
95
Other sales
1
1
1
—
3
2
1
1
4
Tracked product sales
32
37
47
38
154
28
23
46
97
Total revenues
717
707
756
823
3,003
804
779
814
2,397
Segment costs and expenses:
NGL cost of goods sold
15
12
19
14
60
13
14
6
33
Marketing cost of goods sold
44
56
67
53
220
41
28
23
92
Other cost of goods sold
—
—
—
—
—
—
2
—
2
Tracked cost of goods sold
33
38
48
39
158
28
25
46
99
Processing commodity expenses
5
2
3
6
16
5
5
2
12
Operating and administrative costs
177
181
181
197
736
168
198
176
542
Tracked operating and administrative
costs
26
22
24
23
95
30
25
32
87
Other segment costs and expenses
(2
)
(15
)
(29
)
14
(32
)
1
2
(26
)
(23
)
Gain on sale of certain assets
—
—
—
(81
)
(81
)
—
—
—
—
Regulatory charges resulting from Tax
Reform
11
(20
)
—
—
(9
)
—
—
—
—
Total segment costs and expenses
309
276
313
265
1,163
286
299
259
844
Proportional Modified EBITDA of
equity-method investments
43
44
49
47
183
42
44
44
130
Modified EBITDA
451
475
492
605
2,023
560
524
599
1,683
Adjustments
15
(19
)
(12
)
(76
)
(92
)
—
35
12
47
Adjusted EBITDA
$
466
$
456
$
480
$
529
$
1,931
$
560
$
559
$
611
$
1,730
NGL Margin
$
10
$
8
$
12
$
9
$
39
$
7
$
6
$
5
$
18
Statistics for Operated Assets
Gathering, Processing, and Crude Oil
Transportation
Gathering volumes (Bcf per day) -
Consolidated (1)
0.29
0.23
0.26
0.24
0.26
0.25
0.25
0.22
0.24
Gathering volumes (Bcf per day) -
Non-consolidated (2)
0.24
0.25
0.25
0.31
0.26
0.35
0.38
0.36
0.36
Plant inlet natural gas volumes (Bcf per
day) - Consolidated (1)
0.54
0.43
0.51
0.53
0.50
0.53
0.55
0.50
0.52
Plant inlet natural gas volumes (Bcf per
day) - Non-consolidated (2)
0.24
0.25
0.25
0.32
0.27
0.35
0.39
0.36
0.36
Crude transportation volumes (Mbbls/d)
142
132
147
140
140
146
136
128
137
Consolidated (1)
Ethane margin ($/gallon)
$
.03
$
.16
$
.24
$
.14
$
.14
$
.10
$
.02
$
.01
$
.05
Non-ethane margin ($/gallon)
$
.66
$
.74
$
.76
$
.58
$
.68
$
.48
$
.28
$
.35
$
.35
NGL margin ($/gallon)
$
.40
$
.48
$
.51
$
.36
$
.43
$
.26
$
.17
$
.22
$
.21
Ethane equity sales (Mbbls/d)
2.82
1.91
3.05
2.98
2.69
4.16
4.11
1.85
3.36
Non-ethane equity sales (Mbbls/d)
3.87
2.35
3.14
3.21
3.14
3.28
5.34
3.15
3.92
NGL equity sales (Mbbls/d)
6.69
4.26
6.19
6.19
5.83
7.44
9.45
5.00
7.28
Ethane production (Mbbls/d)
12
12
15
16
14
17
14
9
13
Non-ethane production (Mbbls/d)
19
17
18
19
18
19
19
18
19
NGL production (Mbbls/d)
31
29
33
35
32
36
33
27
32
Non-consolidated (2)
NGL equity sales (Mbbls/d)
3
5
4
5
4
7
8
6
7
NGL production (Mbbls/d)
18
20
20
23
20
24
27
24
25
Transcontinental Gas Pipe Line
Throughput (Tbtu)
1,099.9
965.5
1,092.3
1,150.9
4,308.5
1,183.9
1,109.4
1,216.2
3,509.5
Avg. daily transportation volumes
(Tbtu)
12.2
10.6
11.9
12.5
11.8
13.2
12.2
13.2
12.9
Avg. daily firm reserved capacity
(Tbtu)
15.4
15.0
15.0
16.4
15.5
17.1
17.0
17.3
17.1
(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.
West
(UNAUDITED)
2018
2019
(Dollars in millions)
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
Year
1st Qtr
2nd Qtr
3rd Qtr
Year
Revenues:
Service revenues:
Nonregulated gathering & processing
fee-based revenue
$
386
$
398
$
387
$
335
$
1,506
$
319
$
331
$
282
$
932
Regulated transportation revenue
109
104
106
110
429
110
104
107
321
Other fee revenues
36
32
40
41
149
44
42
44
130
Nonregulated commodity consideration
82
78
97
64
321
46
40
30
116
Tracked service revenues
—
1
—
—
1
—
1
—
1
Product sales:
NGL sales from gas processing
85
76
90
71
322
48
41
31
120
Marketing sales
419
465
615
571
2,070
426
389
352
1,167
Other sales
10
9
16
3
38
1
1
2
4
Tracked product sales
16
10
11
(19
)
18
4
3
4
11
Total revenues
1,143
1,173
1,362
1,176
4,854
998
952
852
2,802
Segment costs and expenses:
NGL cost of goods sold
85
81
101
66
333
49
41
32
122
Marketing cost of goods sold
418
458
605
587
2,068
421
389
354
1,164
Other cost of goods sold
7
8
12
2
29
2
3
(9
)
(4
)
Tracked cost of goods sold
16
10
12
(20
)
18
3
4
5
12
Processing commodity expenses
30
20
26
40
116
31
19
13
63
Operating and administrative costs
193
215
200
166
774
166
180
166
512
Tracked operating and administrative
costs
—
1
—
—
1
—
1
—
1
Other segment costs and expenses
6
10
19
15
50
6
1
9
16
Impairment of certain assets
—
—
—
1,849
1,849
12
64
—
76
Gain on sale of certain assets
—
—
—
(591
)
(591
)
2
—
—
2
Regulatory charges resulting from Tax
Reform
(7
)
—
—
—
(7
)
—
—
—
—
Total segment costs and expenses
748
803
975
2,114
4,640
692
702
570
1,964
Proportional Modified EBITDA of
equity-method investments
18
19
25
32
94
26
28
29
83
Modified EBITDA
413
389
412
(906
)
308
332
278
311
921
Adjustments
(7
)
—
12
1,264
1,269
14
78
2
94
Adjusted EBITDA
$
406
$
389
$
424
$
358
$
1,577
$
346
$
356
$
313
$
1,015
NGL margin
$
52
$
53
$
60
$
29
$
194
$
14
$
21
$
16
$
51
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day) -
Consolidated (1)
4.58
4.60
4.48
3.44
4.27
3.42
3.53
3.62
3.52
Gathering volumes (Bcf per day) -
Non-consolidated (2)
—
—
0.15
0.16
0.08
0.17
0.15
0.21
0.18
Plant inlet natural gas volumes (Bcf per
day) - Consolidated (1)
2.16
2.12
2.11
1.65
2.01
1.41
1.52
1.56
1.49
Plant inlet natural gas volumes (Bcf per
day) - Non-consolidated (2)
—
—
0.14
0.17
0.08
0.17
0.14
0.21
0.11
Ethane equity sales (Mbbls/d)
19.01
10.23
12.19
16.40
14.44
14.63
14.59
3.32
10.80
Non-ethane equity sales (Mbbls/d)
19.83
18.80
19.48
14.40
18.12
12.59
13.54
14.02
13.39
NGL equity sales (Mbbls/d)
38.84
29.03
31.67
30.80
32.56
27.22
28.13
17.34
24.19
Ethane margin ($/gallon)
$
.01
$
.07
$
.18
$
.02
$
.06
$
(.03
)
$
(.03
)
$
(.06
)
$
(.03
)
Non-ethane margin ($/gallon)
$
.69
$
.71
$
.69
$
.49
$
.65
$
.34
$
.42
$
.32
$
.36
NGL margin ($/gallon)
$
.35
$
.48
$
.49
$
.24
$
.39
$
.14
$
.19
$
.25
$
.19
Ethane production (Mbbls/d)
31
26
28
29
28
29
22
9
20
Non-ethane production (Mbbls/d) -
Consolidated (1)
62
61
59
41
55
33
37
39
36
Non-ethane production (Mbbls/d) -
Jackalope equity-method investment - 100%
—
—
5
5
3
6
1
—
2
NGL production (Mbbls/d)
93
87
92
75
86
68
60
48
58
NGL and Crude Transportation volumes
(Mbbls) (3)
21,263
21,334
22,105
23,049
87,751
22,848
24,465
22,972
70,285
Northwest Pipeline LLC
Throughput (Tbtu)
226.1
188.1
193.5
212.3
820.0
243.5
184.6
179.2
607.3
Avg. daily transportation volumes
(Tbtu)
2.5
2.1
2.1
2.3
2.2
2.7
2.0
1.9
2.2
Avg. daily firm reserved capacity
(Tbtu)
3.1
3.1
3.1
3.1
3.1
3.1
3.0
3.0
3.0
(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.
Northeast G&P
(UNAUDITED)
2018
2019
(Dollars in millions)
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
Year
1st Qtr
2nd Qtr
3rd Qtr
Year
Revenues:
Service revenues:
Nonregulated gathering and processing
fee-based revenue
$
189
$
196
$
211
$
226
$
822
$
230
$
267
$
284
$
781
Other fee revenues
39
36
36
43
154
46
63
69
178
Nonregulated commodity consideration
4
4
6
6
20
5
3
1
9
Product sales:
NGL sales from gas processing
4
5
6
5
20
5
3
—
8
Marketing sales
89
65
57
35
246
37
28
26
91
Tracked product sales
5
5
6
5
21
5
6
4
15
Total revenues
330
311
322
320
1,283
328
370
384
1,082
Segment costs and expenses:
NGL cost of goods sold
4
5
6
5
20
5
3
—
8
Marketing cost of goods sold
90
65
57
36
248
37
29
26
92
Processing commodity expenses
2
2
3
2
9
3
2
1
6
Operating and administrative costs
85
91
96
108
380
97
130
120
347
Other segment costs and expenses
2
1
4
5
12
4
—
(3
)
1
Tracked cost of goods sold
5
7
6
3
21
5
6
3
14
Total segment costs and expenses
188
171
172
159
690
151
170
147
468
Proportional Modified EBITDA of
equity-method investments
108
115
131
139
493
122
103
108
333
Modified EBITDA
250
255
281
300
1,086
299
303
345
947
Adjustments
—
—
—
4
4
3
16
(2
)
17
Adjusted EBITDA
$
250
$
255
$
281
$
304
$
1,090
$
302
$
319
$
343
$
964
NGL margin
$
2
$
2
$
3
$
4
$
11
$
2
$
1
$
—
$
3
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day) -
Consolidated (1)
3.38
3.45
3.67
4.02
3.63
4.05
4.16
4.33
4.18
Gathering volumes (Bcf per day) -
Non-consolidated (2)
3.82
3.59
3.73
3.89
3.76
4.27
4.08
4.35
4.23
Plant inlet natural gas volumes (Bcf per
day)
0.49
0.55
0.52
0.52
0.52
0.63
1.04
1.16
0.94
Ethane equity sales (Mbbls/d)
1.33
3.17
2.74
2.80
2.52
2.73
1.83
1.94
2.16
Non-ethane equity sales (Mbbls/d)
0.79
1.09
1.49
1.28
1.16
1.21
1.09
0.67
0.99
NGL equity sales (Mbbls/d)
2.12
4.26
4.23
4.08
3.68
3.94
2.92
2.61
3.15
Ethane production (Mbbls/d)
23
27
26
20
24
22
24
24
23
Non-ethane production (Mbbls/d)
21
21
23
22
22
22
34
54
37
NGL production (Mbbls/d)
44
48
49
42
46
44
58
78
60
(1) Includes gathering volumes associated
with Susquehanna Supply Hub, the Northeast JV, 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), which we do not
operate, are not included.
Capital Expenditures and
Investments
(UNAUDITED)
2018
2019
(Dollars in millions)
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
Year
1st Qtr
2nd Qtr
3rd Qtr
Year
Capital expenditures:
Northeast G&P
$
114
$
104
$
114
$
139
$
471
$
152
$
177
$
131
$
460
Atlantic-Gulf
764
746
549
359
2,418
193
234
497
924
West
69
74
96
93
332
69
80
153
302
Other
10
9
10
6
35
8
6
5
19
Total (1)
$
957
$
933
$
769
$
597
$
3,256
$
422
$
497
$
786
$
1,705
Purchases of investments:
Northeast G&P
$
20
$
70
$
114
$
58
$
262
$
47
$
61
$
34
$
142
Atlantic-Gulf
1
—
5
—
6
—
12
3
15
West
—
—
593
271
864
52
70
82
204
Total
$
21
$
70
$
712
$
329
$
1,132
$
99
$
143
$
119
$
361
Summary:
Northeast G&P
$
134
$
174
$
228
$
197
$
733
$
199
$
238
$
165
$
602
Atlantic-Gulf
765
746
554
359
2,424
193
246
500
939
West
69
74
689
364
1,196
121
150
235
506
Other
10
9
10
6
35
8
6
5
19
Total
$
978
$
1,003
$
1,481
$
926
$
4,388
$
521
$
640
$
905
$
2,066
Capital investments:
Increases to property, plant, and
equipment
$
934
$
930
$
618
$
539
$
3,021
$
418
$
559
$
730
$
1,707
Purchases of businesses, net of cash
acquired
—
—
—
—
—
727
—
1
728
Purchases of investments
21
70
712
329
1,132
99
143
119
361
Total
$
955
$
1,000
$
1,330
$
868
$
4,153
$
1,244
$
702
$
850
$
2,796
(1) Increases to property, plant, and
equipment
$
934
$
930
$
618
$
539
$
3,021
$
418
$
559
$
730
$
1,707
Changes in related accounts payable and
accrued liabilities
23
3
151
58
235
4
(62
)
56
(2
)
Capital expenditures
$
957
$
933
$
769
$
597
$
3,256
$
422
$
497
$
786
$
1,705
Contributions from noncontrolling
interests
$
3
$
8
$
2
$
2
$
15
$
4
$
28
$
—
$
32
Contributions in aid of construction
$
190
$
149
$
56
$
16
$
411
$
10
$
8
$
7
$
25
Proceeds from sale of businesses, net of
cash divested
$
—
$
—
$
—
$
1,296
$
1,296
$
(2
)
$
—
$
—
$
(2
)
Proceeds from sale of partial interest in
consolidated subsidiary
$
—
$
—
$
—
$
—
$
—
$
—
$
1,330
$
—
$
1,330
Proceeds from disposition of equity-method
investments
$
—
$
—
$
—
$
—
$
—
$
—
$
485
$
—
$
485
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 or dividends/ distributions paid 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.
Reconciliation of Income (Loss)
Attributable to The Williams Companies, Inc. to Adjusted
Income
(UNAUDITED)
2018
2019
(Dollars in millions, except per-share
amounts)
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
Year
1st Qtr
2nd Qtr
3rd Qtr
Year
Income (loss) attributable to The
Williams Companies, Inc. available to common stockholders
$
152
$
135
$
129
$
(572
)
$
(156
)
$
194
$
310
$
220
$
724
Income (loss) - diluted earnings (loss)
per common share (1)
$
.18
$
.16
$
.13
$
(.47
)
$
(.16
)
$
.16
$
.26
$
.18
$
.60
Adjustments:
Northeast
G&P
Expenses associated with new venture
$
—
$
—
$
—
$
—
$
—
$
3
$
6
$
1
$
10
Settlement charge from pension early
payout program
—
—
—
4
4
—
—
—
—
Severance and related costs
—
—
—
—
—
—
10
(3
)
7
Total Northeast G&P adjustments
—
—
—
4
4
3
16
(2
)
17
Atlantic-Gulf
Constitution Pipeline project development
costs
2
1
1
—
4
—
1
1
2
Settlement charge from pension early
payout program
—
—
—
7
7
—
—
—
—
Regulatory adjustments resulting from Tax
Reform
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
2
—
—
—
2
—
—
—
—
Reversal of expenditures capitalized in
prior years
—
—
—
—
—
—
15
—
15
Gain on sale of certain Gulf Coast
pipeline assets
—
—
—
(81
)
(81
)
—
—
—
—
Gain on asset retirement
—
—
(10
)
(2
)
(12
)
—
—
—
—
Severance and related costs
—
—
—
—
—
—
19
11
30
Total Atlantic-Gulf adjustments
15
(19
)
(12
)
(76
)
(92
)
—
35
12
47
West
Impairment of certain assets
—
—
—
1,849
1,849
12
64
—
76
Settlement charge from pension early
payout program
—
—
—
6
6
—
—
—
—
Regulatory adjustments resulting from Tax
Reform
(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
)
2
—
—
2
Severance and related costs
—
—
—
—
—
—
14
2
16
Total West adjustments
(7
)
—
12
1,264
1,269
14
78
2
94
Other
Loss on early retirement of debt
7
—
—
—
7
—
—
—
—
Impairment of certain assets
—
66
—
—
66
—
—
—
—
Settlement charge from pension early
payout program
—
—
—
5
5
—
—
—
—
Regulatory adjustments resulting from Tax
Reform
—
1
—
—
1
—
—
—
—
(Benefit) adjustment of regulatory assets
associated with increase in Transco’s estimated deferred state
income tax rate following WPZ Merger
—
—
(45
)
—
(45
)
12
—
—
12
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
—
—
—
—
Accrual for loss contingencies associated
with former operations
—
—
—
—
—
—
—
9
9
Total Other adjustments
7
71
5
(14
)
69
12
—
9
21
Adjustments included in Modified
EBITDA
15
52
5
1,178
1,250
29
129
21
179
Adjustments below
Modified EBITDA
Gain on deconsolidation of Jackalope
interest
—
(62
)
—
—
(62
)
—
—
—
—
Gain on deconsolidation of certain Permian
assets
—
—
—
(141
)
(141
)
2
—
—
2
Impairment of equity-method
investments
—
—
—
32
32
74
(2
)
114
186
Gain on sale of equity-method
investments
—
—
—
—
—
—
(122
)
—
(122
)
Allocation of adjustments to
noncontrolling interests
(5
)
21
—
—
16
—
(1
)
—
(1
)
(5
)
(41
)
—
(109
)
(155
)
76
(125
)
114
65
Total adjustments
10
11
5
1,069
1,095
105
4
135
244
Less tax effect for above items
(3
)
(3
)
(1
)
(267
)
(274
)
(26
)
(1
)
(34
)
(61
)
Adjustments for tax-related items (2)
—
—
110
—
110
—
—
—
—
Adjusted income available to common
stockholders
$
159
$
143
$
243
$
230
$
775
$
273
$
313
$
321
$
907
Adjusted diluted earnings per common
share (1)
$
.19
$
.17
$
.24
$
.19
$
.79
$
.22
$
.26
$
.26
$
.75
Weighted-average shares - diluted
(thousands)
830,197
830,107
1,026,504
1,212,822
976,097
1,213,592
1,214,065
1,214,165
1,213,943
(1) 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.
(2) The third quarter of 2018 reflects tax
adjustments driven by the WPZ Merger, primarily a valuation
allowance for foreign tax credits.
Reconciliation of Distributable Cash
Flow (DCF)
(UNAUDITED)
2018
2019
(Dollars in millions, except coverage
ratios)
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
Year
1st Qtr
2nd Qtr
3rd 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)
$
270
$
269
$
200
$
(546
)
$
193
$
214
$
324
$
242
$
780
Provision (benefit) for income taxes
55
52
190
(159
)
138
69
98
77
244
Interest expense
273
275
270
294
1,112
296
296
296
888
Equity (earnings) losses
(82
)
(92
)
(105
)
(117
)
(396
)
(80
)
(87
)
(93
)
(260
)
Other investing (income) loss - net
(4
)
(68
)
(2
)
(113
)
(187
)
73
(126
)
107
54
Proportional Modified EBITDA of
equity-method investments
169
178
205
218
770
190
175
181
546
Depreciation and amortization expenses
431
434
425
435
1,725
416
424
435
1,275
Accretion for asset
retirement obligations associated with nonregulated operations
8
10
8
7
33
9
8
8
25
Modified EBITDA
1,120
1,058
1,191
19
3,388
1,187
1,112
1,253
3,552
EBITDA adjustments
15
52
5
1,178
1,250
29
129
21
179
Adjusted EBITDA
1,135
1,110
1,196
1,197
4,638
1,216
1,241
1,274
3,731
Maintenance capital expenditures (1)
(110
)
(160
)
(138
)
(122
)
(530
)
(93
)
(130
)
(128
)
(351
)
Preferred dividends
—
—
—
(1
)
(1
)
(1
)
—
(1
)
(2
)
Net interest expense - cash portion
(2)
(276
)
(279
)
(274
)
(299
)
(1,128
)
(304
)
(302
)
(301
)
(907
)
Cash taxes
(1
)
(10
)
(1
)
1
(11
)
3
85
(2
)
86
Income attributable to noncontrolling
interests (3)
(25
)
(24
)
(19
)
(28
)
(96
)
Dividend and distributions paid to
noncontrolling interests
(41
)
(27
)
(20
)
(88
)
Distributable cash flow
$
723
$
637
$
764
$
748
$
2,872
$
780
$
867
$
822
$
2,469
Total cash distributed (4)
$
438
$
443
$
412
$
411
$
1,704
$
460
$
461
$
461
$
1,382
Coverage ratios:
Distributable cash flow divided by Total
cash distributed
1.65
1.44
1.85
1.82
1.69
1.70
1.88
1.78
1.79
Net income (loss) divided by Total cash
distributed
0.62
0.61
0.49
(1.33
)
0.11
0.47
0.70
0.52
0.56
(1) Includes proportionate share of
maintenance capital expenditures of equity-method investments.
(2) Includes proportionate share of
interest expense of equity-method investments.
(3) Excludes allocable share of certain
EBITDA adjustments.
(4) Includes cash dividends paid on common
stock each quarter by WMB, as well as the public unitholders share
of distributions declared by WPZ for the first two quarters of
2018.
Reconciliation of "Net Income (Loss)"
to “Modified EBITDA” and Non-GAAP “Adjusted EBITDA”
(UNAUDITED)
2018
2019
(Dollars in millions)
1st Qtr
2nd Qtr
3rd Qtr
4th Qtr
Year
1st Qtr
2nd Qtr
3rd Qtr
Year
Net income (loss)
$
270
$
269
$
200
$
(546
)
$
193
$
214
$
324
$
242
$
780
Provision (benefit) for income taxes
55
52
190
(159
)
138
69
98
77
244
Interest expense
273
275
270
294
1,112
296
296
296
888
Equity (earnings) losses
(82
)
(92
)
(105
)
(117
)
(396
)
(80
)
(87
)
(93
)
(260
)
Other investing (income) loss - net
(4
)
(68
)
(2
)
(113
)
(187
)
73
(126
)
107
54
Proportional Modified EBITDA of
equity-method investments
169
178
205
218
770
190
175
181
546
Depreciation and amortization expenses
431
434
425
435
1,725
416
424
435
1,275
Accretion expense associated with asset
retirement obligations for nonregulated operations
8
10
8
7
33
9
8
8
25
Modified EBITDA
$
1,120
$
1,058
$
1,191
$
19
$
3,388
$
1,187
$
1,112
$
1,253
$
3,552
Northeast G&P
$
250
$
255
$
281
$
300
$
1,086
$
299
$
303
$
345
$
947
Atlantic-Gulf
451
475
492
605
2,023
560
524
599
1,683
West
413
389
412
(906
)
308
332
278
311
921
Other
6
(61
)
6
20
(29
)
(4
)
7
(2
)
1
Total Modified EBITDA
$
1,120
$
1,058
$
1,191
$
19
$
3,388
$
1,187
$
1,112
$
1,253
$
3,552
Adjustments included in Modified EBITDA
(1):
Northeast G&P
$
—
$
—
$
—
$
4
$
4
$
3
$
16
$
(2
)
$
17
Atlantic-Gulf
15
(19
)
(12
)
(76
)
(92
)
—
35
12
47
West
(7
)
—
12
1,264
1,269
14
78
2
94
Other
7
71
5
(14
)
69
12
—
9
21
Total Adjustments included in Modified
EBITDA
$
15
$
52
$
5
$
1,178
$
1,250
$
29
$
129
$
21
$
179
Adjusted EBITDA:
Northeast G&P
$
250
$
255
$
281
$
304
$
1,090
$
302
$
319
$
343
$
964
Atlantic-Gulf
466
456
480
529
1,931
560
559
611
1,730
West
406
389
424
358
1,577
346
356
313
1,015
Other
13
10
11
6
40
8
7
7
22
Total Adjusted EBITDA
$
1,135
$
1,110
$
1,196
$
1,197
$
4,638
$
1,216
$
1,241
$
1,274
$
3,731
(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.
Reconciliation of GAAP "Net Income
(Loss)" to Non-GAAP "Modified EBITDA", "Adjusted EBITDA" and
"Distributable Cash Flow"
2019 Guidance
(Dollars in millions, except coverage
ratio)
Low
Mid
High
Net income (loss)
$
1,100
$
1,250
$
1,400
Provision (benefit) for income taxes
425
Interest expense
1,200
Equity (earnings) losses
(410
)
Impairment of equity-method
investments
74
Estimated 2Q 2019 gain on sale of
equity-method investment (Jackalope)
(120
)
Proportional Modified EBITDA of
equity-method investments
780
Depreciation and amortization expenses and
accretion for asset retirement obligations associated with
nonregulated operations
1,760
Other
2
Modified EBITDA
$
4,811
$
4,961
$
5,111
EBITDA Adjustments (1)
39
Adjusted EBITDA
$
4,850
$
5,000
$
5,150
Net interest expense - cash portion
(2)
(1,210
)
Maintenance capital expenditures (2)
(625
)
(575
)
(525
)
Cash taxes
75
Dividends and distributions paid to
noncontrolling interests and other
(190
)
Distributable cash flow (DCF)
$
2,900
$
3,100
$
3,300
Dividends paid
(1,850
)
Excess cash available after dividends
$
1,050
$
1,250
$
1,450
Dividend per share
$
1.52
Coverage ratio (Distributable cash flow
/ Dividends paid)
1.57x
1.68x
1.78x
(1) Includes 1Q 2019 adjustments of $29
and anticipated future adjustments of $10.
(2) Includes proportionate share of equity
investments.
Reconciliation of Income (Loss)
Attributable to The Williams Companies, Inc. to Adjusted
Income
2019 Guidance
(Dollars in millions, except per-share
amounts)
Low
Mid
High
Net income (loss)
$
1,100
$
1,250
$
1,400
Less: Net income (loss) attributable to
noncontrolling interests
90
90
90
Less: Preferred stock dividends
3
3
3
Net income (loss) attributable to The
Williams Companies, Inc. available to common stockholders
1,007
1,157
1,307
Adjustments:
Adjustments included in Modified EBITDA
(1)
39
Adjustments below Modified EBITDA (2)
(44
)
Total adjustments
(5
)
Less tax effect for above items (3)
4
Adjusted income available to common
stockholders
$
1,006
$
1,156
$
1,306
Adjusted diluted earnings per common
share
$
0.83
$
0.95
$
1.07
Weighted-average shares - diluted
(millions)
1,217
1,217
1,217
(1) Includes 1Q 2019 adjustments of $29
and anticipated future adjustments of $10.
(2) Includes 1Q 2019 adjustments of $76
and anticipated gain on sale of Jackalope equity investment of
~($120).
(3) Includes 1Q 2019 tax effect for
adjustments of ($26) and taxes on anticipated gain on sale of
Jackalope equity investment of ~$30.
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 include, among others, statements regarding:
- 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;
- 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 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, 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;
- 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 and referred to below 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 21, 2019.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20191030005950/en/
MEDIA CONTACT: Keith Isbell (918) 573-7308
INVESTOR CONTACTS: Brett Krieg (918) 573-4614
Grace Scott (918) 573-1092
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