Press Release

HOUSTON, Aug. 9, 2023 /PRNewswire/ -- Summit Midstream Partners, LP (NYSE: SMLP) ("Summit", "SMLP" or the "Partnership") announced today its financial and operating results for the three months ended June 30, 2023.

Highlights

• Second quarter 2023 net loss of $13.5 million, adjusted EBITDA of $58.6 million, cash flow available for distributions ("Distributable Cash Flow" or "DCF") of $24.4 million and free cash flow ("FCF") of $9.1 million
• Connected 89 wells during the quarter, bringing total wells connected during the first half of 2023 to 150 versus original planned level of approximately 200
• Turned in-line 45 wells after quarter-end and continue to expect approximately 300 well connects in 2023
• Expect third and fourth quarter Adjusted EBITDA to range from $65 million to $75 million and $75 million to $85 million, respectively
• Updating 2023 Adjusted EBITDA guidance to $260 million to $280 million to reflect completion delays trending one to two quarters behind schedule and lower-than-expected commodity price impacts
• Customer base remains active with 11 drilling rigs and more than 180 DUCs behind our systems currently
• Trending towards $300 million of LTM Adjusted EBITDA during the first half of 2024

Management Commentary

Heath Deneke, President, Chief Executive Officer, and Chairman, commented, "Summit's second quarter 2023 financial and operating results were below management expectations, primarily due to temporary production shut-ins behind our Barnett system, completion delays in the Williston and Utica, and lower than expected commodity prices. Despite these headwinds, we had a very active quarter, connecting 89 wells, including 26 in the Northeast, 4 in the Barnett, 15 in the Piceance, 38 in the DJ that we expect will reach peak production in the fourth quarter, and 6 in the Williston. Our Northeast segment experienced 15% volume growth, driving segment adjusted EBITDA growth of $2.4 million, or 13% for the quarter. The Rockies segment fell behind quarterly expectations due to 30 wells that were delayed to the second half of the year. NGL prices and residue gas prices were very challenged in the second quarter, approximately 25% to 35% lower than our expectations. We believe this decline incentivized producers to delay completions a few months, shut-in approximately 25 MMcf/d of Barnett production, and directly impacted our percent-of-proceeds contracts in the DJ Basin. We expect the second quarter to be the low point for commodity prices, with strip NGL and natural gas prices projected to strengthen in the third and fourth quarter.

Overall, the total number of well connects we expected in 2023 remains relatively consistent at approximately 300 for the year, however, the delay in completion timing will impact calendar year results. Subsequent to quarter-end, we connected 45 wells, including 28 in the Williston and 17 in the Utica, which will serve as a meaningful volumetric catalyst behind the Rockies and Northeast segments. We estimate that on average we are trending one to two quarters behind schedule, which results in a revised 2023 Adjusted EBITDA expectation of $260 million to $280 million. We expect third quarter and fourth quarter Adjusted EBITDA to range from $65 million to $75 million and  $75 million to $85 million, respectively. While the impact of well completion timing delays to calendar year results is disappointing, customer activity levels remain strong with 195 wells turned in-line to-date, and more than 180 drilled-but-uncompleted wells ("DUCs") and 11 rigs currently running behind our systems. With our third and fourth quarter outlook for 2023 and the latest cadence of customer activity expected in the first half of 2024, we expect to trend towards $300 million of LTM Adjusted EBITDA during the first half of 2024."

Business Highlights

SMLP's average daily natural gas throughput for its wholly owned operated systems increased by 22 MMcf/d to 1,207 MMcf/d, and liquids volumes decreased by 3 Mbbl/d to 71 Mbbl/d, relative to the first quarter of 2023. OGC natural gas throughput increased from 636 MMcf/d to 781 MMcf/d, a 23% increase quarter-over-quarter, and generated $9.5 million of adjusted EBITDA net to SMLP for the second quarter of 2023. Double E Pipeline gross volumes transported declined by 21 MMcf/d to 243 MMcf/d and generated $4.6 million of adjusted EBITDA, net to SMLP, for the second quarter of 2023.

Natural gas-price driven segments:

• Natural gas price-driven segments had combined quarterly segment adjusted EBITDA of $41.8 million, representing 7.6% sequential growth, and combined capital expenditures of $1.7 million in the second quarter of 2023.
• Northeast segment adjusted EBITDA totaled $20.2 million, an increase of $2.3 million from the first quarter 2023, primarily due to a 6.4% increase in volume on our wholly owned systems and a 23% increase in volume from our OGC joint venture. Two new wells were brought online behind our wholly owned SMU system, seven new wells behind our Mountaineer system, and 17 new wells were connected behind our OGC joint venture during the quarter. Segment volumes continued to be impacted by customers temporarily shutting-in producing wells as they completed new wells on the pad site ("frac-protect activities"). We estimate frac-protect activities impacted quarterly volume by approximately 35 MMcf/d on our wholly owned systems, and segment adjusted EBITDA by approximately $0.8 million. The approximately 50 MMcf/d of frac-protect activities behind our Ohio Joint Venture in the first quarter were largely all back online in the second quarter. Additionally, after quarter-end, we brought online an additional nine wells behind our wholly owned SMU system, including approximately 30 MMcf/d of the frac-protect activities in the second quarter, as well as eight wells behind our OGC joint venture, which we expect to lead to continued volume growth in the third quarter. There are currently three rigs running and 16 DUCs behind our systems.
• Piceance segment adjusted EBITDA totaled $14.4 million, an increase of $0.4 million from the first quarter of 2023, primarily due to a 3.5% increase in volume throughput from 15 wells brought online during the quarter, partially offset by natural production declines. There is currently one rig running and 24 DUCs behind the system. We are still expecting approximately 55 total wells to be connected behind the system in 2023.
• Barnett segment adjusted EBITDA totaled $7.3 million, an increase of $0.2 million relative to the first quarter of 2023, primarily due to approximately $1.8 million in other revenue recognized during the quarter, partially offset by an 8.5% decrease in volume throughput from shut-in volumes from our customers. We estimate approximately 25 MMcf/d from shut-ins in response to the decline commodity prices and approximately 5 MMcf/d from frac-protect activities negatively impacted segment adjusted EBITDA by approximately $1.8 million for the quarter. There were four wells connected to the system with one rig running and 24 DUCs behind the system.

Oil price-driven segments

• Oil price-driven segments generated $22.2 million of combined segment adjusted EBITDA in the second quarter of 2023 and had combined capital expenditures of $13.1 million.
• Permian segment adjusted EBITDA totaled $5.4 million, an increase of $0.3 million from the first quarter of 2023, primarily due to a $0.4 million increase in proportionate EBITDA from our Double E joint venture.
• Rockies segment adjusted EBITDA totaled $16.9 million, a decrease of $6.3 million relative to the first quarter of 2023, primarily due to a 4% decline in liquids volume throughput and an 8% decline in natural gas volume throughput and reduction in commodity prices. There were 44 new wells connected during the quarter, including 38 in the DJ Basin, which we expect to generate peak production in the fourth quarter, and six in the Williston Basin. Subsequent to quarter-end, we've connected an additional 28 wells in the Williston Basin. There are currently six rigs running and approximately 120 DUCs behind the systems.

Revised 2023 Guidance

Based on recently updated completion timing from our customers, we currently expect activity to be approximately one to two quarters delayed relative to the mid-point of our original expectations. We believe the unexpected reduction in commodity prices over the past several months has incentivized customers to delay completions and in the case of the Barnett segment, temporarily shut-in production. As a result, we now expect calendar year 2023 adjusted EBITDA of $260 million to $280 million. Despite delays, activity levels remain robust behind our systems, and we continue to expect the business to generate sequential quarterly adjusted EBITDA growth in third and fourth quarter of 2023. At current strip pricing, we expect third quarter 2023 Adjusted EBITDA to range from $65 million to $75 million and expect fourth quarter 2023 adjusted EBITDA to range from $75 million to $85 million. With our third and fourth quarter outlook for 2023 and the latest cadence of customer activity expected in the first half of 2024, we expect to trend towards $300 million of LTM Adjusted EBITDA during the first half of 2024. We continue to expect to turn-in-line approximately 300 wells in 2023 and capital expenditures to trend toward the midpoint of our original $45 million to $65 million range for the year.

The following are the primary drivers of the shift in timing:

• Barnett Shale: One of our customers temporarily shut-in approximately 25 MMcf/d of natural gas in response to significantly lower natural gas price outlook in 2023 versus future expected prices in late 2023 and 2024. In addition, our anchor customer decided to increase the number of wells being drilled on a particular pad site from five wells to 11 wells. While this is a positive development, it has extended drilling and completion timing and delayed turn-in-line until 2024. We now only expect 10 wells to be turned-in-line in calendar year 2023 and expect to end the year with over 20 DUCs. We estimate the adjusted EBITDA impact of these revisions to calendar year 2023 results to be approximately $15 million relative to the mid-point of our original guidance range.
• Rockies Segment: Customers have been delayed one to two quarters on completion timing, with approximately 15 wells in the Williston Basin, including four wells that Summit provides crude oil and produced water gathering services, until the end of 2023 or early 2024. These 15 wells, all of which have been drilled since March 2023, were originally expected to turn-in-line in the second quarter. Despite the delays, we connected 28 new Williston wells in July that we expect will increase liquids volumes beginning in the third quarter of 2023. Crude oil, natural gas and NGL prices have trended well below our original expectations, which impacted year-to-date DJ Basin margins by approximately $2.0 million. We estimate the adjusted EBITDA impact of the timing delays and lower commodity prices on calendar year 2023 results to be approximately $15 million relative to the mid-point of our original guidance range.
• Northeast Segment: We have experienced approximately one quarter delay in well connects in the Northeast. However, the wells that have turned-in-line have been outperforming our expectations, which is mitigating the impact of the delays. We connected 26 wells behind the system during the second quarter and another 17 subsequent to quarter-end. The incremental wells and continued better than expected well performance are expected to lead to further volume and EBITDA growth through the end of 2023. Segment performance is expected to trend toward the low end of our original guidance range of $95 million to $105 million, or approximately $5 million below the mid-point.

The following table presents average daily throughput by reportable segment for the periods indicated:

The following table presents adjusted EBITDA by reportable segment for the periods indicated:

Capital Expenditures

Capital expenditures totaled $15.7 million in the second quarter of 2023, inclusive of maintenance capital expenditures of $2.1 million. Capital expenditures in the second quarter of 2023 were primarily related to pad connections and DJ Basin integration projects in the Rockies segment.

Capital & Liquidity

As of June 30, 2023, SMLP had $13.6 million in unrestricted cash-on-hand and $328 million drawn under its $400 million ABL Revolver and $67.7 million of borrowing availability, after accounting for $4.3 million of issued, but undrawn, letters of credit. As of June 30, 2023, SMLP's gross availability based on the borrowing base calculation in the credit agreement was $708 million, which is $308 million greater than the $400 million of lender commitments to the ABL Revolver. As of June 30, 2023, SMLP was in compliance with all financial covenants, including interest coverage of 2.14x relative to a minimum interest coverage covenant of 2.0x and first lien leverage ratio of 1.4x relative to a maximum first lien leverage ratio of 2.5x. As of June 30, 2023, SMLP reported a total leverage ratio of approximately 5.8x. We expect all leverage metrics to start trending lower beginning in the third quarter of 2023.

As of June 30, 2023, the Permian Transmission Credit Facility balance was $150.2 million, a reduction of $2.6 million relative to the March 31, 2023 balance of $152.8 million due to scheduled mandatory amortization. The Permian Transmission Term Loan remains non-recourse to SMLP.

MVC Shortfall Payments

SMLP billed its customers $7.2 million in the second quarter of 2023 related to MVC shortfalls. For those customers that do not have MVC shortfall credit banking mechanisms in their gathering agreements, the MVC shortfall payments are accounted for as gathering revenue in the period in which they are earned. In the second quarter of 2023, SMLP recognized $7.2 million of gathering revenue associated with MVC shortfall payments. SMLP had no adjustments to MVC shortfall payments in the second quarter of 2023. SMLP's MVC shortfall payment mechanisms contributed $7.2 million of total adjusted EBITDA in the second quarter of 2023.

 

Quarterly Distribution 

The board of directors of SMLP's general partner continued to suspend cash distributions payable on its common units and on its Series A fixed-to-floating rate cumulative redeemable perpetual preferred units (the "Series A Preferred Units") for the period ended June 30, 2023. Unpaid distributions on the Series A Preferred Units will continue to accumulate.

Second Quarter 2023 Earnings Call Information

SMLP will host a conference call at 10:00 a.m. Eastern on August 10, 2023, to discuss its quarterly operating and financial results. The call can be accessed via teleconference at: Q2 2023 Summit Midstream Partners LP Earnings Conference Call (https://register.vevent.com/register/BI44389e5d1dac4661818d5e27cc079001). Once registration is completed, participants will receive a dial-in number along with a personalized PIN to access the call. While not required, it is recommended that participants join 10 minutes prior to the event start. The conference call, live webcast and archive of the call can be accessed through the Investors section of SMLP's website at www.summitmidstream.com.

Upcoming Investor Conference

Members of SMLP's senior management team will attend the 2023 Citi One-on-One Midstream / Energy Infrastructure Conference taking place on August 22–23, 2023. The presentation materials associated with this event will be accessible through the Investors section of SMLP's website at www.summitmidstream.com prior to the beginning of the 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, Distributable Cash Flow, and Free Cash Flow, non-GAAP financial measures.

Adjusted EBITDA

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, impairments, items of income or loss that we characterize as unrepresentative of our ongoing operations and other noncash expenses or losses, income tax benefit, income (loss) from equity method investees and other noncash income or gains. Because adjusted EBITDA may be defined differently by other entities in our industry, our definition of this non-GAAP financial measure may not be comparable to similarly titled measures of other entities, thereby diminishing its utility.

Management uses adjusted EBITDA in making financial, operating and planning decisions and in evaluating our financial performance. Furthermore, management believes that adjusted EBITDA 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 is used as a supplemental financial measure to assess:

• the ability of our assets to generate cash sufficient to make future potential 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 MVC shortfall payments under our gathering agreements or (iii) the timing of impairments or other income or expense items that we characterize as unrepresentative of our ongoing operations.

Adjusted EBITDA has limitations as an analytical tool and investors should not consider it in isolation or as a substitute for analysis of our results as reported under GAAP. For example:

• certain items excluded from adjusted EBITDA 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 does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
• adjusted EBITDA does 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 does not reflect any cash requirements for such replacements.

We compensate for the limitations of adjusted EBITDA as an analytical tool by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.

Distributable Cash Flow

We define Distributable Cash Flow as adjusted EBITDA, as defined above, less cash interest paid, cash paid for taxes, net interest expense accrued and paid on the senior notes, and maintenance capital expenditures.

Free Cash Flow

We define free cash flow as distributable cash flow attributable to common and preferred unitholders less growth capital expenditures, less investments in equity method investees, less distributions to common and preferred unitholders. Free cash flow excludes proceeds from asset sales and cash consideration paid for acquisitions. 

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 and (ii) 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 value-driven 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, processing and transportation services pursuant to primarily long-term, fee-based agreements with customers and counterparties in five unconventional resource basins: (i) the Appalachian Basin, which includes the Utica and Marcellus shale formations in Ohio and West Virginia; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in North Dakota; (iii) the Denver-Julesburg Basin, which includes the Niobrara and Codell shale formations in Colorado and Wyoming; (iv) the Fort Worth Basin, which includes the Barnett Shale formation in Texas; and (v) the Piceance Basin, which includes the Mesaverde formation as well as the Mancos and Niobrara shale formations in Colorado. SMLP has an equity method investment in Double E Pipeline, LLC, which provides interstate natural gas transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. SMLP also has an equity method investment in Ohio Gathering, which operates extensive natural gas gathering and condensate stabilization infrastructure in the Utica Shale in Ohio. SMLP is headquartered in Houston, Texas.

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 include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words "expect," "intend," "plan," "anticipate," "estimate," "believe," "will be," "will continue," "will likely result," and similar expressions, or future conditional verbs such as "may," "will," "should," "would," and "could", including the estimated closing date of the acquisitions, sources and uses of funding, the benefits of the acquisitions to us and any related opportunities. In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies and possible actions taken by us or our subsidiaries are also forward-looking statements. Forward-looking statements also 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 2022 Annual Report on Form 10-K filed with the Securities and Exchange Commission (the "SEC") on March 1, 2023, as amended and updated from time to time. Any forward-looking statements in this press release 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.

 

 

 

 

 

 

View original content to download multimedia:https://www.prnewswire.com/news-releases/summit-midstream-partners-lp-reports-second-quarter-2023-financial-and-operating-results-301897223.html

SOURCE Summit Midstream Partners, LP

832-413-4770, ir@summitmidstream.com