NGL Pipelines &
Service
s
The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services
segment for the periods indicated (dollars in millions, volumes as noted):
|
|
For the Three Months
Ended March 31,
|
|
|
|
2019
|
|
|
2018
|
|
Segment gross operating margin:
|
|
|
|
|
|
|
Natural gas processing and related NGL marketing activities
|
|
$
|
292.7
|
|
|
$
|
248.5
|
|
NGL pipelines, storage and terminals
|
|
|
557.3
|
|
|
|
509.3
|
|
NGL fractionation
|
|
|
109.2
|
|
|
|
127.1
|
|
Total
|
|
$
|
959.2
|
|
|
$
|
884.9
|
|
|
|
|
|
|
|
|
|
|
Selected volumetric data:
|
|
|
|
|
|
|
|
|
Equity NGL production (MBPD) (1)
|
|
|
154
|
|
|
|
165
|
|
Fee-based natural gas processing (MMcf/d) (2)
|
|
|
5,299
|
|
|
|
4,364
|
|
NGL pipeline transportation volumes (MBPD)
|
|
|
3,436
|
|
|
|
3,287
|
|
NGL marine terminal volumes (MBPD)
|
|
|
540
|
|
|
|
575
|
|
NGL fractionation volumes (MBPD)
|
|
|
969
|
|
|
|
824
|
|
|
|
(1)
Represents the NGL volumes we earn and take title to in connection with our processing activities.
(2)
Volumes reported correspond to the revenue streams earned by our gas plants.
|
|
Natural gas processing and related
NGL marketing activities
Gross operating margin from natural gas processing and
related NGL marketing activities for the first quarter of 2019 increased $
44.2
million when compared to the first quarter of 2018. Gross operating
margin from our NGL marketing activities increased a net $24.7 million quarter-to-quarter primarily due to higher average sales margins. Results from our marketing strategies that optimize our transportation and export activities increased
$30.3 million and $6.5 million, respectively, quarter-to-quarter, partially offset by a $15.9 million decrease in earnings related to the optimization of our storage assets.
Gross operating margin from our Permian Basin natural gas
processing plants increased $
19.2
million quarter-to-quarter primarily due to higher fee-based processing volumes, which accounted for a $16.8 million
increase, and higher average sales margins, which accounted for an additional $3.9 million increase. Fee-based processing volumes at our Permian Basin natural gas processing plants increased 517 MMcf/d quarter-to-quarter primarily due to our
Orla Gas Processing Plant, which commenced operations in May 2018. Gross operating margin from our South Texas natural gas processing plants increased $12.6 million quarter-to-quarter primarily due to higher average processing margins
(including the impact of hedging activities), which accounted for a $7.0 million increase, and higher deficiency and processing fees, which accounted for an additional $5.0 million increase. Fee-based natural gas processing volumes and equity
NGL production at our South Texas plants decreased 174 MMcf/d and 12 MBPD, respectively.
On a combined basis, gross operating margin from our natural gas processing plants in Louisiana and Mississippi increased a net
$4.2 million quarter-to-quarter primarily due to higher equity NGL production volumes, which accounted for a $6.2 million increase, higher processing volumes, which accounted for an additional $5.7 million increase, partially offset by lower
average processing margins, which accounted for a $4.9 million decrease. Equity NGL production volumes and natural gas fee-based processing volumes for these plants increased a combined 21 MBPD and 464 MMcf/d, respectively, quarter-to-quarter.
Gross operating margin from our Meeker, Pioneer and Chaco natural gas processing plants decreased $17.1 million quarter-to-quarter
primarily due to lower equity NGL production, which accounted for a $9.0 million decrease, lower deficiency fee revenues, which accounted for a $4.6 million decrease, and lower average processing margins (including the impact of hedging
activities), which accounted for an additional $3.2 million decrease. On a combined basis, fee-based natural gas processing volumes at these plants increased 140 MMcf/d and equity NGL production volumes decreased 22 MBPD quarter-to-quarter.
NGL pipelines, storage and terminals
Gross operating margin from our NGL pipelines, storage and terminal assets during the first quarter of 2019 increased $48.0 million when compared
to the first quarter of 2018. Gross operating margin from our underground facilities at the Mont Belvieu hub increased $28.6 million quarter-to-quarter primarily due to higher storage fee revenues, which accounted for a $22.1 million increase,
and higher product handling fee revenues, which accounted for an additional $9.4 million increase.
The Shin Oak NGL Pipeline, which was placed into limited commercial service in February 2019, contributed $8.3 million to gross operating margin
for the first quarter of 2019. The Shin Oak NGL pipeline has been operating at near its current transportation capacity of 250 MBPD, which includes offloads from affiliate pipelines and 79 MBPD of direct tariff movements. Gross operating margin
from our ATEX pipeline increased $4.4 million quarter-to-quarter primarily due to a 14 MBPD increase in transportation volumes. Gross operating margin from terminals connected to our Mid-America Pipeline System increased $4.4 million
quarter-to-quarter due to increased demand for terminal services. Gross operating margin from our Morgan’s Point Ethane Export Terminal increased $3.9 million primarily due to higher loading volumes of 18 MBPD. Gross operating margin from our
South Louisiana NGL Pipeline System increased $3.2 million quarter-to-quarter primarily due to a 68 MBPD increase in transportation volumes.
Gross operating margin from EHT decreased $5.4 million quarter-to-quarter primarily due to lower LPG exports, which decreased 49 MBPD. Ship and
barge traffic scheduled at EHT was adversely impacted by temporary closures and restrictions impacting the Houston Ship Channel during the first quarter of 2019.
NGL fractionation
Gross operating margin from NGL fractionation for the first quarter of 2019 decreased $17.9 million when compared to the first
quarter of 2018. Gross operating margin at our Hobbs NGL fractionator decreased $21.0 million quarter-to-quarter primarily due to major maintenance activities completed in February 2019. NGL fractionation volumes at Hobbs decreased 20 MBPD.
Gross operating margin from our Mont Belvieu NGL fractionation complex increased a net $4.1 million quarter-to-quarter primarily
due to higher fractionation volumes, which accounted for a $16.7 million increase, partially offset by higher operating costs, which accounted for a $12.3 million decrease. NGL fractionation volumes at our Mont Belvieu NGL fractionation complex
increased 120 MBPD (net to our interest), primarily due to the start-up of our ninth NGL fractionator in May 2018. Gross operating margin from our equity investment in Promix increased $1.7 million quarter-to-quarter primarily due to higher
fractionation volumes of 15 MBPD. Our Tebone NGL fractionator, which was restarted in February 2019 in light of regional demand for fractionation services, contributed 18 MBPD of fractionation volumes to the first quarter of 2019 results. Gross
operating margin from Tebone for the first quarter of 2019 was a loss of $2.7 million due to start-up expenses.
Crude Oil Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines &
Services segment for the periods indicated (dollars in millions, volumes as noted):
|
|
For the Three Months
Ended March 31,
|
|
|
|
2019
|
|
|
2018
|
|
Segment gross operating margin
|
|
$
|
662.3
|
|
|
$
|
220.0
|
|
|
|
|
|
|
|
|
|
|
Selected volumetric data:
|
|
|
|
|
|
|
|
|
Crude oil pipeline transportation volumes (MBPD)
|
|
|
2,227
|
|
|
|
1,997
|
|
Crude oil marine terminal volumes (MBPD)
|
|
|
886
|
|
|
|
634
|
|
Gross operating margin from our Crude Oil Pipelines & Services segment for the first quarter of 2019 increased $442.3 million
when compared to the first quarter of 2018.
Gross operating margin from our Midland-to-ECHO 1 Pipeline
System and related business activities increased $221.0
million quarter-to-quarter primarily due to changes in non-cash mark-to-market earnings, which were a $67.2 million benefit in the first quarter of 2019 compared to a $114.0 million
loss in the first quarter of 2018, and lower expenses, which accounted for a $28.9 million increase. Gross operating margin for the first quarter of 2018 was reduced by $24.2 million in connection with the expected allocation of pipeline earnings
to Western Gas Partners, LP (“Western”) upon closing of their acquisition of a 20% ownership interest in Whitethorn Pipeline Company LLC (“Whitethorn”), which owns the majority of the Midland-to-ECHO 1 Pipeline System. Western acquired its
interest in Whitethorn in June 2018.
Transportation volumes for the Midland-to-ECHO 1 Pipeline System increased 58 MBPD quarter-to-quarter.
The mark-to-market earnings attributable to the Midland-to-ECHO 1 Pipeline System are associated with the hedging
of crude oil market price differentials (basis spreads) between the Midland and Houston area markets. At March 31, 2019, these hedges, which were primarily entered into during 2017,
serve to lock in a $2.75
per barrel
positive margin on our anticipated purchases of crude oil at Midland and subsequent anticipated sales to customers
in the Houston area for periods extending predominantly into 2019 and minimally through 2020. The volume hedged through 2020 varies from quarter-to-quarter and year-to-year; however, the hedge levels generally correspond to pipeline capacity
currently expected to be available to us on the Midland-to-ECHO 1 Pipeline System as customer commitment volumes ramp up to peak levels. The mark-to-market gain for the first quarter of 2019 reflects a decrease in the basis spread between the
Midland and Houston markets since December 31, 2018 to an average of $4.51
per barrel through 2020 relative to our average hedged amount of $2.75
per barrel across these same periods (as of March 31, 2019). When the forecasted physical receipts and deliveries of crude oil ultimately occur in the future, we
will realize a physical gross margin at then-prevailing commodity price spreads; however the realized settlement of the associated financial hedges would convert that physical margin to the average $2.75
per barrel spread of the financial hedges. The basis spread between the Midland and Houston markets continues to fluctuate.
For information regarding our commodity hedging activities,
see Note 13
of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
Gross operating margin from other crude oil marketing activities increased $132.5 million primarily due to higher average sales
margins, which accounted for an $83.6 million increase, and higher non-cash mark-to-market earnings, which accounted for an additional $48.1 million increase. Non-cash mark-to-market earnings for this business was a gain of $32.6 million during
the first quarter of 2019 compared to a loss of $15.5 million during the first quarter of 2018. The higher crude oil marketing earnings relate to higher market price differentials for crude oil between the Permian Basin region, Cushing hub and
Gulf Coast markets.
Gross operating margin from our West Texas System and equity investment in the Eagle Ford Crude Oil Pipeline System increased a
combined $27.4 million quarter-to-quarter primarily due to higher transportation volumes of 52 MBPD (net to our interest). Gross operating margin from our Midland-to-ECHO 2 Pipeline System, which was in limited commercial service during the
first quarter of 2019, was $17.4 million on transportation volumes of 147 MBPD. Gross operating margin from our equity investment in the Seaway Pipeline increased $22.4 million quarter-to-quarter primarily due to higher average transportation
fees. Lastly, gross operating margin from crude oil activities at EHT increased a net $9.6 million quarter-to-quarter primarily due to higher export volumes of 326 MBPD.
Natural Gas Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines &
Services segment for the periods indicated (dollars in millions, volumes as noted):
|
|
For the Three Months
Ended March 31,
|
|
|
|
2019
|
|
|
2018
|
|
Segment gross operating margin
|
|
$
|
264.3
|
|
|
$
|
197.9
|
|
|
|
|
|
|
|
|
|
|
Selected volumetric data:
|
|
|
|
|
|
|
|
|
Natural gas pipeline transportation volumes (BBtus/d)
|
|
|
14,197
|
|
|
|
13,021
|
|
Gross operating margin from our Natural Gas Pipelines & Services segment for the first quarter of 2019 increased $66.4 million
when compared to the first quarter of 2018. Gross operating margin from our natural gas marketing activities increased $34.0 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $25.2 million increase,
and higher non-cash mark-to-market earnings, which accounted for an additional $5.4 million increase.
Gross operating margin from our Texas Intrastate System increased $23.2 million quarter-to-quarter primarily due to higher
capacity reservation fees. Transportation volumes on our Texas Intrastate System increased 278 BBtus/d. Gross operating margin from our Haynesville Gathering System increased $11.9 million quarter-to-quarter primarily due to higher treating and
other fee revenues, which accounted for a $7.6 million increase, and higher gathering volumes, which accounted for an additional $5.9 million increase. Natural gas gathering volumes on the Haynesville Gathering System increased 392 BBtus/d
quarter-to-quarter. Gross operating margin from our Permian Basin Gathering System increased $7.6 million primarily due to a 486 BBtus/d increase in natural gas gathering volumes, which accounted for a $6.4 million increase, and higher condensate
sales, which accounted for an additional $3.1 million increase.
Gross operating margin from our San Juan Gathering System decreased $4.8 million primarily due to a 123 BBtus/d decrease in
gathering volumes, which accounted for a $1.7 million decrease, and lower condensate sales, which accounted for an additional $1.3 million decrease. Gross operating margin from our BTA Gathering System decreased $3.7 million quarter-to-quarter
primarily due to higher operating costs.
Petrochemical &
Refined Products Services
The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined
Products Services segment for the periods indicated (dollars in millions, volumes as noted):
|
|
For the Three Months
Ended March 31,
|
|
|
|
2019
|
|
|
2018
|
|
Segment gross operating margin:
|
|
|
|
|
|
|
Propylene production and related marketing activities
|
|
$
|
102.3
|
|
|
$
|
129.4
|
|
Butane isomerization and related DIB operations
|
|
|
24.0
|
|
|
|
24.7
|
|
Octane enhancement and related operations
|
|
|
24.3
|
|
|
|
32.4
|
|
Refined products pipelines and related activities
|
|
|
81.9
|
|
|
|
80.9
|
|
Marine transportation and other
|
|
|
10.1
|
|
|
|
4.5
|
|
Total
|
|
$
|
242.6
|
|
|
$
|
271.9
|
|
|
|
|
|
|
|
|
|
|
Selected volumetric data:
|
|
|
|
|
|
|
|
|
Propylene production volumes (MBPD)
|
|
|
90
|
|
|
|
98
|
|
Butane isomerization volumes (MBPD)
|
|
|
111
|
|
|
|
113
|
|
Standalone DIB processing volumes (MBPD)
|
|
|
93
|
|
|
|
78
|
|
Octane additive and related plant production volumes (MBPD)
|
|
|
28
|
|
|
|
26
|
|
Pipeline transportation volumes, primarily refined products and
petrochemicals (MBPD)
|
|
|
810
|
|
|
|
852
|
|
Refined products and petrochemical marine terminal volumes (MBPD)
|
|
|
338
|
|
|
|
370
|
|
Propylene production and related
marketing activities
Gross operating margin from propylene production and related marketing activities for the first quarter of 2019 decreased $27.1 million when
compared to the first quarter of 2018. Gross operating margin from our Mont Belvieu propylene splitters decreased $50.7 million quarter-to-quarter primarily due to lower average propylene sales margins, which accounted for a $33.4 million
decrease, and lower average propylene fractionation fees, which accounted for an additional $14.9 million decrease. Propylene production volumes from our splitter units decreased 14 MBPD quarter-to-quarter. Gross operating margin from our PDH
facility, which completed its commissioning (or start up) phase and began full commercial operations in April 2018, increased $22.8 million quarter-to-quarter. Plant production for the PDH facility, which includes by-products, increased 6 MBPD
quarter-to-quarter.
Butane isomerization and related DIB
operations
Gross operating margin from butane isomerization and deisobutanizer (“DIB”) operations for the first quarter of 2019 decreased a net $0.7 million
when compared to the first quarter of 2018. Lower deficiency revenues on our Port Neches isobutane pipeline, which accounted for a $1.4 million decrease, were partially offset by higher Mont Belvieu DIB processing volumes of 15 MBPD, which
accounted for a $0.7 million increase.
Octane enhancement and related
operations
Gross operating margin from our octane enhancement facility and high purity isobutylene plant for the first quarter of 2019 decreased a net $8.1
million when compared to the first quarter of 2018 primarily due to lower plant sales volumes, which accounted for a $14.7 million decrease, partially offset by higher average sales margins, which accounted for a $7.8 million increase.
Refined products pipelines and
related activities
Gross operating margin from refined products pipelines and
related marketing activities for the first quarter of 2019 increased a net $1.0 million when compared to the first quarter of 2018. Gross operating margin from our refined products marine terminal at EHT increased a net $
0.8
million quarter-to-quarter primarily due to higher average terminaling fees, which accounted for a $5.0 million increase, partially offset by lower storage fees,
which accounted for a $2.8 million decrease, and lower terminaling volumes of 19 MBPD, which accounted for a $1.1 million decrease.
Marine transportation and other
Gross operating margin from marine transportation for the first quarter of 2019 increased $5.8 million when compared to the first quarter of 2018
primarily due to higher marine vessel fees and utilization rates quarter-to-quarter.
Liquidity and Capital Resources
Based on current market conditions (as of the filing date of
this quarterly report), we believe we will have sufficient liquidity, cash flow from operations and access to capital markets to fund our capital expenditures and working capital needs for the reasonably foreseeable future. At March 31, 2019,
we had $4.70
billion of consolidated liquidity, which was comprised of $4.60
billion of available borrowing capacity under EPO’s revolving credit facilities and $99.3
million of unrestricted cash on hand.
We may issue equity and debt securities to assist us in meeting our future funding and liquidity requirements, including those
related to capital investments. We have a universal shelf registration statement (the “2019 Shelf”) on file with the SEC which allows Enterprise Products Partners L.P. and EPO (each on a standalone basis) to issue an unlimited amount of equity
and debt securities, respectively. The 2019 Shelf replaced our prior universal shelf registration statement, which was set to expire in May 2019.
Common Unit Repurchases under 2019 Buyback Program
In January 2019, the Board approved the 2019 Buyback Program, which authorized the partnership to repurchase up to $2.0 billion of
our common units. For additional information regarding the 2019 Buyback Program, see “Significant Recent Developments” within this Part I, Item 2.
We repurchased 1,852,392
common units under the
2019 Buyback Program during the three months ended March 31, 2019 for a total purchase price of $51.6
million, excluding commissions and fees. At March 31,
2019, the remaining available capacity under the
2019 Buyback Program was $1.95
billion.
Consolidated Debt
The following table presents scheduled maturities of our consolidated debt obligations at March 31, 2019 for the periods indicated
(dollars in millions):
|
|
|
|
|
Scheduled Maturities of Debt
|
|
|
|
Total
|
|
|
Remainder
of 2019
|
|
|
2020
|
|
|
2021
|
|
|
2022
|
|
|
2023
|
|
|
Thereafter
|
|
Commercial Paper Notes
|
|
$
|
1,395.0
|
|
|
$
|
1,395.0
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
--
|
|
|
$
|
--
|
|
Senior Notes
|
|
|
23,050.0
|
|
|
|
800.0
|
|
|
|
1,500.0
|
|
|
|
1,325.0
|
|
|
|
1,400.0
|
|
|
|
1,250.0
|
|
|
|
16,775.0
|
|
Junior Subordinated Notes
|
|
|
2,670.6
|
|
|
|
--
|
|
|
|
--
|
|
|
|
--
|
|
|
|
--
|
|
|
|
--
|
|
|
|
2,670.6
|
|
Total
|
|
$
|
27,115.6
|
|
|
$
|
2,195.0
|
|
|
$
|
1,500.0
|
|
|
$
|
1,325.0
|
|
|
$
|
1,400.0
|
|
|
$
|
1,250.0
|
|
|
$
|
19,445.6
|
|
For additional information regarding our debt agreements, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial
Statements included under Part I, Item 1 of this quarterly report.
Credit Ratings
At May 8, 2019, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard
and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings. In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings.
EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or
hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated
independently of credit ratings from other rating agencies.
Issuance of Common Units under DRIP and EUPP
We issued a combined 1,516,779
common units in the
first quarter of 2019 in
connection with our distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In total, the net cash proceeds
we received from these issuances was $42.7 million. For additional information regarding our issuance of common units and related registration statements, see Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements
included under Part I, Item 1 of this quarterly report.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods
indicated (dollars in millions). For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.
|
|
For the Three Months
Ended March 31,
|
|
|
|
2019
|
|
|
2018
|
|
Net cash flows provided by operating activities
|
|
$
|
1,160.4
|
|
|
$
|
1,233.6
|
|
Cash used in investing activities
|
|
|
1,174.5
|
|
|
|
1,119.1
|
|
Cash provided by (used in) financing activities
|
|
|
(288.5
|
)
|
|
|
30.8
|
|
Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities.
Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemical and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products
and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions and government regulations
affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their obligations to us in connection with our marketing activities and long-term take-or-pay agreements. For a more complete
discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of the 2018 Form 10-K.
The following information highlights primary drivers of the quarter-to-quarter fluctuations in our consolidated cash flow amounts:
Operating activities
Net cash flows provided by operating activities for the first quarter of 2019 decreased a net $73.2 million when compared to the
first quarter of 2018 primarily due to:
§
|
a $356.7 million decrease quarter-to-quarter primarily due to the timing of cash receipts and payments related to operations; partially offset by
|
§
|
a $252.0 million increase quarter-to-quarter resulting from higher
partnership earnings in the first quarter of 2019 when compared to the first quarter of 2018 (after adjusting our $368.9 million increase in net income
quarter-to-quarter
for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and
|
§
|
a $31.5 million increase
quarter-to-quarter
in cash distributions received on earnings from unconsolidated affiliates attributable to our investments in NGL and crude oil pipeline joint ventures.
|
For information regarding significant changes in our consolidated net income and underlying segment results, see “Results of
Operations” within this Part I, Item 2.
Investing activities
Cash used for investing activities in the first quarter of
2019 increased a net $
55.4
million when compared to the first quarter of 2018 primarily due to:
§
|
a $
202.4
million increase
quarter-to-quarter
in expenditures for consolidated property, plant and equipment (see “Capital
Investments” within this Part I, Item 2 for additional information); partially offset by
|
§
|
a $
149.8
million decrease
quarter-to-quarter
in net cash used for business combinations. We used $
149.8
million in the first quarter of 2018 to acquire the remaining 50% equity interest in Delaware Processing.
|
Financing activities
Cash used in financing activities for the first quarter of
2019 increased a net $319.3
million when compared to the first quarter of 2018 primarily due to:
§
|
a
net $145.9 million decrease quarter-to-quarter in net cash inflows
from debt. In the first quarter of 2019, we issued $1.4 billion principal amount of short-term notes under EPO’s commercial paper program, partially offset by the repayment of $700 million principal amount of Senior Notes N. In the
first quarter of 2018, we issued $2.7 billion aggregate principal amount of senior notes and junior subordinated notes, partially offset by the repayment of $1.18 billion principal amount of short-term notes under EPO’s commercial
paper program and the redemption of all $682.7 million outstanding aggregate principal amount of its Junior Subordinated Notes B;
|
§
|
a $134.3 million decrease quarter-to-quarter in net cash proceeds from the issuance of common units in connection with
our DRIP and EUPP;
|
§
|
the use of $51.6 million in the first quarter of 2019 to acquire 1,852,392 common units under the 2019 Buyback Program;
and
|
§
|
a $
31.9
million increase
quarter-to-quarter
in cash distributions paid to limited partners primarily due to an
increase in the quarterly cash distribution rate per unit; partially offset by,
|
§
|
a $
34.7
million increase
quarter-to-quarter
in cash contributions from noncontrolling interests.
|
Non-GAAP Cash Flow Measures
Distributable Cash Flow
Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after any cash
reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital expenditures, debt service, working capital, operating expenses, common unit
repurchases, commitments and contingencies and other amounts. The retention of cash by the partnership allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets.
We measure available cash by reference to distributable cash flow (“DCF”), which is a non-GAAP cash flow measure. DCF is an
important financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows
at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured
by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our partners. Using this metric, management computes
our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.
Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board of
Enterprise GP, which has sole authority in approving such matters. Unlike several other master limited partnerships, our general partner has a non-economic ownership interest in us and is not entitled to receive any cash distributions from us
based on incentive distribution rights or other equity interests.
Our use of DCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by
operating activities, which is the most comparable GAAP measure. For a discussion of net cash flows provided by operating activities, see the previous section titled “Cash Flow Statement Highlights” within this Part I, Item 2.
The following table summarizes our calculation of DCF for the periods indicated (dollars in millions):
|
|
For the Three Months
Ended March 31,
|
|
|
|
2019
|
|
|
2018
|
|
Net income attributable to limited partners (GAAP) (1)
|
|
$
|
1,260.5
|
|
|
$
|
900.7
|
|
Adjustments to net income attributable to limited partners to derive
DCF
(addition or subtraction indicated by sign):
|
|
|
|
|
|
|
|
|
Depreciation, amortization and accretion expenses
|
|
|
474.5
|
|
|
|
425.9
|
|
Cash distributions received from unconsolidated affiliates (2)
|
|
|
143.5
|
|
|
|
122.4
|
|
Equity in income of unconsolidated affiliates
|
|
|
(154.6
|
)
|
|
|
(115.7
|
)
|
Change in fair
market value of derivative instruments
|
|
|
(96.3
|
)
|
|
|
136.9
|
|
Change in fair value of Liquidity Option Agreement
|
|
|
57.8
|
|
|
|
7.5
|
|
Gain on step acquisition of unconsolidated affiliate
|
|
|
--
|
|
|
|
(37.0
|
)
|
Sustaining capital expenditures (3)
|
|
|
(61.6
|
)
|
|
|
(66.3
|
)
|
Other, net
|
|
|
2.9
|
|
|
|
8.5
|
|
Subtotal DCF, before proceeds from asset sales and monetization
of interest rate
derivative instruments accounted for as cash flow hedges
|
|
$
|
1,626.7
|
|
|
$
|
1,382.9
|
|
Proceeds from asset sales
|
|
|
1.7
|
|
|
|
1.1
|
|
Monetization of interest rate derivative instruments accounted for as cash flow
hedges
|
|
|
--
|
|
|
|
1.5
|
|
DCF (non-GAAP)
|
|
$
|
1,628.4
|
|
|
$
|
1,385.5
|
|
|
|
|
|
|
|
|
|
|
Cash distributions paid to limited partners with respect to period
|
|
$
|
963.5
|
|
|
$
|
933.5
|
|
|
|
|
|
|
|
|
|
|
Cash distribution per unit declared by Enterprise GP with respect to period
|
|
$
|
0.4375
|
|
|
$
|
0.4275
|
|
|
|
|
|
|
|
|
|
|
Total DCF retained by partnership with respect to period (4)
|
|
$
|
664.9
|
|
|
$
|
452.0
|
|
|
|
|
|
|
|
|
|
|
Distribution coverage ratio (5)
|
|
|
1.7x
|
|
|
|
1.5x
|
|
|
|
(1)
For a discussion of the primary drivers of changes in our comparative income statement amounts, see “Income Statements Highlights” within this Part I, Item 2.
(2)
Reflects both distributions received on earnings from unconsolidated affiliates and those attributable to a return of capital from unconsolidated affiliates.
(3)
Sustaining capital expenditures include cash payments and accruals applicable to the period.
(4)
At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these periods was primarily reinvested in growth capital projects.
This retainage of cash substantially reduced our reliance on the equity capital markets to fund such expenditures.
(5)
Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to limited partners and in connection with distribution equivalent rights with respect to the
period.
|
|
The following table presents a reconciliation of net cash flows provided by operating activities to non-GAAP DCF for the periods indicated
(dollars in millions):
|
|
For the Three Months
Ended March 31,
|
|
|
|
2019
|
|
|
2018
|
|
Net cash flows provided by operating activities (GAAP)
|
|
$
|
1,160.4
|
|
|
$
|
1,233.6
|
|
Adjustments to reconcile net cash flows provided by operating activities to DCF
(addition or subtraction indicated by sign):
|
|
|
|
|
|
|
|
|
Net effect of changes in operating accounts
|
|
|
559.8
|
|
|
|
203.1
|
|
Sustaining capital expenditures
|
|
|
(61.6
|
)
|
|
|
(66.3
|
)
|
Other, net
|
|
|
(30.2
|
)
|
|
|
15.1
|
|
DCF (non-GAAP)
|
|
$
|
1,628.4
|
|
|
$
|
1,385.5
|
|
Free Cash Flow
Free Cash Flow (“FCF”), a non-GAAP financial measure, is a traditional cash flow metric that is widely used by a variety of investors and other
participants in the financial community, as opposed to DCF, which is a cash flow measure primarily used by investors and others in evaluating master limited partnerships. In general, FCF is a measure of how much cash flow a business generates
during a specified time period after accounting for all capital investments, including expenditures for growth and sustaining capital projects. By comparison, only sustaining capital expenditures are reflected in DCF.
We believe that FCF is important to traditional investors since it reflects the amount of cash available for reducing debt, investing in
additional capital projects, paying distributions, common unit repurchases and similar matters. Since business partners fund certain capital projects of our consolidated subsidiaries, our determination of FCF reflects the amount of cash we
receive from noncontrolling interests, net of any distributions paid to such interests.
Our calculation of FCF may or may not be comparable to similarly
titled measures used by other companies.
Our use of FCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by
operating activities, which is the most comparable GAAP measure.
FCF fluctuates based on our earnings, the level of investing activities we undertake each period, and the timing of operating cash
receipts and payments. In addition to providing the quarterly amounts presented below, we also provide a calculation of aggregate FCF over the twelve months ended March 31, 2019 in order to measure FCF over a longer term. The following table
summarizes our calculation of FCF for the periods indicated (dollars in millions):
|
|
For the Three Months
Ended March 31,
|
|
|
For the Twelve
Months Ended
March 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
Net cash flows provided by operating activities (GAAP)
|
|
$
|
1,160.4
|
|
|
$
|
1,233.6
|
|
|
$
|
6,053.1
|
|
Adjustments to net cash flows provided by operating activities to derive FCF
(addition or subtraction indicated by sign):
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(1,174.5
|
)
|
|
|
(1,119.1
|
)
|
|
|
(4,337.0
|
)
|
Cash contributions from noncontrolling interests
|
|
|
34.8
|
|
|
|
0.1
|
|
|
|
272.8
|
|
Cash distributions paid to noncontrolling interests
|
|
|
(18.0
|
)
|
|
|
(15.4
|
)
|
|
|
(84.2
|
)
|
FCF (non-GAAP)
|
|
$
|
2.7
|
|
|
$
|
99.2
|
|
|
$
|
1,904.7
|
|
For a discussion of primary drivers of our quarterly net cash flows provided by operating activities and cash used in investing
activities, see “Cash Flows from Operating, Investing and Financing Activities” within this Part I, Item 2.
Capital Investments
We currently have $5.0 billion of growth capital projects scheduled to be completed by mid-2020 including:
§
|
the completion of joint venture-owned dock infrastructure in Corpus Christi designed to accommodate crude oil volumes
(second quarter of 2019),
|
§
|
the third processing train at our Orla natural gas processing facility (second quarter of 2019),
|
§
|
expansion of our Front Range and Texas Express NGL pipelines (third quarter of 2019),
|
§
|
increase in LPG loading capacity at EHT (third quarter of 2019),
|
§
|
our isobutane dehydrogenation (“ iBDH”) facility (fourth quarter of 2019),
|
§
|
the Shin Oak NGL pipeline (full service expected in fourth quarter of 2019),
|
§
|
our ethylene export terminal (fourth quarter of 2019 through the fourth quarter of 2020),
|
§
|
our Mentone cryogenic natural gas processing plant (first quarter of 2020), and
|
§
|
two new NGL fractionators in Chambers County, Texas (“Frac X” in the fourth quarter of 2019 and “Frac XI” in the first
half of 2020).
|
Based on information currently available, we expect our total capital investments for 2019 to approximate $3.8 billion to $4.2
billion, which reflects growth capital expenditures of $3.4 billion to $3.8 billion and $350 million for sustaining capital expenditures.
Our forecast of capital investments for 2019 is based on our announced strategic operating and growth plans (through the filing
date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt
securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather related issues and changes in supplier prices. Furthermore, our forecast
of capital investments may change as a result of decisions made by management at a later date, which may include unforeseen acquisition opportunities.
Our success in raising capital, including partnering with other companies to share costs and risks, continues to be a significant
factor in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we expect to make the forecast capital expenditures noted
above, we may adjust the timing and amounts of projected expenditures in response to changes in capital market conditions.
The following table summarizes the primary elements of our capital investments for the periods indicated (dollars in millions):
|
|
For the Three Months
Ended March 31,
|
|
|
|
2019
|
|
|
2018
|
|
Capital investments for property,
plant and equipment:
(1)
|
|
|
|
|
|
|
Growth capital projects (2)
|
|
$
|
1,077.4
|
|
|
$
|
873.3
|
|
Sustaining capital projects (3)
|
|
|
71.5
|
|
|
|
73.2
|
|
Total
|
|
$
|
1,148.9
|
|
|
$
|
946.5
|
|
|
|
|
|
|
|
|
|
|
Cash used for business combinations, net
|
|
$
|
--
|
|
|
$
|
149.8
|
|
|
|
|
|
|
|
|
|
|
Investments in unconsolidated affiliates
|
|
$
|
29.1
|
|
|
$
|
37.9
|
|
|
|
(
1)
Growth and sustaining capital amounts presented in the table above are presented on a cash basis.
(2)
Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility,
etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows.
(3)
Sus
t
aining capital expenditures are capital expenditures (as defined by GAAP) resulting
from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings.
|
|
Fluctuations in our spending for growth capital projects and investments in unconsolidated affiliates are explained in large part
by increases or decreases in spending on major expansion projects. Our most significant growth capital expenditures for the three months ended March 31, 2019 involved projects to support crude oil, natural gas and NGL production from the Permian
Basin, export activities at our Gulf Coast terminals and spending on our iBDH unit. Fluctuations in spending for sustaining capital projects are explained in large part by the timing and cost of pipeline integrity and similar projects.
Comparison of Three Months Ended March 31, 2019 with Three Months Ended March 31, 2018
Investments in growth capital projects at our Mont Belvieu complex increased $149.7 million quarter-to-quarter primarily due to increased
expenditures at our iBDH unit, which accounted for a $126.4 million increase, and Frac X and Frac XI, which accounted for an additional $118.0 million increase, partially offset by lower expenditures at our PDH facility and ninth Mont Belvieu
area NGL fractionator (“Frac IX”), which accounted for a combined $115.8 million decrease. Our PDH facility and Frac IX were placed into service during the second quarter of 2018.
Our growth capital investments in support of Permian Basin production increased $70.4 million quarter-to-quarter primarily due to increased
expenditures for our Shin Oak NGL Pipeline, which accounted for a $109.5 million increase, and the conversion of a portion of our Seminole NGL Pipeline system to crude oil service (the Midland-to-ECHO 2 Pipeline System), which accounted for an
additional $62.1 million increase, partially offset by lower expenditures at our Orla natural gas processing facility, which accounted for a $100.8 million decrease.
Investments in our ethylene export terminal and related assets increased $63.1 million quarter-to-quarter.
Net cash used for business combinations in the first quarter of 2018 reflects our acquisition of the remaining 50% member interest in Delaware
Processing in March 2018.
Critical Accounting Policies and Estimates
A discussion of our critical accounting policies and estimates is included in our 2018 Form 10-K. The following types of
estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:
§
|
depreciation methods and estimated useful lives of property, plant and equipment;
|
§
|
measuring recoverability of long-lived assets and equity method investments;
|
§
|
amortization methods and estimated useful lives of qualifying intangible assets;
|
§
|
methods we employ to measure the fair value of goodwill; and
|
§
|
revenue recognition policies and the use of estimates for revenue and expenses.
|
When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our
current knowledge and understanding of the underlying facts and circumstances. Such estimates may be revised as a result of changes in the underlying facts and circumstances. Subsequent changes in these estimates may have a significant impact
on our consolidated financial position, results of operations and cash flows.
Other Items
Contractual Obligations
The principal amount of our consolidated debt obligations were $27.12 billion at March 31, 2019 compared to $26.42 billion at
December 31, 2018. For information regarding the scheduled maturities of such debt, see “Liquidity and Capital Resources – Consolidated Debt” within this Part I, Item 2. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial
Statements under Part I, Item 1 of this quarterly report for information regarding our consolidated debt obligations.
During the first quarter of 2019, we entered into additional long-term purchase commitments for NGLs with third party suppliers.
On a combined basis, these new agreements increased our estimated long-term purchase obligations by $3.2 billion, with $1.1 billion committed over the next five years and $2.1 billion thereafter. At March 31, 2019, our estimated long-term
purchase obligations totaled $13.5 billion after reflecting the agreements added in the first quarter of 2019 and those commitments that expired during the quarter. At December 31, 2018, our estimated long-term purchase obligations totaled $10.8
billion.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our
financial position, results of operations and cash flows.
Recent Accounting Developments
For information regarding recent changes in our accounting for leases, see Note 2 of the Notes to Unaudited Condensed Consolidated
Financial Statements included under Part I, Item 1 of this quarterly report.
Related Party Transactions
For information regarding our related party transactions, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial
Statements included under Part I, Item 1 of this quarterly report.