從 Outrigger Energy II LLC 收購 Outrigger DJ Midstream LLC，以及從 Sterling Investment Holdings LLC 收購 Sterling Energy Investments LLC、Grasslands Energy Marketing LLC 和 Centennial Water Pipelines LLC
貸款和安防-半導體協議，日期爲2021年11月2日，由summit holdings作爲借款人，SMLP及其不時成爲當事方的某些子公司作爲擔保人，美國銀行N.A.作爲代理人，ING Capital LLC，加拿大皇家銀行和Regions Bank作爲共同承銷代理，以及美國銀行N.A.，ING Capital LLC，RBC Capital Markets和Regions Capital Markets作爲聯合主承銷商和聯合圖書管理人
ABL工具
由ABL協議管理的資產支持貸款信用額度
修訂和重述的ABL協議
修訂和重述的貸款和安防-半導體協議，日期爲2024年7月26日，借款人爲Summit Holdings，擔保人爲SMLP及不時爲此協議簽署的某些子公司，代理人爲美國銀行，聯合安排人和聯合簿記人爲美國銀行、加拿大皇家銀行、Regions Capital Markets、TD Securities (USA) LLC、摩根大通銀行、Citizens銀行和Truist銀行
修訂和重述的ABL融資
由修訂和重述的ABL協議管理的基於資產的貸款信用融資
ASC
會計準則編碼
會計準則更新
會計準則更新
每天十億立方英尺
每天十億立方英尺
董事會
summit midstream corp的董事會
合共發行人
summit holdings and finance corp，作爲2025年高級票據和2026年
a proven geological formation that contains commercial amounts of hydrocarbons
Permian Holdco
Summit Permian Transmission Holdco, LLC
Permian Term Loan Facility
the term loan governed by the Credit Agreement, dated as of March 8, 2021, among Summit Permian Transmission, LLC, as borrower, MUFG Bank Ltd., as administrative agent, Mizuho Bank (USA), as collateral agent, ING Capital LLC, Mizuho Bank, Ltd. and MUFG Union Bank, N.A., as L/C issuers, coordinating lead arrangers and joint bookrunners, and the lenders from time to time party thereto
Permian Transmission Credit Facilities
the credit facilities governed by the Credit Agreement, dated as of March 8, 2021, among Summit Permian Transmission, as borrower, MUFG Bank Ltd., as administrative agent, Mizuho Bank (USA), as collateral agent, ING Capital LLC, Mizuho Bank, Ltd. and MUFG Union Bank, N.A., as L/C issuers, coordinating lead arrangers and joint bookrunners, and the lenders from time to time party thereto
produced water
water from underground geologic formations that is a by-product of natural gas and crude oil production
SEC
Securities and Exchange Commission
Securities Act
Securities Act of 1933, as amended
segment adjusted EBITDA
total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit-based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains
Series A Preferred Stock
Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock issued
by the Company
Series A Preferred Units
Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units issued by the Partnership
shortfall payment
the payment received from a counterparty when its volume throughput does not meet its MVC for the applicable period
SMC LTIP
Summit Midstream Corporation 2024 Long-Term Incentive Plan
SMLP
Summit Midstream Partners, LP
SMLP LTIP
SMLP 2022 Long-Term Incentive Plan
SOFR
Secured Overnight Financing Rate
Subsidiary Series A Preferred Units
Series A Fixed Rate Cumulative Redeemable Preferred Units issued by Permian Holdco
the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, dated May 28, 2020
the Transaction
the consummation of the transaction contemplated by Tall Oak Business Combination Agreement between Summit Midstream Corporation, Summit Midstream Partners, LP and Tall Oak Midstream Holdings, LLC
throughput volume
the volume of natural gas, crude oil or produced water gathered, transported or passing through a pipeline, plant or other facility during a particular period; also referred to as volume throughput
unconventional resource basin
a basin where natural gas or crude oil production is developed from unconventional sources that require hydraulic fracturing as part of the completion process, for instance, natural gas produced from shale formations and coalbeds; also referred to as an unconventional resource play
wellhead
the equipment at the surface of a well, used to control the well’s pressure; also, the point at which the hydrocarbons and water exit the ground
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION, BUSINESS OPERATIONS, CORPORATE REORGANIZATION AND PRESENTATION AND CONSOLIDATION
Organization. Summit Midstream Partners, LP (“SMLP” or the “Partnership”) was formed in May 2012 and prior to August 1, 2024, the Partnership’s common units were listed on NYSE under the ticker symbol “SMLP.” The Partnership reorganized from a Delaware limited partnership to a Delaware corporation (the “Corporate Reorganization”) named Summit Midstream Corporation (including its subsidiaries, collectively “SMC” or the “Company”) effective as of August 1, 2024.
Summit Midstream Corporation is a Delaware corporation that was incorporated in May 2024 and as of August 1, 2024, the Company’s common stock, par value $0.01 per share (the “common stock”), is listed on NYSE under the ticker symbol “SMC.” SMC is a value-oriented company focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States. The Company’s business activities are primarily conducted through various operating subsidiaries, each of which is owned or controlled by its wholly owned subsidiary holding company, Summit Holdings, a Delaware limited liability company.
Business Operations. The Company provides natural gas gathering, compression, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term, fee-based agreements with its customers. In addition to these services, the Company also provides freshwater delivery services pursuant to short-term agreements with customers. The Company’s results are primarily driven by the volumes of natural gas that it transports, gathers, compresses, treats and/or processes as well as by the volumes of crude oil and produced water that it gathers. As of September 30, 2024, other than the Company’s investment in Double E, all of its business activities are conducted through wholly owned operating subsidiaries.
Corporate Reorganization. In connection with the Corporate Reorganization, the Partnership entered into an Agreement and Plan of Merger (the “Merger Agreement”), by and among the Partnership, the Company, Summit SMC NewCo, LLC (“Merger Sub”), a wholly owned subsidiary of the Company, and the General Partner. Pursuant to the Merger Agreement, Merger Sub merged with and into the Partnership (the “Merger”), with the Partnership continuing as the surviving entity and a wholly owned subsidiary of the Company, with (i) each then outstanding common unit representing limited partner interests in the Partnership automatically converting into the right to receive one share of the Company’s common stock and (ii) each then outstanding Series A Preferred Unit automatically converting into the right to receive one share of Series A Preferred Stock. The Merger was accounted for as a common-control transaction between the Partnership and Summit Midstream Corporation as a result of the Partnership’s unitholders controlling both the Partnership and Summit Midstream Corporation before and after the Merger. Upon consummation of the Corporate Reorganization, Summit Midstream Corporation recognized (i) income tax expense in its unaudited condensed consolidated statements of operations for temporary differences that existed as of the date of the Corporate Reorganization, (ii) a tax benefit to equity due to changes in tax bases and liabilities and (iii) a net deferred tax liability in its unaudited condensed consolidated balance sheets. Upon completion of the Merger, the Partnership’s common limited partner capital accounts were eliminated and replaced with shares of common stock, paid in capital, and retained deficit. Additionally, the Series A Preferred Units were exchanged for an equivalent number of shares of Series A Preferred Stock, with no substantive changes in contractual terms or investor cash flows.
As a result of the Corporate Reorganization, periods prior to August 1, 2024 reflect Summit Midstream as a limited partnership, not a corporation. References to common units for periods prior to the Corporate Reorganization refer to common units of SMLP, and references to common stock for periods following the Corporate Reorganization refer to shares of common stock of SMC. The primary financial impacts of the Corporate Reorganization to the consolidated financial statements were (i) reclassification of the partnership capital accounts to equity accounts reflective of a corporation and (ii) income tax effects.
Presentation and Consolidation.The Company prepares its condensed consolidated financial statements in accordance with GAAP as established by the FASB and pursuant to the rules and regulations of the SEC pertaining to interim financial information. The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. These unaudited condensed consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and related notes that are included in the SMLP’s Annual Report on Form 10-K for the year ended December 31, 2023 (the “2023 Annual Report”).
The Company makes estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenues and expenses and the disclosure of commitments and contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.
The unaudited condensed consolidated financial statements include the assets, liabilities and results of operations of SMC. All intercompany transactions among the consolidated entities have been eliminated in consolidation. Comprehensive income or loss is the same as net income or loss for all periods presented.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND RECENTLY ISSUED ACCOUNTING STANDARDS APPLICABLE TO THE COMPANY
Income Taxes. Prior to the consummation of the Corporate Reorganization on August 1, 2024, SMLP was treated as a partnership for federal and state income tax purposes, in which the taxable income or loss generally was passed through to its unitholders. SMLP was subject to Texas margin tax. Therefore, for periods prior to the Corporate Reorganization, with the exception of the state of Texas, SMLP did not directly pay federal and state income taxes and no entity-level income tax provision was recognized other than for the effects of the Texas margin tax.
Effective upon the consummation of the Corporate Reorganization, SMC became subject to federal and state income taxes as a C-corporation. As such, it accounts for income taxes, as required, under ASC 740, Accounting for Income Taxes. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates applied to taxable income in the relevant years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income or loss in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2024, SMC did not have any uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
Accounting standards recently implemented. ASU No. 2020-06 Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815–40) (“ASU 2020-06”). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in GAAP. The ASU’s amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within those fiscal years. The provisions of ASU 2020-06 did not have a material impact on the Company’s condensed consolidated financial statements and disclosures.
New accounting standards not yet implemented. ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 enhances disclosures on reportable segments and provides additional detailed information about significant segment expenses. The guidance in ASU 2023-07 is effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. The Company continues to assess the impact of the new guidance, but does not expect the provisions of ASU 2023-07 will have a material impact on its consolidated financial statements and disclosures.
3. DIVESTITURES
Summit Utica Sale.On March 22, 2024, the Partnership completed the disposition of Summit Utica, LLC (“Summit Utica”) to a subsidiary of MPLX LP for a cash sale price of $625.0 million, subject to customary post-closing adjustments (the “Utica Sale”). Summit Utica was the owner of (i) approximately 36% of the issued and outstanding equity interests in OGC, (ii) approximately 38% of the issued and outstanding equity interests in OCC, together with OGC, Ohio Gathering and (iii) midstream assets located in the Utica Shale. Ohio Gathering was the owner of a natural gas gathering system and condensate stabilization facility located in Belmont and Monroe counties in the Utica Shale in southeastern Ohio.
During the quarterly period ended March 31, 2024, the Partnership recognized a total gain on the disposition of Summit Utica of $212.5 million based on total cash proceeds received of $625.0 million and net assets sold of $412.5 million. A portion of the cash proceeds was used to reduce amounts outstanding under the ABL Facility and pay the costs and expenses in connection with the Asset Sale Offer (as defined below; see Note 8 - Debt, for additional information) and are subject to final working capital adjustments.
The $625.0 million sale price did not discretely list values for OGC, OCC or the Partnership’s midstream assets located in the Utica Shale. Using fair value methods allowed by GAAP, the Partnership derived a preliminary fair value estimate for the disposed assets and then determined the appropriate gain recognition amount for each disposal to include in its unaudited condensed consolidated financial statements. The estimated fair values were determined utilizing a discounted cash flow technique based on estimated revenues, costs, capital expenditures and an appropriate discount rate. Given the unobservable nature of the inputs, the fair value measurement is deemed to use Level 3 inputs. These fair value estimates are preliminary, and
subject to change and such changes could be material. Based on these preliminary fair values, the Partnership recognized a gain on the disposition of the Utica midstream business of $85.6 million, which is recorded within gain on sale of business in the Company’s unaudited condensed consolidated statements of operations, and a gain of $126.3 million related to the disposition of Ohio Gathering, which is recorded within gain on sale of Ohio Gathering in the Company’s unaudited condensed consolidated statements of operations.
Mountaineer Midstream System. On May 1, 2024, the Partnership completed the sale of its Mountaineer Midstream system, to Antero Midstream LLC for a cash sale price of $70.0 million, subject to customary post-closing adjustments (the “Mountaineer Transaction”). Mountaineer Midstream was the owner of midstream assets located in the Marcellus Shale. Prior to closing the Mountaineer Transaction, the Partnership sold related compression assets located in the Marcellus Shale to a compression service provider for cash consideration of approximately $5 million in April 2024.
During the three months ended March 31, 2024, the Partnership recognized an impairment of $68.0 million in connection with the Mountaineer Transaction and the sale of compression assets based on their estimated fair value and net assets of approximately $143.0 million.
4. REVENUE
The following table presents estimated revenue, as of September 30, 2024, expected to be recognized during the remainder of 2024 and over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated MVC shortfall payments.
(In thousands)
2024
2025
2026
2027
2028
Thereafter
Gathering services and related fees
$
12,044
$
37,249
$
26,112
$
7,685
$
5,137
$
—
Revenue by category. In the following tables, revenue is disaggregated by geographic area and major products and services. For more detailed information about reportable segments, see Note 16 – Segment Information.
Details on the Company’s property, plant and equipment follow.
September 30, 2024
December 31, 2023
(In thousands)
Gathering and processing systems and related equipment
$
1,939,969
$
2,335,980
Construction in progress
38,707
56,064
Land and line fill
11,534
11,534
Other
63,542
65,029
Total
2,053,752
2,468,607
Less: accumulated depreciation
(702,994)
(770,022)
Property, plant and equipment, net
$
1,350,758
$
1,698,585
Depreciation expense and capitalized interest for the Company follow.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In thousands)
(In thousands)
Depreciation expense
$
19,977
$
23,926
$
63,905
$
70,130
Capitalized interest
257
351
904
790
6. EQUITY METHOD INVESTMENTS
As of September 30, 2024, the Company has an equity method investment in Double E, the balance of which is included in the Investment in equity method investees caption on the unaudited condensed consolidated balance sheets. On March 22, 2024, in connection with the Utica Sale, the Company sold its investment in Ohio Gathering and recognized an estimated $126.3 million gain, which is recorded within Gain on sale of Ohio Gathering within the unaudited condensed consolidated statements of operations. See Note 3 - Divestitures for additional information.
Details of the Company’s equity method investments follow.
September 30, 2024
December 31, 2023
(In thousands)
Double E
$
269,939
$
276,221
Ohio Gathering
—
210,213
Total
$
269,939
$
486,434
7. DEFERRED REVENUE
The balances in deferred revenue as of September 30, 2024 and December 31, 2023 are primarily related to contributions in aid of construction which will be recognized as revenue over the life of the contract. An update of current deferred revenue follows.
Total
(In thousands)
Current deferred revenue, December 31, 2023
$
10,196
Add: additions
6,159
Less: revenue recognized and other
(6,885)
Current deferred revenue, September 30, 2024
$
9,470
An update of noncurrent deferred revenue follows.
Total
(In thousands)
Noncurrent deferred revenue, December 31, 2023
$
30,085
Add: additions
3,436
Less: reclassification to current deferred revenue and other
Debt for the Company at September 30, 2024 and December 31, 2023, follows:
September 30, 2024
December 31, 2023
(In thousands)
Amended and Restated ABL Facility: Summit Holdings’ asset based credit facility due July 2029
$
150,000
$
313,000
Permian Transmission Term Loan: Summit Permian Transmission’s variable rate senior secured term loan due January 2028
133,291
144,846
2029 Secured Notes: 8.625% senior secured second lien notes due October 2029
575,000
—
2026 Unsecured Notes: 12.00% senior unsecured notes due October 2026
—
209,510
2025 Senior Notes: 5.75% senior unsecured notes due April 2025
—
49,783
2026 Secured Notes: 8.50% senior second lien notes due October 2026
114,659
785,000
Less: unamortized debt discount and debt issuance costs
(15,985)
(31,449)
Total debt, net of unamortized debt discount and debt issuance costs
956,965
1,470,690
Less: current portion of Permian Transmission Term Loan and 2026 Secured Notes
(130,512)
(15,524)
Total long-term debt
$
826,453
$
1,455,166
ABL Facility. Concurrently with the issuance of the 2029 Secured Notes, as discussed below, on July 26, 2024, Summit Holdings, as borrower, amended and restated its existing first-lien, senior secured credit agreement, with the Partnership, the subsidiaries party thereto, Bank of America, N.A., as agent, and the several lenders and other agents party thereto, consisting of a $500.0 million asset-based revolving credit facility (the “Amended and Restated ABL Facility”), subject to a borrowing base comprised of a percentage of eligible accounts receivable of Summit Holdings and its subsidiaries that guarantee the Amended and Restated ABL Facility (collectively, the “Amended and Restated ABL Facility Subsidiary Guarantors”) and a percentage of eligible above-ground fixed assets including eligible compression units, processing plants, compression stations and related equipment of Summit Holdings and the Amended and Restated ABL Facility Subsidiary Guarantors. As of September 30, 2024, the most recent borrowing base determination of eligible assets totaled $538.8 million, an amount greater than the $500.0 million of aggregate lending commitments.
Summit Holdings amended and restated its existing ABL Facility pursuant to that certain Amended and Restated Loan and Security Agreement (the “Amended and Restated ABL Agreement”), dated as of July 26, 2024.
The Amended and Restated ABL Facility will mature on the earliest of (a) July 26, 2029, (b) July 31, 2029 if either (i) the outstanding amount of the 2029 Secured Notes (or any refinancing debt permitted under the Amended and Restated ABL Facility in respect thereof that has a final maturity date, scheduled amortization or any other scheduled repayment, mandatory prepayment, mandatory redemption or sinking fund obligation prior to the date that is 91 days after the Amended and Restated ABL Termination Date (as defined below) (provided, that the terms of such permitted refinancing debt may (x) require the payment of interest from time to time and (y) include customary mandatory redemptions, prepayments or offers to purchase with proceeds of asset sales or upon the occurrence of a change of control)) on such date equals or exceeds $50.0 million or (ii) the outstanding amount of such debt described in clause (i) above on such date is less than $50.0 million and Liquidity (as defined in the Amended and Restated ABL Agreement) at any time on or after such date is less than the sum of (A) such outstanding amount and (B) the greater of (x) 10% of the aggregate Commitments (as defined in the Amended and Restated ABL Agreement) then in effect and (y) $50.0 million, and (c) any date on which the aggregate Commitments terminate thereunder (such date, the “Amended and Restated ABL Termination Date”). As of September 30, 2024, the Amended and Restated ABL Facility will mature on July 26, 2029.
Borrowings under the Amended and Restated ABL Facility will bear interest, at the election of Summit Holdings, at a SOFR-based rate or a base rate, in each case, plus an applicable borrowing margin based on our Total Net Leverage Ratio (as defined in the Amended and Restated ABL Agreement consistent with the Amended and Restated ABL Facility). The applicable margin for base rate loans will vary from 1.50% to 2.25% and the applicable margin for SOFR-based loans will vary from 2.50% to 3.25%, in each case, depending on our Total Net Leverage Ratio.
The Amended and Restated ABL Facility (together with certain Secured Bank Product Obligations (as defined in the Amended and Restated ABL Agreement)) will be jointly and severally guaranteed, on a senior first-priority secured basis (subject to permitted liens), by the Partnership, Summit Holdings and each of the Amended and Restated ABL Facility Subsidiary Guarantors.
The Amended and Restated ABL Facility restricts, among other things, Summit Holdings’ and its Restricted Subsidiaries’ (as defined in the Amended and Restated ABL Agreement) ability and the ability of certain of their subsidiaries to: (i) incur
additional debt or issue preferred stock; (ii) make distributions or repurchase equity; (iii) make payments on or redeem junior lien, unsecured or subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject both to a number of important exceptions and qualifications.
The Amended and Restated ABL Facility requires that Summit Holdings not permit (i) the First Lien Net Leverage Ratio (as defined in the Amended and Restated ABL Agreement) as of the last day of any fiscal quarter to be greater than 2.50:1.00, or (ii) the Interest Coverage Ratio (as defined in the Amended and Restated ABL Agreement) as of the last day of any fiscal quarter to be less than 2.00:1.00. As of September 30, 2024, the First Lien Net Leverage Ratio was 0.84:1.00 and the Interest Coverage Ratio was 2.42:1.00. As of September 30, 2024, the Company was in compliance with the financial covenants of the Amended and Restated ABL Facility.
The Amended and Restated ABL Facility contains certain events of default customary for instruments of this type. In the case of an event of default arising from certain events of bankruptcy, insolvency or reorganization with respect to Summit Holdings, all outstanding Obligations (as defined in the Amended and Restated ABL Agreement) will become due and payable immediately without further action or notice and all commitments under the Amended and Restated ABL Facility will terminate.
Pursuant to the Amended and Restated ABL Agreement, the Obligations (as defined in the Amended and Restated ABL Agreement) are generally secured by a first priority lien on and security interest in (subject to permitted liens), subject to certain exclusions and limitations set forth in the Amended and Restated ABL Agreement, (i) substantially all of the personal property of Summit Holdings and the Amended and Restated ABL Facility Subsidiary Guarantors, (ii) all equity interests in Summit Holdings and certain other entities, all debt securities and certain rights related to the foregoing, in each case, owned by the Partnership, (iii) Closing Date Gathering Station Real Property and Closing Date Pipeline Systems Real Property (each, as defined in the Amended and Restated ABL Agreement) and certain other material real property interests (including improvements thereon) of Summit Holdings and the Amended and Restated ABL Facility Subsidiary Guarantors as provided in the Amended and Restated ABL Agreement and (iv) all proceeds of the foregoing collateral.
As of September 30, 2024, the applicable margin under the adjusted SOFR borrowings was 2.750%, the interest rate was 7.70%, and the total available borrowing capacity totaled $349.2 million, after giving effect to the issuance of $0.8 million in outstanding but undrawn irrevocable standby letters of credit.
Intercreditor Agreement. On November 2, 2021, Summit Holdings and the other guarantors party thereto entered into an Intercreditor Agreement (as amended, restated, supplemented or otherwise modified, the “Intercreditor Agreement”) with Bank of America, N.A., as first lien representative and collateral agent for the initial first lien claimholders, and Regions Bank, as initial second lien representative for the initial second lien claimholders and collateral agent for the initial second lien claimholders, which was reaffirmed by Bank of America, N.A., in connection with its entry into the Amended and Restated ABL Facility, and which Regions Bank joined as an additional second lien representative for the additional second lien claimholders and additional second lien collateral agent for the additional second lien claimholders, in each case, substantially concurrently with the entry into the Amended and Restated ABL Facility. The Intercreditor Agreement establishes (i) a first-priority lien (subject to permitted liens) status for the liens on the collateral securing the ABL Facility (and will apply to the Amended and Restated ABL Facility) and any additional first-lien indebtedness and (ii) a junior priority lien (subject to permitted liens) status for the liens on the collateral securing the 2029 Secured Notes.
Permian Transmission Credit Facilities. On March 8, 2021, the Partnership’s unrestricted subsidiary, Summit Permian Transmission, entered into a Credit Agreement which allows for $175.0 million of senior secured credit facilities (the “Permian Transmission Credit Facilities”), including a $160.0 million Term Loan Facility and a $15.0 million working capital facility. The Permian Transmission Credit Facilities can be used to finance Summit Permian Transmission’s capital calls associated with its investment in Double E, debt service and other general corporate purposes. Unexpended proceeds from draws on the Permian Transmission Credit Facilities are classified as restricted cash on the accompanying unaudited condensed consolidated balance sheets.
As of September 30, 2024, the applicable margin under adjusted term SOFR borrowings was 2.475%, the average interest rate was 7.79% and the unused portion of the Permian Transmission Credit Facilities totaled $4.5 million, subject to a commitment fee of 0.7% after giving effect to the issuance of $10.5 million in outstanding but undrawn irrevocable standby letters of credit. Summit Permian Transmission entered into interest rate hedges with notional amounts representing approximately 90% of the Permian Term Loan Facility at a fixed SOFR rate of 1.23%. As of September 30, 2024, the Company was in compliance with the financial covenants of the Permian Transmission Credit Facilities.
Permian Transmission Term Loan. In accordance with the terms of the Permian Transmission Credit Facilities, in January 2022, the Permian Term Loan Facility was converted into a Term Loan (the “Permian Transmission Term Loan”). The Permian Transmission Term Loan is due January 2028. As of September 30, 2024, the applicable margin under adjusted term SOFR
borrowings was 2.475% and the average interest rate was 7.79%. As of September 30, 2024, the Company was in compliance with the financial covenants of the Permian Transmission Term Loan.
In accordance with the terms of the Permian Transmission Term Loan, Summit Permian Transmission is required to make mandatory principal repayments. Below is a summary of the remaining mandatory principal repayments as of September 30, 2024:
(In thousands)
Total
2024
2025
2026
2027
2028
Amortizing principal repayments
$
133,291
$
3,969
$
16,580
$
16,967
$
17,769
$
78,006
2029 Secured Notes. On July 26, 2024, Summit Holdings issued $575.0 million aggregate principal amount of 8.625% Senior Secured Second Lien Notes due 2029 (the “2029 Secured Notes”). The 2029 Secured Notes are guaranteed on a senior second-priority basis by Summit Midstream Corporation and certain of Summit Midstream Corporation’s existing and future subsidiaries and are secured on a second-priority basis by substantially the same collateral that is pledged for the benefit of the lenders under the Amended and Restated ABL Facility. The 2029 Secured Notes mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15, commencing on February 15, 2025.
At any time prior to July 31, 2026, Summit Holdings may on any one or more occasions redeem up to 40% of the aggregate principal amount of the 2029 Secured Notes at a redemption rate of 108.625% of the principal amount plus accrued and unpaid interest, if any, to, but not including, the redemption date, in an amount not greater than the net cash proceeds of one or more equity offerings. At any time before July 31, 2026, Summit Holdings may also redeem the 2029 Secured Notes, in whole or in part, at a price equal to 100% of their principal amount, plus a make-whole premium, together with accrued and unpaid interest to, but not including, the redemption date. Thereafter, Summit Holdings may redeem all or a portion of the 2029 Secured Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest if redeemed during the periods indicated below:
Period
Redemption Price
July 31, 2026 to July 30, 2027
104.313
%
July 31, 2027 to July 30, 2028
102.156
%
July 31, 2028 and thereafter
100.000
%
As of September 30, 2024, the Company was in compliance with the financial covenants of the 2029 Secured Notes.
2026 Secured Notes. In 2021, the Co-Issuers issued $700.0 million of 8.500% Senior Secured Second Lien Notes due 2026 to eligible purchasers pursuant to Rule 144A and Regulation S of the Securities Act, at a price of 98.5% of their face value. Additionally, in November 2022, in connection with the 2022 DJ Acquisitions, the Co-Issuers issued an additional $85.0 million of 2026 Secured Notes at a price of 99.26% of their face value. The Company paid interest on the 2026 Secured Notes semi-annually on April 15 and October 15 of each year.
2026 Secured Notes Tender Offers and Redemption. On March 27, 2024, the Co-Issuers commenced a cash tender offer to
purchase up to $19.3 million of the outstanding 2026 Secured Notes (the “Excess Cash Flow Offer”). The Excess Cash Flow
Offer expired on April 24, 2024 with $13.6 million of the 2026 Secured Notes tendered and validly accepted and fully
discharged.
On May 7, 2024, the Co-Issuers commenced a cash tender offer to purchase up to $215.0 million of the outstanding 2026 Secured Notes (the “Asset Sale Offer”). The Asset Sale Offer expired on June 5, 2024 with $6.9 million of the 2026 Secured Notes tendered and validly accepted and fully discharged.
On July 26, 2024, concurrently with closing the offering of 2029 Secured Notes, the Co-Issuers consummated a cash tender offer to purchase any and all of the outstanding 2026 Secured Notes (the “2026 Secured Notes Tender Offer”). The Co-Issuers accepted for payment and made payment for $649.8 million aggregate principal amount of the 2026 Secured Notes validly tendered in the 2026 Secured Notes Tender Offer. On July 26, 2024, concurrently with consummation of the 2026 Secured Notes Tender Offer, the Co-Issuers delivered a notice of redemption to holders of 2026 Secured Notes for the redemption of all $114.7 million aggregate principal amount of 2026 Secured Notes not purchased in the 2026 Secured Notes Tender Offer, at a price equal to 102.125% of the principal amount thereof, plus accrued and unpaid interest to the redemption date (which was October 15, 2024). On July 26, 2024, concurrently with delivery of the notice of redemption, the Co-Issuers irrevocably deposited $121.2 million in aggregate principal amount of non-callable United States Treasury securities, which included amounts for principal, interest, and premium with the trustee to satisfy and discharge the 2026 Secured Notes until redeemed on October 15, 2024 with the funds deposited with the trustee. On October 15, 2024, the 2026 Secured Notes were fully repaid, however as of September 30, 2024, $114.7 million aggregate principal amount of 2026 Secured Notes remained outstanding and classified under current portion of long term debt on the unaudited condensed consolidated balance sheet.
2026 Unsecured Notes. In November 2023, the Co-Issuers issued a total of $209.5 million aggregate principal amount of 2026 Unsecured Notes in exchange for $180.0 million aggregate principal amount of the 2025 Senior Notes and $29.5 million in cash. The cash raised was used to repurchase $29.7 million aggregate principal amount of the remaining 2025 Senior Notes that were not exchanged. The Partnership paid interest on the 2026 Unsecured Notes semi-annually in cash in arrears on April 15 and October 15 of each year.
On June 7, 2024, the Co-Issuers delivered a redemption notice with respect to all $209.5 million of the outstanding 2026 Unsecured Notes. On June 24, 2024, the 2026 Unsecured Notes were fully repaid and discharged. As of September 30, 2024, no amounts of the 2026 Unsecured Notes remained outstanding.
2025 Senior Notes. In February 2017, the Co-Issuers issued the 2025 Senior Notes. The Partnership paid interest on the 2025 Senior Notes semi-annually in cash in arrears on April 15 and October 15 of each year. The 2025 Senior Notes were senior, unsecured obligations and ranked equally in right of payment with all of the Partnership’s existing and future senior obligations. The 2025 Senior Notes were effectively subordinated to all of the Partnership’s secured indebtedness, to the extent of the collateral securing such indebtedness including indebtedness incurred under the ABL Facility and the 2026 Secured Notes.
The Co-Issuers had the right to redeem all or part of the 2025 Senior Notes at a redemption price of 100.00%, plus accrued and unpaid interest, if any, to, but not including the redemption date.
In November, 2023, the Partnership exchanged $180.0 million aggregate principal amount of the 2025 Senior Notes and repurchased $29.7 million aggregate principal amount of the remaining 2025 Senior Notes that were not exchanged.
On July 17, 2024, the Co-Issuers delivered a conditional notice of redemption to holders of 2025 Senior Notes for the redemption of all $49.8 million aggregate principal amount of outstanding 2025 Senior Notes, at a price equal to 100.000% of the principal amount thereof, plus accrued and unpaid interest to the redemption date, which was conditioned on the closing of the offering of 2029 Secured Notes. On July 26, 2024, concurrently with the closing of the offering of 2029 Secured Notes, the Co-Issuers irrevocably deposited $50.6 million in aggregate principal amount of non-callable United States Treasury securities, which included amounts for principal and interest with the trustee to satisfy and discharge the 2025 Senior Notes until redeemed with the funds deposited with the trustee. On August 16, 2024, the 2025 Senior Notes were fully repaid, and as of September 30, 2024, no amounts of the 2025 Senior Notes remained outstanding.
9. FINANCIAL INSTRUMENTS
Fair Value.A summary of the estimated fair value of our debt financial instruments follows.
September 30, 2024
December 31, 2023
Carrying
Value (1)
Estimated fair value (Level 2)
Carrying
Value (1)
Estimated fair value (Level 2)
(In thousands)
2025 Senior Notes
$
—
$
—
$
49,783
$
48,414
2026 Secured Notes (2)
$
114,659
$
114,659
$
785,000
$
778,131
2026 Unsecured Notes
$
—
$
—
$
209,510
$
203,225
2029 Secured Notes
$
575,000
$
596,323
$
—
$
—
(1) Excludes applicable unamortized debt issuance costs and debt discounts.
(2) Estimated fair value of the 2026 Secured Notes equaled carrying value as of September, 30, 2024, as notes were satisfied and discharged on July 26, 2024.
The carrying values on the balance sheets of the Amended and Restated ABL Facility and the Permian Transmission Term Loan represent their fair value due to their floating interest rates. The fair values of the 2029 Secured Notes, 2026 Unsecured Notes, 2026 Secured Notes and 2025 Senior Notes are based on an average of nonbinding broker quotes as of September 30, 2024 and December 31, 2023. The use of different market assumptions or valuation methodologies may have a material effect on their estimated fair value.
Deferred earn-out. The Company’s deferred earn-out liability was settled in full during the quarterly period ended June 30, 2024. As of December 31, 2023, the estimated fair value of the deferred earn-out liability was $5.1 million, and was estimated using a discounted cash flow technique based on estimated future freshwater deliveries and appropriate discount rates. Given the unobservable nature of the inputs, the fair value measurement of the deferred earn-out is deemed to use Level 3 inputs.
Interest Rate Swaps. In connection with the Permian Transmission Term Loan, the Partnership entered into amortizing interest rate swap agreements. As of September 30, 2024 and December 31, 2023, the outstanding notional amounts of interest rate swaps were $120.0 million and $130.4 million, respectively. These interest rate swaps manage exposure to variability in expected cash flows attributable to interest rate risk. Interest rate swaps convert a portion of the Company’s variable rate debt to fixed rate debt. The Company chooses counterparties for its derivative instruments that it believes are creditworthy at the time
the transactions are entered into, and the Company actively monitors the creditworthiness where applicable. However, there can be no assurance that a counterparty will be able to meet its obligations to the Company. The Company presents its derivative positions on a gross basis and does not net the asset and liability positions.
As of September 30, 2024 and December 31, 2023, the Company’s interest rate swap agreements had a fair value of $8.9 million and $11.9 million, respectively, and are recorded within other noncurrent assets within the unaudited condensed consolidated balance sheets. The derivative instruments’ fair value are determined using level 2 inputs from the fair value hierarchy.
For the three months ended September 30, 2024 and September 30, 2023, the Company recorded a loss on interest rate swaps of $2.6 million and a gain on interest rate swaps of $2.9 million, respectively.
For the nine months ended September 30, 2024 and September 30, 2023, the Company recorded a gain on interest rate swaps of $0.9 million and $4.9 million, respectively.
10. EQUITY AND MEZZANINE EQUITY
Common Stock. Upon the consummation of the Corporate Reorganization, each outstanding common unit of the Partnership was converted into the right to receive 1.000 shares of common stock of Summit Midstream Corporation. An update on the number of shares of common stock is as follows for the period from December 31, 2023 to September 30, 2024:
Common Units
Shares of Common Stock
Units, December 31, 2023
10,376,189
—
Common units issued for SMLP LTIP, net
272,496
—
Corporate Reorganization
(10,648,685)
10,648,685
Shares, September 30, 2024
—
10,648,685
Series A Preferred Stock. Upon the consummation of the Corporate Reorganization, each outstanding Series A Preferred Unit was converted into the right to receive 1.000 shares of Series A Preferred Stock of Summit Midstream Corporation, with the liquidation preference of each share of Series A Preferred Stock initially equal to $1,000 and the Certificate of Designation of Series A Floating Rate Cumulative Redeemable Perpetual Preferred Stock of Summit Midstream Corporation (the “Series A Certificate of Designation”) deeming all accumulated and unpaid distributions on the Series A Preferred Units to be Series A Unpaid Cash Dividends (as defined in the Series A Certificate of Designation) per share of Series A Preferred Stock, which constituted all consideration to be paid in respect to such Series A Preferred Units, and any rights to accumulated and unpaid distributions on such Series A Preferred Units were discharged. As of September 30, 2024, the Company had 65,508 shares of Series A Preferred Stock outstanding and $43.0 million of accrued and unpaid distributions on its Series A Preferred Stock.
An update on the number of shares of Series A Preferred Stock is as follows for the period from December 31, 2023 to September 30, 2024:
Series A Preferred Units
Series A Preferred Stock
Units, December 31, 2023
65,508
—
Corporate Reorganization
(65,508)
65,508
Shares, September 30, 2024
—
65,508
Subsidiary Series A Preferred Units. The Company records its Subsidiary Series A Preferred Units at fair value upon issuance, net of issuance costs, and subsequently records an effective interest method accretion amount each reporting period to accrete the carrying value to a most probable redemption value that is based on a predetermined internal rate of return measure. Net income (loss) attributable to common stockholders includes adjustments for payment-in-kind distributions and redemption accretion.
As of September 30, 2024, the Company had 93,039 Subsidiary Series A Preferred Units issued and outstanding.
If the Subsidiary Series A Preferred Units were redeemed on September 30, 2024, the redemption amount would be $130.6 million when considering the applicable multiple on invested capital metric and make-whole amount provisions contained in the Amended and Restated Limited Liability Company Agreement of Permian Holdco.
The following table shows the change in the Company’s Subsidiary Series A Preferred Unit balance from January 1, 2024 to September 30, 2024, net of $1.3 million and $1.7 million of unamortized issuance costs at September 30, 2024 and December 31, 2023, respectively:
(In thousands)
Balance at December 31, 2023
$
124,652
Redemption accretion, net of issuance cost amortization
11,643
Cash distribution (includes a $1.6 million distribution payable as of September 30, 2024)
(4,885)
Balance at September 30, 2024
$
131,410
Blank Check Common Stock. The Board of Directors is authorized to establish one or more series of Blank Check Common Stock (including convertible Blank Check Common Stock). The Board of Directors has the ability to determine, with respect to any series of Blank Check Common Stock, the powers, preferences and relative, participating, optional or other special rights, and the qualifications, limitations or restrictions thereof, including, without limitation (i) the designation of the series; (ii) the number of shares of the series, which the Board of Directors may, except where otherwise provided in the Blank Check Common Stock designation, increase (but not above the total number of authorized shares of the class) or decrease (but not below the number of shares then outstanding); (iii) whether dividends, if any, will be cumulative or non-cumulative and the dividend rate of the series; (iv) the dates at which dividends, if any, will be payable; (v) the redemption or repurchase rights and price or prices, if any, for shares of the series; (vi) the terms and amounts of any sinking fund provided for the purchase or redemption of shares of the series; (vii) the amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding-up of the Company’s affairs; (viii) whether the shares of the series will be convertible into shares of any other class or series, or any other security, of the Company or any other entity, and, if so, the specification of the other class or series or other security, the conversion price or prices or rate or rates, any rate adjustments, the date or dates as of which the shares will be convertible and all other terms and conditions upon which the conversion may be made; (ix) restrictions on the issuance of shares of the same series or of any other class or series; and (x) the voting rights, if any, of the holders of the series. As of September 30, 2024, no Blank Check Common Stock has been issued.
Cash Distribution Policy. In March 2020, the Partnership suspended cash distributions to holders of its common units and Series A Preferred Units, commencing with respect to the quarter ended March 31, 2020. Upon the resumption of distributions, the Partnership Agreement would have required that it distribute all available cash, subject to reserves established by its General Partner, within 45 days after the end of each quarter to unitholders of record on the applicable record date. The amount of distributions paid under this policy was subject to fluctuations based on the amount of cash the Partnership generated from its business and the decision to make any distribution was determined by the General Partner, taking into consideration the terms of the Partnership Agreement.
There were no distributions paid by the Company or the Partnership, as applicable, during the three and nine months ended September 30, 2024, or during the twelve months ended December 31, 2023. In connection with the consummation of the Corporate Reorganization, the Partnership Agreement was amended by the Fifth Amended and Restated Agreement of Limited Partnership to, among other things, reflect that all of the issued and outstanding limited partnership interests of the Partnership are held by the Company. For information on the Corporate Reorganization, see Note 1– Organization, Business Operations, Corporate Reorganization and Presentation and Consolidation.
SMLP Long-Term Incentive Plan. The Partnership’s 2022 Long-Term Incentive Plan, as amended by the First Amendment, effective as of March 16, 2022 (the “SMLP LTIP”) provided for equity awards to eligible officers, employees, consultants and directors of the Partnership, thereby linking the recipients’ compensation directly to SMLP’s performance. Significant items to note:
•For the nine-month period ended September 30, 2024, the Partnership granted 230,815 time-based phantom units and associated distribution equivalent rights to employees in connection with the Partnership’s annual incentive compensation award cycle. The grant date fair value of these awards totaled $3.7 million and the awards vest ratably over a 3-year period.
•For the nine-month period ended September 30, 2024, the Partnership granted 122,867 performance-based phantom units and associated distribution equivalent rights to certain members of management in connection with the Partnership’s annual incentive compensation award cycle. The grant date fair value of these awards totaled $2.4 million and the awards vest at the end of three years.
•For the nine-month period ended September 30, 2024, the Partnership issued 39,486 common units to the Partnership’s six independent directors in connection with their annual compensation plan. The grant date fair value of these awards totaled $0.6 million and became fully vested at the grant date.
•On May 16, 2024, the Board of Directors of the General Partner approved the First Amendment to the SMLP LTIP, which increased the number of common units that may be delivered with respect to awards granted under the SMLP LTIP by 750,000 common units.
SMC Long-Term Incentive Plan. In connection with the consummation of the Corporate Reorganization, the Company assumed the SMLP LTIP, and all the obligations of the Partnership thereunder. The SMLP LTIP units were exchanged on a one-for-one basis with equivalent terms. In connection with the assumption of the SMLP LTIP and the Corporate Reorganization, the Board of Directors approved the amendment and restatement of the 2022 LTIP, with such amendment and restatement effective as of August 1, 2024 (such amended and restated plan, the Summit Midstream Corporation 2024 Long-Term Incentive Plan (the “SMC LTIP”)). The SMC LTIP authorizes the Compensation Committee of the Board of Directors, in its discretion, to grant awards of restricted stock, restricted stock units, stock options, stock appreciation rights and other awards related to the Company’s common stock upon such terms and conditions as it may determine appropriate and in accordance with the terms of the SMC LTIP.
As of September 30, 2024, approximately 0.6 million shares of common stock remained available for future issuance under the SMC LTIP, which includes the impact of 0.9 million granted but unvested restricted stock and performance-based awards.
14. COMMITMENTS AND CONTINGENCIES
Environmental Matters. Although the Company believes that it is in material compliance with applicable environmental regulations, the risk of environmental remediation costs and liabilities are inherent in pipeline ownership and operation. Furthermore, the Company can provide no assurances that significant environmental remediation costs and liabilities will not be incurred in the future. The Company is currently not aware of any material contingent liabilities that exist with respect to environmental matters, except as noted below.
As of September 30, 2024, the Company has recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures expected to be incurred subsequent to September 30, 2025. Each of these amounts represent the Company’s best estimate for costs expected to be incurred. Neither of these amounts have been discounted to their present value.
An update of the Company’s undiscounted accrued environmental remediation is as follows and is primarily related to the 2015 Blacktail Release and other environmental remediation activities, as detailed below.
(In thousands)
Accrued environmental remediation, December 31, 2023
$
2,937
Payments made
(968)
Changes in estimates
429
Accrued environmental remediation, September 30, 2024
$
2,398
In 2015, the Partnership learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota (“2015 Blacktail Release”). On August 4, 2021, subsidiaries of the Partnership entered into the following agreements to resolve the U.S. federal and North Dakota state governments’ environmental claims with respect to the 2015 Blacktail Release: (i) a Consent Decree with the U.S. Department of Justice (“DOJ”), the U.S.
Environmental Protection Agency (“EPA”), and the State of North Dakota (“Consent Decree”); (ii) a Plea Agreement with the United States (“Plea Agreement”); and (iii) a Consent Agreement with the North Dakota Industrial Commission (“Consent Agreement” together with the Consent Decree and Plea Agreement, the “Global Settlement”). As of September 30, 2024 and December 31, 2023, the accrued loss liability for the 2015 Blacktail Release were $18.6 million and $21.7 million, respectively and are recorded within Other noncurrent liabilities and Accrued settlement payable within the Company’s unaudited condensed consolidated balance sheets.
Key terms of the Global Settlement included (i) payment of penalties and fines totaling $36.3 million, consisting of $1.25 million in natural resource damages payable to federal and state governments, $25.0 million payable to the federal government over 5 years, and $10.0 million payable to state governments over, for the federal and state civil amounts, six years and, for the federal criminal amounts, five years, with interest applied to unpaid amounts accruing at, for the federal and state civil amounts, a fixed rate of 3.25% and, for the federal criminal amounts, a variable rate set by statute, and of which $6.7 million is expected to be paid within the next twelve months; (ii) continuation of remediation efforts at the site of the 2015 Blacktail Release; (iii) other injunctive relief, including, but not limited to, control room management, environmental management system audit, training, and reporting; (iv) guilty pleas by defendant Summit Midstream Partners, LLC (the “Defendant”) for (a) one charge of negligent discharge of a harmful quantity of oil and (b) one charge of knowing failure to immediately report a discharge of oil; and (v) organizational probation for a minimum period of three years from sentencing on December 6, 2021, including payment in full of certain components of the fines and penalty amounts. The agreements comprising the Global Settlement were subject to the approval of the U.S. District Court for the District of North Dakota (the “U.S. District Court”). The U.S. District Court entered an order making the civil components of the Global Settlement effective on September 28, 2021 and accepted the sentencing in the Plea Agreement on December 6, 2021, completing approval of the Global Settlement.
Subsidiaries of the Company are also participating in two proceedings before the EPA as a result of the Plea Agreement becoming effective. Following the U.S. District Court’s entering judgment on Defendant subsidiary’s guilty plea to one count of negligent discharge of produced water in violation of the Clean Water Act, Defendant subsidiary was statutorily debarred by operation of law pursuant to 33 U.S.C. § 1368(a) to participate in federal awards performed at the “violating facility,” which EPA determined to be the Marmon subsystem of the produced water gathering system in North Dakota. The scope and effect of the debarment as defined do not materially affect our operations. Defendant has submitted a petition for reinstatement, which was denied by the EPA’s suspension and debarment office (“SDO”) on July 11, 2022. The SDO determined that the term of probation in the Plea Agreement was the appropriate period of time to demonstrate Defendant subsidiary’s change of corporate attitude, policies, practices, and procedures. The Partnership and certain subsidiaries of the Company have also received a show cause notice from the EPA requesting us to “show cause” why SDO should not issue a Notice of Proposed Debarment to the Defendant subsidiary and certain affiliates under 2 C.F.R. § 180.800(d), to which the Partnership has responded, and in which proceeding no further developments have occurred.
Legal Proceedings. The Company is involved in various litigation and administrative proceedings arising in the ordinary course of business. In the opinion of management, any liabilities, which include insured claims, would not individually or in the aggregate have a material adverse effect on the Company’s financial position or results of operations. When a liability is covered by insurance, the Company reports the gross liability for the loss and a separate asset for the estimate of the probably amount recoverable from the insurance company.
15. INCOME TAXES
Effective August 1, 2024, pursuant to the Corporate Reorganization, Summit Midstream Corporation became subject to federal and state income taxes. Prior to consummation of the Corporate Reorganization, SMLP was treated as a partnership for federal and state income tax purposes, in which the Partnership’s taxable income or loss was passed through to its unitholders. SMLP was subject to Texas margin tax. Therefore, with the exception of the state of Texas, SMLP did not directly pay federal and state income taxes and no entity-level income tax provisions was recorded other than for the effects of the Texas margin tax.
Upon consummation of the Corporate Reorganization, Summit Midstream Corporation recognized (i) a $148.6 million income tax expense in its unaudited condensed consolidated statements of operations for temporary differences that existed as of the date of the Corporate Reorganization, (ii) a $28.1 million tax benefit to equity due to changes in tax bases and liabilities and (iii) a net deferred tax liability of $120.5 million in its unaudited condensed consolidated balance sheets. The tax amounts recognized in the financial statements are based on management’s best estimates, are preliminary and subject to change, and such changes could be material. The Partnership has not yet completed its tax return process for tax year 2024, which will require the receipt of final brokerage trade data and the determination of the Partnership’s final outside tax basis.
SMC’s effective income tax rate for the three and nine months ended September 30, 2024, was -259% and 264%, respectively. The effective tax rate differed from the statutory rate primarily due to the tax expense to establish a net deferred tax liability upon the Company’s change in tax status and SMLP’s pre-Corporate Reorganization income not being subject to U.S. federal or state income tax, other than the Texas margin tax.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized, and when necessary, valuation allowances are provided. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. SMC assesses the realizability of its deferred tax assets quarterly and considers carryback availability, the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. No valuation allowance has been recognized as of September 30, 2024.
SMC continues to monitor income tax developments in the United States. SMC will incorporate into its future financial statements the impacts, if any, of future regulations and additional authoritative guidance when finalized.
16. SEGMENT INFORMATION
As of September 30, 2024, the Company’s reportable segments are:
•Rockies – Includes the Company’s wholly owned midstream assets located in the Williston Basin and the DJ Basin.
•Permian – Includes the Company’s equity method investment in Double E.
•Northeast –Included the operations of the Company’s wholly owned midstream assets located in the Marcellus shale play and its wholly owned midstream assets located in the Utica shale play together with its equity method investment in Ohio Gathering that is focused on the Utica Shale. On March 22, 2024 and May 1, 2024, the Partnership completed the Utica Sale and Mountaineer Transaction, respectively. For additional information regarding the Utica Sale and Mountaineer Transaction, see Note 3 - Divestitures regarding the disposition of Northeast assets.
•Piceance – Includes the Company’s wholly owned midstream assets located in the Piceance Basin.
•Barnett – Includes the Company’s wholly owned midstream assets located in the Barnett Shale.
Corporate and Other represents those results that: (i) are not specifically attributable to a reportable segment; (ii) are not individually reportable; or (iii) have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs, acquisition integration costs and interest expense.
Assets by reportable segment follow.
September 30, 2024
December 31, 2023
(In thousands)
Assets:
Rockies
$
904,005
$
904,974
Permian
284,171
291,073
Northeast
1,257
573,663
Piceance
399,704
431,687
Barnett
274,322
281,861
Total reportable segment assets
1,863,459
2,483,258
Corporate and Other
135,707
10,940
Total assets
$
1,999,166
$
2,494,198
Segment adjusted EBITDA by reportable segment follows.
A reconciliation of income or loss before income taxes and income from equity method investees to total of reportable segments’ measures of profit follows.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In thousands)
Reconciliation of income (loss) before income taxes and income from equity method investees to total of reportable segments’ measures of profit:
Income (loss) before income taxes and income from equity method investees
$
(59,878)
$
(6,265)
$
33,909
$
(46,311)
Add:
Corporate and Other expense
10,201
5,478
21,598
20,650
Interest expense
25,712
34,568
95,015
103,966
Depreciation and amortization (1)
23,774
31,013
76,028
91,438
Proportional adjusted EBITDA for equity method investees (2)
7,585
16,917
35,102
42,655
Adjustments related to capital reimbursement activity
(2,283)
(3,111)
(7,934)
(6,778)
Equity compensation
1,840
1,396
6,698
5,158
(Gain) loss on asset sales, net
(6)
(40)
1
(183)
(Gain) loss on sale of business
1,672
9
(82,338)
45
Gain on sale of equity method investment
—
—
(126,261)
—
Long-lived asset impairment
—
—
67,936
455
Transaction costs and other
2,579
—
16,407
—
Early extinguishment of debt
42,235
—
47,199
—
Total of reportable segments’ measures of profit
$
53,431
$
79,965
$
183,360
$
211,095
________
(1) Includes the amortization expense associated with our favorable gas gathering contracts as reported in other revenues.
(2) The Company recorded financial results of its investment in Ohio Gathering on a one-month lag and is based on the financial information available to us during the reporting period. With the divestiture of Ohio Gathering in March 2024, proportional adjusted EBITDA includes financial results from December 1, 2023 through March 22, 2024.
17. SUBSEQUENT EVENTS
Redemption of 2026 Secured Notes. On July 26, 2024, concurrently with consummation of the 2026 Secured Notes Tender Offer, the Co-Issuers delivered a notice of redemption to holders of 2026 Secured Notes for the redemption of all $114.7 million aggregate principal amount of 2026 Secured Notes not purchased in the 2026 Secured Notes Tender Offer, at a price equal to 102.125% of the principal amount thereof, plus accrued and unpaid interest to the redemption date. On July 26, 2024, concurrently with delivery of the notice of redemption, the Co-Issuers irrevocably deposited $121.2 million in aggregate principal amount of non-callable United States Treasury securities, which included amounts for principal, interest, and premium with the trustee to satisfy and discharge the 2026 Secured Notes until redeemed on October 15, 2024 with the funds deposited with the trustee. On October 15, 2024, the 2026 Secured Notes were fully repaid.
Tall Oak Business Combination Agreement. On October 1, 2024, the Company entered into a Business Contribution Agreement (the “Business Contribution Agreement”), by and among the Company, the Partnership, and Tall Oak Midstream Holdings, LLC, a Delaware limited liability company (“Tall Oak Parent”), pursuant to which, among other things, upon the satisfaction of the terms and conditions set forth therein, Tall Oak Parent will contribute all of its equity interests (the “Tall Oak Interests”) in Tall Oak Midstream Operating, LLC, a Delaware limited liability company (“Tall Oak”), to the Partnership, in exchange for an aggregate amount equal to (i) $425.0 million, consisting of (a) $155.0 million in cash consideration, subject to certain adjustments contemplated by the Business Contribution Agreement, and (b) 7,471,008 shares of Class B common stock of the Company, par value $0.01 per share (the “Class B Common Stock”) and 7,471,008 common units representing limited partner interests of the Partnership (together with the Class B Common Stock, the “Securities”), plus (ii) potential cumulative earnout payments continuing through March 31, 2026 not to exceed $25.0 million in the aggregate that Tall Oak Parent may become entitled to receive pursuant to the Business Contribution Agreement subject to Tall Oak and its customers meeting certain development requirements.
The consummation of the transaction contemplated by the Business Contribution Agreement (the “Transaction”) is subject to various closing conditions, including, among other things, the approval by the holders of a majority of all votes cast at a special meeting of the stockholders of the Company relating to the issuance of the Securities. At the closing of the Transaction, the Board of Directors will be increased from the current seven directors to eleven directors, and Tailwater Capital LLC will elect four new directors to the Board of Directors.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to inform the reader about matters affecting the financial condition and results of operations of the Company and its subsidiaries for the periods since December 31, 2023. As a result, the following discussion should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and notes thereto included in this report and the MD&A and the audited consolidated financial statements and related notes that are included in the Partnership’s 2023 Annual Report. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in the section “Forward-Looking Statements.” Actual results may differ materially from those contained in any forward-looking statements.
Unless the context requires otherwise or unless otherwise noted, all references to “Summit Midstream,” the “Company,” “we,” “us,” “our” or like terms are to Summit Midstream Corporation (including its subsidiaries) for the periods after August 1, 2024, the date the Corporate Reorganization was consummated. For the periods prior to August 1, 2024, unless the context requires otherwise or unless otherwise noted, all reference to “Summit Midstream,” or the “Company” are to Summit Midstream Partners, LP. (including its subsidiaries).
Overview
We are a value-oriented company focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States.
Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn a portion of our revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Rockies and Piceance segments, (ii) the sale of natural gas we retain from certain Barnett segment customers, (iii) the sale of condensate we retain from our gathering services in the Rockies and Piceance segment and (iv) additional gathering fees that are tied to the performance of certain commodity price indexes which are then added to the fixed gathering rates.
We also have indirect exposure to changes in commodity prices such that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue.
The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the “Segment Overview for the Three and Nine Months Ended September 30, 2024 and 2023” section included herein.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In thousands)
Net income (loss)
$
(197,541)
$
3,874
$
(88,392)
$
(23,829)
Reportable segment adjusted EBITDA
Rockies
$
24,850
$
24,998
$
70,582
$
64,986
Permian
8,472
5,840
23,434
16,283
Northeast
—
27,751
30,634
65,806
Piceance
12,831
15,292
40,912
43,640
Barnett
7,278
6,084
17,798
20,380
Net cash provided by operating activities
$
9,151
$
59,119
$
40,124
$
110,759
Capital expenditures (1)
10,941
17,685
37,861
49,863
Proceeds from Summit Utica Sale (excluding Ohio Gathering)
—
—
292,266
—
Proceeds from sale of Ohio Gathering
—
—
332,734
—
Proceeds from Mountaineer Transaction
(696)
—
69,304
—
Investment in Double E equity method investee
989
—
1,431
3,500
Debt repayments - ABL Facility
—
(33,000)
(313,000)
(70,000)
Debt repayments - Redemption of 2026 Unsecured Notes
Debt repayments - 2026 Secured Notes (Asset Sale Offer)
—
—
(6,910)
—
Debt repayments - Permian Transmission Term Loan
(3,934)
(2,684)
(11,555)
(7,804)
Debt repayments - 2025 Senior Notes Redemption
(49,783)
—
(49,783)
—
Debt repayments - 2026 Secured Notes Redemption
(649,805)
—
(649,805)
—
Borrowings on Amended and Restated ABL Facility
150,000
—
150,000
35,000
Issuance of 2029 Secured Notes
565,800
—
565,800
—
Debt extinguishment costs
(19,260)
—
(21,355)
—
(1)See “Liquidity and Capital Resources” herein to the unaudited condensed consolidated financial statements for additional information on capital expenditures.
Trends and Outlook
Our business has been, and we expect our future business to continue to be, affected by the following key trends:
•Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices, including the continued conflict in the Middle East, current Russia-Ukraine conflict, the international sanctions against Russia and other sustained military campaigns;
•Natural gas, NGL and crude oil supply and demand dynamics;
•Actions of the OPEC and its allies, including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls;
•Production from U.S. shale plays;
•Capital markets availability and cost of capital; and
•Inflation and shifts in operating costs.
Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the “Trends and Outlook” section of MD&A included in the 2023 Annual Report.
Tall Oak Business Combination Agreement. On October 1, 2024, we entered into a Business Contribution Agreement (the “Business Contribution Agreement”), by and among the Company, the Partnership, and Tall Oak Midstream Holdings, LLC, a Delaware limited liability company (“Tall Oak Parent”), pursuant to which, among other things, upon the satisfaction of the terms and conditions set forth therein, Tall Oak Parent will contribute all of its equity interests (the “Tall Oak Interests”) in Tall Oak Midstream Operating, LLC, a Delaware limited liability company (“Tall Oak”), to the Partnership, in exchange for an aggregate amount equal to (i) $425.0 million, consisting of (a) $155.0 million in cash consideration, subject to certain adjustments contemplated by the Business Contribution Agreement, and (b) 7,471,008 shares of Class B common stock of the Company, par value $0.01 per share (the “Class B Common Stock”) and 7,471,008 common units representing limited partner interests of the Partnership (together with the Class B Common Stock, the “Securities”), plus (ii) potential cumulative earnout payments continuing through March 31, 2026 not to exceed $25.0 million in the aggregate that Tall Oak Parent may become entitled to receive pursuant to the Business Contribution Agreement subject to Tall Oak and its customers meeting certain development requirements.
The consummation of the transaction contemplated by the Business Contribution Agreement (the “Transaction”) is subject to various closing conditions, including, among other things, the approval by the holders of a majority of all votes cast at a special meeting of the stockholders of the Company relating to the issuance of the Securities. At the closing of the Transaction, the Board of Directors will be increased from the current seven directors to eleven directors, and Tailwater Capital LLC will elect four new directors to the Board of Directors.
Corporate Reorganization. On August 1, 2024, following unitholder approval at the Partnership’s Special Meeting of Unitholders on July 18, 2024, the Partnership consummated a previously announced transaction that resulted in the Partnership becoming a wholly owned subsidiary of a newly formed Delaware corporation, Summit Midstream Corporation. Upon the consummation of the Corporate Reorganization, each outstanding common unit of the Partnership was converted into the right to receive 1.000 shares of common stock of Summit Midstream Corporation and each outstanding Series A Preferred Unit was converted into the right to receive 1.000 shares of Series A Preferred Stock of Summit Midstream Corporation, with the liquidation preference of each share of Series A Preferred Stock initially equal to $1,000 and the Series A Certificate of Designation deeming all accumulated and unpaid distributions on the Series A Preferred Units to be Series A Unpaid Cash Dividends (as defined in the Series A Certificate of Designation) per share of Series A Preferred Stock, which constituted all consideration to be paid in respect to such Series A Preferred Units, and any rights to accumulated and unpaid distributions on such Series A Preferred Units were discharged.
The Corporate Reorganization was accounted for as a common-control transaction between the Partnership and Summit Midstream Corporation as a result of the Partnership’s unitholders controlling both the Partnership and Summit Midstream Corporation before and after the Merger. In the case of this common-control transaction, the historical financial statements of the Partnership became the historical financial statements of Summit Midstream Corporation, except for certain changes that conform the Partnership’s historical financial statements to a corporate entity. These changes include, but are not limited to, the reclassification of the Partnership’s capital accounts to shareholders’ equity accounts and an update of certain limited partner terms to synonymous corporate entity terms. The Corporate Reorganization had no impact to historical revenues, expenses, assets, liabilities, or cash flows.
Mountaineer Transaction. On May 1, 2024, we completed the Mountaineer Transaction for a cash sale price of $70.0 million, subject to customary post-closing adjustments. Mountaineer Midstream was the owner of midstream assets located in the Marcellus Shale. Prior to closing the Mountaineer Transaction, we sold related compression assets located in the Marcellus Shale to a compression service provider for approximately $5 million in April 2024.
Summit Utica Sale. As previously announced on March 22, 2024, we completed the Utica Sale for a cash sale price of $625.0 million, subject to customary post-closing adjustments. Summit Utica was the owner of (i) approximately 36% of the issued and outstanding equity interests in OGC, (ii) approximately 38% of the issued and outstanding equity interests in OCC, together with OGC, Ohio Gathering and (iii) midstream assets located in the Utica Shale. Ohio Gathering was the owner of a natural gas gathering system and condensate stabilization facility located in Belmont and Monroe counties in the Utica Shale in southeastern Ohio.
Refinancing Transactions. The Partnership issued the 2029 Secured Notes and completed the 2026 Secured Notes Tender Offer and subsequent redemption, and the redemption of the 2025 Senior Notes.
2029 Secured Notes. On July 26, 2024, Summit Holdings issued $575.0 million aggregate principal amount of 8.625% Senior Secured Second Lien Notes due 2029. The 2029 Secured Notes mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15, commencing on February 15, 2025.
2026 Secured Notes Tender Offer and Redemption. Concurrently with closing the offering of 2029 Secured Notes, Summit Holdings and Finance Corp. consummated a cash tender offer to purchase any and all of the outstanding 2026 Secured Notes. Summit Holdings and Finance Corp. accepted for payment and made payment for $649.8 million aggregate principal amount of
the 2026 Secured Notes validly tendered in the 2026 Notes Tender Offer. On July 26, 2024, concurrently with consummation of the 2026 Secured Notes Tender Offer, Summit Holdings and Finance Corp. delivered a notice of redemption to holders of 2026 Secured Notes for the redemption of all $114.7 million aggregate principal amount of 2026 Secured Notes not purchased in the 2026 Secured Notes Tender Offer, at a price equal to 102.125% of the principal amount thereof, plus accrued and unpaid interest to the redemption date (which was October 15, 2024). On July 26, 2024, concurrently with delivery of the notice of redemption, Summit Holdings and Finance Corp. irrevocably deposited $121.2 million in aggregate principal amount of non-callable United States Treasury securities, which included amounts for principal, interest, and premium with the trustee to satisfy and discharge the 2026 Secured Notes until redeemed on October 15, 2024 with the funds deposited with the trustee. On
October 15, 2024, the 2026 Secured Notes were fully repaid.
2025 Senior Notes Redemption. On July 17, 2024, Summit Holdings and Finance Corp. delivered a conditional notice of redemption to holders of 2025 Senior Notes for the redemption of all $49.8 million aggregate principal amount of outstanding 2025 Senior Notes, at a price equal to 100.000% of the principal amount thereof, plus accrued and unpaid interest to the redemption date, which was conditioned on the closing of the offering of 2029 Secured Notes. On July 26, 2024, concurrently with closing of the offering of 2029 Secured Notes, Summit Holdings and Finance Corp. irrevocably deposited $50.6 million in aggregate principal amount of non-callable United States Treasury securities, which included amounts for principal and interest with the trustee to satisfy and discharge the 2025 Senior Notes until redeemed with the funds deposited with the trustee. On
August 16, 2024, the 2025 Senior Notes were fully repaid.
Conclusion of Strategic Alternatives Review. In connection with the announcement of the Utica Sale, we also announced the conclusion of the strategic alternative review process undertaken by our Board of Directors that was previously announced on October 3, 2023. While we have concluded our active process, we remain open to all potential value-enhancing transactions.
Capital structure optimization and portfolio management. We intend to continue to improve our capital structure in the future by reducing our indebtedness with free cash flow, and when appropriate, we may pursue opportunistic transactions with the objective of increasing long term shareholder value. This may include opportunistic acquisitions, divestitures, re-allocation of capital to new or existing areas, and development of joint ventures involving our existing midstream assets or new investment opportunities. We believe that our current cash balance, internally generated cash flow, our Amended and Restated ABL Facility, the Permian Credit Facility, and access to debt or equity will be adequate to finance our strategic initiatives. To attain our overall corporate strategic objectives, we may conduct an asset divestiture, or divestitures, at a transaction valuation that is less than the net book value of the divested asset. For additional information, see Note 17 – Subsequent Events.
Ongoing impact of political and economic conditions and events in foreign oil and natural gas producing countries on commodity prices. Although we operate solely in the United States, certain events and conditions in foreign oil and natural gas producing countries, such as the continued conflict in the Middle East, including the Hamas-Israel war, the Hezbollah-Israel conflict, and Russia’s invasion of Ukraine, could have potential effects on us, including, but not limited to, volatility in currencies and commodity prices, higher inflation, cost and supply chain pressures and availability and disruptions in banking systems and capital markets. As of the date of filing, there have been no material impacts to us.
Impact of increases in interest rates. Increases in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of existing and any additional financing. Since March 2022, the Federal Reserve has raised its target range for the federal funds rate multiple times to a current target range of 4.50% to 4.75%, and the timing of any potential further increases or decreases remains uncertain. As of September 30, 2024, we had approximately $689.7 million principal of fixed-rate debt, $150.0 million outstanding under our variable rate Amended and Restated ABL Facility and $133.3 million outstanding under the variable rate Permian Transmission Term Loan (see Note 8 - Debt). As of September 30, 2024, we had $120.0 million of interest rate exposure hedged to offset the impact of changes in interest rates on our Permian Transmission Term Loan.
How We Evaluate Our Operations
Prior to the Utica Sale and Mountaineer Transaction, we conducted and reported our operations in the midstream energy industry through five reportable segments: Northeast, Rockies, Permian, Piceance and Barnett. Each of our reportable segments provides midstream services in a specific geographic area and our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations. For additional information see Note 16 - Segment Information.
Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance. We view these metrics as important factors in evaluating our profitability. These metrics include:
•throughput volume;
•revenues;
•operation and maintenance expenses;
•capital expenditures; and
•segment adjusted EBITDA.
We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the three and nine months ended September 30, 2024.
Additional Information. For additional information, see the “Results of Operations” section herein and the notes to the unaudited condensed consolidated financial statements. For additional information on how these metrics help us manage our business, see the “How We Evaluate Our Operations” section of MD&A included in the 2023 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 – Summary of Significant Accounting Policies and Recently Issued Accounting Standards Applicable to the Company.
Consolidated Overview for the Three and Nine Months Ended September 30, 2024 and 2023
The following table presents certain consolidated financial and operating data.
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
(In thousands)
Revenues:
Gathering services and related fees
$
44,013
$
66,035
$
151,211
$
180,492
Natural gas, NGLs and condensate sales
48,243
45,120
145,294
130,365
Other revenues
10,159
10,038
26,096
20,728
Total revenues
102,415
121,193
322,601
331,585
Costs and expenses:
Cost of natural gas and NGLs
28,246
27,110
88,047
77,967
Operation and maintenance
24,473
26,161
72,925
75,291
General and administrative
12,419
11,098
41,368
31,897
Depreciation and amortization
23,540
30,778
75,324
90,734
Transaction costs
2,094
144
13,156
926
Acquisition integration costs
—
171
40
2,396
(Gain) loss on asset sales, net
(6)
(40)
1
(183)
Long-lived asset impairment
—
—
67,936
455
Total costs and expenses
90,766
95,422
358,797
279,483
Other income (expense), net
666
(315)
2,784
747
Gain (loss) on interest rate swaps
(2,574)
2,856
936
4,851
Gain (loss) on sale of business
(1,672)
(9)
82,338
(45)
Gain on sale of equity method investment
—
—
126,261
—
Interest expense
(25,712)
(34,568)
(95,015)
(103,966)
Loss on early extinguishment of debt
(42,235)
—
(47,199)
—
Equity method investees income
4,910
10,211
19,828
22,302
Income (loss) before income taxes
(54,968)
3,946
53,737
(24,009)
Income tax benefit (expense)
(142,573)
(72)
(142,129)
180
Net income (loss)
$
(197,541)
$
3,874
$
(88,392)
$
(23,829)
Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)
667
1,352
903
1,249
Aggregate average daily throughput - liquids (Mbbl/d)
70
85
73
76
________
(1)Excludes volume throughput for Ohio Gathering and Double E. For additional information, see the Northeast and Permian sections herein under the caption “Segment Overview for the Three and Nine Months Ended September 30, 2024 and 2023”.
Volumes – Gas. Natural gas throughput volumes decreased685 MMcf/d for the three months ended September 30, 2024 compared to the three months ended September 30, 2023, primarily reflecting:
•a volume throughput decrease of 752 MMcf/d for the Northeast segment.
•a volume throughput increase of 11 MMcf/d for the Rockies segment.
•a volume throughput decrease of 29 MMcf/d for the Piceance segment.
•a volume throughput increase of 85 MMcf/d for the Barnett segment.
Natural gas throughput volumes decreased346 MMcf/d for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, primarily reflecting:
•a volume throughput decrease of 389 MMcf/d for the Northeast segment.
•a volume throughput increase of 19 MMcf/d for the Rockies segment.
•a volume throughput decrease of 4 MMcf/d for the Piceance segment.
•a volume throughput increase of 28 MMcf/d for the Barnett segment.
Volumes – Liquids. Crude oil and produced water throughput volumes at the Rockies segment decreased for the three months ended September 30, 2024, compared to the three months ended September 30, 2023, primarily as a result of natural production declines, offset by 25 new well connections that came online subsequent to September 30, 2023.
Crude oil and produced water throughput volumes at the Rockies segment decreased for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023, primarily as a result of natural production declines, offset by 25 new well connections that came online subsequent to September 30, 2023.
For additional information on volumes, see the “Segment Overview for the Three and Nine Months Ended September 30, 2024 and 2023” section herein.
Revenues. Total revenues decreased $18.8 million during the three months ended September 30, 2024 compared to the three months ended September 30, 2023, comprised of a $22.0 million decrease in gathering services and related fees, offset by a $3.1 million increasein natural gas, NGLs and condensate sales, a $0.1 million increase in other revenue.
Gathering Services and Related Fees. Gathering services and related fees decreased $22.0 million compared to the three months ended September 30, 2023, primarily reflecting:
•a $3.1 million decrease in the Rockies, primarily due to decreased volume throughput;
•a $18.2 million decrease in the Northeast, primarily due to the sale of the Mountaineer Midstream system and the disposition of Summit Utica;
•a $3.1 million decrease in the Piceance, primarily due to decreased volume throughput and contractual step-downs; and
•a $2.3 million increase in the Barnett, primarily due to increased volume throughput.
Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate revenues increased$3.1 million compared to the three months ended September 30, 2023, primarily reflecting:
•a $3.8 million increase in the Rockies, primarily due to increased volume throughput.
Total revenues decreased $9.0 million during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, comprised of a $29.3 million decrease in gathering services and related fees, offset by a $14.9 million increasein natural gas, NGLs and condensate sales and a $5.4 million increase in other revenue.
Gathering Services and Related Fees. Gathering services and related fees decreased $29.3 million compared to the nine months ended September 30, 2023, primarily reflecting:
•a $24.9 million decrease in the Northeast, primarily due to the sale of the Mountaineer Midstream system and the disposition of Summit Utica; and
•a $3.7 million decrease in the Piceance, primarily due to contractual step-downs; offset by increased volume throughput.
Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate revenues increased$14.9 million compared to the nine months ended September 30, 2023, primarily reflecting:
•a $17.0 million increase in the Rockies, primarily due to increased volume throughput; and
•a $1.8 million decrease in the Piceance; primarily due to lower commodity prices; partially offset by increased volume throughput.
Costs and Expenses. Total costs and expenses decreased $4.7 million during the three months ended September 30, 2024 compared to the three months ended September 30, 2023.
Total costs and expenses increased $79.3 million during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023.
Cost of Natural Gas and NGLs. Cost of natural gas and NGLs increased $1.1 million for the three months ended September 30, 2024, compared to the three months ended September 30, 2023.
Cost of natural gas and NGLs increased $10.1 million for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023.
Operation and Maintenance. Operation and maintenance expense decreased $1.7 million for the three months ended September 30, 2024, compared to the three months ended September 30, 2023.
Operation and maintenance expense decreased $2.4 million for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023.
Long-lived asset impairments. During the quarterly period ended March 31, 2024, we recognized an impairment charge of $67.9 million in connection with the Mountaineer Transaction.
Interest Expense. Interest expense decreased $8.9 million for the three months ended September 30, 2024, compared to three months ended September 30, 2023, primarily due to $10.5 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and Asset Sale Offer that occurred in July 2024 and May 2024, respectively, $4.5 million of reduced interest expense as a result of decreased borrowings on the Amended and Restated ABL Facility and $3.4 million of reduced interest expense as a result of the exchange and repurchase of $209.7 million of the 2025 Senior Notes that occurred in November 2023, partially offset by $8.9 million of increased borrowing costs in connection with issuance of the 2029 Secured Notes in July 2024.
Interest expense decreased $9.0 million for the nine months ended September 30, 2024, compared to nine months ended September 30, 2023, primarily due to $12.3 million of reduced interest expense as a result of decreased borrowings on the Amended and Restated ABL Facility, $9.6 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and Asset Sale Offer that occurred in July 2024 and May 2024, respectively and $9.4 million of reduced interest expense as a result of the exchange and repurchase of $209.7 million of the 2025 Senior Notes that occurred in November 2023, partially offset by $12.0 million of increased borrowing costs on the 2026 Unsecured Notes issued in November 2023 and $9.0 million of increased borrowing costs on the 2029 Secured Notes issued in July 2024.
Segment Overview for the Three and Nine Months Ended September 30, 2024 and 2023
Northeast.
Volume throughput for the Northeast reportable segment follows.
Northeast
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
Average daily throughput (MMcf/d)
—
752
*
269
658
*
Average daily throughput (MMcf/d) (Ohio Gathering)
—
870
*
283
763
*
* Not considered meaningful
On March 22, 2024, we completed the disposition of Summit Utica, the owner of our equity method investment, Ohio Gathering, and on May 1, 2024, we completed the disposition of our Mountaineer Midstream system.
Volume throughput for the Northeast, excluding Ohio Gathering, decreased for the three and nine months ended September 30, 2024, compared to the three and nine months ended September 30, 2023, primarily due to the sale of our Mountaineer Midstream system and the disposition of Summit Utica as discussed above.
Volume throughput for the Ohio Gathering system decreased for the three and nine months ended September 30, 2024, compared to the three and nine months ended September 30, 2023, primarily due to the disposition of Summit Utica, which owns an interest in the Ohio Gathering system.
Financial data for our Northeast reportable segment follows.
Northeast
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
(In thousands)
(In thousands)
Revenues:
Gathering services and related fees
$
—
$
18,157
*
$
18,851
$
43,717
*
Total revenues
—
18,157
*
18,851
43,717
*
Costs and expenses:
Operation and maintenance
—
2,094
*
2,259
6,204
*
General and administrative
—
205
*
220
607
*
Depreciation and amortization
—
4,435
*
4,248
13,319
*
Gain on asset sales, net
—
—
*
(21)
(7)
*
Long-lived asset impairment
—
—
*
67,916
—
*
Total costs and expenses
—
6,734
*
74,622
20,123
*
Add:
Depreciation and amortization
—
4,435
4,248
13,319
Adjustments related to capital reimbursement activity
—
(20)
—
(61)
Gain on asset sales, net
—
—
(21)
(7)
Long-lived asset impairment
—
—
67,916
—
Proportional adjusted EBITDA for Ohio Gathering (1)
—
11,913
14,282
28,832
Other
—
—
(20)
129
Segment adjusted EBITDA
$
—
$
27,751
*
$
30,634
$
65,806
*
* Not considered meaningful
(1)The Partnership recorded its financial results of its investment in Ohio Gathering on a one-month lag based on financial information available to us during the reporting period. With the divestiture of Ohio Gathering in March 2024, proportional adjusted EBITDA includes financial results from December 1, 2023 through March 22, 2024 ($2.5 million for March 1, 2024 - March 22, 2024).
Three and nine months ended September 30, 2024. Segment adjusted EBITDA decreased $27.8 million and$35.2 million, compared to the three and nine months ended September 30, 2023, respectively, primarily as the result of the sale of our Mountaineer Midstream system and the disposition of Summit Utica, the owner of our equity method investment, Ohio Gathering.
Volume throughput for our Rockies reportable segment follows.
Rockies
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
Aggregate average daily throughput - natural gas (MMcf/d)
128
117
9%
127
108
18%
Aggregate average daily throughput - liquids (Mbbl/d)
70
85
(18%)
73
76
(4%)
Natural gas. Natural gas volume throughput increased for the three and nine months ended September 30, 2024,compared to the three and nine months ended September 30, 2023, primarily reflecting 123 new well connections that came online subsequent to September 30, 2023, partially offset by winter related interruptions which occurred during the first quarter of 2024.
For the three months ended September 30, 2024 and 2023, costs of natural gas and NGLs includes $13.5 million and $10.1 million, respectively, of gathering fees collected under percentage of proceeds arrangements.
For the nine months ended September 30, 2024 and 2023, costs of natural gas and NGLs includes $36.0 million and $30.6 million, respectively, of gathering fees collected under percentage of proceeds arrangements.
Liquids. Liquids volume throughput decreased for the three and nine months ended September 30, 2024, compared to the three and nine months ended September 30, 2023, primarily due to natural production declines, offset by 25 new well connections that came online subsequent to September 30, 2023.
Financial data for our Rockies reportable segment follows.
Rockies
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
(In thousands)
(In thousands)
Revenues:
Gathering services and related fees
$
15,302
$
18,383
(17)%
$
48,141
$
48,595
(1%)
Natural gas, NGLs and condensate sales
47,733
43,967
9%
142,917
125,871
14%
Other revenues
4,615
5,541
(17)%
12,044
8,885
36%
Total revenues
67,650
67,891
—%
203,102
183,351
11%
Costs and expenses:
Cost of natural gas and NGLs
28,029
26,693
5%
87,139
75,977
15%
Operation and maintenance
12,088
13,494
(10%)
37,159
37,739
(2%)
General and administrative
1,050
1,272
(17%)
3,532
3,013
17%
Depreciation and amortization
9,143
9,228
(1%)
27,178
26,241
4%
Integration costs
—
49
*
—
511
*
(Gain) loss on asset sales, net
(6)
—
*
30
(111)
*
Long-lived asset impairment
—
—
*
20
455
(96%)
Total costs and expenses
50,304
50,736
(1%)
155,058
143,825
8%
Add:
Depreciation and amortization
9,143
9,228
27,178
26,241
Integration costs
—
49
—
511
Adjustments related to capital reimbursement activity
(1,645)
(1,434)
(4,702)
(1,905)
(Gain) loss on asset sales, net
(6)
—
30
(111)
Long-lived asset impairment
—
—
20
455
Other
12
—
12
269
Segment adjusted EBITDA
$
24,850
$
24,998
(1)%
$
70,582
$
64,986
9%
* Not considered meaningful
Three and nine months ended September 30, 2024. Segment adjusted EBITDA increased $5.6 million, compared to the nine months ended September 30, 2023, primarily as a result of increased natural gas throughput as described above, partially offset by the decrease in liquids throughput and lower natural gas and NGL pricing.
Volume throughput for our Permian reportable segment follows.
Permian
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
Average daily throughput (MMcf/d) (Double E)
661
327
102%
559
278
101%
Volume throughput for Double E increased for the three and nine months ended September 30, 2024,compared to the three and nine months ended September 30, 2023.
The following table presents the MVC quantities that Double E’s shippers have contracted to with firm transportation service agreements and related negotiated rate agreements:
(Amounts in MMBTU/day)
Weighted average MVC quantities for the year ended December 31,
Financial data for our Permian reportable segment follows.
Permian
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
(In thousands)
(In thousands)
Revenues:
Other revenues
$
910
$
893
2%
$
2,731
$
2,678
2%
Total revenues
910
893
2%
2,731
2,678
2%
Costs and expenses:
General and administrative
24
58
(59)%
117
218
(46)%
Transaction costs
—
—
*
—
75
*
Total costs and expenses
24
58
(59)%
117
293
(60)%
Add:
Transaction costs
—
—
—
75
Proportional adjusted EBITDA for Double E
7,586
5,005
52%
20,820
13,823
51%
Segment adjusted EBITDA
$
8,472
$
5,840
45%
$
23,434
$
16,283
44%
*Not considered meaningful
Three and nine months ended September 30, 2024. Segment adjusted EBITDA increased$2.6 million and $7.2 million, compared to the three and nine months ended September 30, 2023, primarily as a result of an increase in proportional adjusted EBITDA from our equity method investment in Double E.
Volume throughput for our Piceance reportable segment follows.
Piceance
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
Aggregate average daily throughput (MMcf/d)
284
313
(9%)
295
299
(1%)
Volume throughput decreased for the three and nine months ended September 30, 2024,compared to the three and nine months ended September 30, 2023,primarily as a result of natural production declines, offset by 21 new well connections that came online subsequent to September 30, 2023.
Financial data for our Piceance reportable segment follows.
Piceance
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
(In thousands)
(In thousands)
Revenues:
Gathering services and related fees
$
17,604
$
20,658
(15%)
$
56,054
$
59,791
(6%)
Natural gas, NGLs and condensate sales
510
937
(46)%
2,124
3,913
(46)%
Other revenues
1,492
1,569
(5)%
3,971
4,368
(9)%
Total revenues
19,606
23,164
(15%)
62,149
68,072
(9%)
Costs and expenses:
Cost of natural gas and NGLs
219
417
(47)%
895
1,990
(55)%
Operation and maintenance
6,011
5,962
1%
17,435
18,138
(4)%
General and administrative
319
275
16%
932
793
18%
Depreciation and amortization
10,524
12,949
(19%)
31,521
38,728
(19%)
Gain on asset sales, net
—
(6)
*
(8)
(10)
(20%)
Total costs and expenses
17,073
19,597
(13)%
50,775
59,639
(15)%
Add:
Depreciation and amortization
10,524
12,949
31,521
38,728
Adjustments related to capital reimbursement activity
(298)
(1,325)
(2,211)
(3,828)
Gain on asset sales, net
—
(6)
(8)
(10)
Other
72
107
236
317
Segment adjusted EBITDA
$
12,831
$
15,292
(16%)
$
40,912
$
43,640
(6%)
________
*Not considered meaningful
Three and nine months ended September 30, 2024. Segment adjusted EBITDA decreased $2.5 million and $2.7 million, compared to the three and nine months ended September 30, 2023 primarily related to the contractual step-downs.
Volume throughput for our Barnett reportable segment follows.
Barnett
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
Average daily throughput (MMcf/d)
255
170
50%
212
184
15%
Volume throughput increased for the three and nine months ended September 30, 2024,compared to the three and nine months ended September 30, 2023,primarily as a result of 27 new well connections that came online subsequent to September 30, 2023, partially offset by temporary production curtailments associated with reductions in commodity pricing.
Financial data for our Barnett reportable segment follows.
Barnett
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
(In thousands)
(In thousands)
Revenues:
Gathering services and related fees
$
11,107
$
8,837
26%
$
28,165
$
28,389
(1%)
Natural gas, NGLs and condensate sales
—
216
(100%)
253
581
(56%)
Other revenues (1)
3,142
2,035
54%
6,625
4,835
37%
Total revenues
14,249
11,088
29%
35,043
33,805
4%
Costs and expenses:
Operation and maintenance
6,546
4,575
43%
15,982
13,205
21%
General and administrative
321
332
(3%)
967
925
5%
Depreciation and amortization
3,841
3,803
1%
11,481
11,406
1%
Gain on asset sales, net
—
(33)
(100%)
—
(47)
(100%)
Total costs and expenses
10,708
8,677
23%
28,430
25,489
12%
Add:
Depreciation and amortization
4,076
4,038
12,185
12,110
Adjustments related to capital reimbursement activity
(339)
(332)
(1,000)
(984)
Gain on asset sales, net
—
(33)
—
(47)
Other
—
—
—
985
Segment adjusted EBITDA
$
7,278
$
6,084
20%
$
17,798
$
20,380
(13)%
________
*Not considered meaningful
(1) Includes the amortization expense associated with our favorable gas gathering contracts as reported in Other revenues.
Three and nine months ended September 30, 2024. Segment adjusted EBITDA increased $1.2 million compared to the three months ended September 30, 2023, primarily as a result of increase throughput discussed above. Segment adjusted EBITDA decreased $2.6 million, compared to the nine months ended September 30, 2023, primarily as a result of production curtailments discussed above and unfavorable margin mix, partially offset by increased volume throughput.
Corporate and Other Overview for the Three and Nine Months Ended September 30, 2024 and 2023
Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs, acquisition integration costs and interest expense. Corporate and Other includes intercompany eliminations.
Corporate and Other
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Percentage Change
2024
2023
Percentage Change
(In thousands)
(In thousands)
Costs and expenses:
General and administrative
$
10,705
$
8,956
20%
$
35,600
$
26,341
35%
Transaction costs
2,094
144
*
13,156
851
*
Interest expense
25,712
34,568
(26)%
95,015
103,966
(9)%
________
* Not considered meaningful
General and administrative. General and administrative expenses increased by $1.7 million and $9.3 million for the three and nine months ended September 30, 2024,compared to the three months ended September 30, 2023, respectively, primarily due to increased employee salaries and benefit expense, as well as professional and other expenses associated with our Corporate Reorganization.
Transaction costs. Transaction costs in 2024 are primarily related to the Utica Sale that closed on March 22, 2024, the Mountaineer Transaction that closed on May 1, 2024 and the costs incurred in connection with our Corporate Reorganization and strategic alternatives review.
Interest expense. Interest expense decreased $8.9 million for the three months ended September 30, 2024, compared to three months ended September 30, 2023, primarily due to $10.5 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and Asset Sale Offer that occurred in July 2024 and May 2024, respectively, $4.5 million of reduced interest expense as a result of decreased borrowings on the Amended and Restated ABL Facility and $3.4 million of reduced interest expense as a result of the exchange and repurchase of $209.7 million of the 2025 Senior Notes that occurred in November 2023, partially offset by $8.9 million of increased borrowing costs in connection with issuance of the 2029 Secured Notes in July 2024.
Interest expense decreased $9.0 million for the nine months ended September 30, 2024, compared to nine months ended September 30, 2023, primarily due to $12.3 million of reduced interest expense as a result of decreased borrowings on the Amended and Restated ABL Facility, $9.6 million of reduced interest expense as a result of the 2026 Secured Notes Tender Offer and Asset Sale Offer that occurred in July 2024 and May 2024, respectively and $9.4 million of reduced interest expense as a result of the exchange and repurchase of $209.7 million of the 2025 Senior Notes that occurred in November 2023, partially offset by $12.0 million of increased borrowing costs on the 2026 Unsecured Notes issued in November 2023 and $9.0 million of increased borrowing costs on the 2029 Secured Notes issued in July 2024.
Liquidity and Capital Resources
We rely primarily on internally generated cash flows as well as current cash balance and external financing sources, including commercial bank borrowings, and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our Amended and Restated ABL Facility and Permian Transmission Credit Facility, together with internally generated cash flows, current cash balance and access to debt or equity capital markets, will be adequate to finance our operations for the next twelve months without adversely impacting our liquidity.
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2024, our material off-balance sheet arrangements and transactions include (i) letters of credit outstanding against our Amended and Restated ABL Facility aggregating to $0.8 million, and (ii) letters of credit outstanding against our Permian Transmission Credit Facility aggregating to $10.5 million. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources.
We are in compliance with all covenants contained in the 2029 Secured Notes, the Amended and Restated ABL Facility and the Permian Transmission Credit Facility. The Amended and Restated ABL Facility requires that Summit Holdings not permit (i) the First Lien Net Leverage Ratio as of the last day of any fiscal quarter to be greater than 2.50:1.00, or (ii) the Interest Coverage Ratio (as defined in the Amended and Restated ABL Agreement) as of the last day of any fiscal quarter to be less than 2.00:1.00. As of September 30, 2024, the First Lien Net Leverage Ratio and the Interest Coverage Ratio was 0.84:1.00 and 2.42:1.00, respectively.
ABL Facility. Concurrently with the issuance of the 2029 Secured Notes, on July 26, 2024, Summit Holdings, as borrower, amended and restated its existing first-lien, senior secured credit agreement, with the Partnership, consisting of a $500.0 million asset-based revolving credit facility. As of September 30, 2024, the Amended and Restated ABL Facility will mature on the earliest of (a) July 26, 2029, (b) July 31, 2029 if either (i) the outstanding amount of the 2029 Secured Notes (or any refinancing debt permitted under the Amended and Restated ABL Facility in respect thereof that has a final maturity date, scheduled amortization or any other scheduled repayment, mandatory prepayment, mandatory redemption or sinking fund obligation prior to the date that is 91 days after the Amended and Restated ABL Termination Date (provided, that the terms of such permitted refinancing debt may (x) require the payment of interest from time to time and (y) include customary mandatory redemptions, prepayments or offers to purchase with proceeds of asset sales or upon the occurrence of a change of control)) on such date equals or exceeds $50.0 million or (ii) the outstanding amount of such debt described in clause (i) above on such date is less than $50.0 million and Liquidity (as defined in the Amended and Restated ABL Agreement) at any time on or after such date is less than the sum of (A) such outstanding amount and (B) the greater of (x) 10% of the aggregate Commitments (as defined in the Amended and Restated ABL Agreement) then in effect and (y) $50.0 million, and (c) any date on which the aggregate Commitments terminate thereunder. As of September 30, 2024, there was $150.0 million outstanding under the Amended and Restated ABL Facility and the available borrowing capacity totaled $349.2 million after giving effect to the issuance thereunder of $0.8 million of outstanding but undrawn irrevocable standby letters of credit.
2029 Secured Notes. On July 26, 2024, Summit Holdings issued $575.0 million aggregate principal amount of 8.625% Senior Secured Second Lien Notes due 2029. The 2029 Secured Notes are guaranteed on a senior second-priority basis by Summit Midstream Corporation and certain of Summit Midstream Corporation’s existing and future subsidiaries and are secured on a second-priority basis by substantially the same collateral that is pledged for the benefit of the lenders under the Amended and Restated ABL Facility. The 2029 Secured Notes mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15, commencing on February 15, 2025. As of September 30, 2024, the outstanding balance of the 2029 Secured Notes was $575.0 million.
Other. We may in the future use a combination of cash, secured or unsecured borrowings and issuances of our common stock or other securities and the proceeds from asset sales to retire or refinance our outstanding debt or Series A Preferred Stock through privately negotiated transactions, open market repurchases, redemptions, exchange offers, tender offers or otherwise, but we are under no obligation to do so.
Cash Flows
The components of the net change in cash and cash equivalents were as follows:
Nine Months Ended September 30,
2024
2023
(In thousands)
Net cash provided by operating activities
$
40,124
$
110,759
Net cash provided by (used in) investing activities
659,412
(55,846)
Net cash used in financing activities
(571,815)
(49,549)
Net change in cash, cash equivalents and restricted cash
$
127,721
$
5,364
Operating activities.
Cash flows provided by operating activities for the nine months ended September 30, 2024 primarily reflected:
•a net loss of $88.4 million plus positive adjustments of $158.6 million for non-cash operating items; and
•a $30.1 million change in working capital accounts.
Cash flows provided by operating activities for the nine months ended September 30, 2023 primarily reflected:
•a net loss of $23.8 million plus adjustments of $127.9 million for non-cash operating items; and
•a $6.7 million change in working capital accounts.
Cash flows provided by investing activities during the nine months ended September 30, 2024 primarily reflected:
•$332.7 million of cash inflows from the proceeds of the sale Ohio Gathering;
•$292.3 million of cash inflows from the proceeds of the Utica Sale (excluding Ohio Gathering);
•$69.3 million of cash inflows from the proceeds of the Mountaineer Transaction;
•$4.4 million of cash inflows from the sale of compressor equipment; and
•$37.9 million of cash outflows for capital expenditures.
Cash flows used in investing activities during the nine months ended September 30, 2023 primarily reflected:
•$49.9 million of cash outflows for capital expenditures; and
•$3.5 million for cash investments in the Double E Project.
Financing activities.
Cash flows used in financing activities during the nine months ended September 30, 2024 primarily reflected:
•$649.8 million of cash outflows for the redemption of Secured Notes;
•$313.0 million of cash outflows for repayments on the Amended and Restated ABL Facility;
•$209.5 million of cash outflows from the redemption of 2026 Unsecured Notes;
•$49.8 million of cash outflows from the 2025 Notes Redemption;
•$21.4 million of cash outflows for debt extinguishment costs;
•$13.6 million of cash outflows for the Excess Cash Flow Offer;
•$11.6 million of cash outflows for repayments on the Permian Transmission Term Loan; and
•$6.9 million of cash outflows for the Asset Sale Offer; partially offset by
•$565.8 million of cash inflows from the issuance of the 2029 Secured Notes;
•$150.0 million of cash inflows from borrowings on the Amended and Restated ABL Facility.
Cash flows used in financing activities during the nine months ended September 30, 2023 primarily reflected:
•$70.0 million of cash outflows for repayments on the Amended and Restated ABL Facility;
•$7.8 million of cash outflows for repayments on the Permian Transmission Term Loan; offset by
•$35.0 million of cash inflows from borrowings on the Amended and Restated ABL Facility.
Capital Requirements
Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our Partnership Agreement required that we categorize our capital expenditures as either:
•maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of, new capital assets) made to maintain our long-term operating income or operating capacity; or
•expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.
In connection with the consummation of the Corporate Reorganization, the Partnership Agreement was amended to, among other things, reflect that all of the issued and outstanding limited partnership interests of the Partnership are held by Summit Midstream Corporation. For information on the Corporate Reorganization, see Note 1 – Organization, Business Operations, Corporate Reorganization and Presentation and Consolidation.
For the nine months ended September 30, 2024, cash paid for capital expenditures totaled $37.9 million which included $7.4 million of maintenance capital expenditures. For the nine months ended September 30, 2024, we did not make any contributions to Ohio Gathering and we contributed $1.4 million to Double E.
We rely primarily on internally generated cash flows, our current cash balance as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our internally generated cash flows, current cash balance, our Amended and Restated ABL Facility and the Permian Transmission Credit Facility, and access to debt or equity capital markets, will be adequate to finance our operations for the next twelve months without adversely impacting our liquidity.
There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreements with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and NGLs and markets, and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources.
Credit and Counterparty Concentration Risks
We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.
Certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers’ wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers’ commodities flow and, in many cases, the only way for our customers to get their production to market.
We have exposure due to nonperformance under our MVC contracts whereby a potential customer, may not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period.
Off-Balance Sheet Arrangements
During the three and nine months ended September 30, 2024, there were no material changes to the off-balance sheet obligations disclosed in our 2023 Annual Report.
Critical Accounting Estimates
We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. There have been no significant changes to our critical accounting estimates from those disclosed on 2023 Annual Report.
Forward-Looking Statements
Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are “forward-looking” statements. 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.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Part II. Item 1A. Risk Factors included in this report.
Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others:
•our ability and the time required to consummate the Transaction;
• our ability to achieve the strategic and other objectives relating to the proposed Transaction;
• the risk that regulatory approvals for the Transaction are not obtained or are obtained subject to conditions that are not anticipated;
• the risk that we are unable to integrate Tall Oak’s operations in a successful manner and in the expected time period;
•our decision whether to pay, or our ability to grow, our cash dividends;
•fluctuations in natural gas, NGLs and crude oil prices, including as a result of political or economic measures taken by various countries or OPEC;
•the extent and success of our customers’ drilling and completion efforts, as well as the quantity of natural gas, crude oil, freshwater deliveries, and produced water volumes produced within proximity of our assets;
•failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects;
•competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems;
•actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers;
•our ability to divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets;
•the ability to attract and retain key management personnel;
•commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;
•changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets;
•restrictions placed on us by the agreements governing our debt and preferred equity instruments;
•the availability, terms and cost of downstream transportation and processing services;
•natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;
•the current and potential future impact of pandemics on our business, results of operations, financial position or cash flows;
•operational risks and hazards inherent in the gathering, compression, treating and/or processing of natural gas, crude oil and produced water;
•our ability to comply with the terms of the agreements comprising the Global Settlement;
•weather conditions and terrain in certain areas in which we operate;
•physical and financial risks associated with climate change;
•any other issues that can result in deficiencies in the design, installation or operation of our gathering, compression, treating, processing and freshwater facilities;
•timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;
•our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results;
•the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation;
•certain factors discussed elsewhere in this report.
Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common stock, Series A Preferred Stock and 2029 Secured Notes.
The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.
Information About Us
Investors should note that we make available, free of charge on our website at www.summitmidstream.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. We may use the Investors section of our website to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. Documents and information on our website are not incorporated by reference herein.
The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Interest Rate Risk
Our interest rate risk exposure, which is largely related to our indebtedness, has not changed materially since December 31, 2023. As of September 30, 2024, we had approximately $689.7 million principal of fixed-rate debt, $150.0 million outstanding under our variable rate Amended and Restated ABL Facility and $133.3 million outstanding under the variable rate Permian Transmission Term Loan (see Note 8 - Debt). As of September 30, 2024, we had $120.0 million of interest rate exposure hedged to offset the impact of changes in interest rates on our Permian Transmission Term Loan. While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Amended and Restated ABL Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. For additional information, see the “Interest Rate Risk” section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2023 Annual Report and updates to our risk factors included herein.
See Note 8 – Debt for additional information on our Refinancing Transactions.
Commodity Price Risk
We generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and other processing arrangements with certain of our customers in the Rockies and Piceance segments, (ii) the sale of natural gas we retain from certain Barnett segment customers and (iii) the sale of condensate we retain from certain gathering services in the Piceance segment. Our gathering agreements with certain Barnett customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes. Our current commodity price risk exposure has not changed materially since December 31, 2023. For additional information, see the “Commodity Price Risk” section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2023 Annual Report.
Item 4. Controls and Procedures.
Under the direction of our Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and concluded that (i) our disclosure controls and procedures were effective as of September 30, 2024 and (ii) no change in internal control over financial reporting occurred during the quarter ended September 30, 2024, other than the change discussed below, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
During the third quarter of 2024, we added internal control processes over financial reporting as a result of our Corporate Reorganization and resulting federal and state income tax requirements.
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not currently a party to any significant legal or governmental proceedings, except as described below. In addition, we are not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which we are subject.
Fiberspar Corporation.On May 3, 2022, Fiberspar Corporation (“Fiberspar”) filed a petition in the District Court of Harris County, Texas alleging, before costs and interest, over $5.0 million owed but not paid for orders of pipeline product from Fiberspar. The petition asserts causes of action for breach of contract and suit on sworn account. A civil action on the same claims had been filed by Fiberspar in 2016 but was dismissed without prejudice pursuant to a standstill and tolling agreement that expired in 2021. We filed an answer on September 6, 2022 denying Fiberspar’s claims and asserting counter claims. The case is pending in the District Court of Harris County, Texas. We are unable to predict the final outcome of this matter.
Global Settlement.On August 4, 2021, the Partnership and several of its subsidiaries entered into agreements to resolve government investigations into the previously disclosed 2015 Blacktail Release, from a pipeline owned and operated by Meadowlark Midstream, which at the time was a wholly owned subsidiary of Summit Investments (together with Meadowlark Midstream, the “Companies”). The Companies entered into the following agreements to resolve the U.S. federal and North Dakota state governments’ environmental claims against the Companies with respect to the 2015 Blacktail Release: (i) a Consent Decree with (a) the DOJ, on behalf of the U.S. Environmental Protection Agency and the U.S. Department of Interior, and (b) the State of North Dakota, on behalf of the North Dakota Department of Environmental Quality and the North Dakota Game and Fish Department, lodged with the U.S. District Court; (ii) a Plea Agreement with the United States, by and through the U.S. Attorney for the District of North Dakota, and the Environmental Crimes Section of the DOJ; and (iii) a Consent Agreement with the North Dakota Industrial Commission (together, the “Global Settlement”).
The Consent Decree provides for, among other requirements and subject to the conditions therein, (i) payment of total civil penalties and reimbursement of assessment costs of approximately $21.25 million, with the federal portion of penalties payable over up to five years and the state portion of penalties payable over up to, for the federal and state civil amounts, six years and, for the federal criminal amounts, five years, with interest accruing at, for the federal and state civil amounts, a fixed rate of 3.25% and, for the federal criminal amounts, a variable rate set by statute; (ii) continuation of remediation efforts at the site of the 2015 Blacktail Release; (iii) other injunctive relief, including, but not limited to, control room management, an environmental management system audit, training, and reporting; and (iv) no admission of liability to the U.S. or North Dakota. The Consent Decree was entered by the U.S. District Court on September 28, 2021.
The Consent Agreement settles a complaint brought by the North Dakota Industrial Commission in an administrative action against the Companies for alleged violations of the North Dakota Administrative Code (“NDAC”) arising from the 2015 Blacktail Release on the following terms: (i) the Companies admit to three counts of violating the NDAC; (ii) the Companies agree to follow the terms and conditions of the Consent Decree, including payment of penalty and reimbursement amounts set forth in the Consent Decree; and (iii) specified conditions in the Consent Decree regarding operation and testing of certain existing produced water pipelines shall survive until those pipelines are properly abandoned.
Under the Plea Agreement, the Companies agreed to, among other requirements and subject to the conditions therein, (i) enter guilty pleas for one charge of negligent discharge of a harmful quantity of oil and one charge of knowing failure to immediately report a discharge of oil; (ii) sentencing that includes payment of a fine of $15.0 million plus mandatory special assessments over a period of up to five years with interest accruing at the federal statutory rate; (iii) organizational probation for a minimum period of three years from sentencing on December 6, 2021, which will include payment in full of certain components of the fines and penalty amounts; and (iv) compliance with the remedial measures in the Consent Decree.
On December 6, 2021, the U.S. District Court accepted the Plea Agreement. This Global Settlement resulted in losses amounting to $36.3 million and will be paid over five to six years, of which we have paid principal amounts of $17.7 million as of September 30, 2024.
Item 1A. Risk Factors.
You should carefully consider the following risk factors in addition to the other information included in this Quarterly Report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock. Below is a summary of the principal risks associated with an investment in the Company. This summary should not be relied upon as an exhaustive list of the material risks facing our business.
•We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, to enable us to pay dividends to holders of our Series A Preferred Stock and common stock.
•We depend on a relatively small number of customers for a significant portion of our revenues.
•We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results.
•Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and results of operations.
•If our customers do not increase the volumes they provide to our gathering systems, our results of operations and financial condition may be materially adversely affected.
•Certain of our gathering and processing agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.
•We have not obtained independent evaluations of all of the reserves connected to our gathering systems; therefore, in the future, customer volumes on our systems could be less than we anticipate.
•Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results.
•We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.
•If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenues and cash flows could be materially adversely affected.
•Crude oil and natural gas production and gathering may be adversely affected by weather conditions and terrain, which in turn could negatively impact the operations of our gathering, treating, transportation and processing facilities and our construction of additional facilities.
•Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could materially adversely affect our results of operations and financial condition.
•We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
•A transition from hydrocarbon energy sources to alternative energy sources could lead to changes in demand, technology and public sentiment, which could have material adverse effects on our business and results of operations.
Risks Related to Our Finances
•Limited access to and/or availability of the commercial bank market or debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.
•We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and may limit our flexibility to obtain financing and to pursue other business opportunities.
•We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful.
•Restrictions in the Permian Transmission Credit Facilities, the indenture governing the 2029 Secured Notes and the Amended and Restated ABL Facility could materially adversely affect our business, financial condition, results of operations and ability to make cash dividends.
•An increase in interest rates will cause our debt service obligations to increase.
•A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and independent third parties determine our credit ratings outside of our control.
•We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. As a result, we may be required to expend significant funds for legal defense or to settle claims. Any such loss, if incurred, could be material.
•A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.
•Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues.
•We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state and local regulation and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.
•We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
•We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.
•Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the services we provide.
•Statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
•Our business is subject to complex and evolving United States and international laws and regulations regarding privacy and data protection. Many of these data protection laws are subject to change and uncertain interpretation, and could result in claims, increased cost of operations or otherwise harm our business.
Risks Related to the Common Stock and Series A Preferred Stock
•The price of the common stock or Series A Preferred Stock may experience volatility.
•Our Governing Documents contain provisions that may make it difficult for a third party to acquire control of the Company, even if a change in control would result in the purchase of your shares of common stock or Series A Preferred Stock at a premium to the market price or would otherwise be beneficial to you.
•We do not expect to pay dividends on our common stock for the foreseeable future.
•The value of our common stock may be diluted by future equity issuances and shares eligible for future sale may have adverse effects on our share price.
Risks Related to the Transaction
•We will be subject to certain uncertainties while the Transaction is pending, which could adversely affect our business.
•Company stockholders as of immediately prior to the Transaction will have reduced ownership in the combined company immediately following the Transaction.
•The market price for Common Stock following the closing of the Transaction may be affected by factors different from those that historically have affected or currently affect the Common Stock.
•We may be subject to lawsuits relating to the Transaction, which could adversely affect our business, financial condition and operating results.
•The termination of the Business Contribution Agreement could negatively impact our business or result in us being required to pay a termination fee.
•The failure to successfully integrate the business and operations of Tall Oak in the expected time frame may adversely affect the Company’s future results.
•We will incur a substantial amount of additional debt to complete the Transaction. Our debt level may limit our financial and business flexibility.
•The market value of our Common Stock could decline if large amounts of our equity securities are sold following the Transaction.
•We may not achieve the anticipated benefits of the Transaction.
•The Transaction and subsequent changes in stock ownership of the Company (including upon the redemption or exchange of the Class B Common Stock and associated Partnership Common Units for Common Stock) may trigger a limitation on the utilization of net operating loss carryforwards of the Company.
•If the Partnership were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, the Company and the Partnership might be subject to potentially significant tax inefficiencies.
Risks Related to Our Operations
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, to enable us to pay dividends to holders of our Series A Preferred Stock and common stock.
We may not have sufficient available cash from operating surplus each quarter to pay the dividends to holders of our Series A Preferred Stock and common stock. We have not made a distribution on our common stock or Series A Preferred Stock, or prior to the Corporate Reorganization, our Series A Preferred Units or our common units, since we announced suspension of those dividends on May 3, 2020. Because our Series A Preferred Stock rank senior to our common stock with respect to divided rights, any accrued amounts on our Series A Preferred Stock must first be paid prior to our resumption of dividends to our holders of common stock. As of September 30, 2024, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $43.0 million.
Further, absent a material change to our business, we do not expect to pay dividends on the common stock or Series A Preferred Stock in the foreseeable future, and our outstanding indebtedness restricts our ability to pay cash dividends on any of our equity securities. We intend to use our cash flow to reduce debt and invest in our business.
The amount of cash we can distribute on our common stock principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
•the volumes we gather, transport, treat and process;
•the level of production of natural gas and crude oil (and associated volumes of produced water) from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, crude oil, natural gas and NGLs;
•damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters, accidents and acts of terrorism;
•leaks or accidental releases of hazardous materials into the environment;
•weather conditions and seasonal trends;
•changes in the fees we charge for our services;
•changes in contractual MVCs and our customer’s capacity to make MVC shortfall payments when due;
•the level of competition from other midstream energy companies in our areas of operation;
•changes in the level of our operating, maintenance and general and administrative expenses;
•regulatory action affecting the supply of, or demand for, crude oil, natural gas and NGLs, the fees we can charge, how we contract for services, our existing contracts, our operating and maintenance costs or our operating flexibility;
•adverse economic impacts from the COVID-19 pandemic or other epidemics, including disruptions in demand for oil, natural gas and other petroleum products, supply chain disruptions, and decreased productivity resulting from illness, travel restrictions, quarantine, or government mandates; and
•prevailing economic and market conditions.
In addition, the actual amount of cash we have available for distribution to our holders of common stock depends on other factors, some of which are beyond our control, including:
•the level and timing of capital expenditures we make;
•the level of our operating, maintenance and general and administrative expenses;
•the cost of acquisitions, if any;
•our ability to sell assets, if any, and the price that we may receive for such assets;
•our debt service requirements and other liabilities;
•our ability to borrow funds and access the debt and equity capital markets;
•restrictions contained in our debt agreements;
•the amount of cash reserves established by us;
•not receiving anticipated shortfall payments from our customers;
•adverse legal judgments, fines and settlements;
•dividends, if any, paid on our Series A Preferred Stock or on the preferred stock of our subsidiaries, including the Subsidiary Series A Preferred Units; and
•other business risks affecting our cash levels.
We depend on a relatively small number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of our customers could materially adversely affect our revenues, cash flows and results of operations.
Certain of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our customers could have a material adverse effect on our revenues, cash flows and results of operations. We expect our exposure to concentrated risk of nonpayment or nonperformance to continue as long as we remain substantially dependent on a relatively small number of customers for a significant portion of our revenues.
If any of our customers curtail or reduce production in our areas of operation, it could reduce throughput on our systems and, therefore, materially adversely affect our revenues, cash flows and results of operations.
Further, we are subject to the risk of non-payment or non-performance by our larger customers. We cannot predict the extent to which our customers’ businesses would be impacted if conditions in the energy industry deteriorate, nor can we estimate the impact such conditions would have on any of our customers’ abilities to execute their drilling and development programs or perform under our gathering and processing agreements. An extended low commodity price environment negatively impacts natural gas producers causing some producers in the industry significant economic stress, including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent that any customer is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material non-payment or non-performance by our customers could adversely affect our business and operating results.
We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results.
Although we attempt to assess the creditworthiness and associated liquidity of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and cash flows. In addition, there can be no assurance that our contract counterparties will perform or adhere to existing or future contractual arrangements, including making any required shortfall payments or other payments due under their respective contracts.
The policies and procedures we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, if necessary, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our policies and procedures prove to be inadequate, our financial and operational results may be negatively impacted.
Some of our counterparties may be highly leveraged, have limited financial resources and/or have recently experienced a rating agency downgrade and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices could have a negative impact on our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us.
Any material nonpayment or nonperformance by any of our counterparties or suppliers could require us to pursue substitute counterparties or suppliers for the affected operations or reduce our operations. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.
Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and results of operations.
Lower natural gas, NGL and crude oil prices could negatively impact exploration, development and production of natural gas and crude oil, thereby resulting in reduced throughput on our gathering systems. If natural gas, NGL and/or crude oil prices decrease, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In the latter half of 2022 and the first half of 2023, the Henry Hub Natural Gas Spot Price declined from a monthly average of $8.81 per MMBtu in August 2022 to a monthly average of $2.18 per MMBtu in June 2023, before rising slightly in the second half of 2023 to close the year at $2.58 per MMBtu on December 29, 2023. As of September 30, 2024, Henry Hub 12-month strip pricing closed at $2.65 per MMBtu. Cushing, Oklahoma West Texas Intermediate crude oil spot prices similarly trended down in the latter half of 2022 through early 2023, from a monthly average of $114.84 per barrel in June 2022 to a monthly average of $70.25 per barrel in June 2023, closing the year at $71.89 per barrel on December 29, 2023. As of September 30, 2024, West Texas Intermediate 12-month strip pricing closed at $68.75 per barrel.
Because of the natural decline in production from our customers’ existing wells, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes that we gather and process could materially adversely affect our business and operating results.
The customer volumes that support our business depend on the level of production from natural gas and crude oil wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of volume throughput. The primary factors affecting our ability to obtain new sources of volume throughput include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for new volumes on our systems.
We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things:
•the availability and cost of capital;
•prevailing and projected hydrocarbon commodity prices;
•demand for crude oil, natural gas and other hydrocarbon products, including NGLs;
•levels of reserves;
•geological considerations;
•environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and
•the availability of drilling rigs and other costs of production and equipment.
Fluctuations in energy prices can also greatly affect the development of new crude oil and natural gas reserves. Drilling and production activities generally decrease as commodity prices decrease. In general terms, the prices of crude oil, natural gas and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
•worldwide economic and geopolitical conditions;
•global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19, which may reduce demand for crude oil, natural gas and NGLs because of reduced global or national economic activity;
•weather conditions and seasonal trends;
•the levels of domestic production and consumer demand;
•the availability of imported liquefied natural gas (“LNG”);
•the ability to export LNG;
•the availability of transportation and storage systems with adequate capacity;
•the volatility and uncertainty of regional pricing differentials and premiums;
•the price and availability of alternative fuels, including alternative fuels that benefit from government subsidies;
•the cost and availability of alternative energy sources;
•the nature and extent of governmental regulation and taxation; and
•the anticipated future prices of crude oil, natural gas and other hydrocarbon products, including NGLs.
Because of these factors, even if new crude oil or natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenues and cash flows and materially adversely affect our results of operations.
In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins and may have steeper production decline curves than initially anticipated. Should we determine that the economics of our gathering, treating, transportation and processing assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution.
Many of our costs are fixed and do not vary with our throughput. These costs will not decline ratably or at all should we experience a reduction in throughput, which could result in a decline in our revenues and cash flows and materially adversely affect our results of operations and financial condition.
If our customers do not increase the volumes they provide to our gathering systems, our results of operations and financial condition may be materially adversely affected.
If we are unsuccessful in attracting new customers and/or new gathering opportunities with existing customers, our results of operations will be impaired. Our customers are not obligated to provide additional volumes to our gathering systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. Reductions by our customers in our areas of mutual interest could result in reductions in throughput on our systems and materially adversely impact our results of operations and financial condition.
Certain of our gathering and processing agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.
We designed those gathering and processing agreements that contain MVC provisions to generate stable cash flows for us over the life of the MVC contract term while also minimizing our direct commodity price risk. Under certain of these MVCs, our customers agree to ship a minimum volume on our gathering systems or send a minimum volume to our processing plants or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. In addition, our gathering and processing agreements may also include an aggregate MVC, which represents the total amount that the customer must flow on our gathering system or send to our processing plants (or an equivalent monetary amount) over the MVC term. If such customer’s actual throughput volumes are less than its MVC for the contracted measurement period, it must make a shortfall payment to us at the end of the applicable measurement period. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable fee. To the extent that a customer’s actual throughput volumes are above or below its MVC for the applicable contracted measurement period, certain of our gathering agreements contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments, which could have a material adverse effect on our results of operations, financial condition and cash flows.
We have not obtained independent evaluations of all of the reserves connected to our gathering systems; therefore, in the future, customer volumes on our systems could be less than we anticipate.
We do not routinely obtain or update independent evaluations of the reserves connected to our systems. Moreover, even if we did obtain independent evaluations of all of the reserves connected to our systems, such evaluations may prove to be incorrect. Crude oil and natural gas reserve engineering requires subjective estimates of underground accumulations of crude oil and natural gas and assumptions concerning future crude oil and natural gas prices, future production levels and operating and development costs.
Accordingly, we may not have accurate estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional volumes, it could have a material adverse effect on our business, results of operations and financial condition.
Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results.
We compete with other midstream companies in our areas of operations, some of which are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors may have assets in closer proximity to natural gas and crude oil supplies and may have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our areas of mutual interest, non-customer producers that lease acreage within any of our areas of mutual interest may choose to use one of our competitors for their gathering and/or processing service needs.
In addition, our customers may develop their own gathering systems outside of our areas of mutual interest. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be materially adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.
We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.
Our gathering, treating, transportation and processing contracts have terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with other customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain areas of mutual interest from new customers in the future, and we may be unable to renew existing areas of mutual interest with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
•the level of existing and new competition to provide gathering and/or processing services in our areas of operation;
•the macroeconomic factors affecting gathering, treating, transporting and processing economics for our current and potential customers;
•the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
•the extent to which the customers in our areas of operation are willing to contract on a long-term basis; and
•the effects of federal, state or local regulations on the contracting practices of our customers.
To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline.
If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenues and cash flows could be materially adversely affected.
Our gathering systems connect to third-party pipelines and other midstream facilities, such as processing plants, rail terminals and produced water disposal facilities. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable due to issues including, but not limited to, testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other hazards. In addition, we do not have interconnect agreements with all of these pipelines and other facilities and the agreements we do have may be terminated in certain circumstances and/or on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the natural gas, crude oil and produced water that we gather and/or process, our revenues, cash flows and results of operations could be materially adversely affected.
Crude oil and natural gas production and gathering may be adversely affected by weather conditions and terrain, which in turn could negatively impact the operations of our gathering, treating, transportation and processing facilities and our construction of additional facilities.
Extended periods of below freezing weather and unseasonably wet weather conditions, especially in North Dakota, Colorado, Texas and West Virginia, can be severe and can adversely affect crude oil and natural gas operations due to the potential shut-in of producing wells or decreased drilling activities. These types of interruptions could result in a decrease in the volumes supplied to our gathering systems. Further, delays and shutdowns caused by severe weather may have a material negative impact on the continuous operations of our gathering, treating, transporting and processing systems, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our customers
and thereby give rise to certain termination rights and/or the release of dedicated acreage. Any resulting terminations or releases could materially adversely affect our business and results of operations.
We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their locations and surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly. For example, certain of our pipeline facilities are located in locations with significant elevation changes, which may require specially designed facilities and special installation considerations. If such facilities are not designed or installed correctly, do not perform as intended, or fail, we may be required to incur significant expenditures to correct or repair the deficiencies, or may incur significant damages to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damage to the surrounding environment, including slope failures, stream impacts and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines.
Finally, most scientists have concluded that increasing concentrations of greenhouse gasses (“GHGs”) in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods, changes in weather patterns, extreme temperatures and other climatic events. While we cannot predict with any certainty at this time whether we will be affected by these possibilities, severe weather associated with climate change could result in disruptions or delays to our operations, damage to our assets and facilities and increased operating costs, any of which could materially adversely affect our business and results of operations.
Interruptions in operations at any of our facilities may adversely affect our operations and cash flows available for dividends.
Our operations depend upon the infrastructure that we have developed and constructed. Any significant interruption at any of our gathering, treating, transporting or processing facilities, or in our ability to provide gathering, treating, transporting or processing services, could adversely affect our operations and cash flows available for dividends. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:
•unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities;
•restrictions imposed by governmental authorities or court proceedings;
•labor difficulties that result in a work stoppage or slowdown;
•a disruption in the supply of resources necessary to operate our midstream facilities;
•damage to our facilities resulting from production volumes that do not comply with applicable specifications; and
•inadequate transportation and/or market access to support production volumes, including lack of pipeline, rail terminals, produced water disposal facilities and/or third-party processing capacity.
Any significant interruption at any of our gathering, treating, transporting or processing facilities, or in our ability to provide gathering, treating, transporting or processing services, could adversely affect our operations.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant incident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant incidents or events for which we are insured, our operations and financial results could be materially adversely affected.
Our operations are subject to all of the risks and hazards inherent in the operation of gathering, treating, transporting and processing systems, including:
•damage to pipelines, processing plants, compression assets, related equipment and surrounding properties caused by tornadoes, floods, freezes, fires and other natural disasters and acts of terrorism;
•inadvertent damage from construction, vehicles, farm and utility equipment;
•leaks or losses resulting from the malfunction of equipment or facilities;
•ruptures, fires and explosions; and
•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain of our systems in or near
populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from such events.
These events may also result in the curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on portions or all of our gathering systems. Potential customer impacts arising from service interruptions on segments of our gathering systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive MVCs during times of constrained capacity, temporary or permanent release of production dedications, and solicitation of existing customers by others for potential new projects that would compete directly with our existing services. Such circumstances could materially adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operations.
Although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant incident or event occurs for which we are not fully insured, it could materially adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of industry or market conditions, including any reluctance by insurance companies to insure oil and gas operations for political or other reasons, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover from the seller of the assets in the event of any potential environmental liabilities.
Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could materially adversely affect our results of operations and financial condition.
The construction of new assets, including for example, the Double E Pipeline, which was placed into service in November 2021, involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control.
Such construction projects may also require the expenditure of significant amounts of capital and financing, traditional or otherwise, that may not be available on economically acceptable terms or at all. If we undertake these projects, our revenue may not increase immediately upon the expenditure of funds for a particular project and they may not be completed on schedule, at the budgeted cost, or at all.
Moreover, we could construct facilities to capture anticipated future production growth in a region where such growth does not materialize or only materializes over a period materially longer than expected. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate due to the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition.
In addition, the construction of additions or modifications to our existing gathering, treating, transporting and processing assets and the construction of new midstream assets may require us to obtain federal, state and local regulatory environmental or other authorizations. The approval process for gathering, treating, transporting and processing activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering, treating, transporting and processing activities in new production areas. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. In addition, various officials and candidates at the federal, state and local levels have made climate-related pledges or proposed banning hydraulic fracturing altogether. As a result, we may be unable to obtain such authorizations and may, therefore, be unable to connect new volumes to our systems or capitalize on other attractive expansion opportunities. A future government shutdown could delay the receipt of any federal regulatory approvals. Additionally, it may become more expensive for us to obtain authorizations or to renew existing authorizations. If the cost of renewing or obtaining new authorizations increases materially, our cash flows could be materially adversely affected.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies either perpetually or for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we might have to
relocate our pipelines and related infrastructure. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition.
Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel, and a shortage of skilled labor in the midstream energy industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations.
Our ability to operate our business and implement our strategies depends on our continued ability to attract and retain highly skilled personnel with midstream energy industry experience and competition for these persons in the midstream energy industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.
Furthermore, as a result of labor shortages we have experienced difficulty in recruiting and hiring skilled labor throughout our organization. The operation of gathering, treating, transporting and processing systems requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. If we continue to experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our employees, our business and results of operations could be materially adversely affected.
A transition from hydrocarbon energy sources to alternative energy sources could lead to changes in demand, technology and public sentiment, which could have material adverse effects on our business and results of operations.
Increased public attention on climate change and corresponding changes in consumer, commercial and industrial preferences and behavior regarding energy use and generation may result in:
•technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power as well as battery technology);
•increased availability of, and increased demand from consumers and industry for, energy sources other than crude oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and
•development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.
Such developments relating to a transition from oil and gas to alternative energy sources and a lower-carbon economy may reduce the demand for natural gas and crude oil and other products made from hydrocarbons. For example, in November 2023, the international community, including over 150 governments, gathered in Dubai at the United Nations Climate Change Conference in the United Arab Emirates (“COP28”) and announced a new climate deal that calls on countries to ratchet up action on climate, and, on December 13, 2023, COP28 issued its first global stocktake, which calls on parties, including the U.S., to contribute to global efforts to transition away from fossil fuels, reduce methane emissions, and triple renewable energy capacity and double energy efficiency improvement by 2030, among other things, to achieve net zero by 2050. Any significant decrease in the demand for natural gas and crude oil resulting from such developments could reduce the volumes of natural gas and crude oil that we gather and process, which could adversely affect our business and operating results.
Furthermore, if any such developments reduce the desirability of participating in the midstream oil and gas industry, then such developments could also reduce the availability to us of necessary third-party services or facilities that we rely on, which could increase our operational costs and have an adverse effect on our business and results of operations.
Such developments and accompanying societal expectations on companies to address climate change, investor and societal expectations regarding voluntary environmental, social and governance (“ESG”) initiatives and disclosures could, among other things, increase costs related to compliance and stakeholder engagement, increase reputational risk and negatively impact our access to and cost of accessing capital. For example, some prominent investors have announced their intention to no longer invest in the oil and gas sector, citing climate change concerns. If other financial institutions and investors refuse to invest in or provide capital to the oil and gas sector in the future because of these reputational risks, that could result in capital being unavailable to us, or only at significantly increased cost. In addition, we have established a corporate strategy intended to meet ESG-related objectives, which currently includes certain ESG targets. However, we cannot guarantee that our strategy will meet our ESG-related objectives. Such initiatives are voluntary, not binding on our business or management and subject to change. We may determine in our discretion that it is not feasible or practical to implement or complete certain of our ESG-related initiatives, or to meet previously set goals and targets based on cost, timing or other considerations. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters (or meet ESG-related goals and targets that we have set), as they continue to evolve, if we are perceived to have not responded appropriately or quickly enough to
growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, or if estimates, assumptions, and/or third-party information we currently believe to be reasonable are subsequently considered erroneous or misinterpreted, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected.
Furthermore, negative public perception regarding the oil and gas industry resulting from, among other things, concerns raised by advocacy groups about climate change, emissions, hydraulic fracturing, seismicity, or oil spills may lead to increased litigation risk and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. More broadly, the enactment of climate change-related policies and initiatives across the market at the corporate level and/or investor community level may in the future result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation, driving down demand for our products, or stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels).
Risks Related to Our Finances
Limited access to and/or availability of the commercial bank market or debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.
To expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gathering and processing agreements also require us to spend significant amounts of capital, over a short period of time, to construct and develop additional midstream assets to support our customers’ development projects. Depending on our customers’ future development plans, it is possible that the capital required to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under the Amended and Restated ABL Facility or the Permian Transmission Credit Facilities.
We plan to use cash from operations, incur borrowings and/or sell additional shares of capital stock or other securities to fund our future expansion capital expenditures. Our ability to obtain financing or to access the capital markets for future debt or equity offerings may be limited by (i) our financial condition at the time of any such financing or offering, (ii) covenants in our debt agreements, (iii) restrictions imposed by our Series A Preferred Stock, (iv) general economic conditions and contingencies, (v) increasing disfavor among many investors towards investments in fossil fuel companies and (vi) general weakness in the debt and equity capital markets and other uncertainties that are beyond our control, including political uncertainty in the U.S. (including the ongoing debates related to the U.S. federal government budget), volatility and disruption in global capital and credit markets (including those resulting from geopolitical events, such as the Russian invasion of Ukraine or the continued conflict in the Middle East), uncertainty regarding increases or decreases in interest rates resulting from changes in the federal funds rate range targeted by the Federal Reserve, pandemics, epidemics and other outbreaks, such as COVID-19, or other adverse developments that affect financial institutions. In addition, lenders are facing increasing pressure to curtail their lending activities to companies in the oil and natural gas industry.
We have not made a dividend on our common stock or Series A Preferred Stock, or prior to the Corporate Reorganization, the common units or Series A Preferred Units, since we announced suspension of those distributions on May 3, 2020, and these suspensions of dividends may further reduce demand for our common stock or Series A Preferred Stock. Because our Series A Preferred Stock ranks senior to our common stock with respect to distribution rights, any accrued amounts on our Series A Preferred Stock must first be paid prior to our resumption of dividends to holders of our common stock. As of September 30, 2024, the amount of accrued and unpaid dividends on the Series A Preferred Stock totaled $43.0 million. Further, absent a material change to our business, we do not expect to pay dividends on the common stock or Series A Preferred Stock in the foreseeable future. Additionally, our debt agreements restrict our ability to pay cash dividends on any of our equity securities. As such, if we are unable to raise expansion capital, we may lose the opportunity to make acquisitions, pursue new organic development projects, or to gather, treat and process new production volumes from our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining external funds for expansion capital expenditures through the capital markets, the terms thereof could limit our ability to pay dividends to our common equityholders.
We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and may limit our flexibility to obtain financing and to pursue other business opportunities.
As of September 30, 2024, we had $957.0 million of indebtedness outstanding, and the unused portion of the Amended and Restated ABL Facility totaled $349.2 million after giving effect to the issuance of $0.8 million in outstanding but undrawn
irrevocable standby letters of credit. Our existing and future debt services obligations could have significant consequences, including among other things:
•limiting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes and/or obtaining such financing on favorable terms;
•reducing our funds available for operations, future business opportunities and cash dividends by that portion of our cash flow required to make interest payments on our debt;
•increasing our vulnerability to competitive pressures or a downturn in our business or the economy generally; and
•limiting our flexibility in responding to changing business and economic conditions.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control, such as commodity prices and governmental regulation.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful.
Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including the Amended and Restated ABL Facility, the Permian Transmission Credit Facilities and the 2029 Secured Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our operating cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to adopt alternative financing strategies, such as reducing or delaying investments and capital expenditures, selling assets, seeking additional capital or restructuring or refinancing our indebtedness, some or all of which may not be available to us on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness.
The 2029 Secured Notes will mature on October 31, 2029 and have interest payable semi-annually in arrears on each February 15 and August 15, commencing on February 15, 2025. As of September 30, 2024, $575.0 million of the 2029 Secured Notes were outstanding.
The Amended and Restated ABL Facility will mature on the earliest of (a) July 26, 2029, (b) July 31, 2029 if either (i) the outstanding amount of the 2029 Secured Notes (or any refinancing debt permitted under the Amended and Restated ABL Facility in respect thereof that has a final maturity date, scheduled amortization or any other scheduled repayment, mandatory prepayment, mandatory redemption or sinking fund obligation prior to the date that is 91 days after the Amended and Restated ABL Termination Date (provided, that the terms of such permitted refinancing debt may (x) require the payment of interest from time to time and (y) include customary mandatory redemptions, prepayments or offers to purchase with proceeds of asset sales or upon the occurrence of a change of control)) on such date equals or exceeds $50.0 million or (ii) the outstanding amount of such debt described in clause (i) above on such date is less than $50.0 million and Liquidity (as defined in the Amended and Restated ABL Agreement) at any time on or after such date is less than the sum of (A) such outstanding amount and (B) the greater of (x) 10% of the aggregate Commitments (as defined in the Amended and Restated ABL Agreement) then in effect and (y) $50.0 million, and (c) any date on which the aggregate Commitments terminate thereunder. As of September 30, 2024, the Amended and Restated ABL Facility will mature on July 26, 2029.
Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior secured or unsecured notes, and our financial condition at the time. Any refinancing of our indebtedness could be at higher interest rates, may require the pledging of collateral and may require us to comply with more onerous covenants than we are currently subject to, which could further restrict our business operations. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations.
The agreements governing our debt place certain restrictions on our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions on terms acceptable to us, if at all, and the proceeds of any such dispositions may not be adequate to meet any debt service obligations then due.
Further, if for any reason we are unable to meet our debt service and principal repayment obligations, or if we fail to comply with the financial covenants in the documents governing our debt, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder
to be due and payable (which would in turn trigger cross-acceleration or cross-default rights among our other debt agreements), the lenders under the Amended and Restated ABL Facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our debt agreements were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to our creditors.
Restrictions in the Permian Transmission Credit Facilities, the indenture governing the 2029 Secured Notes and the Amended and Restated ABL Facility could materially adversely affect our business, financial condition, results of operations and ability to make cash dividends.
We are dependent upon the earnings and cash flows generated by our operations to meet our debt service obligations and to make cash dividends. The operating and financial restrictions and covenants in the Permian Transmission Credit Facilities, the indenture governing the 2029 Secured Notes, the Amended and Restated ABL Facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, the Amended and Restated ABL Facility, the Permian Transmission Credit Facilities and the indenture governing the 2029 Secured Notes, taken together, restrict our ability to, among other things:
•incur or guarantee certain additional debt;
•make certain cash dividends on or redeem or repurchase certain equity securities;
•make payments on certain other indebtedness;
•make certain investments and acquisitions;
•make certain capital expenditures;
•incur certain liens or other encumbrances or permit them to exist;
•enter into certain types of transactions with affiliates;
•enter into sale and lease-back transactions and certain operating leases;
•merge or consolidate with another company or otherwise engage in a change of control transaction; and
•transfer, sell or otherwise dispose of certain assets.
The Amended and Restated ABL Facility also contains covenants requiring Summit Holdings to maintain certain financial ratios and meet certain tests. Summit Holdings’ ability to meet those financial ratios and tests can be affected by events beyond its control, and we cannot guarantee that Summit Holdings will meet those ratios and tests.
The provisions of the Permian Transmission Credit Facilities, the indenture governing the 2029 Secured Notes, and the Amended and Restated ABL Facility may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the Permian Transmission Credit Facilities, the indenture governing the 2029 Secured Notes, and the Amended and Restated ABL Facility could result in a default or an event of default that could enable our lenders and/or senior noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, the lenders under the Amended and Restated ABL Facility could proceed against the collateral granted to them to secure such debt. If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and our equityholders could experience a partial or total loss of their investment. The Amended and Restated ABL Facility also has cross default provisions that apply to any other indebtedness we may have, and the indenture governing the 2029 Secured Notes have cross default provisions that apply to certain other indebtedness. Any of these restrictions in the Amended and Restated ABL Facility, the Permian Transmission Credit Facilities and the indenture governing the 2029 Secured Notes could materially adversely affect our business, financial condition, cash flows and results of operations.
Inflation could have adverse effects on our results of operation.
Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021 through 2023 due to a substantial increase in money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose from 5.4% in June 2021 to 7.0% in December 2021 to 8.2% in September 2022.
While inflation has declined since the second half of 2022, declining to 2.4% in September 2024, further increases in inflation in 2024 could increase our labor and other operating costs and the overall cost of capital projects we undertake. An increase in inflation rates could negatively affect our profitability and cash flows, due to higher wages, higher operating costs, higher
financing costs, and/or higher supplier prices. We may be unable to pass along such higher costs to its customers. In addition, inflation may adversely affect customers’ financing costs, cash flows, and profitability, which could adversely impact their operations and our ability to offer credit and collect receivables.
An increase in interest rates will cause our debt service obligations to increase.
Since March 2022, the Federal Reserve has raised its target range for the federal funds rate multiple times to a current target range of 4.50% to 4.75%, and the timing of any potential further increases or decreases remains uncertain. Borrowings under the Amended and Restated ABL Facility and the Permian Transmission Credit Facilities bear interest at rates equal to SOFR plus margin. The interest rates are subject to adjustment based on fluctuations in SOFR, as applicable. An increase in the interest rates associated with our floating rate debt would increase our debt service costs and affect our results of operations and cash flow available for payments of our debt obligations. In addition, an increase in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.
A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and independent third parties determine our credit ratings outside of our control.
Moody’s Investors Service, Inc., Standard & Poor’s Ratings Services or Fitch Ratings, Inc. assign ratings to our senior unsecured credit from time to time. A downgrade of our credit rating could increase our future cost of borrowing and could require us to post collateral with third parties, including our hedging arrangements, which could negatively impact our available liquidity and increase our cost of debt. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we are experiencing significant working capital requirements or otherwise lacking liquidity, our results of operations, financial condition and cash flows could be adversely affected.
We have in the past and may in the future incur losses due to an impairment in the carrying value of our long-lived assets or equity method investments.
We recorded long-lived asset impairments of $67.9 million during the nine months ended September 30, 2024, $0.5 million in 2023 and $91.6 million in 2022. When evidence exists that we will not be able to recover a long-lived asset’s carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test long-lived assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. With respect to property, plant and equipment and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset’s use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carrying value exceeds the asset’s fair value. We determine fair value using either a market-based approach, an income-based approach in which we discount the asset’s expected future cash flows to reflect the risk associated with achieving the underlying cash flows, or a mixture of both market-and income-based approaches. We evaluate our equity method investments for impairment whenever events or circumstances indicate that a decline in fair value is other than temporary. Any impairment determinations involve significant assumptions and judgments. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to impairment charges. Adverse changes in our business or the overall operating environment, such as lower commodity prices, may affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.
A portion of our revenues are directly exposed to changes in crude oil, natural gas and NGL prices, and our exposure may increase in the future.
During the year ended December 31, 2023, we derived 39% of our revenues from (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Rockies and Piceance segments, (ii) the sale of natural gas we retain from certain Barnett customers, (iii) the sale of condensate we retain from our gathering services in the Rockies and Piceance segment and (iv) additional gathering fees that are tied to performance of certain commodity price indexes, which are then added to the fixed gathering rates. Consequently, our existing operations and cash flows have direct exposure to commodity price risk. Although we will seek to limit our commodity price exposure with new customers in the future, our efforts to obtain fee-based contractual terms may not be successful or the local market for our services may not support fee-based gathering and processing agreements. For example, we have percent-of-proceeds contracts with certain natural gas producer customers and we may, in the future, enter into additional percent-of-proceeds contracts with these customers or other customers or enter into keep-whole arrangements, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of the underlying commodities.
Furthermore, we may acquire or develop additional midstream assets in the future that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of natural gas and crude oil prices could have a material adverse effect on our business, results of operations and financial condition. For example, for a small portion of the natural gas gathered on our systems, we purchase natural gas from producers prior to delivering the natural gas to pipelines
where we typically resell the natural gas under arrangements including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices. If we expand the implementation of such natural gas purchase and sale arrangements within our business, such fluctuations could materially affect our business.
Regulatory and Environmental Policy Risks
We settled a matter that was previously under investigation by federal and state regulatory agencies regarding a pipeline rupture and release of produced water by one of our subsidiaries. The resulting compliance requirements of the settlement may impact our results of operations or cash flows.
On August 4, 2021, we settled an incident involving a produced water disposal pipeline owned by our subsidiary Meadowlark Midstream Company, LLC that resulted in a discharge of materials into the environment, which was investigated by federal and state agencies. This settlement resulted in losses amounting to $36.3 million and will be paid over five (5) to six (6) years, of which we have paid principal amounts of $17.7 million as of September 30, 2024 and requires compliance with certain conditions and terms and conditions, which may impact our results of operations or cash flows.
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. As a result, we may be required to expend significant funds for legal defense or to settle claims. Any such loss, if incurred, could be material.
Expenditures made by us for the payment of litigation related costs, including legal defense costs and settlement payments, if any, reduce our cash flows available for debt service and dividends. Any such expenditures, if incurred, could be material.
A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.
Various aspects of our operations are subject to regulation by the various federal, state and local departments and agencies that have jurisdiction over participants in the energy industry. The regulation of our activities and the natural gas and crude oil industries frequently change as they are reviewed by legislators and regulators. For example, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has issued new proposed and final rules concerning pipeline safety in recent years. In November 2021, PHMSA issued a final rule that extended pipeline safety requirements to onshore gas gathering pipelines. The rule requires all onshore gas gathering pipeline operators to comply with PHMSA’s incident and annual reporting requirements. It also extends existing pipeline safety requirements to a new category of gas gathering pipelines, “Type C” lines, which generally include high-pressure pipelines that are larger than 8.625 inches in diameter. Safety requirements applicable to Type C lines vary based on pipeline diameter and potential failure consequences. The final rule became effective in May 2022 and operators were required to comply with the applicable safety requirements by November 2022. In addition, in August 2022, PHMSA issued a final rule that established new or additional requirements for natural gas transmission lines related to the management of change process, integrity management, corrosion control standards, and pipeline inspections and repairs. In May 2023, PHMSA published a Notice of Proposed Rulemaking for regulatory amendments to reduce methane emissions from new and existing gas transmission, distribution, and regulated gas gathering pipelines with strengthened leakage survey and patrolling requirements, performance standards for advanced leak detection programs, leak grading and repair criteria with mandatory repair timelines, requirements for mitigation of emissions from blowdowns, pressure relief device design, configuration, and maintenance requirements, clarified requirements for investigating failures, and expanded reporting requirements. To the extent these or other new proposed or final rules create additional requirements for our pipelines, they could have a material adverse effect on our operations, operating and maintenance expenses and revenues. For additional information on the potential risks associated with PHMSA requirements, see “—We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.”
In addition, the adoption of proposals for more stringent legislation, regulation or taxation of drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. For example, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the Colorado Energy and Carbon Management Commission (“ECMC,” formerly the Colorado Oil and Gas Conservation Commission) from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. As part of its implementation of this law, in November 2020 the ECMC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. In addition, in May 2024, the Governor of Colorado signed into law Senate Bill 24-230, which imposes a production fee that applies to all oil and gas produced by a producer in the state on or after July 1, 2025 to fund clean transit initiatives. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. Regulatory agencies establish and, from time to time, change priorities, which may result in additional burdens on us, such as additional reporting requirements and more frequent audits of operations. Our operations and the markets in which we participate are affected by these laws,
regulations and interpretations and may be affected by changes to them or their implementation, which may cause us to realize materially lower revenues or incur materially increased operation and maintenance costs or both.
Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues.
Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations and is primarily regulated by state agencies. However, Congress has in the past considered, and may in the future consider, legislation to regulate hydraulic fracturing by federal agencies. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing. A number of states – such as Colorado, as discussed above – have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure and well construction requirements on crude oil and/or natural gas drilling activities. For example, during the 2021-2022 election cycle, Colorado representatives proposed a ballot initiative to ban hydraulic fracturing on all non-federal land, but the proposed initiative failed to garner significant support. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, Oregon, Washington, California and Vermont have done. In addition, certain local governments have adopted, and additional local governments may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. These initiatives and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future.
The EPA has also moved forward with various regulatory actions, including announcing final new regulations under the New Source Performance Standard (“NSPS”) to expand and strengthen emissions reduction requirements under NSPS OOOOa for new, modified and reconstructed oil and natural gas sources, and require states to reduce methane emissions from existing sources nationwide. The Bureau of Land Management (“BLM”) has also asserted regulatory authority over aspects of the hydraulic fracturing process and issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands, including requirements relating to well construction and integrity, handling of wastewater and chemical disclosure. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The U.S. District Court for the Northern District of California upheld the December 2017 rescission rule in a March 2020 decision, and the State of California and environmental plaintiffs appealed. The parties remain in settlement discussion.
Further, several federal governmental agencies (including the EPA) have conducted reviews and studies on the environmental aspects of hydraulic fracturing in the past. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.
State and federal regulatory agencies have also focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies, including those in Colorado and Texas, have modified their regulations or guidance to account for induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers.
Additionally, certain of our customers produce oil and gas on federal lands. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. Several states filed lawsuits challenging the suspension, and on June 15, 2021, a judge in the U.S. District Court for the Western District of Louisiana issued a nationwide temporary injunction blocking the suspension in July 2021. Although the injunction was subsequently overturned by the Court of Appeals for the Fifth Circuit, on remand the U.S. District Court issued a permanent injunction as requested by the plaintiff states in August 2022. The Department of the Interior has since resumed leasing. In July 2023, U.S. Department of Interior (“DOI”) proposed updates to its onshore oil and gas leasing regulations, which could further restrict oil and gas exploration and production on federal lands. DOI issued a final rule in April 2024, which includes new bonding requirements and attempts to direct oil and gas development away from wildlife habitat and cultural sites. The Biden Administration continues to evaluate federal leasing and could impose additional restrictions in the future.
If new or more stringent federal, state or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.
We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state and local regulation and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.
We believe that our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Interstate movements of crude oil on the Epping Pipeline in North Dakota are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”), and the rates, terms and conditions of service, and practices on the pipeline are subject to review and challenge before FERC.
Additionally, the Double E Pipeline, which provides interstate natural gas transmission service from southeastern New Mexico to the Waha hub in Texas, is subject to FERC jurisdiction under the NGA with respect to post-construction remediation activities, operations, and rates and terms and conditions of service. Pursuant to the NGA, Double E Pipeline’s existing interstate natural gas transportation rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate changes and changes to terms and conditions of service proposed by a regulated natural gas interstate pipeline may be protested and such changes can be delayed and may ultimately be rejected by FERC. FERC may also initiate reviews of an interstate pipeline’s rates. We cannot guarantee that any new or existing tariff rate for service on our FERC-regulated pipelines would not be rejected or modified by the FERC or subjected to refunds. Any successful challenge by a regulator or shipper in any of these matters could have a material adverse effect on our business, financial condition and results of operations.
We have certain long-term fixed priced natural gas and crude oil transportation contracts that cannot be adjusted even if our costs increase. As a result, our costs could exceed our revenues. In 2021, we entered into negotiated rate agreements with an average term of 10 years from the in-service date of the pipeline, which occurred on November 18, 2021 and with total maximum daily transportation quantities that increases from 585,000 Dth/d during the first year of the agreement to 1,000,000 Dth/d in the fourth year, which equates to approximately 74% of its certificated capacity of 1,350,000 Dth/d; these contracts are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts. It is possible that costs to perform services under our “negotiated or discount rate” contracts will exceed the negotiated or discounted rates. It is also possible with respect to discounted rates that if our filed “recourse rates” should ever be reduced below applicable discounted rates, we would only be allowed by FERC to charge the lower recourse rates, since FERC policy does not allow discount rates to be charged to the extent that they exceed applicable recourse rates. If these events were to occur, it could decrease the cash flow realized by our assets.
Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate,” which is generally fixed between the natural gas pipeline and the shipper for the contract term and does not necessarily vary with changes in the level of cost-based “recourse rates,” provided that the affected customer is willing to agree to such rates and that the FERC has accepted the negotiated rate agreement. These “negotiated or discount rate” contracts are not generally subject to adjustment for increased costs, which could be caused by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated or discounted rates, under current FERC policy, may be recoverable from other shippers in certain circumstances. For example, the FERC may recognize this shortfall in the determination of prospective rates in a future rate case. However, if the FERC were to disallow the recovery of such costs from other customers, it could decrease the cash flow realized by our assets.
We are also generally subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, and to FERC’s regulations thereunder, and also must comply with the other applicable provisions of the NGA and NGPA and FERC’s rules, regulations, and orders concerning the Double E Pipeline’s interstate natural gas pipeline business, including those that require us to provide firm and interruptible transportation service on an open access basis that is not unduly discriminatory or preferential. Violations of the NGA or NGPA, or the rules, regulations, and orders issued by FERC thereunder could result in the imposition of administrative and criminal remedies, including without limitation, revocation of certain authorities, disgorgement of ill-gotten gains, and civil penalties of up to approximately $1.5 million per day per violation of the NGA or its implementing regulations, subject to future adjustment for inflation. In addition, the Federal Trade Commission (“FTC”) holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in oil markets and has adopted broad rules and regulations prohibiting fraud and market manipulation. The FTC is also authorized to seek fines of up to approximately $1.5 million per violation, subject to future adjustment for inflation. The Commodity Futures Trading Commission (“CFTC”) is directed under the Commodity Exchange Act (“CEA”) to prevent price manipulation in the commodity, futures and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (the “Dodd-Frank Act”), and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures and swaps markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1.5 million per
violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for each violation of the anti-market manipulation provisions of the CEA.
The distinction between federally unregulated natural gas and crude oil pipelines and FERC-regulated natural gas and crude oil pipelines has been the subject of extensive litigation and is determined by FERC on a case-by-case basis. FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC, Congress or the courts. If our natural gas gathering operations or crude oil operations beyond the Epping Pipeline become subject to FERC jurisdiction under the NGA, the NGPA or the ICA, the result may materially adversely affect the rates we are able to charge and the services we currently provide and may include the potential for a termination of our gathering agreements with our customers. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, the NGPA or the ICA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.
We are subject to state and local regulation regarding the construction and operation of our gathering, treating, transporting and processing systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of natural gas and crude oil we may gather, treat and process. Ratable take statutes and regulations generally require gatherers to take natural gas and crude oil production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather, treat and process. Many states have adopted complaint-based regulation of gathering, treating, transporting and processing activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve access issues, rate grievances and other matters. Other state and municipal regulations do not directly apply to our business but may nonetheless affect the availability of natural gas and crude oil for gathering, treating, transporting and processing, including state regulation of production rates, maximum daily production allowable from wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs and revenues.
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our gathering, treating, transporting and processing operations are subject to stringent and complex federal, state and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection, including, for example, the Clean Air Act (“CAA”), the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Water Act, the Oil Pollution Control Act, the Resource Conservation and Recovery Act, the Endangered Species Act (the “ESA”) and the Toxic Substances Control Act. It is possible that future changes in environmental laws, regulations, or enforcement policies, including judicial or agency opinions or orders, could impose additional requirements or give rise to claims for damages to persons, property, natural resources, or the environment.
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and requisite permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.
There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass, and on which certain of our facilities are located, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third
parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance.
The Biden Administration is considering revisions to the leasing and permitting programs for oil and gas development on federal lands, which could materially adversely affect our industry and our financial condition and results of operations.
We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.
The U.S. Department of Transportation (“DOT”), through PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream Services LLC system is located. While the majority of our pipelines have historically met the DOT definition of gathering lines and were thus exempt from PHMSA’s integrity management requirements, we also operate a limited number of pipelines that are subject to the integrity management requirements. The regulations require operators, including us, to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•maintain processes for data collection, integration and analysis;
•repair and remediate pipelines as necessary;
•adopt and maintain procedures, standards and training programs for control room operations; and
•implement preventive and mitigating actions.
For additional information on PHMSA regulations relating to pipeline safety, see “—A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.”
Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the services we provide.
In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of GHGs, such as carbon dioxide and methane that may be contributing to global warming and energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. For example, the Inflation Reduction Act (“IRA”), signed into law in August 2022, includes a Methane Emissions Reduction Program to incentivize methane emission reductions and impose a fee on GHG emissions from certain oil and gas facilities. In addition, in January 2024, the EPA issued a proposed rule that would impose and collect methane emissions charges authorized under the IRA, beginning in March 2025. The methane charge and other related initiatives targeting methane emissions could impose additional costs on our operations.
In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). It is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. For example, in June 2022, as part of a Governor-directed statewide initiative to reduce GHG emissions by at least 45% by 2030, the New Mexico Environment Department finalized new rules that would establish emissions standards for volatile organic compounds and nitrogen oxides for oil and gas production and processing sources located in certain areas of the state with high ozone concentrations. Similarly, due to recent legislation approved in May 2024, the Colorado Department of Public Health and Environment is now required to propose rules to the Colorado Air Quality Control Commission to reduce nitrogen oxide emissions that oil and gas operations generate by 50% by 2030 relative to 2017 levels. We cannot currently determine the effect of these proposed regulations and other regulatory initiatives to implement state directives to reduce GHG emissions, that could, if implemented, impact the business, reputation, financial condition or results of our operations or that of our customers. In addition, in April 2021, the New Mexico Department of Energy, Minerals, and Natural Resources (“EMNRD”) finalized new rules concerning venting and
flaring of natural gas. EMNRD’s final rule could impose new or increased costs and obligations on our customers upstream of the Double E Pipeline.
Independent of Congress, the EPA has adopted regulations under its existing CAA authority. In 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations that, among other things, establish Prevention of Significant Deterioration construction and Title V operating permit reviews for certain large stationary sources of GHG emissions.
Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016 after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement (the “Paris Agreement”). In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the Paris Agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that, reversed the prior withdrawal, and the United States officially rejoined the Paris Agreement on February 19, 2021. As part of rejoining the Paris Agreement, President Biden announced that the United States would commit to a 50 to 52 percent reduction from 2005 levels of GHG emissions by 2030 and set the goal of reaching net-zero GHG emissions by 2050. In September 2021, the United States and the European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution by at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. Since its formal launch at the 26th Conference of the Parties, over 150 countries have joined the pledge. In November 2021, the Biden Administration expanded on this commitment and announced “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” establishing a roadmap to net zero emissions in the United States by 2050 through, among other things, improvements in energy efficiency; decarbonization of energy sources via electricity, hydrogen, and sustainable biofuels; and reductions in non-CO2 GHG emissions, such as methane and nitrous oxide. These initiatives followed a series of executive orders by President Biden designed to address climate change. On December 13, 2023, COP28 issued its first global stocktake, which calls on parties, including the U.S., to contribute to global efforts to transition away from fossil fuels, reduce methane emissions, triple renewable energy capacity and double energy efficiency improvements by 2030, among other things, to achieve net zero by 2050. While the stocktake agreement is not legally binding and has no enforcement mechanism, the United States could pass further legislation based on the agreement. Reentry into the Paris Agreement, the related stocktake agreement, new legislation, or President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations, which could have a material adverse effect on our business and that of our customers. In addition, in March 2024, the SEC issued rules regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The rules will require registrants to provide certain climate-related information in their registration statements and annual reports, including governance, risk management, financial impacts and strategy related to material climate-related risks, certain climate-related financial disclosures (subject to de minimis thresholds) and, in some instances, Scopes 1 and 2 GHG emissions. The SEC voluntarily stayed the rules pending completion of judicial review and are widely expected to face additional legal challenges going forward. While we cannot predict how the stay may ultimately impact the deadlines for compliance, we anticipate that the costs associated with preparation for implementation and compliance may be substantial. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors. While the Supreme Court’s June 2024 decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. ended the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives could continue.
Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address climate change and GHG emissions could require us to incur increased operating costs and could materially adversely affect demand for our services. The potential increase in the costs of our operations resulting from any legislation or regulation to address climate change or restrict emissions of GHG could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions, adhere to alternative energy requirements and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates we charge, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
In the Dodd-Frank Act, Congress adopted comprehensive financial reform legislation that establishes federal oversight over and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. Under this
legislation, the CFTC and the SEC and other regulatory authorities have promulgated rules and regulations, including rules and regulations relating to the regulation of certain swaps market participants, such as swap dealers, the clearing of certain swaps through central counterparties, the execution of certain swaps on designated contract markets or swap execution facilities, mandatory margin requirements for uncleared swaps, and the reporting and recordkeeping of swaps. In light of the continuing adjustment of the regulations, we cannot predict the ultimate effect of the rules and regulations on our business. Any new regulations or modifications to existing regulations could increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, or increase our exposure to less creditworthy counterparties.
In October 2020, the CFTC adopted rules that place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. We do not expect these regulations to materially impede our hedging activity at this time, but a companion rule on aggregation among entities under common ownership or control may have an impact on our ability to hedge our exposure to certain enumerated commodities.
The CFTC has implemented final rules regarding mandatory clearing of certain classes of interest rate swaps and certain classes of index credit default swaps. Mandatory trading on designated contract markets or swap execution facilities of certain interest rate swaps and index credit default swaps also began in 2014. At this time, the CFTC has not proposed any rules designating other classes of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. Although we may qualify for a commercial end-user exception from the mandatory clearing, trade execution and certain uncleared swaps margin requirements, mandatory clearing and trade execution requirements and uncleared swaps margin requirements applicable to other market participants, such as swap dealers, may affect the cost and availability of the swaps that we use for hedging.
Under the Dodd-Frank Act, the CFTC is also directed generally to prevent price manipulation and fraud in the following two markets: (i) physical commodities traded in interstate commerce, including physical energy and other commodities, and (ii) financial instruments, such as futures, options and swaps. The CFTC has adopted additional anti-market manipulation, anti-fraud and disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets. Should we violate these laws and regulations, we could be subject to CFTC enforcement action, material penalties and sanctions.
We currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to mitigate our exposure to fluctuations in the price of natural gas with respect to those volumes. The CFTC has finalized an interpretation clarifying whether and when certain forwards with volumetric optionality are to be regulated as forwards or qualify as options on commodities and therefore swaps. The application of this interpretation to any particular situation may impact our ability to enter into certain forwards or may impose additional requirements with respect to certain transactions.
In addition to the Dodd-Frank Act, regulators within the European Union and other foreign regulators have adopted and implemented local reforms generally comparable with the reforms under the Dodd-Frank Act. Enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties or may make any transactions involving cross-border swaps more expensive and burdensome. Additionally, the lingering absence of regulatory equivalency across jurisdictions may increase compliance costs and make it more costly to satisfy regulatory obligations.
We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups.
We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from environmental groups, landowners, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or other facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could have a material adverse effect on our business, financial condition and results of operations. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.
For example, in an April 15, 2020 ruling, amended May 11, 2020, the U.S. District Court for the District of Montana issued an order invalidating the U.S. Army Corps of Engineers (“Corps”) 2017 reissuance of Nationwide Permit 12 (“NWP 12”), the general permit governing discharges of dredged or fill material associated with pipeline and other utility line construction projects, to the extent it was used to authorize construction of new oil and gas pipelines. Environmental groups had alleged that the Corps failed to consult with federal wildlife agencies as required by the ESA. However, in January 2021, the EPA and Corps reissued NWP 12 as a general permit specific to oil and gas pipelines, moving other utility line activities into separate general permits. The U.S. Court of Appeals for the Ninth Circuit subsequently held that the Corps’ January 2021 reissuance rendered the prior challenge moot. In May 2021, environmental groups once again filed suit in the U.S. District Court for the District of Montana, seeking vacatur of the reissued NWP 12. Environmental groups allege that the reissuance of NWP 12 violated the ESA, National Environmental Policy Act, and Clean Water Act, among other things. In September 2022, the U.S. District Court for Montana dismissed the ESA consultation challenges as moot and dismissed the remainder of the lawsuit without prejudice. The Corps has announced that it will be reviewing all the nationwide permits for consistency with Administration policies, which could result in additional limitations on the use of nationwide permits. Limitations on the use of NWP 12 may make it more difficult to permit our projects, require consideration of alternative construction or siting, which may impose additional costs and delays, and could cause us to lose potential and current customers and limit our growth and revenue.
In addition, on July 6, 2020, the U.S. District Court for the District of Columbia issued an order vacating a Corps Mineral Leasing Act easement for the Dakota Access Pipeline in a lawsuit filed by the Standing Rock Sioux Tribe and other Native American tribes. The court’s decision requires the pipeline to shut down operations by August 5, 2020 but was stayed by the U.S. Court of Appeals for the District of Columbia Circuit. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision affirming the district court’s holding that the easement should be vacated but reversing the requirement to shut down the pipeline. The Court of Appeals left it to the Corps to determine how to proceed after the loss of the easement, and while the Corps declined to shut down the pipeline, it did not formally approve the pipeline’s ongoing operation without an easement. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and plaintiffs, and Dakota Access has filed its reply.
The Dakota Access Pipeline continues to operate pending the Corps’ ongoing development of a court-ordered environmental impact statement for the project. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. On January 20, 2022, the Standing Rock Sioux Tribe withdrew as a cooperating agency on the draft Environmental Impact Statement (“EIS”), prompting the Corps to temporarily pause on the draft EIS. The Corps published the draft EIS on September 8, 2023 and tribal and public meetings were held in November and December of 2023. A final EIS is expected to be completed by the Corps in 2025. If the Dakota Access Pipeline is forced to shut down, this could have a material adverse effect on our business, financial condition and results of operations associated with the Polar and Divide system, which interconnects with the Dakota Access Pipeline.
Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds, individual investors and other sources of capital restricting or eliminating their investment in fossil fuel-related activities. In addition, financial institutions have begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before providing loans or investing in our equity securities. There is also a risk that financial institutions may adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, such as the adoption of net zero financed emissions targets. Such policies may be hastened by actions under the Biden Administration, including the implementation by the Federal Reserve of any recommendations made by the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Ultimately, this could make it more difficult to secure funding for exploration and production activities or energy infrastructure related projects or adversely impact our cost of capital, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to maintain access to capital or perform services for certain customers.
Our business is subject to complex and evolving United States and international laws and regulations regarding privacy and data protection (“data protection laws”). Many of these data protection laws are subject to change and uncertain interpretation, and could result in claims, increased cost of operations or otherwise harm our business.
Along with our own data and information that we collect and retain in the normal course of our business, we and our business partners collect and retain significant volumes of certain other types of data, some of which are subject to data protection laws. The regulatory environment surrounding the collection, use, transfer and protection of such data, both domestically and internationally, is becoming increasingly complex, constantly evolving, and is subject to frequent significant change. New data
protection laws at the federal, state, international, national, provincial and local levels, including recent Colorado, Connecticut, Virginia and Utah legislation, the European Union General Data Protection Regulation (“GDPR”) and the California Consumer Privacy Act, as amended by the California Privacy Rights Act (“CCPA”), pose increasingly complex compliance challenges and potentially elevate our costs.
Complying with these jurisdictional requirements could increase the costs and complexity of compliance procedures, and violations of applicable data protection laws can result in significant penalties. For example, the GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through business partners. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover that may materially adversely affect our business, reputation, results of operations, and cash flows. Similarly, the CCPA, which came into effect on January 1, 2020, imposes specific obligations on businesses that collect personal data from California residents and provides California residents specific rights in relation to their personal data that we or our business partners collect and use. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could necessitate we change our business practices, and carries the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.
As noted below, we are also subject to the possibility of information security breaches, which themselves may result in material financial and reputational exposure under such data protection laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
Risks Related to Terrorism and Cyberterrorism
Terrorist attacks and threats, escalation of military activity in response to these attacks, or acts of war could have a material adverse effect on our business, financial condition or results of operations.
Terrorist attacks and threats, escalation of military activity, or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Our insurance may not protect us against such occurrences.
Our operations depend on the use of information technology (“IT”) and operational technology (“OT”) systems that could be the target of a cyberattack.
Cybersecurity threats present a large and growing risk to our business, as the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of remote communication devices has increased rapidly. Industrial control systems now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.
Our operations depend on the use of sophisticated IT and OT systems. These systems, as well as those of our customers, business partners and counterparties, may become the target of cyber-attacks or information security breaches. Additionally, increased remote access to information systems by employees and contractors can increase exposure to potential cybersecurity incidents.
Any such cyber-attacks or information security breaches could have a material adverse effect on our revenues and increase our operating and capital costs and could reduce the amount of cash otherwise available for distribution. A cyber-incident involving our IT or OT systems, or that of our customers, business partners or counterparties, could disrupt our business plans and negatively impact our operations in the following ways, among others:
•a cyber-attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
•a cyber-attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;
•a cyber-attack on a communications network or power grid could cause operational disruption, resulting in loss of revenues;
•a deliberate corruption of our financial or operational data could result in events of non-compliance, which could lead to regulatory fines or penalties; and
•business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our common stock or Series A Preferred Stock.
Cyber-incidents and related business interruptions could result in expensive remediation efforts, disproportionate attention of management, damage to our reputation or a negative impact on the price of our common stock or Series A Preferred Stock. In addition, certain cyberattacks and related incidents, such as reconnaissance or surveillance by threat actors, may remain undetected for an extended period notwithstanding our monitoring and detection efforts. As a result, we may be required to incur additional costs to modify or enhance our IT or OT systems to prevent or remediate any such attacks. Finally, laws and regulations governing cybersecurity pose increasingly complex compliance technical challenges, and failure to comply with these laws could result in penalties and legal liability.
Risks Related to the Common Stock and Series A Preferred Stock
The price of the common stock or Series A Preferred Stock may experience volatility.
The price of our common stock or the Series A Preferred Stock may be volatile. In addition to the risk factors described above, some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community, sales of the common stock by significant stockholders, a turnover of the investor base as a result of the Corporate Reorganization, short-selling of the common stock or Series A Preferred Stock by investors, issuance of a significant number of shares for equity-based compensation or to raise additional capital to fund our operations, changes in market valuations of similar companies and speculation in the press or investment community about our financial condition or results of operations, as well as any doubt about its ability to continue as a going concern. General market conditions and United States or international economic factors and political events unrelated to our performance may also affect its stock price. For these reasons, investors should not rely on recent trends in the price of the common stock or Series A Preferred Stock to predict the future price of the common stock or Series A Preferred Stock or our future financial results.
Our Governing Documents contain provisions that may make it difficult for a third party to acquire control of the Company, even if a change in control would result in the purchase of your shares of common stock or Series A Preferred Stock at a premium to the market price or would otherwise be beneficial to you.
There are provisions in our amended and restated certificate of incorporation (the “Charter”), our amended and restated bylaws (the “Bylaws”) and the Certificate of Designation of Series A Floating Rate Cumulative Redeemable Perpetual Preferred Stock (the “Series A Certificate of Designation” and, together with the Charter and the Bylaws, the “Governing Documents”) that may make it difficult for a third party to acquire control of the Company, even if a change in control would result in the purchase of your shares of common stock or Series A Preferred Stock at a premium to the market price or would otherwise be beneficial to you. For example, the Charter authorizes the Board of Directors to issue Preferred Stock and Blank Check Common Stock without stockholder approval. If the Board of Directors elects to issue Preferred Stock or Blank Check Common Stock, it could be more difficult for a third party to acquire the Company. In connection with the Transaction, the Company will establish and issue 7,471,008 shares of Class B common stock of the Company, par value $0.01 per share.
In addition, provisions of the Governing Documents, including a classified board of directors and limitations on stockholder actions by written consent and on stockholder proposals and director nominations at meetings of stockholders, could make it more difficult for a third party to acquire control of the Company. Certain provisions of the DGCL may also discourage takeover attempts that have not been approved by the Board of Directors.
We do not expect to pay dividends on our common stock for the foreseeable future.
We do not expect to pay dividends for the foreseeable future. In addition, the Amended and Restated ABL Facility may limit our subsidiaries subject thereto from distributing cash to the Company, without the prior consent of the lenders under the Amended and Restated ABL Facility, thereby limiting our ability to pay dividends to equity holders, other than dividends payable solely in additional equity interests in the Company.
The value of our common stock may be diluted by future equity issuances and shares eligible for future sale may have adverse effects on our share price.
We cannot predict the effect of future sales of shares or the availability of shares for future sales, on the market price of or the liquidity of the market for the shares. Sales of substantial amounts of shares, or the perception that such sales could occur, could adversely affect the prevailing market price of the shares. Such sales, or the possibility of such sales, could also make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.
Our authorized capital stock consists of 42,000,000 shares of common stock, 500,000 shares of Preferred Stock and 30,000,000 shares of Blank Check Common Stock, a significant portion of which are currently unissued. We may need to raise a significant amount of capital to fund our operations and pay down outstanding indebtedness, including borrowings on the Amended and
Restated ABL Facility and the Permian Transmission Credit Facilities and the 2029 Secured Notes, and may raise such capital through the issuance of newly issued common stock, Preferred Stock or Blank Check Common Stock. Such issuance and sale of equity could be dilutive to the interests of existing stockholders.
Risks Related to the Transaction
We will incur a substantial amount of additional debt to complete the Transaction. Our debt level may limit our financial and business flexibility.
We expect to fund the $155 million cash portion of the aggregate purchase price for the Transaction with a combination of cash on hand and through the incurrence of approximately $155 million of new indebtedness. We currently anticipate such indebtedness will consist of borrowings through our Amended Restated ABL Facility.
Such incurrence would result in an increase to our outstanding long-term indebtedness, which was $826.5 million as of September 30, 2024. Subject to the limitations contained in our existing and any future debt instruments, we may be able to incur additional debt from time to time to finance working capital, capital expenditures, investments or acquisition, or for other purposes. If we do so, the risks related to our level debt could increase. Our ability to repay all the forgoing obligations will depend on, among other things, our financial position and performance, as well as prevailing market conditions and other factors beyond our control.
Our increased indebtedness could have important consequences. For example:
•we may be required to dedicate a substantial portion of our cash flows from operations to payments on our indebtedness, thereby reducing our ability to use our cash flow to fund working capital, acquisitions, capital expenditures and general corporate matters, including dividend payments and stock repurchases;
•we may not be able to generate sufficient cash flow to meet our substantial debt service obligations or to fund our other liquidity needs. If this occurs, we may have to take actions such as selling assets, selling equity, or reducing or delaying capital expenditures, strategic acquisitions, investments and joint ventures, or restructuring our debt;
•as a result of the amount of our outstanding indebtedness and the restrictive covenants to which we are or may become subject, if we determine that we require additional financing to fund future working capital, capital investments, or other business activities, we may not be able to obtain such financing on commercially reasonable terms, or at all; and
•our flexibility in planning for, or reacting to, changes in our business and industry may be limited, thereby placing us at a competitive disadvantage compared with our competitors that have less indebtedness.
We will be subject to certain uncertainties while the Transaction is pending, which could adversely affect our business.
The Transaction is currently pending and we have scheduled a Special Meeting of Stockholders, on November 29, 2024, to approve the issuance of 7,471,008 shares of Class B Common Stock and associated 7,471,008 Partnership common units. Uncertainty about the effect of the Transaction on employees and those that do business with us or invest in our securities may have an adverse effect on the Company or the trading price of our Common Stock. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Transaction is completed and for a period of time thereafter, and could cause those that transact with us to seek to change their existing business relationships with us. During the pendency of the Transaction, management and other personnel will be required to dedicate time and attention to execution of the Transaction, which may partially divert their attention from the Company’s business. The Company will also incur significant transaction expenses regardless of whether the Transaction is consummated or beneficial, and such expenses may be more than anticipated, particularly if the Transaction is not completed on the expected timeline.
In addition, the agreements entered into in connection with the Transaction restrict us from entering into certain corporate transactions and taking other specified actions without the consent of Tall Oak, and generally require us to continue our operations in the ordinary course of business during the pendency of the Transaction. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the Transaction.
Company stockholders as of immediately prior to the Transaction will have reduced ownership in the Company immediately following the Transaction.
After the closing of the Transaction, legacy stockholders will experience immediate and significant dilution to their current equity ownership in the Company. Immediately after the closing, our existing stockholders are expected to control approximately 59% of our issued and outstanding voting power, while Tailwater, after being transferred a portion of the shares of Class B Common Stock issued to Tall Oak at closing, is expected to control approximately 35% of our issued and outstanding voting power and will have the right to designate four of the eleven members of our Board. TOMI, a party unaffiliated with each of the Company and Tall Oak, is expected to control approximately 6% of our issued and outstanding voting power after being transferred a portion of the securities to be issued to Tall Oak at Closing.
The issuance of 7,471,008 shares of Class B Common Stock and associated Partnership common units pursuant to the Business Contribution Agreement could have the effect of depressing the market price of the Common Stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, the Company’s earnings per share could cause the price of the Common Stock to decline or increase at a reduced rate.
The market price for Common Stock following the closing of the Transaction may be affected by factors different from those that historically have affected or currently affect the Common Stock.
Upon the completion of the Transaction, the Company’s financial position may differ from its financial position before the completion of the Transaction, and the results of operations of the combined company may be affected by some factors that are different from those currently affecting the results of operations of the Company and those currently affecting the results of operations of Tall Oak Opco. Accordingly, the market price and performance of the Common Stock is likely to be different from the performance of the Common Stock in the absence of the Transaction. In addition, general fluctuations in stock markets could have a material adverse effect on the market for, or liquidity of, the Common Stock, regardless of the Company’s actual operating performance.
We may be subject to lawsuits relating to the Transaction, which could adversely affect our business, financial condition and operating results.
Lawsuits may be filed challenging the Transaction, which could prevent the Transaction from being completed, or could result in a material delay in, or the abandonment of, the Transaction. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Transaction, then that injunction may delay or prevent the Transaction from being completed, which may adversely affect our business, financial position and results of operations.
The termination of the Business Contribution Agreement could negatively impact our business or result in our having to pay a termination fee.
The Business Contribution Agreement is subject to a number of conditions that must be satisfied, including the approval by the Company’s stockholders of the issuance of the 7,471,008 shares of Class B Common Stock and associated Partnership common units, in each case prior to the completion of the Transaction. These conditions to the completion of the Business Contribution Agreement, some of which are beyond the control of the Company, may not be satisfied or waived in a timely manner by March 31, 2025 or at all, and, accordingly, the Transaction may be delayed or may not be completed. The Business Contribution Agreement may also be terminated under certain circumstances. If the Transaction is not completed for any reason, the Company’s ongoing businesses and financial results may be adversely affected.
Additionally, if the Business Contribution Agreement is terminated under certain circumstances, we may be required to pay a termination fee of approximately $15 million in the aggregate, which would have a negative impact on our liquidity and financial condition.
The Transaction may be completed even though material adverse changes subsequent to the announcement of the Transaction, such as industry-wide changes or other events, may occur.
In general, the parties to the Transaction can refuse to complete the Transaction if there is a material adverse change affecting the other party. However, some types of changes do not permit the Company to refuse to complete the Transaction, even if such changes would have a material adverse effect on any of the parties involved in the Transaction. For example, if Tall Oak Opco is adversely impacted as a result of a decrease in commodity prices or general economic conditions, the Company would not have the right to refuse to complete the Transaction. If adverse changes occur that affect the assets of the Tall Oak Subsidiaries and the parties are still required to complete the Transaction, the Company’s share price, business and financial results after the completion of the Transaction may suffer.
The failure to successfully integrate the business and operations of Tall Oak in the expected time frame may adversely affect the Company’s future results.
The Company believes that the acquisition of the Tall Oak Opco will result in certain benefits, including certain cost synergies and operational efficiencies. However, to realize these anticipated benefits, the businesses of the Company and Tall Oak must be successfully combined. The success of the Transaction will depend on the Company’s ability to realize these anticipated benefits from integrating the business of Tall Oak Opco into the Company. The actual integration may result in additional and unforeseen expenses or delays. If the post-Transaction company is not able to successfully integrate Tall Oak Opco’s business and operations, or if there are delays in combining the businesses, the anticipated benefits of the Transaction may not be realized fully or at all or may take longer to realize than expected.
Risk Factors Relating to the Company Following the Transaction
The market value of our Common Stock could decline if large amounts of our equity securities are sold following the Transaction.
In the Transaction, we expect to issue 7,471,008 shares of Class B Common Stock in exchange for 100% of the equity interests in Tall Oak Opco. Such shares of Class B Common Stock are exchangeable for shares of our Common Stock at the election of the holder for no additional consideration. Pursuant to the Investor Agreement, the estimated 6,480,071 shares of Class B Common Stock and associated Partnership common units to be issued to Tailwater and its designees may not be transferred until one year after closing, after which time 50% of such securities will be available for resale, with the remaining 50% available for resale two years after closing. With respect to the estimated 990,937 shares of Class B Common Stock and associated Partnership common units to be issued to TOMI, TOMI is required to exercise its redemption right in full on or prior to the fourth business day following the closing or, if closing occurs on or prior to December 31, 2024, on January 1, 2025. However, TOMI may not sell the Common Stock received upon redemption until six months after the closing, after which time 50% of such Common Stock will be available for resale, with the remainder of the Common Stock held by TOMI being available for resale one year after the closing. Tailwater and TOMI may decide to reduce their investment in the Company at any time thereafter. Any such sales of our equity securities, or expectations thereof, could have the effect of depressing the market price for our Common Stock.
We may not achieve the anticipated benefits of the Transaction.
The success of the Transaction will depend, in part, on our ability to realize the anticipated benefits of the Transaction. The anticipated benefits of the Transaction may not be fully realized or may take longer to realize for various reasons, including difficulties integrating operations, higher than expected integration and operating costs or other difficulties and fluctuations in market prices. Additionally, there are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates of Tall Oak Opco’s customers and as a result, the revenue generated by Tall Oak Opco’s assets. Actual results may vary substantially from those assumed in our estimates. A customary review of such properties will not necessarily reveal all existing or potential problems. An inability to realize the full extent of the anticipated benefits of the Transaction could have an adverse effect upon our revenues, level of expenses and results of operations.
The Transaction and subsequent changes in stock ownership of the Company (including upon the redemption or exchange of the shares of Class B Common Stock and associated Partnership common units for Common Stock) may trigger a limitation on the utilization of net operating loss carryforwards of the Company.
The Company’s ability to utilize U.S. net operating loss carryforwards to reduce future taxable income depends on many factors, including its future income, which cannot be assured. Section 382 and 383 of the Code generally impose an annual limitation on the amount of net operating losses and certain other tax attributes that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of such corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs, utilization of net operating losses by the Company would be subject to an annual limitation under Section 382, generally determined by multiply (1) the fair market value of its stock at the time of the ownership change by (2) the long-term tax-exempt rate published by the IRS for the month in which the ownership change occurs, subject to certain adjustments. Any unused annual limitation may be carried over to later years. In addition, an ownership change may arise as a result of subsequent changes in the Company’s stock ownership, including as a result of redemptions or exchanges of shares of Class B Common Stock and associated Partnership common units for Common Stock, which would trigger a limitation on the Company’s ability to utilize net operating loss carryforwards.
If the Partnership were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, the Company and the Partnership might be subject to potentially significant tax inefficiencies.
Our intent is to cause the Partnership to be operated in a manner such that the Partnership does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, the exchange of shares of Class B Common Stock for Common Stock or other transfers of Partnership common units could cause the Partnership to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that exchanges or other transfers of Partnership common units qualify for one or more of such safe harbors. For example, we intend to limit the number of holders of Partnership common units, and the A&R Partnership Agreement provides for certain limitations on the ability of holders of common units to transfer their common units and provides the General Partner with the right to impose restrictions on the ability of limited partners to exchange their Partnership
common units for Common Stock pursuant to the redemption right to the extent the General Partner believes there is a material risk that the Partnership would be a publicly traded partnership as a result of such exercise.
Risks Relating to the Company’s Common Stock and Series A Preferred Stock
Our certificate of incorporation and bylaws contain provisions that may make it more difficult for a third party to acquire control of the Company, even if a change in control would result in the purchase of your shares of Common Stock or Series A Preferred Stock at a premium to the market price or would otherwise be beneficial to you.
Our certificate of incorporation and bylaws may make it more difficult for a third party to acquire control of the Company, even if a change in control would result in the purchase of your shares of Common Stock or Series A Preferred Stock at a premium to the market price or would otherwise be beneficial to you. For example, the Company’s certificate of incorporation authorizes the Board to issue preferred stock, $0.01 par value per share (“Preferred Stock”), and common stock, $0.01 par value per share (“Blank Check Common Stock”), without stockholder approval. If the Board elects to issue Preferred Stock or Blank Check Common Stock, it could be more difficult for a third party to acquire the Company.
In addition, provisions of our certificate of incorporation and bylaws, including a classified board of directors and limitations on stockholder actions by written consent and on stockholder proposals and director nominations at meetings of stockholders, could make it more difficult for a third party to acquire control of the Company. Certain provisions of the Delaware General Corporate Law may also discourage takeover attempts that have not been approved by the Board.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosure.
Not applicable.
Item 5. Other Information.
During the three months ended September 30, 2024, the following directors or officers (as defined in Rule 16a-1(f) under the Exchange Act) of the Company adoptedRule 10b5-1 trading arrangements as defined in Item 408(a) of Regulation S-K.
On August 9, 2024, J. Heath Deneke, the Company’s President, Chief Executive Officer and Chairman of the Board of Directors, executed a Rule 10b5-1 trading arrangement to be adopted effective August 13, 2024 providing for the sale from time to time of an aggregate of up to 90,000 shares of our common stock. The trading arrangement is intended to satisfy the affirmative defense in Rule 10b5-1(c). The duration of the trading arrangement is until December 31, 2025, or earlier if all transactions under the trading arrangement are completed.
On August 11, 2024, James D. Johnston, the Company’s Executive Vice President, General Counsel and Chief Compliance Officer, executed a Rule 10b5-1 trading arrangement to be adopted effective August 13, 2024 providing for the sale from time to time of an aggregate of up to 20,000 shares of our common stock. The trading arrangement is intended to satisfy the affirmative defense in Rule 10b5-1(c). The duration of the trading arrangement is until June 18, 2025, or earlier if all transactions under the trading arrangement are completed.
Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
+ Filed herewith.
* Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act are deemed not filed for purposes of Section 18 of the Exchange Act and otherwise are not subject to liability under those sections. The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.
** Certain of the schedules and exhibits to the agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished to the SEC upon request.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Summit Midstream Corporation
(Registrant)
November 12, 2024
/s/ WILLIAM J. MAULT
William J. Mault, Executive Vice President and Chief Financial Officer (Principal Financial Officer)