Summit Midstream Partners, LP Reports Third Quarter 2018 Financial Results and Provides Update for Double E Pipeline
THE WOODLANDS, Texas, Nov. 8, 2018 /PRNewswire/ -- Summit Midstream Partners, LP (NYSE: SMLP) announced today its financial and operating results for the three and nine months ended September 30, 2018. SMLP reported net income of $57.5 million for the third quarter of 2018, compared to net income of $93.6 million for the prior-year period. Net income in the third quarter of 2018 included $37.2 million of non-cash income related to a decrease in the present value of the estimated Deferred Purchase Price Obligation ("DPPO"). Net income for the prior-year period included $70.5 million of non-cash income related to a decrease in the present value of the estimated DPPO. Net cash provided by operations totaled $56.4 million for the third quarter of 2018, compared to $75.2 million for the prior-year period. Adjusted EBITDA totaled $73.4 million and distributable cash flow ("DCF") totaled $43.6 million for the third quarter of 2018, compared to $73.5 million and $52.9 million, respectively, for the prior-year period. Relative to the prior-year period, DCF in the third quarter of 2018 included a $7.1 million distribution adjustment associated with our issuance of Series A Preferred units in the fourth quarter of 2017 and $2.9 million of higher maintenance capital expenditures.
Steve Newby, President and Chief Executive Officer, commented, "SMLP reported another strong quarter of operating and financial results in the third quarter of 2018, primarily reflecting our Williston customers' robust level of drilling and completion activity, which generated liquids volume growth of nearly 31% compared to the third quarter of 2017. Our business continues to perform in line with our expectations and as such, we are reaffirming our 2018 adjusted EBITDA guidance of $285.0 million to $300.0 million and full year 2018 distribution coverage of approximately 1.00x. Producer activity levels in our service areas, amidst a constructive fundamental backdrop, support our volume growth expectations for the balance of 2018 and into 2019. Additionally, our gathering and processing projects in the northern Delaware and DJ Basin are expected to provide meaningful growth for SMLP upon their commissioning this quarter. We expect utilization of this new processing capacity to increase significantly throughout 2019.
We expect to provide formal 2019 financial guidance in February 2019, in accordance with our annual budgeting process, with our fourth quarter of 2018 earnings release. At this time, we are providing a preliminary view on 2019 adjusted EBITDA, which we expect will be at least 10% higher compared to adjusted EBITDA in 2018. Our balance sheet and liquidity position remain strong, and we expect that the forecasted growth in adjusted EBITDA and DCF in 2019 will enable us to return our distribution coverage ratio to levels in excess of 1.15x by the fourth quarter of 2019.
Our Double E project continues to represent an important and strategic project for SMLP, enabling us to provide a natural gas transportation solution for XTO and other shippers in the northern Delaware. We have successfully added additional shippers and continue to engage in discussions with several other prospective shippers on Double E. We remain on schedule for commercial operation date in the second quarter of 2021."
SMLP reported net income of $3.7 million for the first nine months of 2018, compared to net income of $104.3 million for the prior-year period. Net cash provided by operations totaled $166.5 million for the first nine months of 2018, compared to $196.5 million in the prior-year period. SMLP reported adjusted EBITDA of $217.2 million and DCF of $134.9 million for the nine months ended September 30, 2018, compared to $217.5 million and $155.8 million, respectively, for the prior-year period.
Double E Pipeline Project Update
In July 2018, SMLP entered into a precedent agreement with XTO Energy Inc. ("XTO"), a wholly owned subsidiary of Exxon Mobil Corporation ("ExxonMobil"), for firm transportation capacity on the Double E Pipeline Project ("Double E" or the "Project") under a 10-year take-or-pay agreement which increases up to 500,000 dekatherms per day ("dth/d"). In August and September of 2018, SMLP conducted a binding open season process to gauge market interest in the Project and obtain additional firm transportation commitments on Double E. As a result of the binding open season, SMLP executed additional precedent agreements with new shippers and is continuing to discuss potential firm volume commitments with other prospective shippers. SMLP expects to make its final investment decision ("FID") on Double E once these negotiations have concluded, given that the outcome of these discussions could have a material impact on the scope of the Project. The Project will provide up to 1.5 Bcf/d of residue natural gas transportation capacity from the northern Delaware Basin to the Waha Hub.
SMLP remains on schedule for its original target in-service date for the Project of the second quarter of 2021; however, the ultimate in-service date of the Project will be subject to, among other things, the timing of the FID and approval by the Federal Energy Regulatory Commission ("FERC") and other governmental authorities.
SMLP and ExxonMobil executed an equity option agreement in July 2018, which provides ExxonMobil, or an affiliate, the right to become an equity partner in Double E. We expect ExxonMobil to make a decision on its equity option agreement by June 30, 2019. SMLP has also received significant interest from other potential shippers and financial parties regarding equity participation in the Project.
Third Quarter 2018 Segment Results
Natural gas volume throughput averaged 1,629 million cubic feet per day ("MMcf/d") in the third quarter of 2018, a decrease of 10.8% compared to 1,826 MMcf/d in the prior-year period, and a decrease of 9.3% compared to 1,797 MMcf/d in the second quarter of 2018. SMLP's natural gas volume throughput metrics exclude its proportionate share of volume throughput from its 40% interest in Ohio Gathering, which averaged 797 MMcf/d in the third quarter of 2018, an increase of 4.5% compared to 763 MMcf/d in the prior-year period.
Crude oil and produced water volume throughput in the third quarter of 2018 averaged 96.9 thousand barrels per day ("Mbbl/d"), an increase of 30.9% compared to 74.0 Mbbl/d in the prior-year period, and an increase of 9.0% compared to 88.9 Mbbl/d in the second quarter of 2018.
The following table presents average daily throughput by reportable segment:
Three Nine months ended
months September
ended September 30,
30,
2018 2017 2018 2017
Average daily
throughput (MMcf/d):
Utica Shale 357 403 376 364
Williston Basin 19 21 18 19
Piceance/DJ Basins 571 594 574 601
Barnett Shale 232 254 253 270
Marcellus Shale 450 554 499 490
Aggregate average daily
throughput 1,629 1,826 1,720 1,744
Average daily
throughput (Mbbl/d):
Williston Basin 96.9 74.0 90.9 74.7
Aggregate average daily
throughput 96.9 74.0 90.9 74.7
Ohio Gathering average
daily throughput 797 763 765 746
(MMcf/d) (1)
Gross basis,
represents
100% of
volume
throughput
for Ohio
Gathering,
based on a
one-month
(1) lag.
Utica Shale
The Utica Shale reportable segment includes Summit Midstream Utica ("SMU"), a natural gas gathering system located in Belmont and Monroe counties in southeastern Ohio. SMU gathers and delivers dry natural gas to interconnections with a third-party intrastate pipeline that provides access to the Clarington Hub.
Segment adjusted EBITDA for the third quarter of 2018 totaled $6.5 million, a decrease of 22.5% from $8.4 million for the prior-year period and a decrease of 29.3% from $9.2 million in the second quarter of 2018. Total volume throughput averaged 357 MMcf/d in the third quarter of 2018, compared to 403 MMcf/d in the prior-year period and 415 MMcf/d in the second quarter of 2018. Volumes were lower in the third quarter of 2018 compared to both the prior-year period and the second quarter of 2018 primarily due to natural production declines, together with an estimated 40 MMcf/d of temporary volume curtailments related to infill drilling and completion activities on existing pad sites. Volume throughput on the TPL-7 Connector project, which generates a lower gathering margin compared to volumes gathered directly from a pad site, totaled 148 MMcf/d in the third quarter of 2018, compared to 74 MMcf/d in the prior year period and 124 MMcf/d in the second quarter of 2018.
Our customers are currently operating one drilling rig upstream of the SMU system. One SMU customer has recently communicated its intent to increase drilling activities in the liquids-rich and condensate windows of the Utica Shale in 2018 and 2019, versus SMU's dry gas service area. This shift is expected to negatively impact the rate of volume and segment adjusted EBITDA growth in 2019, compared to previous expectations, but should serve as a positive catalyst for SMLP's Ohio Gathering reportable segment. Because SMU is an asset that is included in the DPPO calculation, we have reflected such slower 2019 growth expectations in the estimated future value of the DPPO as of September 30, 2018.
Ohio Gathering
The Ohio Gathering reportable segment includes our 40% ownership interest in Ohio Gathering, a natural gas gathering system spanning the condensate, liquids-rich and dry gas windows of the Utica Shale in Harrison, Guernsey, Noble, Belmont and Monroe counties in southeastern Ohio. This segment also includes our 40% ownership interest in Ohio Condensate, a condensate stabilization facility located in Harrison County, Ohio. Segment adjusted EBITDA for the Ohio Gathering segment includes our proportional share of adjusted EBITDA from Ohio Gathering and Ohio Condensate, based on a one-month lag.
Segment adjusted EBITDA for the third quarter of 2018 totaled $10.2 million, a decrease of 3.3% from $10.5 million for the prior-year period and an increase of 13.8% from $8.9 million for the second quarter of 2018. Volume throughput on the Ohio Gathering system averaged 797 MMcf/d, gross, in the third quarter of 2018, compared to 763 MMcf/d, gross, in the prior-year period and 727 MMcf/d, gross, in the second quarter of 2018. Higher volumes in the third quarter of 2018 were a result of 20 new wells that were connected late in the second quarter of 2018 and 20 new wells that were connected in the third quarter of 2018.
Producer activity levels on the Ohio Gathering system have steadily increased throughout 2018, particularly in the areas that serve the rich gas and condensate windows of the Utica Shale, which have generated attractive well results as a result of improved drilling and completion techniques and higher commodity prices. Our customers are currently operating three drilling rigs upstream of the Ohio Gathering system.
Williston Basin
The Polar and Divide, Tioga Midstream and Bison Midstream systems provide our midstream services for the Williston Basin reportable segment. The Polar and Divide system gathers crude oil in Williams and Divide counties in North Dakota and delivers to third-party intra- and interstate pipelines as well as third-party rail terminals. The Polar and Divide system also gathers and delivers produced water to various third-party disposal wells in the region. Tioga Midstream is a crude oil, produced water and associated natural gas gathering system in Williams County, North Dakota. All crude oil and natural gas gathered on the Tioga Midstream system is delivered to third-party pipelines, and all produced water is delivered to third-party disposal wells. Bison Midstream gathers associated natural gas production in Mountrail and Burke counties in North Dakota and delivers to third-party pipelines serving a third-party processing plant in Channahon, Illinois.
Segment adjusted EBITDA for the Williston Basin segment totaled $19.8 million for the third quarter of 2018, an increase of 22.4% compared to $16.2 million for the prior-year period and an increase of 4.3% from $19.0 million for the second quarter of 2018. The increase over the second quarter of 2018 primarily resulted from 20 new well connections in the period, which generated higher liquids volume throughput, primarily across the Polar and Divide system. Six of these new wells were drilled by a new customer that executed a gathering agreement with SMLP in the third quarter of 2017.
Liquids volumes averaged 96.9 Mbbl/d in the third quarter of 2018, a new quarterly record for SMLP. Third quarter 2018 volumes represented an increase of 30.9% from 74.0 Mbbl/d in the prior-year period and an increase of 9.0% compared to 88.9 Mbbl/d in the second quarter of 2018. Segment adjusted EBITDA in the third quarter of 2018 was negatively impacted by an estimated 12.0 Mbbl/d resulting from (i) certain customers initiating temporary production curtailments on existing wells for nearby drilling and completion activities, and (ii) produced water capacity constraints at third party disposal wells, which necessitated third-party trucking service.
Associated natural gas volumes averaged 19 MMcf/d in the third quarter of 2018, a decrease of 9.5% from the prior-year period, and a 5.6% increase from the second quarter of 2018. Six new associated natural gas wells were connected to our Williston gathering systems in the third quarter of 2018, four of which were drilled by a new customer that executed a gathering agreement with SMLP in the third quarter of 2018.
Our Williston Basin segment continues to benefit from consistent drilling activity and improving wells results from our customers. Currently, our customers are operating three drilling rigs upstream of the systems that comprise our Williston Basin reportable segment. In addition, our quarterly financial and operating results have been impacted by recent commercial successes and our execution of several new gathering agreements in the last twelve months. We expect that the combination of these activities will generate continued volume throughput and segment adjusted EBITDA growth for our Williston Basin segment in the near- and intermediate-term.
Piceance/DJ Basins
The Grand River and the Niobrara G&P systems provide our midstream services for the Piceance/DJ Basins reportable segment. These systems provide natural gas gathering and processing services for producers operating in the Piceance Basin located in western Colorado and eastern Utah and in the Denver-Julesburg ("DJ") Basin located in northeastern Colorado.
Segment adjusted EBITDA totaled $29.8 million for the third quarter of 2018, in line with $30.0 million in the prior-year period and an increase of 7.8% from $27.7 million in the second quarter of 2018. The Piceance/DJ Basins reportable segment generated $1.2 million of lower G&A expense in the third quarter of 2018, compared to the second quarter of 2018, primarily due to certain expense reimbursement activities. Third quarter 2018 volume throughput averaged 571 MMcf/d, a decrease of 3.9% from 594 MMcf/d in the prior-year period and in line with the 576 MMcf/d in the second quarter of 2018. Volume declines relative to the prior-year period were partially offset by the completion of 39 new wells in the third quarter of 2018, including 23 new wells upstream of the Niobrara G&P system in the DJ Basin, which generates higher margin revenue compared to the Grand River system. In the third quarter of 2018, the Niobrara G&P system operated at approximately 85% utilization, including approximately 95% utilization in September 2018.
Volume throughput on the Niobrara G&P system will be constrained by our current 20 MMcf/d of processing capacity until our new 60 MMcf/d processing plant is commissioned, which is expected to occur in the fourth quarter of 2018. Currently, our Piceance/DJ segment customers are operating four drilling rigs, all of which are working upstream of the Niobrara G&P system, and we expect significant drilling and completion activity to continue in and around this system's service area throughout 2019.
Barnett Shale
The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment. This system gathers and delivers low-pressure natural gas received from pad sites, primarily located in southeastern Tarrant County, Texas, to downstream intrastate pipelines serving various natural gas hubs in the region.
Segment adjusted EBITDA for the Barnett Shale segment totaled $10.8 million for the third quarter of 2018, in line with $10.8 million in the prior-year period and a 2.5% decrease from $11.1 million in the second quarter of 2018. Volume throughput in the third quarter of 2018 averaged 232 MMcf/d, which was down 8.7% compared to the prior-year period of 254 MMcf/d and down 12.1% from 264 MMcf/d in the second quarter of 2018. Volume throughput in the third quarter of 2018 was negatively affected by temporary curtailments associated with simultaneous drilling and completion activities, together with our required annual regulatory system shutdown, which resulted in limited volumes for approximately five days in September. Collectively, these activities impacted volume throughput in the third quarter of 2018 by an estimated 15 MMcf/d. In addition, we recognized an approximate $1.0 million net impact to adjusted EBITDA in the third quarter of 2018, related to a customer's estimated MVC shortfall payment due in October 2019.
Drilling and well permitting activities in our DFW Midstream system service area have remained relatively steady throughout 2018. A customer completed five new wells on the DFW Midstream system late in the quarter, which increased third quarter exit rate volumes to approximately 260 MMcf/d. We expect four new well connections by a separate customer by the end of the 2018, which we expect will have a positive impact on volume throughput in the first quarter of 2019.
Marcellus Shale
The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment. This system gathers high-pressure natural gas received from upstream pipeline interconnections with Antero Midstream Partners, LP and Crestwood Equity Partners LP. Natural gas on the Mountaineer Midstream system is delivered to the Sherwood Processing Complex located in Doddridge County, West Virginia.
Segment adjusted EBITDA for the Marcellus Shale segment totaled $5.6 million for the third quarter of 2018, a decrease of 16.9% from $6.7 million for the prior-year period and a decrease of 15.2% from $6.5 million for the second quarter of 2018. Segment adjusted EBITDA was lower in the third quarter of 2018 primarily due to a decrease in volume throughput, which averaged 450 MMcf/d in the third quarter of 2018, compared to 554 MMcf/d in the prior-year period and 524 MMcf/d in the second quarter of 2018. Volume throughput was lower in the third quarter of 2018 due to natural production declines, primarily related to the 27 wells that were commissioned upstream of the Mountaineer Midstream system in 2017 and an additional 9 wells commissioned in the first quarter of 2018.
No new wells were completed in the second or third quarters of 2018, and no new wells are expected for the remainder of 2018.
MVC Shortfall Payments
SMLP billed its customers $12.4 million in the third quarter of 2018 related to MVC shortfalls. For those customers that do not have credit banking mechanisms in their gathering agreements, or do not have the ability to use MVC shortfall payments as credits, the MVC shortfall payments are accounted for as gathering revenue in the period in which they are earned.
In the third quarter of 2018, SMLP recognized $18.8 million of gathering revenue associated with MVC shortfall payments from certain customers in each of its reportable segments. SMLP also recognized ($3.0) million of adjustments to MVC shortfall payments in the third quarter of 2018, primarily in the Barnett Shale segment, which adjusts downward approximately 70% of a certain customer's aggregate estimated MVC shortfall payment due in October 2019. SMLP recognized approximately $6.0 million of this Barnett Shale customer's estimated aggregate MVC shortfall payment as gathering revenue in the third quarter of 2018, and will continue to recognize MVC shortfall payment gathering revenue associated with this expected MVC shortfall payment, on a ratable basis, until it is due and fully recognized, in the fourth quarter of 2019. SMLP's MVC shortfall payment mechanisms contributed $15.8 million of adjusted EBITDA in the third quarter of 2018.
Three
months
ended
September
30, 2018
MVC Billings Gathering Adjustments Net impact to
revenue to MVC adjusted
shortfall EBITDA
payments
(In thousands)
Net change in deferred
revenue related to MVC
shortfall payments:
Utica Shale
$
$
$
$
Williston Basin
Piceance/DJ Basins 3,416 3,416 3,416
Barnett Shale
Marcellus Shale
Total net change $
3,416 $
3,416
$ $
3,416
MVC shortfall payment
adjustments:
Utica Shale $
(82) $
(82)
$ $
(82)
Williston Basin 765 765 2,032 2,797
Piceance/DJ Basins 7,210 7,500 7,500
Barnett Shale 6,114 (5,031) 1,083
Marcellus Shale 1,049 1,049 1,049
Total MVC shortfall
payment adjustments $
8,942 $
15,346 $
(2,999) $
12,347
Total (1) $
12,358 $
18,762 $
(2,999) $
15,763
Exclusive of
Ohio
Gathering due
to equity
method
(1) accounting.
Nine
months
ended
September
30, 2018
MVC Billings Gathering Adjustments Net impact to
revenue to MVC adjusted
shortfall EBITDA
payments
(In thousands)
Net change in deferred
revenue related to MVC
shortfall payments:
Utica Shale
$
$
$
$
Williston Basin
Piceance/DJ Basins 10,363 10,363 10,363
Barnett Shale
Marcellus Shale
Total net change $
10,363 $
10,363
$ $
10,363
MVC shortfall payment
adjustments:
Utica Shale $
49 $
49
$ $
49
Williston Basin 2,250 9,698 (1,354) 8,344
Piceance/DJ Basins 20,765 21,727 (93) 21,634
Barnett Shale 6,393 (5,094) 1,299
Marcellus Shale 3,112 3,112 3,112
Total MVC shortfall
payment adjustments $
26,176 $
40,979 $
(6,541) $
34,438
Total (1) $
36,539 $
51,342 $
(6,541) $
44,801
Exclusive of
Ohio
Gathering due
to equity
method
(1) accounting.
Capital Expenditures
Capital expenditures totaled $46.6 million in the third quarter of 2018, including maintenance capital expenditures of approximately $6.4 million. Development activities during the third quarter of 2018 were primarily related to the ongoing construction and development of associated natural gas gathering and processing infrastructure in the Delaware and DJ basins. We expect the 60 MMcf/d northern Delaware gathering and processing system and the 60 MMcf/d processing plant expansion in the DJ to be commissioned in the fourth quarter of 2018.
Capital & Liquidity
As of September 30, 2018, SMLP had $866.0 million of available borrowing capacity under its $1.25 billion revolving credit facility, subject to covenant limits. Based upon the terms of SMLP's revolving credit facility and total outstanding debt of $1.18 billion (inclusive of $800.0 million of senior unsecured notes), SMLP's total leverage ratio and senior secured leverage ratio (as defined in the credit agreement) as of September 30, 2018, were 4.02 to 1.0 and 1.31 to 1.0, respectively.
Deferred Purchase Price Obligation
SMLP lowered the estimated undiscounted amount of the Deferred Purchase Price Obligation related to the 2016 Drop Down transaction from $538.4 million at June 30, 2018, to $470.9 million at September 30, 2018. The decrease is primarily related to a decrease in the number of well connections expected upstream of the SMU gathering system in 2019 from one of our two primary customers, which, relative to our previous estimate, results in lower projected volume throughput and Business Adjusted EBITDA in 2019. This slower expected pace of activity is expected to be partially offset by the same customer's decision to shift drilling to the condensate and liquids-rich gas acreage serviced by the Ohio Gathering system.
Subsequent to September 30, 2018, SMLP received additional information from customers on our Utica Shale, Ohio Gathering and Williston Basin segments. The impact of this new information would result in a decrease to the calculation of the undiscounted value of the Deferred Purchase Price Obligation of approximately $16.9 million, from $470.9 million to $454.0 million.
The consideration for the 2016 Drop Down consisted of (i) an initial $360.0 million cash payment (the "Initial Payment") which was funded on March 3, 2016, with borrowings under SMLP's revolving credit facility and (ii) a deferred payment which will be paid no later than December 31, 2020 (the "Deferred Purchase Price Obligation," "DPPO" or "Deferred Payment," as defined below). At the discretion of the board of directors of SMLP's general partner, the Deferred Payment can be made in either cash or SMLP common units, or a combination thereof.
The Deferred Payment will be equal to: (a) six-and-one-half (6.5) multiplied by the average Business Adjusted EBITDA of the 2016 Drop Down Assets for 2018 and 2019, less the G&A Adjuster, as defined in the Contribution Agreement; less (b) the Initial Payment; less (c) all capital expenditures incurred for the 2016 Drop Down Assets between March 3, 2016 and December 31, 2019; plus (d) all Business Adjusted EBITDA from the 2016 Drop Down Assets between March 3, 2016 and December 31, 2019, less the Cumulative G&A Adjuster, as defined in the Contribution Agreement.
The Deferred Payment calculation was designed to ensure that, during the deferral period, all of the EBITDA growth and capex development risk associated with the 2016 Drop Down Assets is held by the GP, Summit Investments. The Deferred Payment was structured such that SMLP will ultimately pay a 6.5x multiple of the actual average EBITDA generated from the 2016 Drop Down Assets in 2018 and 2019.
SMLP Financial Guidance
SMLP is reaffirming its 2018 adjusted EBITDA financial guidance range of $285.0 million to $300.0 million and capex guidance range, including contributions to equity method investees, of $175.0 million to $225.0 million. SMLP continues to expect to incur maintenance capex of $15.0 million to $20.0 million in 2018. SMLP expects to report an average full year 2018 distribution coverage ratio of approximately 1.00x.
SMLP is also introducing its preliminary view with respect to 2019 financial guidance, including targeted adjusted EBITDA growth of at least 10% over 2018. SMLP expects its 2019 distribution coverage ratio to expand generally in line with adjusted EBITDA growth throughout 2019 with targeted levels in excess of 1.15x by the fourth quarter of 2019.
Quarterly Distribution
On October 25, 2018, the board of directors of SMLP's general partner declared a quarterly cash distribution of $0.575 per unit on all of its outstanding common units, or $2.30 per unit on an annualized basis, for the quarter ended September 30, 2018. This quarterly distribution remains unchanged from the previous quarter and from the quarter ended September 30, 2017. This distribution will be paid on November 14, 2018, to unitholders of record as of the close of business on November 7, 2018.
Third Quarter 2018 Earnings Call Information
SMLP will host a conference call at 10:00 a.m. Eastern on Friday, November 9, 2018, to discuss its quarterly operating and financial results. Interested parties may participate in the call by dialing 847-585-4405 or toll-free 888-771-4371 and entering the passcode 47745266. The conference call will also be webcast live and can be accessed through the Investors section of SMLP's website at www.summitmidstream.com.
A replay of the conference call will be available until November 23, 2018, at 11:59 p.m. Eastern, and can be accessed by dialing 888-843-7419 and entering the replay passcode 47745266#. An archive of the conference call will also be available on SMLP's website.
Upcoming Investor Conferences
Members of SMLP's senior management team will participate in RBC Capital Markets' 2018 Midstream Conference in Dallas, Texas on November 13, 2018 and November 14, 2018, and in the Wells Fargo Pipeline, MLP and Utility Symposium in New York, New York on December 5, 2018 and December 6, 2018. The presentation materials associated with these events will be accessible through the Investors section of SMLP's website at www.summitmidstream.com prior to the beginning of each conference.
Use of Non-GAAP Financial Measures
We report financial results in accordance with U.S. generally accepted accounting principles ("GAAP"). We also present adjusted EBITDA and distributable cash flow, each a non-GAAP financial measure. We define adjusted EBITDA as net income or loss, plus interest expense, income tax expense, depreciation and amortization, our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, adjustments related to capital reimbursement activity, unit-based and noncash compensation, the change in the Deferred Purchase Price Obligation fair value, early extinguishment of debt expense, impairments and other noncash expenses or losses, less interest income, income tax benefit, income (loss) from equity method investees and other noncash income or gains. We define distributable cash flow as adjusted EBITDA plus cash interest received and cash taxes received, less cash interest paid, senior notes interest adjustment, distributions to Series A Preferred unitholders, Series A Preferred units distribution adjustment, cash taxes paid and maintenance capital expenditures. Because adjusted EBITDA and distributable cash flow may be defined differently by other entities in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other entities, thereby diminishing their utility.
Management uses these non-GAAP financial measures in making financial, operating and planning decisions and in evaluating our financial performance. Furthermore, management believes that these non-GAAP financial measures may provide external users of our financial statements, such as investors, commercial banks, research analysts and others, with additional meaningful comparisons between current results and results of prior periods as they are expected to be reflective of our core ongoing business.
Adjusted EBITDA and distributable cash flow are used as supplemental financial measures by external users of our financial statements such as investors, commercial banks, research analysts and others.
Adjusted EBITDA is used to assess:
-- the ability of our assets to generate cash sufficient to make cash
distributions and support our indebtedness;
-- the financial performance of our assets without regard to financing
methods, capital structure or historical cost basis;
-- our operating performance and return on capital as compared to those of
other entities in the midstream energy sector, without regard to
financing or capital structure;
-- the attractiveness of capital projects and acquisitions and the overall
rates of return on alternative investment opportunities; and
-- the financial performance of our assets without regard to (i) income or
loss from equity method investees, (ii) the impact of the timing of
minimum volume commitments shortfall payments under our gathering
agreements or (iii) the timing of impairments or other noncash income or
expense items.
Distributable cash flow is used to assess:
-- the ability of our assets to generate cash sufficient to make future
cash distributions and
-- the attractiveness of capital projects and acquisitions and the overall
rates of return on alternative investment opportunities.
Both of these measures have limitations as analytical tools and investors should not consider them in isolation or as a substitute for analysis of our results as reported under GAAP. For example:
-- certain items excluded from adjusted EBITDA and distributable cash flow
are significant components in understanding and assessing an entity's
financial performance, such as an entity's cost of capital and tax
structure;
-- adjusted EBITDA and distributable cash flow do not reflect our cash
expenditures or future requirements for capital expenditures or
contractual commitments;
-- adjusted EBITDA and distributable cash flow do not reflect changes in,
or cash requirements for, our working capital needs; and
-- although depreciation and amortization are noncash charges, the assets
being depreciated and amortized will often have to be replaced in the
future, and adjusted EBITDA and distributable cash flow do not reflect
any cash requirements for such replacements.
We compensate for the limitations of adjusted EBITDA and distributable cash flow as analytical tools by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process. Reconciliations of GAAP to non-GAAP financial measures are attached to this press release.
We do not provide the GAAP financial measures of net income or loss or net cash provided by operating activities on a forward-looking basis because we are unable to predict, without unreasonable effort, certain components thereof including, but not limited to, (i) income or loss from equity method investees, (ii) deferred purchase price obligation and (iii) asset impairments. These items are inherently uncertain and depend on various factors, many of which are beyond our control. As such, any associated estimate and its impact on our GAAP performance and cash flow measures could vary materially based on a variety of acceptable management assumptions.
About Summit Midstream Partners, LP
SMLP is a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. SMLP provides natural gas, crude oil and produced water gathering services pursuant to primarily long-term and fee-based gathering and processing agreements with customers and counterparties in five unconventional resource basins: (i) the Appalachian Basin, which includes the Marcellus and Utica shale formations in West Virginia and Ohio; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in North Dakota; (iii) the Fort Worth Basin, which includes the Barnett Shale formation in Texas; (iv) the Piceance Basin, which includes the Mesaverde formation as well as the Mancos and Niobrara shale formations in Colorado and Utah; and (v) the Denver-Julesburg Basin, which includes the Niobrara and Codell shale formations in Colorado and Wyoming. SMLP is in the process of developing new gathering and processing infrastructure in a sixth basin, the Delaware Basin, in New Mexico. SMLP also owns substantially all of a 40% ownership interest in Ohio Gathering, which is developing natural gas gathering and condensate stabilization infrastructure in the Utica Shale in Ohio. SMLP is headquartered in The Woodlands, Texas, with regional corporate offices in Denver, Colorado, Atlanta, Georgia, Pittsburgh, Pennsylvania and Dallas, Texas.
About Summit Midstream Partners, LLC
Summit Midstream Partners, LLC ("Summit Investments") beneficially owns a 35.2% limited partner interest in SMLP and indirectly owns and controls the general partner of SMLP, Summit Midstream GP, LLC, which has sole responsibility for conducting the business and managing the operations of SMLP. Summit Investments is a privately held company controlled by Energy Capital Partners II, LLC, and certain of its affiliates. An affiliate of Energy Capital Partners II, LLC directly owns an 8.1% limited partner interest in SMLP.
Forward-Looking Statements
This press release includes certain statements concerning expectations for the future that are forward-looking within the meaning of the federal securities laws. Forward-looking statements contain known and unknown risks and uncertainties (many of which are difficult to predict and beyond management's control) that may cause SMLP's actual results in future periods to differ materially from anticipated or projected results. An extensive list of specific material risks and uncertainties affecting SMLP is contained in its 2017 Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 26, 2018, and as amended and updated from time to time. Any forward-looking statements in this press release, including forward-looking statements regarding preliminary 2019 financial guidance or financial or operating expectations for 2019, are made as of the date of this press release and SMLP undertakes no obligation to update or revise any forward-looking statements to reflect new information or events.
We do not provide the GAAP financial measures of net income or loss or net cash provided by operating activities on a forward-looking basis because we are unable to predict, without unreasonable effort, certain components thereof including, but not limited to, (i) income or loss from equity method investees, (ii) deferred purchase price obligation and (iii) asset impairments. These items are inherently uncertain and depend on various factors, many of which are beyond our control. As such, any associated estimate and its impact on our GAAP performance and cash flow measures could vary materially based on a variety of acceptable management assumptions.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
September December
30, 31,
2018 2017
(In thousands)
Assets
Current assets:
Cash and cash equivalents $
370 $
1,430
Accounts receivable 85,458 72,301
Other current assets 4,360 4,327
Total current assets 90,188 78,058
Property, plant and equipment,
net 1,911,630 1,795,129
Intangible assets, net 281,207 301,345
Goodwill 16,211 16,211
Investment in equity method
investees 660,254 690,485
Other noncurrent assets 18,566 13,565
Total assets $
2,978,056 $
2,894,793
Liabilities and Partners'
Capital
Current liabilities:
Trade accounts payable $
22,569 $
16,375
Accrued expenses 18,347 12,499
Due to affiliate 13 1,088
Deferred revenue 11,152 4,000
Ad valorem taxes payable 8,223 8,329
Accrued interest 15,285 12,310
Accrued environmental
remediation 2,702 3,130
Other current liabilities 10,388 11,258
Total current liabilities 88,679 68,989
Long-term debt 1,175,313 1,051,192
Deferred Purchase Price
Obligation 416,718 362,959
Noncurrent deferred revenue 39,624 12,707
Noncurrent accrued
environmental remediation 1,182 2,214
Other noncurrent liabilities 5,525 7,063
Total liabilities 1,727,041 1,505,124
Series A Preferred Units 300,741 294,426
Common limited partner capital 913,913 1,056,510
General Partner interests 25,380 27,920
Noncontrolling interest 10,981 10,813
Total partners' capital 1,251,015 1,389,669
Total liabilities and
partners' capital $
2,978,056 $
2,894,793
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Nine
months months
ended September ended September
30, 30,
2018 2017 2018 2017
(In thousands, except per-unit amounts)
Revenues:
Gathering services and related
fees $
86,427 $
96,070 $
260,373 $
298,884
Natural gas, NGLs and condensate
sales 34,017 22,940 92,025 44,655
Other revenues 7,035 5,935 20,584 19,003
Total revenues 127,479 124,945 372,982 362,542
Costs and expenses:
Cost of natural gas and NGLs 26,879 18,177 71,549 36,328
Operation and maintenance 24,382 22,303 73,452 70,011
General and administrative 11,740 13,289 39,666 40,370
Depreciation and amortization 26,743 28,927 80,204 86,184
Transaction costs 119
Loss (gain) on asset sales, net 6 460 (6) 530
Long-lived asset impairment 1,540 1,290 2,127 1,577
Total costs and expenses 91,290 84,446 266,992 235,119
Other income 58 79 78 214
Interest expense (14,862) (17,614) (44,821) (51,883)
Early extinguishment of debt (22,020)
Deferred Purchase Price Obligation 37,204 70,499 (53,759) 54,674
Income before income taxes and
(loss)
income from
equity method investees 58,589 93,463 7,488 108,408
Income tax benefit (expense) 35 (176) (88) (417)
(Loss) income from equity method
investees (1,169) 350 (3,703) (3,691)
Net income $
57,455 $
93,637 $
3,697 $
104,300
Earnings (loss) per limited
partner unit:
Common unit - basic $
0.64 $
1.23 $
(0.33) $
1.32
Common unit - diluted $
0.64 $
1.22 $
(0.33) $
1.31
Weighted-average limited partner
units outstanding:
Common units - basic 73,356 73,059 73,283 72,583
Common units - diluted 73,756 73,433 73,283 72,901
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED OTHER FINANCIAL AND OPERATING DATA
Three Nine
months months
ended September ended September
30,
30,
2018 2017 2018 2017
(Dollars in thousands)
Other financial data:
Net income $
57,455 $
93,637 $
3,697 $
104,300
Net cash provided
by operating
activities $
56,443 $
75,156 $
166,492 $
196,497
Capital
expenditures $
46,639 $
40,294 $
137,033 $
86,206
Contributions to
equity method
investees
$ $
5,932
$ $
21,581
Adjusted EBITDA $
73,416 $
73,477 $
217,220 $
217,464
Distributable cash
flow $
43,629 $
52,877 $
134,941 $
155,837
Distributions
declared (1) $
45,216 $
45,037 $
135,648 $
134,651
Distribution
coverage ratio
(2) 0.96x 1.17x 0.99x 1.16x
Operating data:
Aggregate average daily
throughput - natural gas
(MMcf/d) 1,629 1,826 1,720 1,744
Aggregate average daily
throughput - liquids
(Mbbl/d) 96.9 74.0 90.9 74.7
Ohio Gathering average
daily throughput (MMcf/d)
(3) 797 763 765 746
(1) Represents distributions
declared to common unitholders
in respect of a given period.
For example, for the three
months ended September 30,
2018, represents the
distributions to be paid in
November 2018.
(2) Distribution coverage ratio
calculation for the three
months ended September 30,
2018 and 2017 is based on
distributions declared to
common unitholders in respect
of the third quarter of 2018
and 2017. Represents the ratio
of distributable cash flow to
distributions declared.
(3) Gross basis, represents
100% of volume throughput for
Ohio Gathering, based on a
one-month lag.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED RECONCILIATION OF REPORTABLE SEGMENT ADJUSTED EBITDA
TO ADJUSTED EBITDA
Three Nine
months months
ended September ended September
30,
30,
2018 2017 2018 2017
(In thousands)
Reportable segment
adjusted EBITDA (1):
Utica Shale $
6,521 $
8,412 $
24,459 $
25,857
Ohio Gathering (2) 10,171 10,522 29,583 29,201
Williston Basin 19,849 16,212 54,849 51,176
Piceance/DJ Basins 29,831 30,008 86,739 86,256
Barnett Shale 10,818 10,838 31,770 35,924
Marcellus Shale 5,550 6,682 18,769 17,775
Total $
82,740 $
82,674 $
246,169 $
246,189
Less Corporate and Other
(3) 9,324 9,197 28,949 28,725
Adjusted EBITDA $
73,416 $
73,477 $
217,220 $
217,464
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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
Three Nine
months months
ended September ended September
30, 30,
2018 2017 2018 2017
(In thousands)
Reconciliations of net income or loss
to adjusted
EBITDA and distributable cash
flow:
Net income $
57,455 $
93,637 $
3,697 $
104,300
Add:
Interest expense 14,862 17,614 44,821 51,883
Income tax (benefit) expense (35) 176 88 417
Depreciation and amortization (1) 26,592 28,777 79,752 85,732
Proportional adjusted EBITDA for equity
method
investees (2) 10,171 10,522 29,583 29,201
Adjustments related to MVC shortfall
payments (3) (2,999) (10,124) (6,541) (33,186)
Adjustments related to capital
reimbursement activity (4) (106) 49
Unit-based and noncash compensation 1,965 1,974 6,188 5,973
Deferred Purchase Price Obligation (5) (37,204) (70,499) 53,759 (54,674)
Early extinguishment of debt (6) 22,020
Loss (gain) on asset sales, net 6 460 (6) 530
Long-lived asset impairment 1,540 1,290 2,127 1,577
Income (loss) from equity method
investees 1,169 (350) 3,703 3,691
Adjusted EBITDA $
73,416 $
73,477 $
217,220 $
217,464
Less:
Cash interest paid 13,164 14,028 44,126 47,410
Cash paid for taxes 175
Senior notes interest adjustment (7) 3,063 3,063 3,063 2,594
Distributions to Series A Preferred
unitholders (8) 14,250
Series A Preferred units distribution
adjustment (9) 7,125 7,125
Maintenance capital expenditures 6,435 3,509 13,540 11,623
Distributable cash flow $
43,629 $
52,877 $
134,941 $
155,837
Distributions declared (10) $
45,216 $
45,037 $
135,648 $
134,651
Distribution coverage ratio (11) 0.96x 1.17x 0.99x 1.16x
(1) Includes the amortization expense
associated with our favorable and
unfavorable gas gathering contracts
as reported in other revenues.
(2) Reflects our proportionate share
of Ohio Gathering adjusted EBITDA,
based on a one-month lag.
(3) Adjustments related to MVC
shortfall payments for the three and
nine months ended September 30, 2017
account for (i) the net increases or
decreases in deferred revenue for
MVC shortfall payments and (ii) our
inclusion of expected annual MVC
shortfall payments. For the three
and nine months ended September 30,
2018, adjustments related to MVC
shortfall payments are recognized in
(4) Adjustments related to capital
reimbursement activity represent
contributions in aid of construction
revenue recognized in accordance
with Accounting Standards Update No.
2014-09 Revenue from Contracts with
Customers ("Topic 606").
(5) Deferred Purchase Price
Obligation represents the change in
the present value of the Deferred
Purchase Price Obligation.
(6) Early extinguishment of debt
includes $17.9 million paid for
redemption and call premiums, as
well as $4.1 million of unamortized
debt issuance costs which were
written off in connection with the
repurchase of the outstanding $300.0
million 7.5% Senior Notes in the
first quarter of 2017.
(7) Senior notes interest adjustment
represents the net of interest
expense accrued and paid during the
period. Interest on the $300.0
million 5.5% senior notes is paid in
cash semi-annually in arrears on
February 15 and August 15 until
maturity in August 2022. Interest
on the $500.0 million 5.75% senior
notes is paid in cash semi-annually
in arrears on April 15 and October
(8) Distributions on the Series A
preferred units are paid in cash
semi-annually in arrears on June 15
and December 15 each year, through
and including December 15, 2022,
and, thereafter, quarterly in
arrears on the 15th day of March,
June, September and December of each
year.
(9) Series A Preferred unit
distribution adjustment represents
the net of distributions paid and
accrued on the Series A Preferred
units.
(10) Represents distributions
declared to common unitholders in
respect of a given period. For
example, for the three months ended
September 30, 2018, represents the
distributions to be paid in November
2018.
(11) Distribution coverage ratio
calculation for the three months
ended September 30, 2018 and 2017 is
based on distributions declared in
respect of the third quarter of 2018
and 2017. Represents the ratio of
distributable cash flow to
distributions declared.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
Nine
months
ended September
30,
2018 2017
(In thousands)
Reconciliation of net cash provided
by operating activities to
adjusted
EBITDA and distributable
cash flow:
Net cash provided by operating
activities $
166,492 $
196,497
Add:
Interest expense, excluding
amortization of debt issuance costs 41,637 48,766
Income tax expense 88 417
Changes in operating assets and
liabilities 12,440 4,786
Proportional adjusted EBITDA for
equity method investees (1) 29,583 29,201
Adjustments related to MVC shortfall
payments (2) (6,541) (33,186)
Adjustments related to capital
reimbursement activity (3) 49
Less:
Distributions from equity method
investees 26,528 28,715
Write-off of debt issuance costs 302
Adjusted EBITDA $
217,220 $
217,464
Less:
Cash interest paid 44,126 47,410
Cash paid for taxes 175
Senior notes interest adjustment (4) 3,063 2,594
Distributions to Series A Preferred
unitholders (5) 14,250
Series A Preferred units
distribution adjustment (6) 7,125
Maintenance capital expenditures 13,540 11,623
Distributable cash flow $
134,941 $
155,837
(1) Reflects our proportionate share
of Ohio Gathering adjusted EBITDA,
based on a one-month lag.
(2) Adjustments related to MVC
shortfall payments for the nine
months ended September 30, 2017
account for (i) the net increases or
decreases in deferred revenue for
MVC shortfall payments and (ii) our
inclusion of expected annual MVC
shortfall payments. For the nine
months ended September 30, 2018,
adjustments related to MVC shortfall
payments are recognized in gathering
(3) Adjustments related to capital
reimbursement activity represent
contributions in aid of construction
revenue recognized in accordance
with Accounting Standards Update No.
2014-09 Revenue from Contracts with
Customers ("Topic 606").
(4) Senior notes interest adjustment
represents the net of interest
expense accrued and paid during the
period. Interest on the $300.0
million 5.5% senior notes is paid in
cash semi-annually in arrears on
February 15 and August 15 until
maturity in August 2022. Interest
on the $500.0 million 5.75% senior
notes is paid in cash semi-annually
in arrears on April 15 and October
(5) Distributions on the Series A
Preferred units are paid in cash
semi-annually in arrears on June 15
and December 15 each year, through
and including December 15, 2022,
and, thereafter, quarterly in
arrears on the 15th day of March,
June, September and December of each
year.
(6) Series A Preferred unit
distribution adjustment represents
the net of distributions paid and
accrued on the Series A Preferred
units.
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SOURCE Summit Midstream Partners, LP
