Enable Midstream Partners, LP · years at year-end 2018 to 4.1 years at year-end 20192 ... The...
Transcript of Enable Midstream Partners, LP · years at year-end 2018 to 4.1 years at year-end 20192 ... The...
Enable Midstream Partners, LP
Fourth Quarter 2019 Conference Call
February 19, 2020
Forward-looking Statements
Some of the information in this presentation may contain forward-looking statements. Forward-looking statements give our current
expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as
“could,” “will,” “should,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,”
“believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements.
Without limiting the generality of the foregoing, forward-looking statements contained in this presentation include our expectations of
plans, strategies, objectives, growth and operational performance, including revenue projections, capital expenditures and tax
position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties.
Consequently, no forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We
believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering
these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this presentation and
in our Annual Report on Form 10-K for the year ended December 31, 2019 (“Annual Report”). Those risk factors and other factors
noted throughout this presentation and in our Annual Report could cause our actual results to differ materially from those disclosed
in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements.
Forward-looking statements speak only as of the date on which they are made. We expressly disclaim any obligation to update or
revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.
2
Non-GAAP Financial Measures
3
Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash flow (DCF) and Distribution coverage ratio are not
financial measures presented in accordance with GAAP. Enable has included these non-GAAP financial measures in this
presentation based on information in its consolidated financial statements.
Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio are supplemental financial
measures that management and external users of Enable’s financial statements, such as industry analysts, investors, lenders and
rating agencies may use, to assess:
• Enable’s operating performance as compared to those of other publicly traded partnerships in the midstream energy industry,
without regard to capital structure or historical cost basis;
• The ability of Enable’s assets to generate sufficient cash flow to make distributions to its partners;
• Enable’s ability to incur and service debt and fund capital expenditures; and
• The viability of acquisitions and other capital expenditure projects and the returns on investment of various investment
opportunities.
This presentation includes a reconciliation of Gross margin to total revenues, Adjusted EBITDA and DCF to net income attributable
to limited partners, Adjusted EBITDA to net cash provided by operating activities and Adjusted interest expense to interest expense,
the most directly comparable GAAP financial measures, as applicable, for each of the periods indicated. Distribution coverage ratio
is a financial performance measure used by management to reflect the relationship between Enable's financial operating
performance and cash distributions. Enable believes that the presentation of Gross margin, Adjusted EBITDA, Adjusted interest
expense, DCF and Distribution coverage ratio provides information useful to investors in assessing its financial condition and
results of operations. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio should not
be considered as alternatives to net income, operating income, revenue, cash flow from operating activities, interest expense or any
other measure of financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA, Adjusted
interest expense, DCF and Distribution coverage ratio have important limitations as analytical tools because they exclude some but
not all items that affect the most directly comparable GAAP measures. Additionally, because Gross margin, Adjusted EBITDA,
Adjusted interest expense, DCF and Distribution coverage ratio may be defined differently by other companies in Enable’s industry,
Enable’s definitions of these measures may not be comparable to similarly titled measures of other companies, thereby diminishing
their utility.
2019 Enable Highlights
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• Achieved record full-year natural gas gathered, natural gas
processed, natural gas transported, and crude oil and
condensate gathered volumes1
• Significantly increased crude oil and condensate gathered
volumes in both the Anadarko and Williston Basins
• Extended the weighted-average remaining firm
transportation contract life for EGT, MRT and EOIT from 3.6
years at year-end 2018 to 4.1 years at year-end 20192
• Agreed to rate case settlement terms with 100% of MRT’s
firm capacity customers that participated in the pipeline’s recent
rate cases
• Announced the Merge, Arkoma, SCOOP and STACK (MASS)
natural gas transportation project and continued to develop
the Gulf Run Pipeline project
1. Since Enable’s formation in May 20132. Contract life weighted by volumes; contracts associated with the MRT rate cases are subject to FERC approval3. The partnership increased the quarterly distribution rate from $.3180/unit to $.3305/unit, an increase of approximately 4%, beginning with the Q2-19
distribution
Commercial and Operational Achievements
• Higher fourth quarter and full-year 2019 Adjusted EBITDA
and DCF compared to fourth quarter and full-year 2018
• Achieved the upper end of 2019 outlook for Adjusted EBITDA
and DCF
• Focused on capital efficiency, driving expansion capital below
the 2019 outlook range
• Increased the cash return to common unitholders by raising
the quarterly distribution by approximately 4%3
Financial Achievements
Unionville Storage
Northern Louisiana
2019: A Year of Continued Execution
5
Total Gathered
Volumes
+62% since 2016
Business Growth, Cost Discipline and Efficient Capital Deployment
“Enabled” the Self-Funding of Nearly 80% of the 2019 Capital
Program After Distributions2
1. Enable’s total crude oil and condensate volumes have been converted to an MMBtu equivalent using a conversion factor of 5.80 MMBtus per gathered barrel2. Self-funding calculated as FY2019 DCF plus FY2019 maintenance capital minus FY2019 common unit distributions. FY2019 Capital Program self-funding
percentage calculated by dividing self-funding amount by total FY2019 capital expenditures3. Non-GAAP financial measure are reconciled to the nearest GAAP financial measures in the Appendix4. Non-GAAP measure calculated as DCF divided by distributions related to common and subordinated units
Distribution
Coverage4
+17% since 2016
Transported
Volumes
+27% since 2016
3.283.71
4.72
5.31
2016 2017 2018 2019
Tb
tu/d
Equiv
ale
nt1
Adjusted
EBITDA3
+31% since 2016
4.88 5.04 5.56
6.18
2016 2017 2018 2019
Tb
tu/d
$873$924
$1,074$1,147
2016 2017 2018 2019
$ in
mill
ions
1.18x 1.20x
1.38x 1.38x
2016 2017 2018 2019
3.83x
4.51x 4.51x 4.56x4.82x 4.89x
ENBL Peer A Peer B Peer C Peer D Peer E
Deb
t-to
-EB
ITD
A
ENBL Peer A
$1,255
$1,422
$1,612$1,68137%
33%
31% 31%
25%
27%
29%
31%
33%
35%
37%
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
$1,800
2016 2017 2018 2019
Gross Margin O&M & G&A % Gross Margin
50%
39%
4%7%
Fee-Based Volume Dependent Fee-Based Demand
Commodity-Based Hedged Commodity-Based Unhedged
Financially Strong and Disciplined
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Highlights
• Continued focus on operating efficiency and cost discipline
• Favorable contract structures with significant fee-based and demand-fee margins
• Committed to aligning expansion capital expenditures with the business environment
• Significant liquidity and investment-grade credit metrics
Strong Financial Position
1. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix2. Gross margin profile represents hedges as of Feb. 14, 2020, and Enable’s latest internal 2020 forecast and price assumptions3. ENBL leverage is calculated as Total Debt / Adjusted EBITDA and is based off of FY2019 Actuals 4. Source: Bloomberg. Current (as of Feb. 7, 2020) Total Debt / FY2019 Adjusted EBITDA average analyst estimates; Peers include DCP, ENLC, OKE, WES
and WMB; Peers shown on graph in order of ascending Debt-to-EBITDA rather than alphabetical order
2020F Gross Margin Profile2Cost Discipline
~93% Fee-Based or Hedged
1 3 4
Gulf Run Pipeline Project
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• The Gulf Run Pipeline project, backed by a 20-year
commitment from cornerstone shipper Golden
Pass LNG, will provide access to some of the most
prolific natural gas producing regions in the U.S.
• Expect to file certificate applications with FERC by
the end of first quarter 2020 seeking authorization
for the project
• Project scope expected to be filed would provide
approximately 1.7 Bcf/d of capacity, which would
both accommodate Golden Pass’s 1.1 Bcf/d
commitment and allow for additional capacity
subscriptions that may develop from ongoing
discussions at an estimated total cost for the filed
scope of approximately $640 million1
• Project will be appropriately sized to meet
contracted customer capacity commitments and is
expected to be placed into service in late 2022,
subject to FERC approval
Project
AnnouncementOpen Season Survey Work FERC Pre-
Filing
Public Open
HousesFERC Scoping
MeetingsFERC 7(c)
Filing
FERC
ApprovalBegin
Construction
Project
Completed
2018 20222019 2021
Gulf Run Pipeline Project
Golden Pass
FID
Note: Map as of Jan. 27, 2020
1. Excludes the estimated allowance for funds used during constructions, which represents the approximate net composite interest cost of borrowed funds and
a reasonable return on the equity funds used for construction
2020
Q4 2019 Commercial Highlights
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Note: SCOOP counties are designated as Caddo, Carter, Garvin, Grady, McClain and Stephens and STACK counties are designated as Blaine, Canadian, Custer,
Dewey, Kingfisher, Major and Woodward counties of Oklahoma
1. Rigs per Enverus as of Feb. 10, 2020; represents wells expected to be connected to either Enable’s natural gas gathering or crude oil and condensate
gathering systems
2. Source: Enverus
3. Contracts associated with the MRT rate cases are subject to FERC approval
27Active Rigs on
Enable’s Footprint1
• Producers remain active across Enable’s
gathering footprint with 27 rigs1 currently drilling
wells expected to be connected to Enable’s
gathering systems
‒ 47% of all active rigs1 in the SCOOP and STACK
plays are drilling wells expected to be connected to
Enable’s gathering systems
‒ Operators have reduced the number of days it takes
to drill a well in the Anadarko by an average of 17%
in Q3-19 compared to Q3-182
• Total crude oil and condensate volumes gathered
reached 153 MBbl/d in Q4-19, driven by
continued growth in the Anadarko Basin
Gathering and Processing Transportation and Storage
• Contracted or extended over 1.2 million Dth/d of
transportation capacity during Q4-193
• MRT Rate Case Update:
‒ Agreed to rate case settlement terms with all of
MRT’s firm capacity customers that participated in
the recent rate cases, with 90% of third-party
transportation capacity now extended into 2024
‒ Expect FERC to rule on the proposed settlements in
the first half of 2020
‒ Assuming the settlements are approved in 2020,
MRT expects revenues for 2020 to be higher than the
revenues MRT recognized in 2018, which were
unaffected for the rate case or capacity turnbacks
4.7% Increase
5.72 5.99
Q4 2018 Q4 2019
Transported VolumesTBtu/d
18
1 5
3
SCOOP
Granite Wash
Ark-La-Tex
Williston
Operational and Financial Results
Operational Performance Overview
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Transported Volumes
Natural Gas Gathered Volumes Natural Gas Processed Volumes
TBtu/d
TBtu/d TBtu/d
• Natural gas gathered volumes increased for full-year 2019 compared to full-year 2018 primarily as a result of higher gathered
volumes in the Anadarko and Ark-La-Tex Basins, partially offset by lower gathered volumes in the Arkoma Basin
• Natural gas processed volumes increased for full-year 2019 compared to full-year 2018 primarily as a result of higher
processed volumes in the Anadarko and Ark-La-Tex Basins, partially offset by lower processed volumes in the Arkoma Basin
• Crude oil and condensate gathered volumes increased for full-year 2019 compared to full-year 2018 primarily as a result of
Enable’s crude oil and condensate gathering system acquisition in the Anadarko Basin and growth in the Williston Basin
• Transported volumes increased for full-year 2019 compared to full-year 2018 primarily as a result of newly contracted
capacity on EGT, including volumes from EGT’s CaSE project and EOIT’s Muskogee project
Crude Oil and Condensate Gathered Volumes
1.8% Increase
4.48 4.56
FY 2018 FY 2019
5.4% Increase
2.40 2.53
FY 2018 FY 2019
87.39 MBbls/d Increase
41.07
128.46
FY 2018 FY 2019
11.2% Increase
5.56 6.18
FY 2018 FY 2019
MBbls/d
Three Months Ended Dec. 31 Year Ended Dec. 31
$ in millions, except per-unit and ratio data2019 2018 % Change 2019 2018 % Change
Total Revenues $731 $950 23% $2,960 $3,431 14%
Gross Margin1 $410 $466 12% $1,681 $1,612 4%
Net Income Attributable to Limited Partners $18 $174 90% $396 $521 24%
Net income Attributable to Common Units $9 $165 95% $360 $485 26%
Net Cash provided by Operating Activities $251 $286 12% $942 $924 2%
Adjusted EBITDA1
$274 $271 1% $1,147 $1,074 7%
Distributable Cash Flow1
$177 $173 2% $784 $760 3%
Distribution Coverage Ratio2
1.23x 1.26x 0.03x 1.38x 1.38x
Cash Distribution per Common Unit $0.3305 $0.3180 4% $1.310 $1.272 3%
Cash Distribution per Series A Preferred Unit $0.625 $0.625 $2.500 $2.500
Financial Results
Financial Results
11
1. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
2. A non-GAAP measure calculated as distributable cash flow divided by distributions related to common units
2020 Focus
12
Strong Financial Position
✔ Focused on maintaining strong distribution coverage and investment-grade credit metrics
Optimization✔ Continuing to improve efficiency and generate cost savings
Commercial Excellence
✔ Pursuing additional high-value opportunities across the footprint
Capital Discipline✔ Right-sizing expansion capital program for customer activity
Sustainability Reporting✔ Planning to expand sustainability disclosures by year-end 2020
1
2
3
4
5
Question and AnswerQuestion and Answer
AppendixAppendix
2020 Outlook
15
2020 Financial Outlook
$ in millions
Net Income Attributable to Common Units $385 – $445
Interest Expense $175 – $195
Adjusted EBITDA1 $1,050 – $1,150
Series A Preferred Unit Distributions2 $36
Adjusted Interest Expense1 $170 – $190
Maintenance Capital $110 – $130
Distributable Cash Flow1 $720 – $800
Distribution Coverage Ratio3 +/- 1.3x
Total Debt / Adjusted EBITDA1 +/- 4.0x
2020 Expansion Capital Outlook
$ in millions
Gathering and Processing Segment $120 – $180
Transportation and Storage Segment $40 – $60
Total Expansion Capital $160 – $240
1. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
2. In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available cash with respect to the quarter immediately
preceding the quarter in which the distribution is made
3. Non-GAAP measure calculated as distributable cash flow divided by distributions related to common units
2020 outlook provided Nov. 6, 2019, reaffirmed Feb. 19, 2020
($6)
($2)
$6
$2
($5)
($1)
$5
$1
Derivative Activity and Price Sensitivities
16
1. Price sensitivities are based on Enable’s 2020 outlook and hedges as of Feb. 14, 20202. The impact of price sensitivities is the same for net income attributable to limited partners and net income attributable to common units3. Table includes hedges and commodity exposures associated with equity volumes resulting from Enable’s gathering, processing and transportation businesses;
exposure based on Enable’s 2020 outlook; percentage hedged includes hedges executed through Feb. 14, 20204. Enable hedges net condensate and natural gasoline exposure with crude; net exposure and the percentage hedged excludes the proportion of long condensate
positions offset by short natural gasoline positions
Year Ended Dec. 31
2019 2018
Gain (Loss) on Derivative Activity $16 $11
Change in Fair Value of Derivatives ($11) $26
Realized Gain (Loss) on Derivatives $27 ($15)
Derivative Activity ($ in millions)
2020 Price Sensitivities1 ($ in millions)
Hedging Summary3
Commodity 2020 2021
Natural Gas (NYMEX)
Exposure Hedged (%) 35% 2%
Average Hedge Price ($/MMBtu) $2.53 $2.65
Natural Gas Basis (PEPL / EGTE)
Exposure Hedged (%) 41% 11%
Average Hedge Price ($/MMBtu) $(0.38) $(0.29)
Crude4
Exposure Hedged (%) 53% 8%
Average Hedge Price ($/Bbl) $60.98 $56.22
Propane
Exposure Hedged (%) 29% 0%
Average Hedge Price ($/gal) $0.61 -
Normal Butane
Exposure Hedged (%) 7% 0%
Average Hedge Price ($/gal) $0.53 -
Net Income2
Adjusted EBITDA (including hedges)
(10%) +10%
Natural Gas and Ethane
NGLs (excluding ethane) and Condensate
+10%(10%)
NGLs (excluding ethane) and Condensate
Natural Gas and Ethane
Gathering and Processing Segment Results
17
1. Includes volumes under third-party processing arrangements
2. Excludes condensate
3. Before eliminations upon consolidation
4. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
Operational Results
Three Months Ended Dec. 31 Year Ended Dec. 31
2019 2018 % Change 2019 2018 % Change
An
ad
ark
o
Basin
Gathered Volumes (TBtu/d) 2.42 2.38 2% 2.34 2.21 6%
Processed Volumes (TBtu/d)1 2.19 2.14 2% 2.10 1.99 6%
NGLs Produced (MBbl/d)1,2 116.78 119.92 3% 113.20 113.63 0%
Crude Oil and Condensate Gathered Volumes (MBbl/d) 122.23 48.17 154% 92.70 12.14 664%
Ark
om
a
Basin
Gathered Volumes (TBtu/d) 0.44 0.53 17% 0.47 0.55 15%
Processed Volumes (TBtu/d) 1 0.08 0.10 20% 0.09 0.10 10%
NGLs Produced (MBbl/d) 1,2 4.04 6.56 38% 5.42 6.55 17%
Ark
-La-T
ex
Basin
Gathered Volumes (TBtu/d) 1.76 1.71 3% 1.75 1.72 2%
Processed Volumes (TBtu/d) 0.30 0.33 9% 0.34 0.31 10%
NGLs Produced (MBbl/d) 2 7.63 10.26 26% 9.96 9.80 2%
Williston Basin Crude Oil Gathered Volumes (MBbl/d) 30.83 28.42 8% 35.76 28.93 24%
Financial Results ($ in millions)
To
tal
G&
P
Total Revenues3 $579 $808 28% $2,338 $2,818 17%
Gross Margin3,4 $271 $329 18% $1,135 $1,077 5%
Operation & Maintenance and G&A Expenses3 $82 $82 $320 $312 3%
Depreciation and Amortization $79 $72 10% $308 $263 17%
Impairment $86 - $86 -
Taxes other than Income Tax $10 $9 11% $41 $38 8%
Operating Income $14 $166 92% $380 $464 18%
Transportation and Storage Segment Results
18
1. Before eliminations upon consolidation
2. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
Operational Results
Three Months Ended Dec. 31 Year Ended Dec. 31
2019 2018 % Change 2019 2018 % Change
Transported Volumes (Tbtu/d) 5.99 5.72 5% 6.18 5.56 11%
Interstate Firm Contracted Capacity (Bcf/d) 6.30 6.24 1% 6.31 5.94 6%
Intrastate Average Deliveries (TBtu/d) 2.09 2.21 5% 2.14 2.08 3%
Financial Results ($ in millions)
Total Revenues1 $236 $325 27% $1,038 $1,162 11%
Gross Margin1,2 $139 $135 3% $547 $534 2%
Operation & Maintenance and G&A Expenses1 $55 $48 15% $207 $189 10%
Depreciation and Amortization $31 $34 9% $125 $135 7%
Taxes other than Income Tax $5 $8 38% $26 $27 4%
Operating Income $48 $45 7% $189 $183 3%
Consolidated Statements of Income
19 1. All outstanding subordinated units converted into common units on a one-for-one basis on Aug. 30, 2017
Three Months Ended
December 31,
Year Ended
December 31,
2019 2018 2019 2018 2017 2016
(In millions, except per unit data)
Revenues (including revenues from affiliates):
Product sales$ 377 $ 609 $ 1,533 $ 2,106 $ 1,653 $ 1,172
Service revenue354 341 1,427 1,325 1,150 1,100
Total Revenues731 950 2,960 3,431 2,803 2,272
Cost and Expenses (including expenses from affiliates):
Cost of natural gas and natural gas liquids (excluding depreciation and
amortization shown separately)321 484 1,279 1,819 1,381 1,017
Operation and maintenance116 99 423 388 369 367
General and administrative21 32 103 113 95 98
Depreciation and amortization110 106 433 398 366 338
Impairments86 — 86 — — 9
Taxes other than income tax15 17 67 65 64 58
Total Cost and Expenses669 738 2,391 2,783 2,275 1,887
Operating Income62 212 569 648 528 385
Other Income (Expense):
Interest expense(48) (43) (190) (152) (120) (99)
Equity in earnings of equity method affiliate5 6 17 26 28 28
Other, net1 (1) 3 — — —
Total Other Expense(42) (38) (170) (126) (92) (71)
Income Before Income Tax20 174 399 522 436 314
Income tax expense— (1) (1) (1) (1) 1
Net Income$ 20 $ 175 $ 400 $ 523 $ 437 $ 313
Less: Net income attributable to noncontrolling interest2 1 4 2 1 1
Net Income Attributable to Limited Partners$ 18 $ 174 $ 396 $ 521 $ 436 $ 312
Less: Series A Preferred Unit distributions9 9 36 36 36 22
Net Income Attributable to Common and Subordinated Units (1)
$ 9 $ 165 $ 360 $ 485 $ 400 $ 290
Basic earnings per unit
Common units$ 0.02 $ 0.38 $ 0.83 $ 1.12 $ 0.92 $ 0.69
Subordinated units (1)
$ — $ — $ — $ — $ 0.93 $ 0.68
Diluted earnings per unit
Common units$ 0.02 $ 0.38 $ 0.82 $ 1.11 $ 0.92 $ 0.69
Subordinated units (1)
$ — $ — $ — $ — $ 0.93 $ 0.68
Non-GAAP Reconciliations
20
Three Months
Ended
December 31,
Year Ended
December 31,
2019 2018 2019 2018 2017 2016
(In millions)
Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales$ 377 $ 609 $ 1,533 $ 2,106 $ 1,653 $ 1,172
Service revenue354 341 1,427 1,325 1,150 1,100
Total Revenues731 950 2,960 3,431 2,803 2,272
Cost of natural gas and natural gas liquids (excluding depreciation
and amortization) 321 484 1,279 1,819 1,381 1,017
Gross margin$ 410 $ 466 $ 1,681 $ 1,612 $ 1,422 $ 1,255
Reportable Segments
Gathering and Processing
Product sales$ 353 $ 605 $ 1,449 $ 2,016 $ 1,538 $ 1,081
Service revenue226 203 889 802 632 559
Total Revenues579 808 2,338 2,818 2,170 1,640
Cost of natural gas and natural gas liquids (excluding depreciation
and amortization) 308 479 1,203 1,741 1,285 915
Gross margin$ 271 $ 329 $ 1,135 $ 1,077 $ 885 $ 725
Transportation and Storage
Product sales$ 106 $ 183 $ 487 $ 625 $ 621 $ 479
Service revenue130 142 551 537 525 545
Total Revenues236 325 1,038 1,162 1,146 1,024
Cost of natural gas and natural gas liquids (excluding depreciation
and amortization) 97 190 491 628 604 492
Gross margin$ 139 $ 135 $ 547 $ 534 $ 542 $ 532
Non-GAAP Reconciliations Continued
21
1. Change in fair value of derivatives includes
changes in the fair value of derivatives that
are not designated as hedging instruments
2. Other non-cash losses includes loss on
sale of assets and write-downs of materials
and supplies
3. This amount represents the quarterly cash
distributions on the Series A Preferred
Units declared for the periods presented.
The year-ended 2016 amount includes the
prorated quarterly cash distribution on the
Series A Preferred Units declared on April
26, 2016. In accordance with the
Partnership Agreement, the Series A
Preferred Unit distributions are deemed to
have been paid out of available cash with
respect to the quarter immediately
preceding the quarter in which the
distribution is made
4. Distributions for phantom and performance
units represent distribution equivalent
rights paid in cash. Phantom unit
distribution equivalent rights are paid
during the vesting period and performance
unit distribution equivalent rights are paid
at vesting
5. See below for a reconciliation of Adjusted
interest expense to Interest expense
6. Represents cash distributions declared for
common units outstanding as of each
respective period. Amounts for 2019 reflect
estimated cash distributions for common
units outstanding for the quarter ended
Dec. 31, 2019. All outstanding
subordinated units converted into common
units on a one-for-one basis on Aug. 30,
2017
Three Months Ended
December 31,
Year Ended
December 31,
2019 2018 2019 2018 2017 2016
(In millions, except Distribution coverage ratio)
Reconciliation of Adjusted EBITDA and DCF to net income attributable
to limited partners and calculation of Distribution coverage ratio:
Net income attributable to limited partners$ 18 $ 174 $ 396 $ 521 $ 436 $ 312
Depreciation and amortization expense110 106 433 398 366 338
Interest expense, net of interest income47 43 188 152 120 99
Income tax expense— (1) (1) (1) (1) 1
Distributions received from equity method affiliate in excess of
equity earnings — (4) 8 7 5 15
Non-cash equity-based compensation3 4 16 16 15 13
Change in fair value of derivatives (1)
8 (54) 11 (26) (28) 60
Other non-cash losses (2)
3 3 12 7 11 26
Impairment86 — 86 — — 9
Non-controlling Interest Share of Adjusted EBITDA(1) — (2) — — —
Adjusted EBITDA$ 274 $ 271 $ 1,147 $ 1,074 $ 924 $ 873
Series A Preferred Unit distributions (3)
(9) (9) (36) (36) (36) (31)
Distributions for phantom and performance units (4)
— — (10) (5) (2) —
Adjusted interest expense (5)
(48) (45) (191) (159) (123) (103)
Maintenance capital expenditures(40) (44) (126) (114) (101) (101)
Current income taxes— — — — (2) 1
DCF$ 177 $ 173 $ 784 $ 760 $ 660 $ 639
Distributions related to common and subordinated unitholders (6)
$ 144 $ 138 $ 570 $ 552 $ 551 $ 539
Distribution coverage ratio1.23 1.26 1.38 1.38 1.20 1.18
Non-GAAP Reconciliations Continued
22
1. Other non-cash items include amortization of debt expense, discount and premium on long-term debt and write-downs of materials and supplies
2. Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments
Three Months
Ended
December 31,
Year Ended
December 31,
2019 2018 2019 2018 2017 2016
(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by
operating activities:
Net cash provided by operating activities $ 251 $ 286 $ 942 $ 924 $ 834 $ 721
Interest expense, net of interest income 47 43 188 152 120 99
Net income attributable to noncontrolling interest (2) (1) (4) (2) (1) (1)
Current income taxes — — — — 2 (1)
Other non-cash items(1) (2) 3 2 7 4 12
Proceeds from insurance 1 1 1 2 2 —
Changes in operating working capital which (provided)
used cash:
Accounts receivable (21) (47) (37) 11 28 (4)
Accounts payable (32) (25) 78 (6) (54) 40
Other, including changes in noncurrent assets and
liabilities 24 69 (42) 5 12 (68)
Return of investment in equity method affiliate — (4) 8 7 5 15
Change in fair value of derivatives (2) 8 (54) 11 (26) (28) 60
Adjusted EBITDA $ 274 $ 271 $ 1,147 $ 1,074 $ 924 $ 873
Three Months
Ended
December 31,
Year Ended
December 31,
2019 2018 2019 2018 2017 2016
(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest Expense $ 48 $ 43 $ 190 $ 152 $ 120 $ 99
Interest income (1) — (2) — — —
Amortization of premium on long-term debt 2 2 6 6 6 6
Capitalized interest on expansion capital 1 2 2 6 — 1
Amortization of debt expense and discount (2) (2) (5) (5) (3) (3)
Adjusted interest expense $ 48 $ 45 $ 191 $ 159 $ 123 $ 103
2020 Forward-Looking Non-GAAP Reconciliations
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1. Net income attributable to limited partners range based on adding Series A Preferred Unit distributions to the net income attributable to common units outlook
2. Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments
3. In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available cash with respect to the
quarter immediately preceding the quarter in which the distribution is made
2020 Outlook
(In millions)
Reconciliation of Adjusted EBITDA and distributable cash flow to net income
attributable to limited partners and calculation of Distribution coverage ratio:
Net income attributable to limited partners (1)$421 - $481
Depreciation and amortization expense $420 - $440
Interest expense, net of interest income $175 - $195
Income tax (benefit) expense $0 - $2
Distributions received from equity method affiliate in excess of equity
earnings$5 - $15
Non-cash equity based compensation $15 - $20
Change in fair value of derivatives (2)$0 - $10
Adjusted EBITDA $1,050 - $1,150
Series A Preferred Unit distributions (3)$36
Adjusted interest expense $170 - $190
Maintenance capital expenditures $110 - $130
Other $0 - $10
DCF $720 - $800
2020 Forward-Looking Non-GAAP Reconciliations Continued
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*Enable is unable to present a quantitative reconciliation of forward-looking Adjusted EBITDA to net cash provided by operating
activities because certain information needed to make a reasonable forward-looking estimate of changes in working capital which
may (provide) use cash during the calendar year 2020 cannot be reliably predicted and the estimate is often dependent on future
events which may be uncertain or outside of Enable's control. This includes changes to accounts receivable, accounts payable and
other changes in non-current assets and liabilities.
2020 Outlook
(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest expense, net of interest income $175 - $195
Amortization of premium on long-term debt $0 - $2
Capitalized interest on expansion capital $0 - $2
Amortization of debt expense and discount $(3) - $(7)
Adjusted interest expense $170 - $190