Embed Size (px)
Citation preview
Enable Midstream Partners, LPFourth Quarter Investor Presentation | December 2020
Some of the information in this presentation may contain forward-looking statements. Forward-looking statements give our current expectations and
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 anticipated financial and operational performance, including our
2020 outlook presented in our first quarter 2020 financial results press release dated May 6, 2020, as updated by this presentation. In particular, our
statements with respect to continuity plans and preparedness measures we have implemented in response to the novel coronavirus (COVID-19)
pandemic and its expected impact on our business, operations, earnings and results are forward-looking statements. 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, our Quarterly Report on Form 10-Q for the three months ended March
31, 2020 (March 31 Quarterly Report), and our Annual Report on Form 10-K for the year ended Dec. 31, 2019 (Annual Report). Those risk factors and
other factors noted throughout this presentation and in our March 31 Quarterly Report and 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.
Any forward-looking statements speak only as of the date on which such statement is made, and we undertake no obligation to correct or update any
forward-looking statement, whether as a result of new information or otherwise, except as required by applicable law.
Forward-looking Statements
2
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.
Non-GAAP Financial Measures
3
Enable Midstream Overview
Segment Overview
Appendix
Contents
4
Enable Midstream Overview
• Fully integrated midstream platform serves as a critical link between
production and downstream markets
• Long-term relationships with large-cap producers, LDCs and electric
utilities, many of whom are investment-grade
• Transportation and storage segment is anchored by firm contracts with
high-quality customers, providing stability during volatile market
environments
• Over the long term, Enable is well-positioned from both a producer
operating cost and wellhead pricing perspective, with Enable providing
unique markets for production and many producers holding downstream
capacity commitments
• Enable continues to work with both producers and customers representing
end markets to facilitate competitive market solutions
Enable Benefits from a Diversified Asset Portfolio
6Note: Map as of Nov. 10, 2020
Business Highlights
7
• As of Sept. 1, 2020, all wells that were shut-in due to
depressed commodity prices have been brought back
online
• Recently received the Federal Energy Regulatory
Commission’s (FERC) Environmental Assessment for the
Gulf Run Pipeline, a key milestone for the project
• Released Enable’s inaugural sustainability report,
highlighting the partnership’s commitment to transparency
and sustainable business practices
• COVID-19 safety protocols remain in place; continue to
monitor local, state and federal guidelines and
recommendations from health organizations to ensure the
safety of our employees, customers and communities
• Continue to benefit from significant scale, diversified
assets, integrated systems, unique market solutions and a
strong base of firm, demand-driven transportation and
storage contracts
2020F DCF 2020F Expansion Capital Distributions
Financial Highlights
8
1. 2020 outlook expectations are as of Nov. 4, 2020 and are not being updated as of the time of this presentation
2. Reference is to outlook ranges provided May 6, 2020
3. 2020 year-to-date through Sept. 30, 2020
4. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
5. Third quarter 2020 distribution annualized
$585 - $645
$288
• November 4th guidance1 provided, stated that we expected to
achieve the upper half of the projected ranges of the 2020
outlook2 for Adjusted EBITDA and DCF and that, excluding the
third quarter 2020 non-cash impairment recognized for
Enable’s SESH joint venture, Enable would have expected to
achieve the upper half of the anticipated range of its 2020
outlook2 for net income
• Business performance and actions taken in response to the
industry downturn earlier this year have resulted in DCF
exceeding distributions by $293 million3 and total debt levels
decreasing by $94 million3
• Progress on cost-reduction initiatives includes annualized
savings of $21 million from workforce reductions, $14 million
from rental equipment turnback and $2 million from processing
plant optimization
• Remain focused on capital discipline
• Have experienced no meaningful credit losses to date
On track to achieve capital and cost reduction targets
announced in April 2020 and committed to further
action, as needed, based on market conditions
2,4
Significant excess cash flow to fund expansion
capital expenditures and reduce debt
$105 - $145
52
Gulf Run Pipeline Project
9
• The Gulf Run Pipeline project, backed by a 20-year
commitment for 1.1 Bcf/d with cornerstone shipper Golden
Pass LNG, will provide access to some of the most prolific
natural gas producing regions in the U.S.
• On Oct. 29, 2020, FERC issued the Environmental
Assessment, and the deadline for other agencies to act on a
request for federal authorization for the project is Jan. 27,
2021
• Anticipate finalizing the project scope and financing plans in
the coming months
• Expect to place project into service in late 2022, subject to
FERC approval
PROJECT
ANNOUNCEMENT
2018
OPEN
SEASONSURVEY
WORK
FERC
PRE-FILING
PUBLIC
OPEN HOUSES
FERC SCOPING
MEETINGS
FERC 7(C)
FILING
FERC
APPROVAL
BEGIN
CONSTRUCTION
PROJECT
COMPLETED
GOLDEN
PASS FID
2019
2020
2021 2022
Note: Map as of Nov. 10, 2020
• Segment anchored by large, investment-grade utilities
• Contracted or extended nearly 1,450,000 Dth/d of firm, fee-based
transportation capacity in 2020 at an average volume-weighted contract life
of over five years1
• EGT’s MASS project has received all regulatory approvals, and construction
of the project has begun; expected to be placed into service in second
quarter 2021
‒ Project is designed to deliver gas from Oklahoma to delivery points with
access to emerging Gulf Coast markets and growing demand markets in
the Southeast and is underpinned by a firm, five-year commitment for
100,000 Dth/d
• MRT’s Southbound Expansion project is now in service and is backed by a
firm, five-year commitment for 80,000 Dth/d
• Despite recent contract expirations, the SESH pipeline remains a critical
artery to serve utility markets in the Southeast
Transportation and Storage Highlights
10
1. 2020 year-to-date contracting through Sept. 30, 2020
• As of Sept. 1, 2020, all wells that were shut-in due to depressed
commodity prices have been brought back online
‒ No noticeable production performance degradation from these wells
• Producers remain active on Enable’s gathering footprint with six rigs1
currently drilling wells expected to be connected to Enable’s gathering
systems
• Enable’s customers have approximately 100 drilled but uncompleted2
(DUC) wells behind the Anadarko Basin system and approximately 75
DUC2 wells behind the Williston Basin system, providing an inventory of
wells producers can complete without investing additional drilling capital
• Enable Oklahoma Crude Services, LLC recently completed an extension
into McClain County, increasing the system’s reach and ability to add new
customers
• Natural gas forward curves have increased by nearly 30%3 for 2021,
supporting continued producer activity in the Haynesville Shale
• Recently completed a connection to a seven-well pad for a new Williston
Basin customer
Gathering and Processing Highlights
11
1. Rigs per Enverus as of Oct. 28, 2020; represents wells expected to be connected to either Enable’s natural gas gathering or crude oil and condensate gathering systems
2. Represents DUCs expected to be connected to either Enable’s natural gas gathering or crude oil and condensate gathering system as of Sept. 30, 2020
3. Average percent change of NYMEX forward curves for January 2021 through December 2021, when comparing Jan. 1, 2020, strip prices to Nov. 1, 2020, strip prices
Dedicated Partner
Focus on Sustainability
12
• Enable is making a difference in species conservation,
demonstrated by participation in the American
Burying Beetle Oil & Gas Industry Conservation
Plan, a species that was recently downlisted from
endangered to threatened status
• Enable’s award-winning integrated vegetation
management program along our rights-of-ways, which
uses a variety of techniques to control incompatible and
invasive plant species while promoting the growth of
compatible herbaceous, native plant species that may
also benefit wildlife and pollinator species
• Pipeline inspection program that inspected almost
twice the miles of pipelines in 2019 as required by
current regulations
• Enable has made a series of commitments intended to
minimize methane emissions across Enable’s
operations through INGAA’s Methane Emissions
Commitments
Enable is
committed to
operating
honestly, fairly,
safely and
ethically
Enable released its inaugural sustainability report, highlighting the partnership’s
commitment to transparency and sustainable business practices
• Community partnerships, including Enable’s
Safety Partner Program honoring first
responders, a program to build or refurbish
community basketball courts and a program to
support STEM-focused educational initiatives
• Over 22,000 employee volunteer hours in
2019, including over 15,000 company-paid hours
• A comprehensive contractor safety initiative,
which contributed to a reduction of reported
contractor incidents from 22 in 2015 to three in
2019
Environmental Steward
The full report is available at https://enablemidstream.com/sustainability
Segment Overview
Transportation and Storage Segment
14
EOIT
MRT
SESH
EGT
EGT (Enable Gas Transmission, LLC)
MRT (Enable Mississippi River Transmission, LLC) SESH2 (Southeast Supply Header, LLC)
EOIT (Enable Oklahoma Intrastate Transmission, LLC)
Serves utilities, industrial end-users and producers, providing access to
Mid-continent supply and other Northeastern, Mid-continent and Gulf
Coast markets through interconnects
Serves utilities and industrial end-users, providing access to Mid-continent
supply and Northeastern supply through interconnects
Primarily serves customers that generate electricity for the Florida
power market and interconnects to pipelines serving major Southeast
and Northeast markets
Serves utilities, industrial end-users and producers, including growing
Anadarko Basin production
100% Derived from
Fee-Based Contracts
93% Derived from
Firm Contracts
100%
Fee-Based
EGT 59%
MRT 11%
EOIT 23%
Note: Map as of Nov. 10, 2020
1. As of Dec. 31, 2019; excludes SESH which is reported as an equity method investment
2. 50/50 joint venture with Enbridge Inc.
Transportation and Storage Highlights Transportation and Storage Gross Margin1
Arkoma Basin Williston Basin
Anadarko Basin
Gathering and Processing Segment
15
Our operations primarily serve the Woodford
Shale play located in Oklahoma and the
Fayetteville Shale play located in Arkansas.
Our Arkoma Basin gathering and processing
operations serve both rich and lean gas
production from approximately 80 producers1.
Contracts are primarily fee-based contracts
with significant support from MVCs, which have
a weighted average remaining term of 4.7
years1.
We have operations in the Bakken Shale that
are located in North Dakota. The focus of our
operations in the Williston Basin is the
gathering of crude oil and produced water for
XTO Energy Inc., an affiliate of ExxonMobil
Corporation, with pipeline gathering systems in
Dunn, McKenzie, Williams and Mountrail
counties of North Dakota.
Natural Gas - We have natural gas gathering
and processing operations in the SCOOP,
STACK, Granite Wash, Cleveland, Marmaton,
Tonkawa, Cana Woodford and Mississippi Lime
plays. Enable serves over 200 producers1 in
the Anadarko Basin and has secured 5.0
million gross acres1 of dedication under long-
term, fee-based contracts.
Crude Oil and Condensate - Our operations in
the Anadarko Basin include gathering of crude
oil and condensate from producers in the
SCOOP, STACK and Merge plays.
We have gathering and processing operations
in the Ark-La-Tex Basin located in Arkansas,
Louisiana and Texas. Our Ark-La-Tex gathering
and processing operations primarily serve the
Haynesville, Cotton Valley and the lower
Bossier plays. We serve approximately 90
producers1 in the Ark-La-Tex Basin where our
gathering and processing operations provide
service for both rich and lean gas production.
The scale of Enable’s Ark-La-Tex Basin assets
allows us to be well-positioned to supply
demand growth from LNG exports.
Substantial size and scale in prominent basins
underpinned with favorable contract structures
• 15 Processing Plants with ~2.6 Bcf/d of processing capacity1
• 8.2 million gross acres dedicated under gathering agreements with a
volume-weighted average remaining term of 4.3 years1 for natural gas and
11.8 years1 for crude oil and condensate
• 2019 Gathering and Processing segment gross margin was 80% fee-based1
1. As of Dec. 31, 2019
Gathering and Processing Highlights Basin Highlights
Ark-La-Tex Basin
Appendix
Enable Ownership Structure
17Note: Structure as of Sept. 30, 2020
Large, Diverse and High-Quality Customer Base
Enable’s revenues are
strengthened by a diverse,
high-quality customer base,
including many investment-
grade or affiliates of
investment-grade companies
• Many of our customers rely on us
for multiple midstream services
across both G&P and T&S
• Loyal customer base through
exemplary customer service
and reliable project execution
(Investment Grade)
18Note: Standard and Poor’s, Moody’s and Fitch credit ratings from Bloomberg as of Nov. 4, 2020
Investment grade rated indicates that the company has an investment-grade rating from Standard and Poor’s, Moody’s or Fitch
1. As of Dec.31, 2019
(Investment Grade) (Investment Grade)
(Investment Grade) (Investment Grade)
(Investment Grade) (Investment Grade)
(Investment Grade) (Investment Grade)
(Investment Grade) (Investment Grade)
Top Customers1
Financial Results
191. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
2. Non-GAAP measure calculated as distributable cash flow divided by distributions related to common units
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
$ in millions, except per-unit and ratio data 2020 2019 Change 2020 2019 Change
Total Revenues $596 $699 ($103) $1,759 $2,229 ($470)
Gross Margin1 $346 $436 ($90) $1,106 $1,271 ($165)
Net Income (Loss) Attributable to Limited Partners ($164) $132 ($296) ($8) $378 ($386)
Net Income (Loss) Attributable to Common Units ($173) $123 ($296) ($35) $351 ($386)
Net Cash provided by Operating Activities $232 $264 ($32) $543 $691 ($148)
Adjusted EBITDA1
$229 $295 ($66) $739 $873 ($134)
Distributable Cash Flow1
$147 $202 ($55) $509 $607 ($98)
Distribution Coverage Ratio1,2
2.04x 1.40x 0.64x 2.36x 1.42x 0.94x
Cash Distribution per Common Unit $0.16525 $0.3305 ($0.16525)
Cash Distribution per Series A Preferred Unit $0.625 $0.625 $0
Operational Performance Overview
4.622.54
Natural gas gathered
volumes decreased for
third quarter 2020
compared to third quarter
2019 primarily as a result
of lower gathered volumes
across all basins, inclusive
of continued producer
shut-ins in the Anadarko
Basin that ended in the
third quarter
Natural gas processed
volumes decreased for third
quarter 2020 compared to
third quarter 2019 as a
result of lower processed
volumes across all basins
Crude oil and
condensate gathered
volumes increased for
third quarter 2020
compared to third quarter
2019 primarily as a result
of higher production in
the Anadarko Basin,
partially offset by lower
production in the
Williston Basin
Transported volumes
decreased for third quarter
2020 compared to third
quarter 2019 primarily as a
result of decreased
production in the Anadarko
Basin, which contributed to
lower utilization on both
interstate and intrastate
pipelines
20
8.9% Decrease
4.47 4.07
Q3 2019 Q3 2020
TBtu/d
17.3% Decrease
2.49
2.06
Q3 2019 Q3 2020
TBtu/d
MBbl/d
3.8% Increase
132.99 138.02
Q3 2019 Q3 2020
19.9% Decrease
5.97
4.78
Q3 2019 Q3 2020
TBtu/d
Natural Gas Gathered Volumes
Natural Gas Processed Volumes
Crude Oil and Condensate Gathered Volumes
Transported Volumes
Gathering and Processing Operational Results
21
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
Operational Results 2020 2019 Change 2020 2019 Change
Gathered Volumes (TBtu/d) 1.94 2.27 (0.33) 2.04 2.32 (0.28)
Processed Volumes (TBtu/d)1 1.76 2.04 (0.28) 1.85 2.07 (0.22)
NGLs Produced (MBbl/d)1,2 120.80 103.53 17.27 109.29 111.99 (2.70)
Crude Oil and Condensate Gathered Volumes (MBbl/d) 104.93 91.58 13.35 93.65 82.75 10.90
Gathered Volumes (TBtu/d) 0.41 0.46 (0.05) 0.42 0.48 (0.06)
Processed Volumes (TBtu/d) 1 0.08 0.10 (0.02) 0.08 0.10 (0.02)
NGLs Produced (MBbl/d) 1,2 3.94 4.42 (0. 48) 3.96 5.89 (1.93)
Gathered Volumes (TBtu/d) 1.72 1.74 (0.02) 1.79 1.74 0.05
Processed Volumes (TBtu/d) 0.22 0.35 (0.13) 0.25 0.35 (0.10)
NGLs Produced (MBbl/d) 2 8.37 9.83 (1.46) 9.04 10.74 (1.70)
Crude Oil Gathered Volumes (MBbl/d) 33.09 41.41 (8.32) 27.73 37.42 (9.69)
Financial Results ($ in millions)
To
tal
G&
P
Total Revenues3 $463 $542 ($79) $1,331 $1,759 ($428)
Gross Margin3,4 $219 $304 ($85) $700 $864 ($164)
Operation & Maintenance and G&A Expenses3 $77 $79 $2 $250 $238 ($12)
Depreciation and Amortization $75 $77 $2 $223 $229 $6
Impairment - - - $28 - ($28)
Taxes other than Income Tax $10 $10 - $32 $31 ($1)
Operating Income $57 $138 ($81) $167 $366 ($199)
1. Includes volumes under third-party processing
arrangements
2. Excludes condensate
3. Before eliminations upon consolidation
4. Non-GAAP financial measures are reconciled to the
nearest GAAP financial measures in the Appendix
Arkoma Basin
Ark-La-Tex Basin
Anadarko Basin
Williston Basin
Transportation and Storage Segment Results
221. Before eliminations upon consolidation
2. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
Operational Results Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2020 2019 Change 2020 2019 Change
Transported Volumes (Tbtu/d) 4.78 5.97 (1.19) 5.58 6.22 (0.64)
Interstate Firm Contracted Capacity (Bcf/d) 5.73 6.02 (0.29) 6.00 6.31 (0.31)
Intrastate Average Deliveries (TBtu/d) 1.74 2.10 (0.36) 1.83 2.16 (0.33)
Financial Results ($ in millions) Three Months Ended Sept. 30 Nine Months Ended Sept. 30
Total Revenues1 $205 $234 ($29) $622 $802 ($180)
Gross Margin1,2 $127 $132 ($5) $407 $408 ($1)
Operation & Maintenance and G&A Expenses1 $47 $57 $10 $137 $152 $15
Depreciation and Amortization $30 $31 $1 $91 $94 $3
Taxes other than Income Tax $7 $7 - $20 $21 $1
Operating Income $43 $37 $6 $159 $141 $18
Consolidated Statements of Income
23
Three Months Ended September 30,
Nine Months Ended September 30,
2020 2019 2020 2019
(In millions, except per unit data)
Revenues (including revenues from affiliates):
Product sales $ 280 $ 320 $ 764 $ 1,156
Service revenue 316 379 995 1,073
Total Revenues 596 699 1,759 2,229
Cost and Expenses (including expenses from affiliates):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately) 250 263 653 958
Operation and maintenance 96 105 313 307
General and administrative 28 31 73 82
Depreciation and amortization 105 108 314 323
Impairments of property, plant and equipment and goodwill — — 28 —
Taxes other than income tax 17 17 52 52
Total Cost and Expenses 496 524 1,433 1,722
Operating Income 100 175 326 507
Other Income (Expense):
Interest expense (43) (48) (136) (142)
Equity in earnings (loss) of equity method affiliate, net (222) 5 (211) 12
Other, net 2 1 7 2
Total Other Expense (263) (42) (340) (128)
Income Before Income Tax (163) 133 (14) 379
Income tax benefit — — — (1)
Net Income (Loss) $ (163) $ 133 $ (14) $ 380
Less: Net income (loss) attributable to noncontrolling interest 1 1 (6) 2
Net Income (Loss) Attributable to Limited Partners $ (164) $ 132 $ (8) $ 378
Less: Series A Preferred Unit distributions 9 9 27 27
Net Income (Loss) Attributable to Common Units $ (173) $ 123 $ (35) $ 351
Basic earnings (loss) per unit
Common units $ (0.40) $ 0.28 $ (0.08) $ 0.81
Diluted earnings (loss) per unit
Common units $ (0.40) $ 0.28 $ (0.08) $ 0.81
Non-GAAP Reconciliations
24
Three Months Ended September 30,
Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales $ 280 $ 320 $ 764 $ 1,156
Service revenue 316 379 995 1,073
Total Revenues 596 699 1,759 2,229
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)250 263 653 958
Gross margin $ 346 $ 436 $ 1,106 $ 1,271
Reportable Segments
Gathering and Processing
Product sales $ 271 $ 294 $ 739 $ 1,096
Service revenue 192 248 592 663
Total Revenues 463 542 1,331 1,759
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 244 238 631 895
Gross margin $ 219 $ 304 $ 700 $ 864
Transportation and Storage
Product sales $ 79 $ 100 $ 213 $ 381
Service revenue 126 134 409 421
Total Revenues 205 234 622 802
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 78 102 215 394
Gross margin $ 127 $ 132 $ 407 $ 408
Non-GAAP Reconciliations Continued
25
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 write-downs and net loss on sale and retirement
of assets
3. Represents the quarterly cash distributions on the Series A Preferred Units
declared for the three and nine months ended Sept. 30, 2020, and 2019. 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 the next slide 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 2020 reflect estimated cash distributions for
common units outstanding for the quarter ended Sept. 30, 2020
7. Distribution coverage ratio is computed by dividing DCF by Distributions related
to common unitholders
Three Months Ended September 30,
Nine Months Ended September 30,
2020 2019 2020 2019
(In millions, except Distribution coverage ratio)
Reconciliation of Adjusted EBITDA and DCF to net income (loss) attributable to limited partners and calculation of Distribution coverage ratio:
Net income (loss) attributable to limited partners $ (164) $ 132 $ (8) $ 378
Depreciation and amortization expense 105 108 314 323
Interest expense, net of interest income 43 48 135 141
Income tax benefit — — — (1)
Distributions received from equity method affiliate in excess of equity earnings 1 (1) 9 8
Impairment of equity method affiliate investment 225 — 225 —
Non-cash equity-based compensation 3 4 10 13
Change in fair value of derivatives (1)15 2 17 3
Other non-cash losses (2)1 2 23 9
Impairments of property, plant and equipment and goodwill — — 28 —
Gain on extinguishment of debt — — (5) —
Noncontrolling Interest Share of Adjusted EBITDA — — (9) (1)
Adjusted EBITDA $ 229 $ 295 $ 739 $ 873
Series A Preferred Unit distributions (3)(9) (9) (27) (27)
Distributions for phantom and performance units (4)— (1) (1) (10)
Adjusted interest expense (5)(42) (47) (134) (143)
Maintenance capital expenditures (31) (36) (69) (86)
Current income taxes — — 1 —
DCF $ 147 $ 202 $ 509 $ 607
Distributions related to common unitholders (6)$ 72 $ 144 $ 216 $ 426
Distribution coverage ratio (7)2.04 1.40 2.36 1.42
Non-GAAP Reconciliations Continued
261. Other non-cash items includes write-downs of assets
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 September 30,
Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities $ 232 $ 264 $ 543 $ 691
Interest expense, net of interest income 43 48 135 141Noncontrolling interest share of cash provided by operating
activities (1) (1) (3) (2)
Current income taxes — — 1 —
Other non-cash items (1)(2) — — 4
Proceeds from insurance 1 — 1 —
Changes in operating working capital which (provided) used cash:
Accounts receivable 3 41 (27) (16)
Accounts payable (24) (2) 46 110
Other, including changes in noncurrent assets and liabilities (39) (56) 17 (66)
Return of investment in equity method affiliate 1 (1) 9 8
Change in fair value of derivatives (2)15 2 17 3
Adjusted EBITDA $ 229 $ 295 $ 739 $ 873
Three Months Ended September 30,
Nine Months Ended September 30,
2020 2019 2020 2019
(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest expense $ 43 $ 48 $ 136 $ 142
Interest income — — (1) (1)
Amortization of premium on long-term debt — 1 1 4
Capitalized interest on expansion capital 1 — 2 1
Amortization of debt expense and discount (2) (2) (4) (3)
Adjusted interest expense $ 42 $ 47 $ 134 $ 143
2020 Forward-Looking Non-GAAP Reconciliations
271. Net income attributable to limited partners range based on adding Series A Preferred Unit distributions to the net income attributable to common units outlook; excludes non-cash other than temporary impairment on Enable’s investment in Southeast
Supply Header, LLC
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) $231 – $271
Depreciation and amortization expense $415 – $425
Interest expense, net of interest income $174 – $184
Income tax (benefit) expense $0
Distributions received from equity method affiliate in excess of equity
earnings$5 – $11
Non-cash equity based compensation $19
Change in fair value of derivatives (2) $10
Other non-cash losses $23
Impairments $28
Noncontrolling Interest Share of Adjusted EBITDA ($8)
Adjusted EBITDA $900 – $960
Series A Preferred Unit distributions (3) ($36)
Adjusted interest expense ($170) – ($180)
Maintenance capital expenditures ($95) – ($105)
Other ($4)
DCF $585 – $645
