Kinetik Holdings Inc. (KNTK)

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report. This section of this Annual Report generally discusses 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 that are omitted in this Annual Report are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, filed on March 5, 2024.

Unless otherwise noted or the context requires otherwise, references herein to Kinetik Holdings Inc.,“the Company”, “us”, “our”, “we” or similar terms, with respect to time periods prior to February 22, 2022, include BCP and its consolidated subsidiaries and do not include ALTM and its consolidated subsidiaries, while references herein to Kinetik Holdings Inc.,“the Company”, “us”, “our”, “we” or similar terms, with respect to time periods from and after February 22, 2022, include ALTM and its consolidated subsidiaries.

Significant Business Combinations

On February 22, 2022, (“the Altus Closing Date”), Kinetik Holdings Inc., a Delaware corporation (formerly known as Altus Midstream Company), consummated the business combination transactions contemplated by the Contribution Agreement, dated as of October 21, 2021 (the “Contribution Agreement”), by and among the Company, Altus Midstream LP (now known as Kinetik Holdings LP, the “Partnership”), a Delaware limited partnership and subsidiary of Altus Midstream Company. New BCP Raptor Holdco, LLC, a Delaware limited liability company, and BCP. The transactions contemplated by the Contribution Agreement are referred to herein as the “Altus Acquisition.” In connection with the closing of the transaction, the Company changed its name from “Altus Midstream Company” to “Kinetik Holdings Inc.” Upon closing of the business combination, BCP and its subsidiaries became wholly owned subsidiaries of the Partnership. The Altus Acquisition was accounted for as a reverse merger pursuant to ASC 805.

On June 24, 2024 (the “Durango Closing Date”), the Company consummated the previously announced transaction contemplated by the Membership Interest Purchase Agreement (the “Durango MIPA”), dated May 9, 2024, by and between the Company, the Partnership, and Durango Midstream LLC, an affiliate of Morgan Stanley Equity Partners (the “Durango Seller”), pursuant to which the Partnership purchased all of the membership interests of Durango Permian LLC and its wholly owned subsidiaries (“Durango”) from Durango Seller (“Durango Acquisition”). The Durango Acquisition was accounted for as a business combination in accordance with ASC 805. Refer to Note 3—Business Combination in the Notes to the Consolidated Financial Statements in this Annual Report for further information regarding the Durango Acquisition.

Overview

We are an integrated midstream energy company in the Permian Basin providing comprehensive gathering, transportation, compression, processing and treating services. Our core capabilities include a variety of service offerings including natural gas gathering, transportation, compression, treating and processing; NGLs stabilization and transportation; produced water gathering and disposal; and crude oil gathering, stabilization, storage and transportation. The Company’s corporate office is located in Houston, Texas and our operations are strategically located in the heart of the Delaware Basin.

Our Operations and Segments

We have two reportable segments which are strategic business units with various products and services. The Midstream Logistics segment operates under three service offerings, 1) gas gathering and processing, 2) crude oil gathering, stabilization and storage services and 3) produced water gathering and disposal. The Pipeline Transportation segment consists of three EMI pipelines originating in the Permian Basin with various access points to the U.S. Gulf Coast, Kinetik NGL Pipelines and Delaware Link Pipeline. The pipelines transport crude oil, natural gas and NGLs within the Permian Basin and to the U.S. Gulf Coast.

Midstream Logistics

Gas Gathering and Processing. The Midstream Logistics segment provides gas gathering and processing services with over 3,900 miles of low and high-pressure steel pipeline located throughout the Delaware Basin, including over 2,300 miles of gas

31

Table of Contents

Index to Financial Statements

pipeline acquired through the Durango Acquisition, and over 570,000 horsepower of compression capacity. An additional 214 miles of gathering pipeline was added to our system through the Permian Resources Midstream Acquisition closed during January 2025. Gas processing assets are centralized at seven processing complexes with system-wide front-end amine treating capability, 6.5 MMcf/d AGI capacity and total cryogenic processing capacity of approximately 2.2 Bcf/d as of today and over 2.4 BCF/d once the Kings Landing Project is complete in mid-2025.

Crude Oil Gathering, Stabilization and Storage Services. Crude gathering assets are centralized at the Caprock Stampede Terminal and the Pinnacle Sierra Grande Terminal. The system includes approximately 220 miles of gathering pipeline and 90,000 barrels of crude storage. An additional 75 miles of gathering pipeline was added to our crude gathering assets through the Permian Resources Midstream Acquisition closed during January 2025.

Water Gathering and Disposal. The system includes over 360 miles of gathering pipeline and approximately 580,000 barrels per day of permitted disposal capacity.

Pipeline Transportation

EMI pipelines. The Company owns the following equity interests in three EMI pipelines in the Permian Basin with access to various points along the U.S. Gulf Coast: 1) an approximate 55.5% equity interest in Permian Highway Pipeline LLC (“PHP”), which is also owned and operated by Kinder Morgan; 2) 33.0% equity interest in Shin Oak, which is owned by Breviloba, LLC, and operated by Enterprise Products Operating LLC; and 3) 27.5% equity interest in Epic Crude Holdings, LP (“EPIC”), which is operated by EPIC Consolidated Operations, LLC. The increase of equity interest in EPIC was related to the purchase of an additional 12.5% equity interest from a third party in July 2024.

Kinetik NGL Pipelines. The Kinetik NGL Pipelines consist of approximately 96 miles of NGL pipelines connecting our East Toyah and Pecos complexes to Waha, including our 20-inch Dewpoint pipeline that spans 40 miles, and our 30 mile, 20-inch Brandywine Pipeline connecting to our Diamond Cryogenic complex. The Kinetik NGL pipeline system has a capacity approximate 580 MBbl/d.

Delaware Link Pipeline. The Delaware Link Pipeline consists of approximately 40 miles of 30-inch diameter pipeline with a capacity of approximately 1.0 Bcf/d that provides additional transportation capacity to Waha. The project reached commercial in-service in October 2023.

Recent Developments

Permian Resources Midstream Assets Acquisition

On December 10, 2024, the Company announced it has entered into a definitive agreement with Permian Resources to acquire certain natural gas and crude oil gathering systems assets, primarily located in Reeves County, Texas, for $178.4 million of cash consideration. The Permian Resources Midstream Acquisition provides a multi-stream opportunity for natural gas gathering, compression and processing, as well as crude gathering services for the Company. The transaction closed in early January 2025 following satisfaction of customary closing conditions.

EPIC Equity Interest

During the third quarter of 2024, the Company consummated the Equity Sale and Purchase Agreement with Dos Rios Crude Intermediate LLC to purchase a 12.5% of equity interest in EPIC. The acquisition of additional interest is accounted for as a business acquisition pursuant to ASC 805. After completion of the transaction, the Company owned a 27.5% equity interest in EPIC. EPIC has over 800 miles of pipeline connecting the Delaware and Midland Basins to the U.S. Gulf Coast and has a capacity of 625 MBbl/d.

32

Table of Contents

Index to Financial Statements

Durango Acquisition

On June 24, 2024, the Company consummated the previously announced Durango Acquisition for an adjusted purchase price of approximately $785.7 million, consisting of (i) $358.0 million of cash consideration paid at closing, (ii) approximately 3.8 million shares of Class C Common Stock and an equivalent number of common units in the Partnership (“OpCo Units”), issued at closing and (iii) approximately 7.7 million shares of Class C Common Stock and an equivalent number of OpCo Units to be issued on July 1, 2025. Durango Seller is also entitled to an earn out of up to $75.0 million in cash contingent upon the completion and placing into service of the Kings Landing Project in Eddy County, New Mexico, which is currently under construction. This earn out is subject to reduction based on actual capital costs associated with the Kings Landing Project. This transaction was accounted for as a business combination pursuant to ASC 805. Refer to Note 3—Business Combinations in the Notes to our Consolidated Financial Statements in this Annual Report for further information.

The Durango Acquisition significantly expands Kinetik’s footprint into New Mexico and the Northern Delaware Basin, expanding Kinetik’s processing capacity by over 200 MMcf/d and doubling its existing gathering pipeline mileage. An additional 200 MMcf/d of processing capacity will be added upon completion of the Kings Landing Project.

GCX Divestiture

On June 4, 2024, the Company consummated the previously announced transaction contemplated by the GCX Purchase Agreement to sell its 16% equity interest in GCX for an adjusted purchase price of $524.4 million (the "GCX Sale"), including an additional $30.0 million earn out in cash upon the approval by the GCX Board of Directors of one or more capital projects that achieve certain capacity expansion criteria. Net cash proceeds of $494.4 million were received from the GCX Buyer on June 4, 2024 and the cash earn out was received in September 2024. The Company recognized a gain of $89.8 million upon closing of the GCX Sale.

A/R Facility

On April 2, 2024, Kinetik Receivables, a bankruptcy remote special purpose entity formed as a direct subsidiary of the Partnership, which is a subsidiary of the Company entered into an A/R Facility with an initial facility limit of $150.0 million with PNC Bank, as the administrative agent, and certain purchasers party thereto from time to time, which has a scheduled termination date of April 1, 2025. Pursuant to the A/R Facility, the Company and certain of its subsidiaries continuously transfer receivables to Kinetik Receivables and Kinetik Receivables transfers receivables that meet certain qualifying conditions to third-party purchasers in exchange for cash. These receivables are held by Kinetik Receivables and are pledged to secure the collectability of the sold receivables. The amount available for borrowings at any one time under the A/R Facility is limited to an amount calculated based on the outstanding balance of eligible receivables sold to the purchasers, subject to certain reserves, concentration limits, and other limitations. As of December 31, 2024, eligible accounts receivable of $140.2 million was pledged to the A/R Facility as collateral and $9.8 million was available to be invested by the purchasers. The net proceeds of the A/R Facility were used, together with cash on hand, to repay a portion of the outstanding borrowings under the existing term loan credit facility (the “Term Loan Credit Facility”), lowering the remaining balance to $1.0 billion. As a result, the maturity of the Term Loan Credit Facility extended to December 8, 2026.

Secondary Offering of Common Stock

On March 13, 2024, the Company and Apache (the “Selling Stockholder”) entered into an Underwriting Agreement with Goldman Sachs & Co. LLC, as representative of the several underwriters named therein (collectively, the “Underwriters”), pursuant to which the Selling Stockholder agreed to sell to the Underwriters, and the Underwriters agreed to purchase from the Selling Stockholder, subject to and upon the terms and conditions set forth therein, 13,079,871 shares of Class A Common Stock. The Company did not receive any proceeds from the sale of shares of Common Stock in the offering.

Factors Affecting Our Business

Commodity Price Volatility

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGLs, crude oil and natural gas prices. As a result of uncertainty around global commodity supply and demand, global geopolitical conflicts, foreign and trade policies with the new U.S. presidential administration, as well as the ongoing armed conflict in Ukraine, global oil and natural gas commodity prices continue to remain volatile. The volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems. Although ongoing armed conflicts might generate commodity price upward pressure, and our operations

33

Table of Contents

Index to Financial Statements

could benefit in an environment of higher natural gas, NGLs and condensate prices, the instability of the international political environment and human and economic hardship resulting from the conflicts would have a highly uncertain impact on the U.S. economy, which in turn, might affect our business and operations adversely. Our product sales revenue is exposed to commodity price fluctuations. Therefore, commodity price decline and sustained periods of low natural gas and NGL prices could have an adverse effect on our product revenue stream. The Company continues to monitor commodity prices closely and may enter into commodity price hedges from time to time as necessary to mitigate the volatility risk. In addition, the Company, when economically appropriate, enters into fee-based arrangements that insulate the Company from commodity price volatility.

Inflation and Interest Rates

The annual rate of inflation in the U.S. was 3.00% in January 2025 as measured by the Consumer Price Index. In light of the recent economic activity, unemployment level and uncertainty in policy making with the Trump Administration, the FOMC decided to maintain the target range for the federal funds rate at 4.25 % - 4.50% during its meeting in January 2025. During the meeting, the FOMC noted that the economic outlook is uncertain and the Committee is attentive to the risks to both sides of its dual mandate and is strongly committed to supporting maximum employment and returning inflation to its 2.00% objective. If interest rates elevated beyond the term of our hedges, our financing cost will increase and could have a negative impact on the Company’s ability to meet its contractual debt obligations and to fund its operating expenses and capital expenditures. The Company will continue to monitor the FOMC’s monetary policy and interest rate movement. Refer to Note 13—Derivatives and Hedging Activities in the Notes to Consolidated Financial Statements in this Annual Report for additional discussion regarding our hedging strategies and objectives for interest rate risk.

34

Table of Contents

Index to Financial Statements

Results of Operations

The following table presents the Company’s results of operations for the periods presented:

*Cost of sales (exclusive of depreciation and amortization) is net of gas service revenues totaling $219.7 million and $148.3 million for the years ended December 31, 2024 and 2023, respectively, for certain volumes where we act as principal.

NM - Not meaningful

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

Revenues

For the year ended December 31, 2024, revenue increased $226.5 million, or 18%, to $1,482.9 million, compared to $1,256.4 million for the same period in 2023. The increase was primarily driven by higher period-over-period product revenue due to increased natural gas residue volumes sold and increased gathered and processed gas volumes.

Service revenue

Service revenue consists of service fees paid to the Company by its customers for providing comprehensive gathering, treating, processing and water disposal services necessary to bring natural gas, NGLs and crude oil to market. Service revenue for the year ended December 31, 2024, decreased by $9.8 million, or 2%, to $408.0 million, compared to $417.8 million for the same period in 2023. The decrease was primarily driven by lower period-over-period gas gathering fees of $9.5 million. Total gathered and processed gas volumes increased 227.4 Mcf per day, or 13% and 189.9 Mcf per day, or 13%, respectively. Of the increase, Durango’s operations, on a six months basis, accounted for 105.8 Mcf per day and 98.2 Mcf per day of gathered and processed gas volumes, respectively. However, the total gathered and processed gas volumes where we function as the agent decreased period-over-period causing the change in net gas gathering fees presented as revenues to be down 3%. Over 98% of service revenues are included in the Midstream Logistics segment.

35

Table of Contents

Index to Financial Statements

Product revenue

Product revenue consists of commodity sales (including condensate, natural gas residue and NGLs). Product revenue for the year ended December 31, 2024, increased by $240.6 million, or 29%, to $1,063.0 million, compared to $822.4 million for the same period in 2023, primarily due to period-over-period increases in natural gas residue sales volumes of 51.7 million MMBtu, or over 200% and NGL and condensate volumes sold of 2.0 million barrels, or 6%. The increase was also driven by a period-over-period increase in NGL prices of $0.62 per barrel, or 3% and condensate prices of $2.10 per barrel, or 3%. The overall increase was partially offset by a decrease in natural gas prices of $0.42 per MMBtu, or 24%. Product revenues are included entirely in the Midstream Logistics segment.

Operating Costs and Expenses

Costs of sales (exclusive of depreciation and amortization)

Cost of sales (exclusive of depreciation and amortization) primarily consists of purchases of NGLs and natural gas from our producers at contracted market prices to support product sales to other third parties. For the year ended December 31, 2024, cost of sales increased $104.9 million, or 20%, to $620.6 million, compared to $515.7 million for the same period in 2023. As discussed above, the increase was primarily driven by period-over-period increases in natural gas residue and NGL and condensate volumes sold, slightly offset by lower natural gas prices. More than 99% of the cost of sales (exclusive of depreciation and amortization) are included in the Midstream Logistics segment.

Operating expenses

Operating expenses increased by $34.5 million, or 21%, to $196.0 million for the year ended December 31, 2024, compared to $161.5 million for the same period in 2023. Of the total increase, $23.6 million was driven by Durango’s operations that were acquired during late June 2024. The remaining increase was primarily driven by increases in internal labor and repairs and maintenance totaling $10.7 million, which was related to the increased gathered and processed volumes during 2024. Over 98% of operating expenses are included in the Midstream Logistics segment.

General and administrative expenses

General and administrative expenses increased by $36.3 million, or 37% to $134.2 million for the year ended December 31, 2024, compared to $97.9 million for the same period in 2023. The increase was mainly driven by higher share-based compensation of $20.6 million primarily due to the 2024 STI bonus being paid via stock during December versus March for prior years and $9.1 million of integration and transaction costs associated with the 2024 Durango and EPIC transactions. The remaining increase primarily relates to higher internal labor expenses of $3.3 million related to the overall growth of the organization and payroll taxes on the aforementioned 2024 STI bonus, and higher insurance costs of $1.5 million primarily related to the Durango Acquisition as well as an incremental increase in insurance rates related to the legacy business.

Depreciation and amortization expenses

Depreciation and amortization expense increased by $43.2 million, or 15% to $324.2 million for the year ended December 31, 2024, compared to $281.0 million for the same period in 2023. Of the total increase, $25.5 million was driven by the Durango Acquisition that was completed during late June 2024. The remaining increase was driven by assets placed in service since the second half of 2023, including the Delaware Link Pipeline that was placed in service in October 2023 and the rich gas lateral into Lea County, New Mexico.

Loss on disposal of assets, net

Loss on disposal of asset, net decreased by $15.4 million, or 79% to $4.0 million for the year ended December 31, 2024, compared to $19.4 million for the same period in 2023. The decrease was mainly due to $14.9 million less asset write-offs of obsolete gathering and processing systems and facilities in 2024 compared to 2023.

Other Income (Expense)

Gain on sale of equity method investment

For the year ended December 31, 2024, we had gain on sale of equity method investment of $89.8 million compared to the same period in 2023 related to the GCX Sale consummated in the second quarter of 2024. There was no such gain in 2023.

36

Table of Contents

Index to Financial Statements

Income taxes (benefit) expense

The Company recorded income tax expense of $23.0 million for the year ended December 31, 2024, compared to income tax benefit of $232.9 million for the same period in 2023. The increase was primarily due to the release of the valuation allowance on federal deferred tax assets during the fourth quarter of 2023 compared to the recognition of deferred federal income tax of $19.5 million for year ended December 31, 2024. As the Company achieved a three-year cumulative level of profitability as of December 31, 2024 and 2023, the Company concluded that it is more likely than not that its deferred tax assets will be realized and as such, no valuation allowance was recorded.

Key Performance Metrics

Adjusted EBITDA

Adjusted EBITDA is defined as net income including noncontrolling interests adjusted for interest, taxes, depreciation and amortization, gain or loss on disposal of assets and debt extinguishment, the proportionate EBITDA from our EMI pipelines, equity income and gain from sale of investments recorded using the equity method, share-based compensation expense, noncash increases and decreases related to hedging activities, fair value adjustments for contingent liabilities, integration and transaction costs and extraordinary losses and unusual or non-recurring charges. Adjusted EBITDA provides a basis for comparison of our business operations between current, past and future periods by excluding items that we do not believe are indicative of our core operating performance.

We believe that Adjusted EBITDA provides a meaningful understanding of certain aspects of earnings before the impact of investing and financing charges and income taxes. Adjusted EBITDA is useful to an investor in evaluating our performance because this measure:

•Is widely used by analysts, investors and competitors to measure a company’s operating performance;

•Is a financial measurement that is used by rating agencies, lenders, and other parties to evaluate our credit worthiness; and

•Is used by our management for various purposes, including as a measure of performance and as a basis for strategic planning and forecasting.

Adjusted EBITDA is not defined in GAAP

The GAAP measure used by the Company that is most directly comparable to Adjusted EBITDA is net income including noncontrolling interests. Adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income including noncontrolling interests or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income including noncontrolling interests. Adjusted EBITDA should not be considered in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. The Company’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies in the industry, thereby diminishing its utility.

Reconciliation of non-GAAP financial measure

Company management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between Adjusted EBITDA as compared to net income including noncontrolling interests, and incorporating this knowledge into its decision-making processes. Management believes that investors benefit from having access to the same financial measure that the Company uses in evaluating operating results.

37

Table of Contents

Index to Financial Statements

The following table presents a reconciliation of the GAAP financial measure of net income including noncontrolling interests to the non-GAAP financial measure of Adjusted EBITDA.

NM - Not meaningful

Adjusted EBITDA increased by $132.3 million, or 16% to $971.1 million for the year ended December 31, 2024, compared to $838.8 million for the same period in 2023. As discussed in the Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations to this Annual Report, $226.5 million of the increase was due to increased total operating revenues, partially offset by increased cost of sales (exclusive of depreciation and amortization) of $104.9 million and an increase in operating expenses, ad valorem taxes and general and administrative expenses totaling of $73.8 million. The increase was also driven by (i) higher proportionate EMI EBITDA of $40.6 million due to increased profitability at PHP related to expanded capacity that was placed into service starting in December 2023; (ii) an increase in the add back related to share-based compensation of $20.6 million primarily due to new RSUs and PSUs granted during 2024; (iii) an increase in the add back related to unrealized commodity hedging activities of $15.1 million; and (iv) an increase in the add back of integration and acquisition transaction costs of $8.3 million primarily due to the Durango Acquisition in 2024.

Segment Adjusted EBITDA

Segment Adjusted EBITDA is defined as segment net income including noncontrolling interests adjusted for taxes, depreciation and amortization, gain or loss on disposal of assets, the proportionate EBITDA from our EMI pipelines, equity income and gain from sale of investments recorded using the equity method, noncash increases and decreases related to hedging activities, fair value adjustments for contingent liabilities, integration and transaction costs and extraordinary losses and unusual or non-recurring charges The following table presents Segment Adjusted EBITDA. Also refer to Note 19—Segments in the Notes to our Consolidated Financial Statements in this Annual Report for reconciliation of segment adjusted EBITDA to Income before income taxes.

38

Table of Contents

Index to Financial Statements

* 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 a reportable segment for the purpose of evaluating their performance, including certain general and administrative expense.

Midstream Logistics segment adjusted EBITDA increased by $71.7 million, or 13%, to $614.9 million for the year ended December 31, 2024, compared to $543.2 million for the same period in 2023. The increase was primarily due to the increased total operating revenue of $223.9 million, or 18%, partially offset by increases in cost of sales (exclusive of depreciation and amortization) of $106.6 million, or 21%, and operating expense and ad valorem taxes of $35.1 million or 19%. The reasons for the fluctuations are discussed in the Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations to this Annual Report.

Pipeline Transportation segment adjusted EBITDA increased by $66.4 million, or 21%, to $377.6 million for the year ended December 31, 2024, compared to $311.1 million for the same period in 2023. The increase was primarily driven by higher proportionate EMI EBITDA of $40.6 million, or 13%, due to increased profitability at PHP related to expanded capacity that was placed into service starting in December 2023. The increase was also related to an increase in total operating revenue of $27.0 million, primarily related to the Delaware Link Pipeline that was placed in service in October 2023.

Contractual Obligations

We have contractual obligations for principal and interest payments on our 2028 Notes, 2030 Notes, the Term Loan Credit Facility, Revolving Credit Facility and A/R Facility. See Note 8—Debt and Financing Costs in the Notes to our Consolidated Financial Statements in this Annual Report.

Under certain clauses of our transportation services agreements with third party pipelines to transport natural gas and NGLs, if we fail to ship a minimum throughput volume, then we will pay certain deficiency payments for transportation based on the volume shortfall up to the MVC amount.

For additional information regarding the Company’s obligations, please see Note 8—Debt and Financing Costs and Note 17—Commitments and Contingencies in the Notes to the Consolidated Financial Statements in this Annual Report.

Liquidity and Capital Resources

The Company’s primary use of capital since inception has been for the initial construction of gathering and processing assets, as well as the acquisitions of businesses and EMI pipelines and associated subsequent construction costs. For 2024, the Company’s primary spending requirements were related to the business acquisitions and other budgeted capital expenditures for construction and maintenance of gathering and processing assets, the Company’s contractual debt obligations and quarterly cash dividends. In addition, the Company may repurchase its Class A Common Stock pursuant to the Share Repurchase Program from time to time.

During the year ended December 31, 2024, the Company’s primary sources of cash were distributions from the EMI pipelines, borrowings under the Revolving Credit Facility and the A/R Facility, proceeds from the GCX Sale and cash generated from operations. Based on the Company’s current financial plan, the Company believes that cash from operations and distributions from the EMI pipelines, and remaining borrowing capacity on our credit facilities will generate cash flows in excess of capital expenditures and the amount required to fund the Company’s planned quarterly dividend over the next 12 months.

39

Table of Contents

Index to Financial Statements

Long-term Financing

From time to time, we issue long-term debt. Our senior unsecured notes are fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the Revolving Credit Facility, the Term Loan Credit Facility and the A/R Facility. We use interest rate swaps to mitigate the impact of changes in interest rates on cash flows. See Note 13—Derivatives and Hedging Activities in the Notes to the Consolidated Financial Statements in this Annual Report for detailed discussion.

As of December 31, 2024, we had $800.0 million of our 6.625% senior unsecured notes due 2028 and $1.0 billion of our 5.875% senior unsecured notes due 2030 outstanding. The Term Loan Credit Facility and the Revolving Credit Facility, both with variable rates and maturing in 2026 and 2027, had outstanding borrowings of $1.00 billion and $590.0 million as of December 31,2024, respectively.

A/R Facility

On April 2, 2024, Kinetik Receivables, a bankruptcy remote special purpose entity formed as a direct subsidiary of the Partnership, which is a subsidiary of the Company, entered into an accounts receivable securitization facility with an initial facility limit of $150.0 million with PNC Bank, as the administrative agent, and certain purchasers party thereto from time to time, which has a scheduled termination date of April 1, 2025. As of December 31, 2024, we had outstanding borrowing under the A/R Facility of $140.2 million.

Our operations can be capital intensive, requiring investments to expand, upgrade, maintain or enhance existing operations and to meet environmental and operational regulations. During the year ended December 31, 2024 and 2023, capital spending for property, plant and equipment totaled $263.5 million and $312.9 million, respectively, intangible asset purchases of $12.3 million and $16.7 million, respectively, contributions to EMI totaled $3.3 million and $238.8 million, respectively, and paid net cash of $85.4 million to acquire additional equity interests in EPIC in second quarter 2024. In addition, the Company paid net cash of $341.2 million associated with the Durango Acquisition and net cash of $125.0 million to acquire midstream infrastructure assets through a business combination that closed in the first quarter 2023, see additional information in Note—3. Business Combinations in the Notes to the Consolidated Financial Statements in this Annual Report. Management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its contracts to service its customers. See Note 19—Segments in the Notes to the Consolidated Financial Statements in this Annual Report for capital expenditure for each operating segment.

The Company estimates 2025 capital expenditures of approximately $450.0 million to $540.0 million, which is slightly higher than 2024. This estimate reflects capital to complete the Kings Landing Project, including contingent liabilities due to Durango’s former owner, to continue the build out of the low- and high-pressure gathering system in Eddy County, New Mexico, to integrate the new gathering assets acquired through the Permian Resources Midstream Acquisition in Reeves County, and growth and maintenance capital across the existing Texas and New Mexico systems.

The Company anticipates its existing capital resources will be sufficient to fund the future capital expenditures for EMI pipelines and the Company’s existing infrastructure assets over the next 12 months. For further information on EMIs, refer to Note 7—Equity Method Investments in the Notes to our Consolidated Financial Statements in this Annual Report.

Cash Flows

The following tables present cash flows from operating, investing, and financing activities:

40

Table of Contents

Index to Financial Statements

Operating Activities. Net cash provided by operating activities increased by $52.9 million for the year ended December 31, 2024 compared with the same period in 2023. The change in the operating cash flows reflected a decrease in net income including noncontrolling interests of $142.2 million, an increase in adjustments related to non-cash items of $234.4 million and a decrease in cash provided by changes in working capital of $39.3 million. Period-over-period increase in non-cash adjustments was primarily driven by a $252.9 million increase in deferred tax expense due to recognition of income tax expense from deferred tax assets in 2024 compared to the release of valuation allowance for deferred tax assets made in 2023, an increase in depreciation and amortization expense of $43.2 million compared with the same period in 2023 due to increase in property, plant and equipment acquired and put into service since second half of 2023, an increase in share-based compensation expense of $20.6 million compared with the same period in 2023 due to the 2024 STI bonus being paid in December for 2024 versus March in prior years, and an increase in distribution from unconsolidated affiliates of $17.5 million compared with the same period in 2023 driven by PHP’s expansion project. The increase was partially offset by gain from sale of all equity interest in GCX of $89.8 million, and a decrease in loss on disposal of assets of $15.4 million. Period-over-period changes in working capital were related to fluctuations in trade receivable and payable balances due to timing of collection and payments and fluctuations in accrued revenue and accrued purchases.

Investing Activities. Net cash used in investing activities decreased by $509.4 million for the year ended December 31, 2024 compared with the same period in 2023. The decrease was primarily driven by cash consideration received as a result of the GCX Sale of $524.4 million and a decrease of $235.5 million in contributions made to unconsolidated affiliates as PHP’s expansion project was completed and put into service in December 2023. The decrease was partially offset by the payment of net cash consideration of $341.2 million related to Durango Acquisition.

Financing Activities. Net cash used in financing activities totaled $461.4 million for the year ended December 31, 2024 compared with net cash provided by financing activities totaling $100.0 million in the same period in 2023. The $561.3 million change was primarily due to a net repayment of outstanding debt of $65.4 million made in 2024 compared to net proceeds of $187.8 million from the long-term debt and Revolving Credit Facility in 2023. Increase in cash outflow was also due to an increase of $313.9 million in cash dividends paid to Class A Common Stock shareholders and Class C Common Unit holders as the Reinvestment Agreement (as defined below) terminated in March 2024.

Dividend and Distribution Reinvestment Agreement

On February 22, 2022, the Company entered into a Dividend and Distribution Reinvestment Agreement (the “Reinvestment Agreement”) with certain stockholders including BCP Raptor Aggregator, LP, BX Permian Pipeline Aggregator, LP, Buzzard Midstream LLC, APA Corporation, Apache Midstream LLC and certain individuals (each, a “Reinvestment Holder”). Under the Reinvestment Agreement, each Reinvestment Holder was obligated to reinvest at least 20% of all distributions on common units representing limited partner interests in the Partnership (“Common Units”) or dividends on shares of Class A Common Stock in the Company’s Class A Common Stock. For the calendar year 2023, the Audit Committee resolved 100% of all distributions or dividends received by each Reinvestment Holder would be reinvested in shares of Class A Common Stock. The Reinvestment Agreement terminated automatically on March 8, 2024.

During 2024, the Company made cash dividend payments of $396.0 million to holders of Class A Common Stock and Common Units and $75.6 million was reinvested in shares of Class A Common Stock by the Reinvestment Holders.

Stock Repurchase Program

In February 2023, the Board approved the Repurchase Program, authorizing discretionary purchases of the Company’s Class A Common Stock up to $100.0 million in the aggregate. Repurchases may be made at management’s discretion from time to time, in accordance with applicable securities laws, on the open market or through privately negotiated transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act. Privately negotiated repurchases from affiliates are also authorized under the Repurchase Program, subject to such affiliates’ interest and other limitations. The repurchases will depend on market conditions and may be discontinued at any time without prior notice.

During the year ended December 31, 2024, the Company did not repurchase any of its outstanding shares.

For more information regarding the non-deductible 1% U.S. federal excise tax imposed on certain repurchases of stock by publicly traded U.S. corporations, please refer to Part I—Item 1A Risk Factors—Risks Related to Ownership of our Common Stock.

41

Table of Contents

Index to Financial Statements

Dividend

On January 22, 2025, the Company declared a cash dividend of $0.78 per share on the Company’s Class A Common Stock and a distribution of $0.78 per Common Unit from the Partnership to the holders of Common Units. Dividends are payable on February 12, 2025 to holders of record as of market close on February 3, 2025. As the context requires, dividends paid to holders of Class A Common Stock and distributions paid to holders of Common Units may be referred to collectively as “dividends.”

Liquidity

The following table presents a summary of the Company’s key financial indicators:

Off-Balance Sheet Arrangements

As of December 31, 2024, there were no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Our significant accounting policies are described in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2—Summary of Significant Accounting Policies of this Annual Report.

The Company prepares its financial statements and the accompanying notes in conformity with U.S. GAAP, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Critical accounting estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of the following critical accounting estimates.

Business Combination

For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of these items requires management’s judgment and/or the utilization of independent valuation specialists and involves the use of significant estimates and assumptions. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. See Note 3—Business Combination in our Notes to the Consolidated Financial Statements in this Annual Report for more information regarding our valuation approach.

Impairment of Long-lived Assets

Long-lived assets used in operations are evaluated for potential impairment when events or changes in circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset may not be recovered, the asset is assessed for impairment through an established process in which changes to significant assumptions such as service prices, throughput volumes, future development plans and fluctuation of commodity prices are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset

42

Table of Contents

Index to Financial Statements

group, the carrying value is written down to an estimated fair value. Such fair value is generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market-based valuation approach, which are Level 3 fair value measurements. Estimates and assumptions can be affected by a variety of factors, including external factors such as industry and economic trends, and internal factors such as changes in our business strategy and our internal forecasts. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates.

Equity Method Investment

We evaluate our EMIs for impairment when events or circumstances indicate that the carrying value of the EMI may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, we adjust the carrying values of the investment downward, if necessary, to their estimated fair values.

We estimate the fair value of our EMIs based on a number of factors, including discount rates, projected cash flows, and enterprise value. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our EMIs (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our EMIs, such as their future capital and operating plans and their financial condition.

Derivatives Instruments and Hedging Activities

All our derivative contracts are recorded at estimated fair value. We utilize published prices, broker quotes, and estimates of market prices to estimate the fair value of these contracts; however, actual amounts could vary materially from estimated fair values as a result of changes in market prices. In addition, changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts.

Income Taxes

We make significant judgments and estimates in determining our provision for income taxes, including our assessment of our income tax positions, interpretation and application of complex tax laws and regulations and determining a valuation allowance, if necessary. In particular, there are numerous and complex judgments and assumptions inherent in determining a valuation allowance, including factors such as future operating conditions and profitability. For more information, see Note 15—Income Taxes in our Notes to the Consolidated Financial Statements in this Annual Report.

43

Table of Contents

Index to Financial Statements

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report. This section of this Annual Report generally discusses 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 that are omitted in this Annual Report are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, filed on March 7, 2023.

Unless otherwise noted or the context requires otherwise, references herein to Kinetik Holdings Inc.,“the Company”, “us”, “our”, “we” or similar terms, with respect to time periods prior to February 22, 2022, include BCP and its consolidated subsidiaries and do not include ALTM and its consolidated subsidiaries, while references herein to Kinetik Holdings Inc.,“the Company”, “us”, “our”, “we” or similar terms, with respect to time periods from and after February 22, 2022, include ALTM and its consolidated subsidiaries.

Business Combination

On February 22, 2022, (“the Closing Date”), Kinetik Holdings Inc., a Delaware corporation (formerly known as Altus Midstream Company), consummated the business combination transactions contemplated by the Contribution Agreement, dated as of October 21, 2021 (the “Contribution Agreement”), by and among the Company, Altus Midstream LP (now known as Kinetik Holdings LP), a Delaware limited partnership and subsidiary of Altus Midstream Company (the “Partnership”), New BCP Raptor Holdco, LLC, a Delaware limited liability company, and BCP. The transactions contemplated by the Contribution Agreement are referred to herein as the “Transaction.” In connection with the closing of the Transaction (the “Closing”), the Company changed its name from “Altus Midstream Company” to “Kinetik Holdings Inc.” Upon closing of the business combination, BCP and its subsidiaries became wholly owned subsidiaries of the Partnership. The Transaction was accounted for as a reverse merger pursuant to ASC 805, Business Combination (“ASC 805”).

Refer to Note 3—Business Combination in the Notes to the Consolidated Financial Statements for further information regarding the Transaction.

Overview

We are an integrated midstream energy company in the Permian Basin providing comprehensive gathering, transportation, compression, processing and treating services. Our core capabilities include a variety of service offerings including natural gas gathering, transportation, compression, treating and processing; NGLs stabilization and transportation; produced water gathering and disposal; and crude oil gathering, stabilization, storage and transportation. The Company’s corporate office is located in Houston, Texas and our operations are strategically located in the heart of the Delaware Basin.

Our Operations and Segments

We have two reportable segments which are strategic business units with various products and services. The Midstream Logistics segment operates under three service offerings, 1) gas gathering and processing, 2) crude oil gathering, stabilization and storage services and 3) produced water gathering and disposal. The Pipeline Transportation segment consists of four EMI pipelines originating in the Permian Basin with various access points to the U.S. Gulf Coast, Kinetik NGL Pipelines and Delaware Link Pipeline. The pipelines transport crude oil, natural gas and NGLs within the Permian Basin and to the U.S. Gulf Coast.

Midstream Logistics

Gas Gathering and Processing. The Midstream Logistics segment provides gas gathering and processing services with over 1,600 miles of low and high-pressure steel pipeline located throughout the Delaware Basin. Gas processing assets are centralized at five processing complexes with total cryogenic processing capacity of approximately 2.0 Bcf/d.

Crude Oil Gathering, Stabilization and Storage Services. Crude gathering assets are centralized at the Caprock Stampede Terminal and the Pinnacle Sierra Grande Terminal. The system includes approximately 220 miles of gathering pipeline and 90,000 barrels of crude storage.

32

Table of Contents

Index to Financial Statements

Water Gathering and Disposal. The system includes over 360 miles of gathering pipeline and approximately 580,000 barrels per day of permitted disposal capacity.

Pipeline Transportation

EMI pipelines. The Company owns the following equity interests in four EMI pipelines in the Permian Basin with access to various points along the Texas Gulf Coast: 1) an approximate 55.5% equity interest in Permian Highway Pipeline LLC (“PHP”), which is also owned and operated by Kinder Morgan. The increase of equity interest in PHP was related to the completion of PHP’s expansion project in December 2023; 2) 16.0% equity interest in Gulf Coast Express Pipeline LLC (“GCX”), which is also owned and operated by Kinder Morgan; 3) 33.0% equity interest in Shin Oak, which is owned by Breviloba, LLC, and operated by Enterprise Products Operating LLC; and 4) 15.0% equity interest in Epic Crude Holdings, LP (“EPIC”), which is operated by EPIC Consolidated Operations, LLC.

Kinetik NGL Pipelines. The Kinetik NGL Pipelines consist of approximately 96 miles of NGL pipelines connecting our East Toyah and Pecos complexes to Waha, including our 20-inch Dewpoint pipeline that spans 40 miles, and our 30 mile, 16-inch Brandywine Pipeline connecting to our Diamond Cryogenic complex. The Kinetik NGL pipeline system has a capacity of approximately 580 MBbl/d.

Delaware Link Pipeline. The Delaware Link Pipeline consists of approximately 40 miles of 30-inch diameter pipeline with a capacity of approximately 1.0 Bcf/d that provides additional transportation capacity to Waha. The project reached commercial in-service in October 2023.

Recent Developments

Secondary Offering of Common Stock

On December 11, 2023, the Company and Apache Midstream (the “Selling Stockholder”) entered into an Underwriting Agreement with J.P. Morgan Securities LLC, as representative of the several underwriters named therein (collectively, the “Underwriters”), pursuant to which the Selling Stockholder agreed to sell to the Underwriters, and the Underwriters agreed to purchase from the Selling Stockholder, subject to and upon the terms and conditions set forth therein, 7,475,000 shares of Class A Common Stock. The Company did not receive any proceeds from the sale of shares of Common Stock in the offering.

Sustainability-Linked Senior Notes Offerings

On December 6, 2023, the Partnership completed a private placement of $500.0 million aggregate principal amount of 6.625% Sustainability-Linked Senior Notes due 2028 (the “Original 2028 Notes”) at par; further, on December 19, 2023, the Company completed an additional private placement of $300.0 million aggregate principal amount of 6.625% Sustainability-Linked Senior Notes due 2028 (the “Additional 2028 Notes”) at 100.50% of face amount (collectively, the “2028 Notes”). The Original 2028 Notes and Additional 2028 Notes are treated as a single series of securities under the indenture governing the 2028 Notes, vote together as a single class, and have substantially identical terms, other than the issue date and issue price. The 2028 Notes are fully and unconditionally guaranteed by the Company and issued under our Sustainability-Linked Financing Framework. The Sustainability Performance Targets (“SPT”) as defined in the indenture governing the 2028 Notes related to three key performance indicators: (1) Reduction of Scope 1 and Scope 2 greenhouse gas emissions intensity, (2) Reduction of Scope 1 and Scope 2 methane gas emissions intensity and (3) female representation in corporate officer positions. For additional information regarding our SPTs, please see “—Sustainability-Linked Financing Framework” below.

Proceeds from the 2028 Notes together with cash on hand and borrowings under the Company’s Revolving Credit Facility (as defined below) were used to repay a portion of the outstanding borrowings under the Company’s existing Term Loan (as defined below).

Term Loan Credit Facility Amendment 2023

On December 6, 2023, the Partnership, the Company, PNC Bank, National Association (“PNC Bank”), as administrative agent, and the banks and other financial institutions party thereto, as lenders, entered into a First Amendment to Credit Agreement (the “First Amendment”) to amend certain terms of its existing Term Loan Credit Facility (the “Term Loan”), concurrently with the closing of its 2028 Notes discussed above. The First Amendment (1) extended the maturity of the Term Loan from June 8, 2025 to June 8, 2026 upon the prepayment of a principal amount of loans under the Term Loan of no less than $500.0 million; and (2) provided for an additional automatic six-month extension of the amended maturity date to December 8, 2026, at such time as no more than $1.00 billion of an aggregate principal amount of loans under the Term Loan remain outstanding, subject to customary conditions. The Company determined that the amendment of the maturity date is a

33

Table of Contents

Index to Financial Statements

modification of the original Term Loan. The fee paid directly to lenders in arranging the modification totaling $1.5 million was recorded as original debt discount and the costs incurred with third parties directly related to the modification totaling $0.6 million was expensed as incurred. Furthermore, the partial paydown of the principal totaling $800.0 million, using proceeds from the 2028 Notes, resulted in the $1.9 million write off (loss on extinguishment) of a proportional amount of the remaining unamortized debt issuance cost and original discount from the Term Loan immediately prior to the paydown.

PHP Expansion Project

In June 2022, PHP announced a final investment decision to proceed with its expansion project to increase total capacity to 2.65 Bcf/d, fully subscribed under 10 year take-or-pay contracts. The expansion project increased PHP’s capacity by nearly 550 MMcf/d. Approximately 67% of the funding for the expansion project was borne by the Company and the remainder by Kinder Morgan. As a result, upon completion of the project, the Company’s ownership interest in PHP increased to approximately 55.5%. The Company contributed $238.8 million to the expansion project during 2023 and the expansion went into service on December 1, 2023.

Sustainability-Linked Financing Framework

On May 16, 2022, we published our Sustainability-Linked Financing Framework, which we developed in alignment with the five components outlined in the International Capital Markets Association Sustainability-Linked Bond Principles as of June 2020 and the Loan Syndications and Trading Association Sustainability-Linked Loan Principles as of July 2021 (each as referred to in our Sustainability-Linked Financing Framework) and corresponding Second Party Opinion provided by ISS ESG.

This framework establishes KPIs that will be used to measure our progress against our SPTs. Under this framework, our KPIs are (1) Scope 1 and Scope 2 greenhouse gas emissions intensity, (2) Scope 1 and Scope 2 methane gas emissions intensity and (3) female representation in corporate officer positions. Our long-term SPTs are (1) reducing the intensity of all Scope 1 and Scope 2 greenhouse gas emissions from our operations by 35% by 2030 from a 2021 baseline year (as described in the Sustainability-Linked Financing Framework), (2) reducing the intensity of Scope 1 and Scope 2 methane gas emissions from our operations by 30% by 2030 from a 2021 baseline year, and (3) increasing female representation in corporate officer positions of Vice President and above to 20% by year-end 2026 from a 2021 baseline year.

Fiscal year 2022 marked the first measurement period for our Term Loan and Revolving Credit Facility, which are linked to the methane emissions intensity ratio KPI and the female officer representation KPI. For the methane emissions intensity ratio KPI, we achieved a 12.0% reduction from 2021 to 2022, which was 8.70% higher than the defined 2022 target in our debt agreements. For the female officer representation KPI, Kinetik achieved a 17.70% female participation rate in 2022, which was 8.00% higher than the defined 2022 target in our debt agreements.

Factors Affecting Our Business

Commodity Price Volatility

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGLs, crude oil and natural gas prices. As a result of uncertainty around global commodity supply and demand, the current armed conflict in Israel and the Gaza Strip, the ongoing armed conflict in Ukraine, and uncertainty from failures of two U.S. banks and the resulting effects on financial markets, global oil and natural gas commodity prices continue to remain volatile. The volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems. Although ongoing armed conflicts might generate commodity price upward pressure, and our operations could benefit in an environment of higher natural gas, NGLs and condensate prices, the instability of the international political environment and human and economic hardship resulting from the conflicts would have a highly uncertain impact on the U.S. economy, which in turn, might affect our business and operations adversely. Our product sales revenue is exposed to commodity price fluctuations. Therefore, commodity price decline and sustained periods of low natural gas and NGL prices could have an adverse effect on our product revenue stream. Also, after a rapid rise of oil and natural gas prices in the first half of 2022, oil and natural gas prices have moderated from their peaks during the past twelve months in 2023. The Company continues to monitor commodity prices closely and may enter into commodity price hedges from time to time as necessary to mitigate the volatility risk. In addition, the Company, when economically appropriate, enters into fee-based arrangements that insulate the Company from commodity price volatility.

34

Table of Contents

Index to Financial Statements

Inflation and Interest Rates

The annual rate of inflation in the United States was 3.10% for the 12 months ending January 2024 compared to 6.4% for the 12 months ending in January 2023, as measured by the Consumer Price Index. The Federal Open Market Committee (“FOMC”) seeks to achieve maximum employment and inflation at the rate of 2.00% over the long run. In support of these goals, the FOMC maintained the target range for the federal funds rate to 5.25% - 5.50% during its meeting in January 2024. The Committee indicated it will not be appropriate to reduce the target range for the federal funds rate until it gains greater confidence that inflation is moving sustainably toward 2.00%. Increased interest rates beyond the term of our hedges will increase our financing costs and have a negative impact on the Company’s ability to meet its contractual debt obligations and to fund its operating expenses, capital expenditures, dividends and distributions.

35

Table of Contents

Index to Financial Statements

Results of Operations

The following table presents the Company’s results of operations for the periods presented:

*The results of the legacy ALTM business are not included in the Company’s consolidated financials prior to February 22, 2022. Refer to the Annual Report basis of presentation in Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements in this Annual Report, for further information.

**Cost of sales (exclusive of depreciation and amortization) is net of gas service revenues totaling $148.3 million and $70.4 million for the years ended December 31, 2023 and 2022, respectively, for certain volumes where we act as principal.

NM - Not meaningful

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

Revenues

For the year ended December 31, 2023, revenue increased $42.9 million, or 4%, to $1,256.4 million, compared to $1,213.5 million for the same period in 2022. The increase was primarily driven by increases in gathered and disposed of produced water volumes, as well as similar increases in condensate and NGL volumes sold.

36

Table of Contents

Index to Financial Statements

Service revenue

Service revenue consists of service fees paid to the Company by its customers for providing comprehensive gathering, treating, processing and water disposal services necessary to bring natural gas, NGLs and crude oil to market. Service revenue for the year ended December 31, 2023, increased by $23.8 million, or 6%, to $417.8 million, compared to $394.0 million for the same period in 2022. This increase is primarily due to a period-over-period increase in gathered and disposed of produced water volumes of 76.4 MBbls per day, or $28.2 million. Period over period gathered and processed gas volumes increased 307.4 Mcf per day and 271.5 Mcf per day, respectively. However, the total gathered and processed gas volumes where we function as the agent decreased period over period, which lead to a $3.1 million decrease in service fees. Over 99% of service revenues are included in the Midstream Logistics segment.

Product revenue

Product revenue consists of commodity sales (including condensate, natural gas residue and NGLs). Product revenue for the year ended December 31, 2023, increased by $16.1 million, or 2%, to $822.4 million, compared to $806.4 million for the same period in 2022, primarily due to a period-over-period increase in NGL and condensate sales volumes. NGL and condensate sales volumes increased 14.7 million barrels, or over 80%. The increase in volume was partially offset by decreases in condensate prices of $22.38 per barrel, or 24%, and decreases of NGL prices of $14.31 per barrel, or 40%. In addition, natural gas residue sales volumes increased 0.5 million MMBtu, or 2%, but fully offsetting this increase in residue volumes, natural gas prices decreased period-over-period $3.84 per MMBtu, or 69%. Product revenues are included entirely in the Midstream Logistics segment.

Operating Costs and Expenses

Costs of sales (exclusive of depreciation and amortization)

Cost of sales (exclusive of depreciation and amortization) primarily consists of purchases of NGLs and natural gas from our producers at contracted market prices to support product sales to other third parties. For the year ended December 31, 2023, cost of sales decreased $25.8 million, or 5%, to $515.7 million, compared to $541.5 million for the same period in 2022. The decrease was primarily driven by the period-to-period decreases in the aforementioned commodity prices. More than 99% of the cost of sales (exclusive of depreciation and amortization) are included in the Midstream Logistics segment.

Operating expenses

Operating expenses increased by $24.2 million, or 18%, to $161.5 million for the year ended December 31, 2023, compared to $137.3 million for the same period in 2022. Of the total increase, $6.3 million related to increased operating expenses from our water operations, predominantly related to the newly acquired midstream infrastructure assets. The remaining increase was primarily the result of higher leased compression ($8.8 million) and electricity costs ($5.6 million) from the increased gathered and processed volumes discussed above. Over 99% of operating expenses are included in the Midstream Logistics segment.

Loss on disposal of assets

For the year ended December 31, 2023, the Company recognized a loss on disposal of assets of $19.4 million compared with $12.6 million for the same period in 2022. The change was primarily related to retirements of vehicles, compressor stations and a refrigeration plant that had become idle due to operational changes.

Other Income (Expense)

Loss on debt extinguishment

For the year ended December 31, 2023, the Company recognized a loss on debt extinguishment of $1.9 million, compared with a loss of $28.0 million for the same period in 2022. The loss on debt extinguishment recognized during 2023 was related to unamortized debt issuance costs written off in relation to the $800 million repayment of the Term Loan as discussed in Note—8 Debt and Financing Costs in the Notes to Consolidated Financial Statements. The prior year loss on debt extinguishment was in relation to the comprehensive refinancing completed in June of 2022.

37

Table of Contents

Index to Financial Statements

Gain on embedded derivative

For the year ended December 31, 2022, the Company recognized a gain on an embedded derivative of $89.1 million as a result of the complete redemption of redeemable noncontrolling interest Preferred Units during July of 2022. There were no similar redemptions or activities for the year ended December 31, 2023.

Interest expense

The Company incurred interest expense of $205.9 million for the year ended December 31, 2023 compared with $149.3 million for the same period in 2022. Increases of $77.3 million were driven by higher average debt obligations and an overall increase in interest rates associated with the Term Loan and Revolving Credit Facility, which carried some variability. This increase was partially offset by higher capitalized interest of $15.5 million related to ongoing growth capital projects and the PHP expansion, as well as $7.8 million of year over year favorable valuation marks on our interest rate swaps. Refer to Note—13 Derivatives and Hedging Activities in the Notes to Consolidated Financial Statements regarding the Company’s strategy in managing interest rate risk.

Equity in earnings of unconsolidated affiliates

Income from EMI pipelines increased by $19.1 million, or 11% to $200.0 million for the year ended December 31, 2023, compared to $181.0 million for the same period in 2022. The increase was primarily due to additional equity interests in PHP from the recently completed expansion and due to the Company owning the former ALTM EMI pipelines for a full 12 months during 2023 versus 10 months in 2022. Equity in earnings of unconsolidated affiliates is included entirely in the Pipeline Transportation segment.

Income taxes (benefit) expense

The Company recorded income tax benefit of $232.9 million for the year ended December 31, 2023, compared to income tax expense of $2.6 million for the same period in 2022. The current year tax benefit was primarily due to the release of the valuation allowance on federal deferred tax assets during the fourth quarter of 2023. As the Company achieved a three-year cumulative level of profitability as of December 31, 2023, the Company has concluded that it is more likely than not that its deferred tax assets will be realized and as such, no valuation allowance was recorded.

Key Performance Metrics

Adjusted EBITDA

Adjusted EBITDA is defined as net income including noncontrolling interests adjusted for interest, taxes, depreciation and amortization, impairment charges, asset write-offs, the proportionate EBITDA from our EMI pipelines, equity in earnings from investments recorded using the equity method, share-based compensation expense, noncash increases and decreases related to trading and hedging agreements, extraordinary losses and unusual or non-recurring charges. Adjusted EBITDA provides a basis for comparison of our business operations between current, past and future periods by excluding items that we do not believe are indicative of our core operating performance.

We believe that Adjusted EBITDA provides a meaningful understanding of certain aspects of earnings before the impact of investing and financing charges and income taxes. Adjusted EBITDA is useful to an investor in evaluating our performance because this measure:

•Is widely used by analysts, investors and competitors to measure a company’s operating performance;

•Is a financial measurement that is used by rating agencies, lenders, and other parties to evaluate our credit worthiness; and

•Is used by our management for various purposes, including as a measure of performance and as a basis for strategic planning and forecasting.

38

Table of Contents

Index to Financial Statements

Adjusted EBITDA is not defined in GAAP

The GAAP measure used by the Company that is most directly comparable to Adjusted EBITDA is net income including noncontrolling interests. Adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income including noncontrolling interests or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income including noncontrolling interests. Adjusted EBITDA should not be considered in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. The Company’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies in the industry, thereby diminishing its utility.

Reconciliation of non-GAAP financial measure

Company management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between Adjusted EBITDA as compared to net income including noncontrolling interests, and incorporating this knowledge into its decision-making processes. Management believes that investors benefit from having access to the same financial measure that the Company uses in evaluating operating results.

The following table presents a reconciliation of the GAAP financial measure of net income including noncontrolling interests to the non-GAAP financial measure of Adjusted EBITDA.

*The results of the legacy ALTM business are not included in the Company’s consolidated financials prior to February 22, 2022. Refer to the Annual Report basis of presentation in Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements in this Annual Report, for further information.

NM - Not meaningful

39

Table of Contents

Index to Financial Statements

Adjusted EBITDA increased by $66.6 million, or 9% to $838.8 million for the year ended December 31, 2023, compared to $772.2 million for the same period in 2022. As discussed in the Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations to this Annual Report, $36.2 million of the increase was due to an increase in operating revenues of $42.9 million and lower cost of sales (exclusive of depreciation and amortization) of $25.8 million, partially offset by an increase in operating expenses, ad valorem taxes and general and administrative expenses totaling of $32.5 million. The increase was also driven by (i) higher proportionate EMI EBITDA of $37.2 million due to owning the EMI investments acquired through the Transaction for a full 12 months in 2023 and increased equity ownership in PHP upon completion of the PHP expansion project in December 2023 and (ii) an increase in the add back related to share-based compensation of $13.2 million due primarily to a full 12 months of amortization for the Class A Shares versus only 10 months in the prior period. These increases were partially offset by decreases in the add backs related to transaction and integration costs totaling $17.0 million related to the Transaction from 2022.

Segment Adjusted EBITDA

Segment Adjusted EBITDA is defined as segment net earnings adjusted to exclude interest expense, income tax expense, depreciation and amortization, the proportionate effect of these same items for our EMI pipelines and other non-recurring items. The following table presents segment adjusted EBITDA. Also refer to Note 19—Segments in the Notes to our Consolidated Financial Statements in this Annual Report for reconciliation of segment adjusted EBITDA to net income including noncontrolling interests.

* The results of the legacy ALTM business are not included in the Company’s consolidated financials prior to February 22, 2022. Refer to Note 1—Description of Business and Basis of Presentation in the Notes to the Consolidated Financial Statements of this Annual Report for further information on the Company’s financial statement consolidation.

** 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 a reportable segment for the purpose of evaluating their performance, including certain general and administrative expense

Midstream Logistics segment adjusted EBITDA increased by $27.1 million, or 5%, to $543.2 million for the year ended December 31, 2023, compared to $516.0 million for the same period in 2022. The increase was primarily driven by an increase in the segment’s operating revenue of $38.0 million, or 3% and a decrease in costs of sales, excluding deprecation and amortization expense, of $25.8 million, or 5%. The increase was partially offset by an increase in operating expense of $24.8 million, or 18%. The reasons for the fluctuations are discussed in the Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations to this Annual Report.

Pipeline Transportation segment adjusted EBITDA increased by $41.9 million, or 16%, to $311.1 million for the year ended December 31, 2023, compared to $269.2 million for the same period in 2022. The increase was driven by an increase in segment’s operating revenue of $4.9 million, or 267%, due to higher service revenue and other revenue from the pipelines acquired and constructed by the Company, and an increase in the Company’s EMIs’ proportionate EBITDA of $37.2 million, or 14%, due to owning the EMI investments acquired through the Transaction for a full 12 months and increased equity ownership in PHP upon completion of the PHP expansion project in December 2023.

Contractual Obligations

We have contractual obligations for principal and interest payments on our 2028 Notes, 2030 Notes and Term Loan. See Note 8—Debt and Financing Costs in the Notes to our Consolidated Financial Statements in this Annual Report.

Under certain clauses of our transportation services agreements with third party pipelines to transport natural gas and NGLs, if we fail to ship a minimum throughput volume, then we will pay certain deficiency payments for transportation based on the volume shortfall up to the MVC amount.

40

Table of Contents

Index to Financial Statements

For additional information regarding the Company’s obligations, please see Note 8—Debt and Financing Costs and Note 17—Commitments and Contingencies in the Notes to the Consolidated Financial Statements in this Annual Report.

Capital Resources and Liquidity

The Company’s primary use of capital since inception has been for the initial construction of gathering and processing assets, as well as the acquisition of the EMI pipelines and associated subsequent construction costs. For 2023, the Company’s primary capital spending were related to the PHP expansion project, the midstream infrastructure acquisition and other budgeted capital expenditures for construction of gathering and processing assets, the Company’s contractual debt obligations and quarterly cash dividends and distributions.

During the year ended December 31, 2023, the Company’s primary sources of cash were distributions from the EMI pipelines, borrowings under the Revolving Credit Facility, proceeds from debt offerings and cash generated from operations. Based on the Company’s current financial plan, the Company believes that cash from operations and distributions from the EMI pipelines, and remaining borrowing capacity on our Revolving Credit Facility will generate cash flows in excess of capital expenditures and the amount required to fund the Company’s planned quarterly dividend over the next 12 months. In addition, the Company entered into the First Amendment, which extended maturity of its Term Loan through June 2026. Upon the closing of the First Amendment and in conjunction with paying down $800 million on the Term Loan, the Company terminated one of its existing interest rate swap contracts and partially terminated another. As of December 31, 2023, the Company had two interest rate swap contracts with total notional amounts of $1.70 billion maturing on May 31, 2025, which pay a fixed rate ranging from 4.38% to 4.48% for the respective notional amounts.

Comprehensive Refinancing

On June 8, 2022, the Partnership completed the private placement of $1.00 billion aggregate principal amount of the 2030 Notes, which are fully and unconditionally guaranteed by the Company. The 2030 Notes are issued under our Sustainability-Linked Financing Framework and include sustainability-linked features. In addition, the Partnership entered into a revolving credit agreement, which provides for a $1.25 billion senior unsecured revolving credit facility (the “Revolving Credit Facility”) maturing on June 8, 2027, and term loan credit agreement, which provides for a $2.00 billion senior unsecured Term Loan maturing on June 8, 2025, which was then extended to June 8, 2026 pursuant to the First Amendment. The Term Loan may be further extended to December 8, 2026, at such time as no more than $1.00 billion of an aggregate principal amount of loans under the Term Loan remain outstanding, subject to customary conditions. Proceeds from the 2030 Notes and the Term Loan were used to repay all outstanding borrowings under our then existing credit facilities and to pay fees and expenses related to the offering. Refer to Note 8 — Debt and Financing Costs in the Notes to our Consolidated Financial Statements in this Annual Report for further information.

December 2028 Sustainability-Linked Senior Notes

On December 6, 2023, the Partnership completed a private placement of $500.0 million aggregate principal amount at par. Further, on December 19, 2023, the Company completed an additional private placement of $300.0 million aggregate principal amount at 100.50% of the face amount. The Original 2028 Notes and the Additional 2028 Notes are treated as a single series of securities under the indenture governing the 2028 Notes, vote together as a single class, and have substantially identical terms, other than the issue date and issue price. The 2028 Notes are fully and unconditionally guaranteed by the Company and issued under our Sustainability-Linked Financing Framework. Proceeds from the 2028 Notes together with cash on hand and borrowings under the Partnership’s Revolving Credit Facility were used to repay a portion of the outstanding borrowings under the Partnership’s existing Term Loan.

Term Loan Amendment 2023

On December 6, 2023, the Partnership, the Company, PNC Bank and the banks and other financial institutions party thereto, as lenders, entered into the First Amendment concurrently with the closing of the Partnership’s 2028 Notes discussed above. The First Amendment (1) extended the maturity of the Term Loan from June 8, 2025 to June 8, 2026 upon the prepayment of a principal amount of loans under the Term Loan of no less than $500.0 million; and (2) provided for an additional automatic six-month extension of the amended maturity date if certain criteria are met. In conjunction with the principal prepayment of the existing Term Loan, the Company recognized a loss on extinguishment of debt of approximately $1.9 million from writing off the proportionate amount of unamortized debt issuance costs and original discount related to the partial extinguishment for the year ended December 31, 2023.

41

Table of Contents

Index to Financial Statements

Capital Requirements and Expenditures

Our operations can be capital intensive, requiring investments to expand, upgrade, maintain or enhance existing operations and to meet environmental and operational regulations. During the year ended December 31, 2023 and 2022, capital spending for property, plant and equipment totaled $312.9 million and $206.2 million in 2022, and intangible asset purchases of $16.7 million in 2023 and $15.4 million in 2022. In addition, the Company acquired midstream infrastructure assets totaling $125.0 million through a business combination that closed in the first quarter 2023, see additional information in Note—3. Business Combinations in the Notes to the Consolidated Financial Statements in this Annual Report. Management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its contracts to service its customers. During the year ended December 31, 2023, the Company contributed $238.8 million to PHP for the expansion project, compared to $78.2 million contributed to the same period of 2022. See Note 19—Segments in the Notes to the Consolidated Financial Statements in this Annual Report for capital expenditure for each operating segment.

The Company estimates 2024 capital expenditures of approximately $125.0 million to $165.0 million, which is significantly lower than that in 2023 as the Company concluded the Delaware Link Pipeline construction in September 2023 and the PHP Expansion Project went in service during December 2023.

The Company anticipates its existing capital resources will be sufficient to fund the future capital expenditures for EMI pipelines and the Company’s existing infrastructure assets over the next 12 months. For further information on EMIs, refer to Note 7—Equity Method Investments in the Notes to our Consolidated Financial Statements in this Annual Report.

Cash Flows

The following tables present cash flows from operating, investing, and financing activities:

Operating Activities. Net cash provided by operating activities decreased by $28.5 million for the year ended December 31, 2023 compared with the same period in 2022. The change in the operating cash flows reflected an increase in net income including noncontrolling interests of $135.7 million, and decreases in adjustments related to non-cash items of $135.5 million and cash provided by changes in working capital of $28.7 million. Period-to-period decrease in non-cash adjustments was primarily driven by a $235.5 million increase in deferred tax benefit due to the release of the Company’s valuation allowance for deferred tax assets during 2023 and a decrease in loss on debt extinguishment of $26.1 million related to the comprehensive refinancing which was completed in 2022. The decrease was partially offset by increases in derivative fair value adjustments of $61.8 million and depreciation and amortization expense of $20.6 million. Period-to-period changes in working capital was primarily related to a decrease in accrued liabilities and fluctuations in trade receivables and payables due to timing of collections and payments.

Investing Activities. Net cash used in investing activities increased by $400.2 million for the year ended December 31, 2023 compared with the same period in 2022. The increase was primarily driven by increases in property, plant and equipment expenditures, contributions made to the PHP expansion project and cash paid for the acquisition of certain midstream assets.

Financing Activities. Net cash provided by financing activities totaled $100.0 million for the year ended December 31, 2023 compared with net cash used in financing activities totaling $339.2 million in the same period in 2022. The $439.2 million change was primarily due to a reduction of cash outflow related to the redemption of Preferred Units for $644.8 million, as all Preferred Units were redeemed in 2022, lower net long term debt proceeds of $167.1 million and an increase in cash dividends paid to Class A Common Stock shareholders of $42.1 million.

Dividend and Distribution Reinvestment Agreement

On February 22, 2022, the Company entered into a Dividend and Distribution Reinvestment Agreement (the “Reinvestment Agreement”) with certain stockholders including BCP Raptor Aggregator, LP, BX Permian Pipeline Aggregator, LP, Buzzard Midstream LLC, APA Corporation, Apache Midstream LLC and certain individuals (each, a

42

Table of Contents

Index to Financial Statements

“Reinvestment Holder”). Under the Reinvestment Agreement, each Reinvestment Holder is obligated to reinvest at least 20% of all distributions on common units representing limited partner interests in the Partnership (“Common Units”) or dividends on shares of Class A Common Stock in the Company’s Class A Common Stock. For the calendar year 2023, the Audit Committee resolved 100% of all distributions or dividends received by each Reinvestment Holder would be reinvested in shares of Class A Common Stock. The Reinvestment Agreement will terminate automatically on March 8, 2024.

During 2023, the Company made cash dividend payments of $82.0 million to holders of Class A Common Stock and Common Units and $352.1 million was reinvested in shares of Class A Common Stock by the Reinvestment Holders.

Stock Split

On May 19, 2022, the Company announced a stock split with respect to its Class A Common Stock and Class C Common Stock in the form of a stock dividend (the “Stock Split”). The Stock Split was accomplished by distributing one additional share of Class A Common Stock for each share of Class A Common Stock outstanding and one additional share of Class C Common Stock for each share of Class C Common Stock outstanding. The additional shares of Common Stock were issued on June 8, 2022 to holders of record at the close of business on May 31, 2022.

Stock Repurchase Program

In February 2023, the Board approved the Repurchase Program, authorizing discretionary purchases of the Company’s Class A Common Stock up to $100.0 million in the aggregate. Repurchases may be made at management’s discretion from time to time, in accordance with applicable securities laws, on the open market or through privately negotiated transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act. Privately negotiated repurchases from affiliates are also authorized under the Repurchase Program, subject to such affiliates’ interest and other limitations. The repurchases will depend on market conditions and may be discontinued at any time without prior notice.

During the year ended December 31, 2023, the Company repurchased 194,174 shares at a total cost of $5.8 million. The Company retired all treasury stock as of December 31, 2023.

For more information regarding the non-deductible 1% U.S. federal excise tax imposed on certain repurchases of stock by publicly traded U.S. corporations, please refer to Part I—Item 1A Risk Factors—Risks Related to Ownership of our Common Stock.

Dividend

On January 23, 2024, the Company declared a cash dividend of $0.75 per share on the Company’s Class A Common Stock and a distribution of $0.75 per Common Unit from the Partnership to the holders of Common Units. Dividends are payable on March 7, 2024 to holders of record as of market close on February 22, 2024. Certain holders of Class A Common Stock and Common Units will receive a cash dividend with the balance receiving additional shares of Class A Common Stock under the Reinvestment Agreement.

Series A Cumulative Redeemable Preferred Units

The Company issued Series A Cumulative Redeemable Preferred Units (“Preferred Units”) on June 12, 2019. Because the Transaction was accounted for as a reverse merger, certain Preferred Units that were issued and outstanding were assumed at Closing for accounting purposes. The Company assumed 525,000 Preferred Units as well as 29,983 paid-in-kind (“PIK”) Preferred Units immediately after the Closing.

In 2022, the Company redeemed all outstanding Preferred Units and PIK units for an aggregate redemption price of $644.8 million. The Company recognized a gain of $9.6 million on redemption of the mandatory redeemable Preferred Units and excess of carrying amount over redemption price of $109.5 million on redemption of the redeemable noncontrolling interest Preferred Units during 2022.

43

Table of Contents

Index to Financial Statements

Liquidity

The following table presents a summary of the Company’s key financial indicators:

Off-Balance Sheet Arrangements

As of December 31, 2023, there were no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Our significant accounting policies are described in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2—Summary of Significant Accounting Policies of this Annual Report.

The Company prepares its financial statements and the accompanying notes in conformity with U.S. GAAP, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Critical accounting estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of the following critical accounting estimates.

Business Combination

For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of these items requires management’s judgment and/or the utilization of independent valuation specialists and involves the use of significant estimates and assumptions. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. See Note 3—Business Combination in our Notes to the Consolidated Financial Statements in this Annual Report for more information regarding our valuation approach.

Impairment of Long-lived Assets

Long-lived assets used in operations are evaluated for potential impairment when events or changes in circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset may not be recovered, the asset is assessed for impairment through an established process in which changes to significant assumptions such as service prices, throughput volumes, future development plans and fluctuation of commodity prices are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to an estimated fair value. Such fair value is generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market-based valuation approach, which are Level 3 fair value measurements. Estimates and assumptions can be affected by a variety of factors, including external factors such as industry and economic trends, and internal factors such as changes in our business strategy and our internal forecasts. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates.

44

Table of Contents

Index to Financial Statements

Equity Method Investment

We evaluate our EMIs for impairment when events or circumstances indicate that the carrying value of the EMI may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, we adjust the carrying values of the investment downward, if necessary, to their estimated fair values.

We estimate the fair value of our EMIs based on a number of factors, including discount rates, projected cash flows, and enterprise value. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our EMIs (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our EMIs, such as their future capital and operating plans and their financial condition.

Derivatives Instruments and Hedging Activities

All our derivative contracts are recorded at estimated fair value. We utilize published prices, broker quotes, and estimates of market prices to estimate the fair value of these contracts; however, actual amounts could vary materially from estimated fair values as a result of changes in market prices. In addition, changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts.

Income Taxes

We make significant judgments and estimates in determining our provision for income taxes, including our assessment of our income tax positions, interpretation and application of complex tax laws and regulations and determining a valuation allowance, if necessary. In particular, there are numerous and complex judgments and assumptions inherent in determining a valuation allowance, including factors such as future operating conditions and profitability. For more information, see Note 15—Income Taxes in our Notes to the Consolidated Financial Statements in this Annual Report.

45

Table of Contents

Index to Financial Statements

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 that are omitted in this Annual Report on Form 10-K are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Exhibit 99.6 of the Company’s Current Report on Form 8-K, filed on February 28, 2022.

Unless otherwise noted or the context requires otherwise, references herein to Kinetik Holdings Inc., “the Company”, “us”, “our”, “we” or similar terms, with respect to time periods prior to February 22, 2022, include BCP and its consolidated subsidiaries and do not include ALTM and its consolidated subsidiaries, while references herein to Kinetik Holdings Inc., “the Company”, “us”, “our”, “we” or similar terms, with respect to time periods from and after February 22, 2022, include ALTM and its consolidated subsidiaries.

The Transaction

On February 22, 2022, the Company consummated the business combination transactions contemplated by the Contribution Agreement, dated as of October 21, 2021, by and among the Company, the Partnership, Contributor and BCP. Pursuant to the Contribution Agreement, in connection with the Closing, (i) Contributor contributed all the equity interests in BCP and BCP Raptor Holdco GP, LLC, a Delaware limited liability company and the general partner of BCP (“BCP GP”), to the Partnership; and (ii) in exchange for such contribution, the Partnership transferred to Contributor 50,000,000 Common Units and 50,000,000 shares of the Company’s Class C Common Stock.

The Company’s public stockholders immediately prior to the Closing continued to hold their shares of the Company’s Class A Common Stock. As a result of the Transaction, immediately following the Closing (i) Contributor held approximately 75% of the issued and outstanding Common Stock, (ii) Apache Midstream held approximately 20% of the issued and outstanding Common Stock, and (iii) the Company’s remaining stockholders held approximately 5% of the issued and outstanding Common Stock. Upon close of the Transaction, the Company’s Pipeline Transportation segment expanded to include three additional EMI pipelines and to increase its ownership interest in PHP. Further, a secondary offering of 4 million shares held by Apache Midstream was closed during March of 2022, reducing Apache’s ownership to approximately 13%.

The Transaction also brought in additional volume capacity from ALTM for the Midstream Logistics segment, including a total of 600 MMcf/d of existing state-of-the-art operating processing capacity, 182 miles of in-service natural gas gathering pipelines, approximately 46 miles of residue gas pipelines with four market connections, and approximately 66 miles of NGLs pipelines. The increased volume capacity has contributed to the increase in operating revenue for the year ended December 31, 2022 compared to the same periods in 2021.

Overview

We are an integrated midstream energy company in the Permian Basin providing comprehensive gathering, transportation, compression, processing, and treating services. Our core capabilities include a variety of service offerings including natural gas gathering, transportation, compression, treating and processing; NGLs stabilization and transportation; produced water gathering and disposal; and crude oil gathering, stabilization, storage and transportation. The Company’s corporate office is located in Houston, TX and our operations are strategically located in the heart of the Delaware Basin in the Permian.

Our Operations and Segments

Upon Closing, the Company renamed its Gathering and Processing segment to Midstream Logistics and renamed its Transmission segment to Pipeline Transportation. These name changes were made to better align segment activities with the name of each respective segment. The Midstream Logistics segment operates under three service offerings, 1) gas gathering and processing, 2) crude oil gathering, stabilization, and storage services, and 3) water gathering and disposal. The Pipeline Transportation segment consists of four EMI pipelines in the Permian Basin with various access points to the Texas Gulf Coast, Kinetik NGL Pipeline and our Delaware Link Pipeline that is under construction. The EMI pipelines transport crude oil, natural gas, and NGLs within the Permian Basin and to the Texas Gulf Coast.

27

Table of Contents

Midstream Logistics

Gas Gathering and Processing. The Midstream Logistics segment provides gas gathering and processing services with approximately 1,500 miles of low and high-pressure steel pipeline located throughout the Southern Delaware Basin. Gas processing assets are centralized at five processing complexes with total cryogenic processing capacity of approximately 2.0 Bcf/d.

Crude Oil Gathering, Stabilization, and Storage Services. Crude gathering assets are centralized at the Caprock Stampede Terminal and the Pinnacle Sierra Grande Terminal. The system includes approximately 220 miles of gathering pipeline and 90,000 barrels of crude storage.

Water Gathering and Disposal. The system includes approximately 80 miles of gathering pipeline and approximately 490,000 barrels per day of permitted disposal capacity.

Pipeline Transportation

EMI pipelines. The Company owns the following equity interests in four EMI pipelines in the Permian Basin with access to various points along the Texas Gulf Coast: 1) an approximate 53.3% equity interest in PHP, which is also owned and operated by Kinder Morgan; 2) 16% equity interest in GCX, which is owned and operated by Kinder Morgan; 3) 33% equity interest in Shin Oak, which is owned by Breviloba, LLC, and operated by Enterprise Products Operating LLC; and 4) 15% equity interest in EPIC, which is operated by EPIC Consolidated Operations, LLC.

Brandywine NGL Pipeline. Approximately 30 miles of 20-inch NGL pipelines connected to our Diamond Cryogenic complex.

Delaware Link Pipeline. The Company is currently building the Delaware Link Pipeline, which will provide additional transportation capacity to Waha when it is put into service. The project is expected to be complete in the fourth quarter of 2023. Upon completion, this pipeline is estimated to be 40 miles and to have a capacity of 1.0 Bcf/d.

Recent Developments

Transfer to the New York Stock Exchange

On October 10, 2022, the Company notified the Nasdaq Global Select Market (“Nasdaq”) that it would voluntarily transfer the listing of its Class A Common Stock from Nasdaq to the New York Stock Exchange (the “NYSE”). The listing and trading of the Common Stock on Nasdaq ended at market close on October 21, 2022, and trading commenced on the NYSE at market open on October 24, 2022. The Class A Common Stock continues to trade under the current stock symbol “KNTK”.

Brandywine NGL Acquisition

In September 2022, the Company acquired approximately 30 miles of 20-inch NGL pipelines connected to our Diamond Cryogenic complex, Brandywine, for approximately $25 million. Brandywine is a strategic intrabasin natural gas liquids pipeline, affording Kinetik greater control over its system’s NGLs and providing interconnectivity to Shin Oak.

Comprehensive Refinancing

On June 8, 2022, the Partnership, completed a private placement of $1.0 billion aggregate principal amount of its 5.875% Senior Notes due 2030 (the “Notes”), which are fully and unconditionally guaranteed by the Company. The Notes are issued under our Sustainability-Linked Financing Framework and include sustainability-linked features. In addition, the Partnership entered into a new revolving credit agreement (the “RCA”), which provides for a $1.25 billion senior unsecured revolving credit facility (the “Revolving Credit Facility”) maturing on June 8, 2027, and a new term loan agreement (the “TLA”), which provides for a $2.00 billion senior unsecured term loan credit facility (the “Term Loan Credit Facility”) maturing on June 8, 2025. Proceeds from the Notes and the Term Loan Credit Facility were used to repay all outstanding borrowings under our existing credit facilities and to pay fees and expenses related to the offering. Refer to Note 8 — Debt and Financing Costs in the Notes to our Consolidated Financial Statements in this Form 10-K for further information.

28

Table of Contents

PHP Expansion Project

In June 2022, PHP announced a final investment decision to proceed with its expansion project to increase total capacity to 2.65 Bcf/d fully subscribed under 10 year take-or-pay contracts. The expansion project will increase PHP’s capacity by nearly 550 MMcf/d with a target in-service date in November 2023. Approximately 67% of the funding for the expansion project will be borne and the remainder by Kinder Morgan. As a result, following the in-service date of the expansion, Kinetik’s ownership interest in PHP will increase to approximately 55.5%. During 2022, the Company contributed $78.2 million to the expansion project.

Sustainability-Linked Financing Framework

On May 16, 2022, we published our Sustainability-Linked Financing Framework, which we developed in alignment with the five components outlined in the International Capital Markets Association Sustainability-Linked Bond Principles as of June 2020 and the Loan Syndications and Trading Association Sustainability-Linked Loan Principles as of July 2021 (each as referred to in our Sustainability-Linked Financing Framework) and corresponding Second Party Opinion provided by ISS ESG.

This framework establishes KPIs that will be used to measure our progress against SPTs. Under this framework, our KPIs are (1) Scope 1 and Scope 2 greenhouse gas emissions intensity, (2) Scope 1 and Scope 2 methane gas emissions intensity and (3) female representation in corporate officer positions and our SPTs are (1) reducing the intensity of all Scope 1 and Scope 2 greenhouse gas emissions from our operations by 35% by 2030 from a 2021 baseline year (as described in the Sustainability-Linked Financing Framework), (2) reducing the intensity of Scope 1 and Scope 2 methane gas emissions from our operations by 30% by 2030 from a 2021 baseline year, and (3) increasing female representation in corporate officer positions of Vice President and above to 20% by year-end 2026 from a 2021 baseline year.

Stock Split

On May 19, 2022, the Company announced the Stock Split with respect to its Class A Common Stock and Class C Common Stock in the form of a stock dividend. The Stock Split was accomplished by distributing one additional share of Class A Common Stock for each share of Class A Common Stock outstanding and one additional share of Class C Common Stock for each share of Class C Common Stock outstanding. The additional shares of Common Stock were issued on June 8, 2022 to holders of record at the close of business on May 31, 2022.

Factors Affecting Our Business

Commodity Price Volatility

There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGLs, crude oil and natural gas prices. As a result of uncertainty around global commodity supply and demand, uncertainty in global economic recovery from the aftereffects of the COVID-19 pandemic and the armed conflict in Ukraine, global oil and natural gas commodity prices continue to remain volatile. The volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems. Although the armed conflict in Ukraine generated commodity price upward pressure, and our operation could benefit in an environment of higher natural gas, NGLs and condensate prices, the instability of international political environment and human and economic hardship resulting from the conflict would have a highly uncertain impact on the U.S. economy, which in turn, might affect our business and operations adversely. Our product sales revenue is exposed to commodity price fluctuations. Therefore, commodity price decline and sustained periods of low natural gas and NGL prices could have an adverse effect on our product revenue stream. The Company continues to monitor commodity prices closely and may enter into commodity price hedges from time to time as necessary to mitigate the volatility risk. In addition, the Company, when economically appropriate, enters into fee-based arrangements that insulate the Company from commodity price volatility.

29

Table of Contents

Inflation and Interest Rates

The annual rate of inflation in the United States dropped slightly to 6.40% in January 2023, as measured by the Consumer Price Index, which was the lowest since October 2021. However, the Federal Open Market Committee (“FOMC”) maintains its long run goals of maximum employment and inflation at the rate of 2.00%. In support of these goals, the FOMC decided to raise the target range for the federal funds rate to 4.50% and 4.75% during its meeting in January 2023. There is uncertainty regarding whether inflation will continue to be tamed by the FOMC’s effort or whether the FOMC will continue to tighten its monetary policy in the next 12 months. Increased interest rates will increase our operating costs and have a negative impact on the Company’s ability to meet its contractual debt obligations and to fund its operating expenses, capital expenditures, dividends and distributions. The Company will continue to actively evaluate and analyze whether any additional forms of interest rate hedging should be implemented to mitigate interest rate exposure.

Supply Chain Considerations

During 2021 and 2022, challenging supply chain issues have emerged that will continue at least through the first half of 2023. Geopolitical events have further disrupted global supply chains and caused volatile commodity prices for natural gas, NGLs and crude oil. The United States has banned the import of Russian oil, NGLs and other energy commodities and the European Union has taken steps to reduce imports of Russian oil and natural gas. The principal supply issues facing our industry for the next twelve months include: raw materials availability, finished good inventory, rising freight costs, delays due to port congestion and overall labor shortages.

All bidding will require the risk of shipping costs and delays to be factored into proposals. Trucking availability and pricing will impact North American opportunities while sea-freight costs will impact sales of North American manufactured goods being delivered internationally for the foreseeable future. The import of raw materials from China will also incur price increases. To that end, accelerating tensions between China and the U.S. could also result in further supply disruption.

30

Table of Contents

Results of Operations

The following table presents the Company’s results of operations for the periods presented:

*The results of the legacy ALTM business are not included in the Company’s consolidated financials prior to February 22, 2022. Refer to the Form 10-K basis of presentation in Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements in this Form 10-K, for further information.

NM - Not meaningful

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

Revenues

For the year ended December 31, 2022, revenue increased $551.4 million, or 83%, to $1,213.5 million, compared to $662.0 million for the same period in 2021. The increase was primarily driven by period-to-period higher commodity prices, increases in gas gathered and processed volumes, as well as similar increases in condensate and NGL volumes sold. Volume increase reflected synergy realized from the new operations acquired through the Transaction.

31

Table of Contents

Service revenue

Service revenue consists of service fees paid to the Company by its customers for providing comprehensive gathering, treating, processing and water disposal services necessary to bring natural gas, NGLs and crude oil to the market. Service revenue for the year ended December 31, 2022, increased by $121.3 million, or 44%, to $394.0 million, compared to $272.7 million for the same period in 2021. This increase is primarily due to a period over period increase in gathered and processed gas volumes of 556.4 Mcf per day and 522.9 Mcf per day, respectively, of which 318.7 Mcf per day of gathered gas volume and 236.6 Mcf/d of processed gas volume were result of new operations acquired through the Transaction. Over 99% of service revenues are included entirely in the Midstream Logistics segment.

Product revenue

Product revenue consists of commodity sales (including condensate, natural gas residue, and NGLs). Product revenue for the year ended December 31, 2022, increased by $420.7 million, or 109%, to $806.4 million, compared to $385.6 million for the same period in 2021, primarily due to period-to-period increases in condensate prices combined with increased NGL and condensate sales volumes. Condensate prices increased $27.80 per barrel, or 44%. NGL and condensate sales volumes increased 12.7 million barrels, or over 300%. The increase in NGL and condensate sales volumes offset the decreased NGL prices of $0.80 per barrel, or 2%. This substantial increase in NGL and condensate revenue was due to our plants being run in recovery for part of the year ended December 31, 2022 versus rejection during the same period in 2021. For the same reason, natural gas residue sales volumes decreased 6.3 million MMBtu, or 25%. Partially offsetting this decrease in volumes, natural gas prices increased period over period $1.44 per MMBtu, or 37%. Product revenues are included entirely in the Midstream Logistics segment.

Operating Costs and Expenses

Costs of sales (exclusive of depreciation and amortization)

Cost of sales (exclusive of depreciation and amortization) primarily consists of purchases of NGLs and natural gas from our producers at contracted market prices to support product sales to other third parties. For the year ended December 31, 2022, cost of sales increased $307.9 million, or 132%, to $541.5 million, compared to $233.6 million for the same period in 2021. The increase was primarily driven by the period-to-period increases in commodity prices and NGL and condensate volumes discussed above. Cost of sales (exclusive of depreciation and amortization) are included entirely in the Midstream Logistics segment.

Operating expenses

Operating expenses increased by $46.4 million, or 51%, to $137.3 million for the year ended December 31, 2022, compared to $90.9 million for the same period in 2021. Of the total increase, $25.0 million was driven by the newly acquired operations. The remaining increase was primarily driven by higher period over period electricity costs of $10.7 million, higher internal and contract labor costs of $5.8 million, and higher repairs and maintenance costs of $3.5 million. The higher electricity costs were primarily due to electricity credits received from one of our primary electricity providers during the month of February 2021 related to the extreme weather caused by Winter Storm Uri while no similar credit was generated in 2022.

General and administrative

General and administrative (“G&A”) expense increased by $65.7 million, or 230%, to $94.3 million for the year ended December 31, 2022, compared to $28.6 million for the same period in 2021. The increase was primarily driven by $42.8 million of recognized share-based compensation, higher insurance costs of $2.9 million and acquisition and integration costs of $20.6 million incurred in relation to the newly acquired operations.

Loss on disposal of assets

For the year ended December 31, 2022, the Company recognized a loss on disposal of assets of $12.6 million compared with $0.4 million for the same period in 2021. The change was primarily related to retirements of compressor or booster stations and a refrigeration plant that had become idle due to operational changes.

32

Table of Contents

Other Income (Expense)

Gain (loss) on debt extinguishment

For the year ended December 31, 2022, the Company recognized a loss on debt extinguishment of $28.0 million, compared with a gain of $4 thousand for the same period in 2021. The change reflected the loss on debt extinguishment recognized in relation to the comprehensive refinancing completed in June 2022.

Gain on embedded derivatives

For the year ended December 31, 2022, the Company recognized a gain on embedded derivatives of $89.1 million. The gain is a result of the decrease in fair value of the embedded derivative liability related to the redeemable noncontrolling interest Preferred Units, which was eliminated upon the ultimate redemption of these Preferred Units during July of 2022.

Interest expense

The Company incurred interest expense of $149.3 million for the year ended December 31, 2022 compared with $117.4 million for the same period in 2021. The increase was primarily related to higher debt obligations resulting from the comprehensive refinancing completed in June 2022. The increase also reflected an overall increase in interest rates associated with the Term Loan and Revolving Credit Facility, which carried some variability. Refer to Note—14 Derivatives and Hedging Activities in the Notes to our Consolidated Financial Statements regarding the Company’s strategy in managing interest rate risk.

Equity in earnings of unconsolidated affiliates

Income from EMI pipelines increased by $117.9 million, or 187% to $181.0 million for the year ended December 31, 2022, compared to $63.1 million for the same period in 2021. The increase was primarily due to the acquisition of new EMI pipelines and additional equity interests in the Company’s existing EMI pipeline, PHP, through the Transaction and due to higher earnings from our EMI pipelines. Equity in earnings of unconsolidated affiliates is included entirely in the Pipeline Transportation segment.

Key Performance Metrics

Adjusted EBITDA

Adjusted EBITDA is defined as net income including noncontrolling interests adjusted for interest, taxes, depreciation and amortization, impairment charges, asset write-offs, the proportionate EBITDA from our equity method investments, equity in earnings from investments recorded using the equity method, share-based compensation expense, extraordinary losses and unusual or non-recurring charges. Adjusted EBITDA provides a basis for comparison of our business operations between current, past and future periods by excluding items that we do not believe are indicative of our core operating performance.

We believe that Adjusted EBITDA provides a meaningful understanding of certain aspects of earnings before the impact of investing and financing charges and income taxes. Adjusted EBITDA is useful to an investor in evaluating our performance because this measure:

•Is widely used by analysts, investors and competitors to measure a company’s operating performance;

•Is a financial measurement that is used by rating agencies, lenders, and other parties to evaluate our credit worthiness; and

•Is used by our management for various purposes, including as a measure of performance and as a basis for strategic planning and forecasting.

Adjusted EBITDA is not defined in GAAP

The GAAP measure used by the Company that is most directly comparable to Adjusted EBITDA is net income including noncontrolling interests. Adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income including noncontrolling interests or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income including noncontrolling interests. Adjusted EBITDA should not be considered in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. The Company’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies in the industry, thereby diminishing its utility.

33

Table of Contents

Reconciliation of non-GAAP financial measure

Company management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between Adjusted EBITDA as compared to net income including noncontrolling interests, and incorporating this knowledge into its decision-making processes. Management believes that investors benefit from having access to the same financial measure that the Company uses in evaluating operating results.

The following table presents a reconciliation of the GAAP financial measure of net income including noncontrolling interests to the non-GAAP financial measure of Adjusted EBITDA.

*The results of the legacy ALTM business are not included in the Company’s consolidated financials prior to February 22, 2022. Refer to the Form 10-K basis of presentation in Note 1—Description of Business and Basis of Presentation in the Notes to Consolidated Financial Statements in this Form 10-K, for further information.

NM - Not meaningful

Adjusted EBITDA increased by $356.5 million, or 86% to $772.2 million for the year ended December 31, 2022, compared to $415.7 million for the same period in 2021. The increase was primarily driven by an increase in net income including noncontrolling interest of $249.2 million, or 16818%, and increases in add back related to the Company’s proportionate share of its EMI pipelines’ EBITDA of $185.2 million, or 222%, share-based compensation of $42.8 million, depreciation and amortization expense of $16.8 million and integration costs of $12.2 million, which are results of new operations acquired through the Transaction. The increase in add back was also due to increases in interest expense of $31.9 million and loss on debt extinguishment of $28.0 million as the Company completed its comprehensive refinance in June 2022. The increase in adjusted EBITDA was partially offset by increases in EMI pipelines equity income of $117.9 million and gain on embedded derivatives of $89.1 million, and a decrease in derivative loss add back due to the Winter Storm Uri of $13.5 million as no similar credit was taken during 2022.

34

Table of Contents

Segment Adjusted EBITDA

Segment Adjusted EBITDA is defined as segment net earnings adjusted to exclude interest expense, income tax expense, depreciation and amortization, the proportionate effect of these same items for our equity method investments and other non-recurring items. The following table presents segment adjusted EBITDA for the year ended December 31, 2022. Also refer to Note 20—Segments in the Notes to our Consolidated Financial Statements in this Form 10-K for reconciliation of segment adjusted EBITDA to net income including noncontrolling interests.

* The results of the legacy ALTM business are not included in the Company’s consolidated financials prior to February 22, 2022. Refer to Note 1—Description of Business and Basis of Presentation in the Notes to the Consolidated Financial Statements of this Form 10-K for further information on the Company’s financial statement consolidation.

** 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 a reportable segment for the purpose of evaluating their performance, including certain general and administrative expense items.

NM - Not meaningful

Midstream Logistics segment adjusted EBITDA increased by $172.2 million, or 50%, to $516.0 million for the year ended December 31, 2022, compared to $343.8 million for the same period in 2021. The increase was primarily driven by an increase in segment net income including noncontrolling interests of $186.9 million and increases in the add back related to loss on debt extinguishment of $28.0 million as the Company completed its comprehensive refinancing in June 2022, depreciation and amortization expense of $16.3 million and other one-time costs or amortization of $11.6 million due to new operations acquired through the Transaction, and loss on disposal of assets of $12.3 million for assets retired during 2022. The increase was offset by decreases in add back related to derivative loss due to the Winter Storm Uri of $13.5 million and producer settlement of $6.8 million as no similar credits were taken in 2022 and interest expense of $63.0 million as refinanced debt was consolidated under Corporate and Other for better risk management.

Pipeline Transportation segment adjusted EBITDA increased by $187.4 million, or NM, to $269.2 million for the year ended December 31, 2022, compared to $81.9 million for the same period in 2021. The increase was driven by investments in GCX and Shin Oak and a 100% increase in the Company’s investment in PHP, which were all acquired through the Transaction in February 2022. During the year ended December 31, 2021, the Company only held a 26.67% interest in PHP.

Capital Resources and Liquidity

The Company’s primary use of capital since inception has been for the initial construction of gathering and processing assets, as well as the acquisition of the EMI pipelines and associated subsequent construction costs. For 2022, the Company’s primary capital spending requirements were related to the PHP expansion project, integration by pipeline of the Alpine High gathering system with the legacy BCP system, certain integration-related synergies including the relocation of compression units and treating assets to the legacy BCP processing plants, the Company’s contractual debt obligation, the Company’s payment of quarterly cash dividends on its Class A Common Stock and distributions on Common Units as may be declared by the Board and cash payment upon redemption of all remaining mandatorily redeemable Preferred Units.

For 2023, the Company’s primary capital spending requirements are related to the PHP expansion project and other budgeted capital expenditures for construction of gathering and processing assets and the Company’s contractual debt obligations. The Company will continue to have Apache, Blackstone and I Squared reinvest 100% of their 2023 distribution and dividends into shares of our Class A Common Stock. In addition, the Board has approved a share repurchase program (“Repurchase Program”) authorizing discretionary purchases of the Company’s Class A Common Stock up to $100 million in aggregate.

35

Table of Contents

During the year ended December 31, 2022, the Company’s primary sources of cash were distributions from the EMI pipelines, borrowings under the Term Loan and Revolving Credit Facility, proceeds from the offering of the Notes, and cash generated from operations. Based on the Company’s current financial plan and related assumptions, including the Reinvestment Agreement and Class A Common Stock Repurchase Program, the Company believes that cash from operations and distributions from the EMI pipelines will generate cash flows in excess of capital expenditures and the amount required to fund the Company’s planned quarterly dividend over the next 12 months. Additionally, the Company has locked in the floating base rate, see more information of floating base rate on its Term Loan through April 2023 to reduce short-term interest rate risk. See more information regarding the floating base rate in Note 8—Debt and Financing Costs in the Notes to our Consolidated Financial Statements in this Annual Report Form 10-K. Further, the Company entered into an interest rate swap with a $1.00 billion notional that is effective from May 1, 2023 through May 31, 2025 swapping floating SOFR for a fixed swap rate of 4.46%.

Comprehensive Refinancing

On June 8, 2022, the Partnership completed the private placement of $1.00 billion aggregate principal amount of the Notes, which are fully and unconditionally guaranteed by the Company. The Notes are issued under our Sustainability-Linked Financing Framework and include sustainability-linked features. In addition, the Partnership entered into a new Revolving Credit Agreement, which provides for a $1.25 billion senior unsecured Revolving Credit Facility maturing on June 8, 2027, and a new term loan agreement, which provides for a $2.00 billion senior unsecured Term Loan Credit Facility maturing on June 8, 2025. Proceeds from the Notes and the Term Loan Credit Facility were used to repay all outstanding borrowings under our existing credit facilities and to pay fees and expenses related to the offering. Refer to Note 8 — Debt and Financing Costs in the Notes to our Consolidated Financial Statements in this Form 10-K for further information.

Capital Requirements and Expenditures

Our operations can be capital intensive, requiring investments to expand, upgrade, maintain or enhance existing operations and to meet environmental and operational regulations. During the year ended December 31, 2022 and 2021, capital spending for property, plant and equipment totaled $206.2 million, which included the Brandywine NGL Pipeline acquisition, and $78.0 million, respectively and intangible assets purchases of $15.4 million and $4.7 million, respectively. Management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its contracts to service its customers. During the year ended December 31, 2022, the Company contributed $78.2 million to one of its EMI pipelines, PHP, for the 2022 Capacity Expansion Project, compared to $20.5 million contributed to the same period of 2021. See Note 20—Segments in the Notes to the Consolidated Financial Statements in this Form 10-K for capital expenditure for each operating segment.

The Company estimates 2023 capital expenditures to be between $490 million and $540 million, which includes between $235 million and $265 million of Midstream Logistics capital and between $255 million and $275 million of Pipeline Transportation capital.

The Company anticipates its existing capital resources will be sufficient to fund the future capital expenditures for EMI pipelines and the Company’s existing infrastructure assets over the next 12 months. For further information on EMIs, refer to Note 7—Equity Method Investments in the Notes to our Consolidated Financial Statements in this Form 10-K.

Cash Flows

The following tables present cash flows from operating, investing, and financing activities during the periods presented:

36

Table of Contents

Operating Activities. Net cash provided by operating activities increased by $377.4 million for the year ended December 31, 2022 compared with the same period in 2021. The change in the operating cash flows reflected increases in net income including noncontrolling interests of $249.2 million, adjustments related to non-cash items of $79.0 million and cash provided by changes in working capital of $49.2 million. Period-to-period increase in non-cash adjustments was primarily driven by the new operations acquired through the Transaction, including three EMI pipelines and additional equity interests of the Company’s existing EMI pipeline, PHP, acquired through the Transaction. The increase was offset by derivative fair value adjustment recognized during 2022. Period-to-period changes in working capital was primarily related to fluctuations in trade receivables and accrued liabilities due to timing of collection and payments.

Investing Activities. Net cash used in investing activities increased by $186.5 million for the year ended December 31, 2022 compared with the same period in 2021. The increase was primarily driven by an increase in property, plant and equipment expenditure of $128.1 million, contributions made to the PHP expansion project of $57.6 million and intangible assets expenditure of $10.7 million. The increase in cash outflow was offset by an increase in cash inflow of $13.4 million acquired through the Transaction closed in February 2022.

Financing Activities. Net cash used in financing activities increased by $202.4 million for the year ended December 31, 2022 compared with the same period in 2021. The increase was primarily due to increases in cash outflow for redemption of noncontrolling interest Preferred Units of $461.5 million and redemption of mandatorily redeemable Preferred Units of $183.3 million, cash dividends paid to holders of Class A Common Stock of $39.3 million, cash distributions paid to holders of Preferred Units of $8.8 million and reduction of equity contribution receipt of $14.9 million. The increase in cash outflow was offset by net proceeds from long-term debt of net payments to the Company’s outstanding debts of $455.4 million and a reduction of cash distributions paid to holders of Class C Common Units of $50.0 million.

Dividend and Distribution Reinvestment Agreement

On February 22, 2022, the Company entered into a Dividend and Distribution Reinvestment Agreement (the “Reinvestment Agreement”) with certain stockholders including BCP Raptor Aggregator, LP, BX Permian Pipeline Aggregator, LP, Buzzard Midstream LLC, APA Corporation Apache Midstream LLC, and certain individuals (each, a “Reinvestment Holder”). Under the Reinvestment Agreement, each Reinvestment Holder is obligated to reinvest at least 20% of all distributions on Common Units or dividends on shares of Class A Common Stock in the Company’s Class A Common Stock. Additionally, the Audit Committee resolved that for the calendar year 2022, 100% of all distributions or dividends received by each Reinvestment Holder would be reinvested in shares of Class A Common Stock. The Audit Committee approved a similar determination for 2023. In addition, the Board approved the Repurchase Program in February 2023 authorizing discretionary purchase of the Company’s Class A Common Stock up to $100 million in aggregate. Shares acquired under the Repurchase Program are expected to be reissued under the Company’s reinvestment plan, pursuant to the Reinvestment Agreement.

During 2022, the Company made cash dividend payments of $40.5 million to holders of Class A Common Stock and Common Units and $263.3 million was reinvested in shares of Class A Common Stock by each Reinvestment Holder.

Stock Split

On May 19, 2022, the Company announced the Stock Split with respect to its Class A Common Stock and Class C Common Stock in the form of a stock dividend. The Stock Split was accomplished by distributing one additional share of Class A Common Stock for each share of Class A Common Stock outstanding and one additional share of Class C Common Stock for each share of Class C Common Stock outstanding. The additional shares of Common Stock were issued on June 8, 2022 to holders of record at the close of business on May 31, 2022.

Dividend

On January 17, 2023, the Company declared a cash dividend of $0.75 per share on the Company’s Class A Common Stock and a distribution of $0.75 per Common Unit from the Partnership to the holders of Common Units. Dividends are payable on February 16, 2023. Certain holders of Class A Common Stock and Class C Common Stock will receive a cash dividend with the balance receiving additional shares of Class A Common Stock under the Reinvestment Agreement.

Series A Cumulative Redeemable Preferred Units

The Company issued Preferred Units on June 12, 2019. Because the Transaction was accounted for as a reverse merger, certain Preferred Units that were issued and outstanding were assumed at Closing for accounting purposes. The Company assumed 525,000 Preferred Units as well as 29,983 paid-in-kind (“PIK”) Preferred Units immediately after the Closing.

37

Table of Contents

Since the Closing, the Company redeemed all outstanding Preferred Units and PIK units for an aggregate redemption price of $644.8 million. The Company recognized a gain of $9.6 million on redemption of the mandatorily redeemable Preferred Units and excess of carrying amount over redemption price of $109.5 million on redemption of the redeemable noncontrolling interest Preferred Units. Refer to Note 12—Series A Cumulative Redeemable Preferred Units in the Notes to our Consolidated Financial Statements in this Form 10-K.

Liquidity

The following table presents a summary of the Company’s key financial indicators at the dates presented:

Cash and cash equivalents

At December 31, 2022 and 2021, the Company had $6.4 million and $18.7 million, respectively, in cash and cash equivalents.

Total Debt and Available credit facilities

There is no assurance that the financial condition of banks with lending commitments to the Company will not deteriorate. The Company closely monitors the ratings of the banks in the Company’s bank group. Having a large bank group allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.

Off-Balance Sheet Arrangements

As of December 31, 2022, there were no off-balance sheet arrangements.

Contractual Obligations

We have contractual obligations for principal and interest payments on our term loan credit facility. See Note 8—Debt and Financing Costs in the Notes to our Consolidated Financial Statements in this Form 10-K.

Under certain clauses of our transportation services agreements with third party pipelines to transport natural gas and NGLs, if we fail to ship a minimum throughput volume, then we will pay certain deficiency payments for transportation based on the volume shortfall up to the MVC amount.

For additional information regarding the Company’s obligations, please see Note 8—Debt and Financing Costs, and Note 18—Commitments and Contingencies in the Notes to the Consolidated Financial Statements in this Form 10-K.

Critical Accounting Policies and Estimates

Our significant accounting policies are described in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2—Summary of Significant Accounting Policies of this Annual Report on Form 10-K.

The Company prepares its financial statements and the accompanying notes in conformity with GAAP, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Critical accounting estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of the following critical accounting estimates.

38

Table of Contents

Business Combination

For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired is recorded to goodwill. Determining the fair value of these items requires management’s judgment and/or the utilization of independent valuation specialists and involves the use of significant estimates and assumptions. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. See Note 3—Business Combination in our Notes to the Consolidated Financial Statements in this Annual Report Form 10-K for more information regarding our valuation approach.

Impairment of Long-lived Assets

Long-lived assets used in operations are evaluated for potential impairment when events or changes in circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset may not be recovered, the asset is assessed for impairment through an established process in which changes to significant assumptions such as service prices, throughput volumes, future development plans and fluctuation of commodity pricing are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to an estimated fair value. Such fair value is generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market-based valuation approach, which are Level 3 fair value measurements. The estimates and assumptions can be affected by a variety of factors, including external factors such as industry and economic trends, and internal factors such as changes in our business strategy and our internal forecasts. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates.

Equity Method Investment

We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, we adjust the carrying values of the investment downward, if necessary, to their estimated fair values.

We estimate the fair value of our equity method investments based on a number of factors, including discount rates, projected cash flows, and enterprise value. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our equity method investments (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our equity method investments, such as their future capital and operating plans and their financial condition.

Derivatives and Hedging Activities

All our derivative contracts are recorded at estimated fair value. We utilize published prices, broker quotes, and estimates of market prices to estimate the fair value of these contracts; however, actual amounts could vary materially from estimated fair values as a result of changes in market prices. In addition, changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts.

39

Table of Contents

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are omitted in this Annual Report on Form 10-K are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Exhibit 99.1 of the Company’s Current Report on Form 8-K, filed on December 14, 2021.

Overview

Altus Midstream Company (the Company or Altus), through its ownership interest in Altus Midstream LP (Altus Midstream), owns gas gathering, processing, and transmission assets in the Permian Basin of West Texas, anchored by midstream service agreements to service Apache Corporation’s (Apache) production from its Alpine High resource play and surrounding areas (Alpine High). Additionally, the Company owns equity interests in four intrastate Permian Basin pipelines (the Equity Method Interest Pipelines) that have access to various points along the Texas Gulf Coast. The Company’s operations consist of one reportable segment.

The Company has no independent operations or material assets outside its ownership interest in Altus Midstream, which is reported on a consolidated basis. As of December 31, 2021, Altus Midstream’s assets included approximately 182 miles of in-service natural gas gathering pipelines, approximately 46 miles of residue gas pipelines with four market connections, and approximately 38 miles of NGL pipelines. Three cryogenic processing trains, each with nameplate capacity of 200 MMcf/d, were placed into service during 2019. Other assets include an NGL truck loading terminal with six Lease Automatic Custody Transfer units and eight NGL bullet tanks with 90,000 gallon capacity per tank. The Company’s existing gathering, processing, and transmission infrastructure is expected to provide capacity levels capable of fulfilling its midstream contracts to service Apache’s production from Alpine High and potential third-party customers.

As of December 31, 2021, the Company owns the following Equity Method Interest Pipelines:

•A 16 percent equity interest in the Gulf Coast Express Pipeline Project (GCX), which is owned and operated by Kinder Morgan Texas Pipeline, LLC (Kinder Morgan). GCX transports natural gas from the Waha area in West Texas to Agua Dulce near the Texas Gulf Coast. GCX was placed in service during 2019, with the total capacity of 2.0 Bcf/d fully subscribed under long-term contracts.

•A 15 percent equity interest in the EPIC crude oil pipeline (EPIC), which is operated by EPIC Consolidated Operations, LLC. EPIC transports crude oil from Orla, Texas in Northern Reeves County to the Port of Corpus Christi, Texas. EPIC was placed in service in early 2020, with initial throughput capacity of approximately 600 MBbl/d.

•An approximate 26.7 percent equity interest in the Permian Highway Pipeline (PHP), which is also owned and operated by Kinder Morgan. PHP transports natural gas from the Waha area in northern Pecos County, Texas to the Katy, Texas area with connections to Texas Gulf Coast and Mexico markets. PHP was placed in service in January 2021, with the total capacity of 2.1 Bcf/d fully subscribed under long-term contracts.

•A 33 percent equity interest in the Shin Oak NGL Pipeline (Shin Oak), which is owned by Breviloba, LLC, and operated by Enterprise Products Operating LLC. Shin Oak transports NGLs from the Permian Basin to Mont Belvieu, Texas. Shin Oak was placed in service during 2019, with total capacity of up to 550 MBbl/d.

On October 21, 2021, the Company announced that it will combine with privately-owned BCP Raptor Holdco LP (BCP) in an all-stock transaction (the BCP Business Combination). BCP is the parent company of EagleClaw Midstream, which includes EagleClaw Midstream Ventures, the Caprock Midstream and Pinnacle Midstream businesses, and a 26.7 percent interest in the Permian Highway Pipeline.

As consideration for the transaction, the Company will issue 50 million shares of Class C Common Stock (and Altus Midstream will issue a corresponding number of Common Units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to close during the first quarter of 2022 following completion of customary closing conditions.

The global economy and the energy industry have been deeply impacted by the effects of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainty in the oil markets and the negative demand implications

27

of the COVID-19 pandemic continue to impact oil supply and demand. Altus management continues to monitor natural gas throughput volumes from Apache and capacity utilization of the Equity Method Interest Pipelines.

The current crisis, however, is still evolving and may become more severe and complex. The ultimate impact and the extent to which the COVID-19 pandemic will continue to affect the Company’s business, results of operation, and financial condition is difficult to predict and depends on numerous evolving factors outside of Altus’ control, including the duration and scope of the pandemic, new and continuing government, social, business, and other actions taken in response to the pandemic, any additional waves of the virus, the mandate, availability, and ultimate efficacy of the vaccines on new variants of the virus, and the effect of the pandemic on short- and long-term general economic conditions. As a result, the COVID-19 pandemic may still materially and adversely affect Altus’ results in a manner that is either not currently known or that the Company does not currently consider to be a significant risk to its business. For additional information about the business risks relating to the COVID-19 pandemic, please refer to Part II, Item 1A—Risk Factors of this Annual Report on Form 10-K.

Altus Midstream Operational Metrics

The Company uses a variety of financial and operational metrics to assess the performance of its operations and growth compared to expected plan estimates. These metrics include:

•Throughput volumes and associated revenues;

•Costs and expenses; and

•Adjusted EBITDA (as defined below).

Throughput Volumes and Associated Revenues

The Company’s operating results are driven primarily by the volume of natural gas gathered, processed, compressed, and/or transmitted. For the periods presented, substantially all revenues were generated through fee-based agreements with Apache, a related party. The volumes of natural gas that Altus gathers or processes in future periods will depend on the production level of Apache’s assets in areas Altus services and any additional third-party service contracts or incremental use of Altus Midstream infrastructure resulting from the potential close of the BCP Business Combination discussed above. The Company’s assets were initially constructed to serve Apache’s anticipated development of Alpine High and its surrounding areas. As such, the amount and pace of upstream development activity by Apache could directly impact Altus’ aggregate gathering and processing volumes because the production rate of natural gas wells declines over time.

The Company entered into a new Gas Processing Agreement with Apache in October 2021, which superseded the prior agreement. The updated processing agreement contains modified gas processing fees for new volumes from future Apache drilling activities at Alpine High that are more consistent with current market practices. Part of the modified fee structure in the new Gas Processing Agreement establishes fixed processing rates. Any monthly difference between actual recovery rates and fixed recovery rates will create either excess recovery volumes for ALTM to sell or processing volume deficiencies which ALTM would owe Apache. Commodity price fluctuations and oil and gas industry dynamics that existed when the original agreement was signed have changed dramatically, and the updated terms of the new Gas Processing Agreement were established to potentially attract new business from both Apache and other third-party producers and midstream companies.

The Company remains focused on increasing third-party processing opportunities in addition to Alpine High, and other producers are developing oil and gas plays in surrounding areas that may provide Altus opportunities to enter into third-party processing and gathering agreements. Producers’ willingness to engage in new drilling is determined by a number of factors, all of which are affected by the COVID-19 pandemic, the most important of which are the prevailing and projected prices of oil, natural gas, and NGLs, the cost to drill and operate a well, the availability and cost of capital, and environmental and government regulations. Company management believes that its midstream assets are positioned in one of the most active regions for oil and gas exploration and development activities in the United States. The Company has actively pursued strategic alternatives for future growth, which culminated in the recently announced BCP Business Combination, a combination with a midstream company that has existing commitments with various third-party customers.

For more information about the Company’s relationship with Apache, please see the section entitled Altus’ Relationship with Apache in Part I, Items 1 and 2 of this Annual Report on Form 10-K.

28

Costs and Expenses

Costs of product sales — affiliate

Costs of product sales — affiliate represent the cost of excess recovery volumes of residue gas the Company receives from Apache under the terms of the new Gas Processing Agreement, which the Company then owns and controls prior to ultimate sale to Apache. The costs related to excess recovery volumes are directly associated with volumes of excess recoveries under the new Gas Processing Agreement, if any.

Costs of product sales — third parties

Costs of product sales — third parties represent purchases of NGLs from a third party and the cost of excess recovery volumes of condensate the Company receives from Apache under the terms of the new Gas Processing Agreement. The Company owns and controls such volumes prior to ultimate sale to customers. The costs related to third party purchases of NGLs are directly associated with the volume and amount of third-party contracts entered into and could fluctuate depending on market conditions and product prices.

Operations and maintenance

Operations and maintenance expenses primarily comprise those costs that are directly associated with the operations of the Company’s assets. The most significant of these costs are associated with direct labor and supervision, power, repair and maintenance expenses, and equipment rentals. Fluctuations in commodity prices impact operating cost elements both directly and indirectly. For example, commodity prices directly impact costs such as power and fuel, which are expenses that increase (or decrease) in line with changes in commodity prices. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as labor and equipment rentals.

Depreciation and accretion

Depreciation on the capitalized costs incurred to acquire and develop the Company’s midstream assets is computed based on estimated useful lives and estimated salvage values. Also included within this expense is the accretion associated with estimated asset retirement obligations (ARO). Depreciation and accretion expense would be expected to increase during future periods in-line with additional infrastructure costs incurred; however, any future asset sales or long-lived asset impairments would decrease expected depreciation expense to commensurate levels.

General and administrative

General and administrative (G&A) expense represents indirect costs and overhead expenditures incurred by the Company associated with managing the midstream assets. These expenses primarily comprise fixed fees set forth in the Construction, Operations and Maintenance Agreement (COMA) entered into with Apache. Refer to Note 2—Transactions with Affiliates in the Notes to Consolidated Financial Statements set forth in Part IV of this Annual Report on Form 10-K for further information.

Taxes other than income

Taxes other than income are primarily related to ad valorem taxes on the Company’s midstream assets.

Adjusted EBITDA

The Company defines Adjusted EBITDA as net income (loss) including noncontrolling interests before financing costs (net of capitalized interest), interest income, income taxes, depreciation, and accretion and adjusts such items, as applicable, from income from the Equity Method Interest Pipelines. Altus also excludes (when applicable) impairments, unrealized gains or losses on derivative instruments, and other items affecting comparability of results to peers. Company management believes Adjusted EBITDA is useful for evaluating operating performance and comparing results of operations from period-to-period and against peers without regard to financing or capital structure. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) including noncontrolling interests or any other measure determined in accordance with accounting principles generally accepted in the United States (GAAP) or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing Altus’ financial performance, such as cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. The presentation of Adjusted EBITDA should not be construed as an inference that the Company’s results will be unaffected by unusual or non-recurring items. Additionally, the Company’s computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

29

Adjusted EBITDA is not defined in GAAP

The GAAP measure used by the Company that is most directly comparable to Adjusted EBITDA is net income (loss) including noncontrolling interests. Adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income (loss) including noncontrolling interests or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income (loss) including noncontrolling interests. Adjusted EBITDA should not be considered in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. The Company’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies in the industry, thereby diminishing its utility.

Reconciliation of non-GAAP financial measure

Company management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between Adjusted EBITDA as compared to net income (loss) including noncontrolling interests, and incorporating this knowledge into its decision-making processes. Management believes that investors benefit from having access to the same financial measure that the Company uses in evaluating operating results.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) including noncontrolling interests to the non-GAAP financial measure of Adjusted EBITDA.

30

Results of Operations

The following table presents the Company’s results of operations for the periods presented:

(1)Adjusted EBITDA is not defined by GAAP and should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by (used in) operating activities, or any other measures prepared under GAAP. For the definition and reconciliation of Adjusted EBITDA to its most directly comparable GAAP measure, see the section titled Altus Midstream Operational Metrics—Adjusted EBITDA above.

31

Since the Company commenced operations in the second quarter of 2017, its most significant customer has been Apache. Altus Midstream is pursuing similar long-term commercial service contracts with third-parties that could be accommodated by existing capacity. Altus’ midstream service agreements with Apache contain no minimum volume commitments and as such, future results of operations may be materially impacted by Apache’s production volumes from Alpine High and Altus’ ability to contract third-party business. Refer to Part I, Item 1A—Risk Factors of this Annual Report on Form 10-K for further discussion.

Revenues

The following table summarizes the Company’s revenues for the periods presented:

Midstream services revenue was primarily generated from fee-based midstream services provided under the terms of separate commercial midstream service agreements with Apache for the gas gathering, processing, and transmission of volumes from the dedicated area in the Alpine High field. Altus receives a per-unit fee based on the quantity of natural gas and NGL volumes that flow through its systems. The Company entered into a new Gas Processing Agreement with Apache in October 2021, which superseded the prior agreement. In addition to per unit service fees described above, the new Gas Processing Agreement contains terms for Apache to provide the Company with excess recovery volumes as consideration under the contract. Excess recovery volumes represent the net difference between the actual recovery rate of processed volumes and contractually fixed volumetric recovery rates.

For excess recovery volumes the Company obtains control and takes title, if any, on a monthly basis, the related non-cash consideration of these volumes is included in “midstream services revenue — affiliate” at market value. Subsequent sales of excess recovery volumes are recognized as product sales and, simultaneously, cost of product sales are recognized at the value attributed to the excess recovery volumes when they were earned.

Additionally, during 2020 the Company began providing compressor operations, maintenance, and related services to Apache in exchange for a fixed monthly fee per compressor unit serviced. For more details, please refer to Note 3—Revenue Recognition in the Notes to Consolidated Financial Statements included within Part IV, Item 15 of this Annual Report on Form 10-K.

Midstream services revenue — affiliate

Midstream services revenue — affiliate decreased by $2.0 million to $142.7 million for the year ended December 31, 2021, as compared to $144.7 million for the year ended December 31, 2020. The decrease was primarily driven by lower throughput of natural gas volumes from Apache, which reduced revenues, offset by approximately $13.4 million of revenues related to excess recovery volumes earned under the new Gas Processing Agreement in the fourth quarter of 2021.

Product sales — affiliate

The $9.8 million increase in product sales — affiliate during the year ended December 31, 2021, was solely due to the sale of excess recovery volumes of residue gas received as consideration under the new Gas Processing Agreement, which were subsequently sold to Apache. Refer to Costs of product sales – affiliate under Costs and Expenses below.

Product sales — third parties

The $4.4 million increase in product sales — third parties during the year ended December 31, 2021, as compared to the year ended December 31, 2020, was driven by higher volumes of NGLs and condensates purchased and processed by Altus from a third party and subsequently sold to non-affiliated customers. Additionally, nearly $2.4 million of the increase reflects the sale of excess recovery volumes of condensates received as a consideration under the new Gas Processing Agreement,

32

which was subsequently sold to non-affiliated customers. Refer to Costs of product sales – third parties under Costs and Expenses below.

Costs and Expenses

The following table summarizes the Company’s costs and expenses for the periods presented:

Costs of product sales — affiliate

The $9.8 million increase in cost of product sales — affiliate during the year ended December 31, 2021, as compared to the year ended December 31, 2020, was solely due to the cost of excess recovery volumes of gas received as consideration under the new Gas Processing Agreement subsequently sold to Apache.

Costs of product sales — third parties

The $4.8 million increase in costs of product sales — third parties during the year ended December 31, 2021, as compared to the year ended December 31, 2020, was driven by higher volumes of purchases of NGLs from a third-party and the cost of excess recovery condensate volumes under the new Gas Processing Agreement.

Operations and maintenance

Operations and maintenance expenses decreased by approximately $5.2 million to $32.7 million for the year ended December 31, 2021, as compared to $38.0 million for the year ended December 31, 2020. This decrease was primarily driven by increased operational efficiency as a result of transitioning from mechanical refrigeration units to the Company’s centralized Diamond cryogenic complex. Work related to this transition was still being completed in the first half of 2020. The transition resulted in decreases in various costs, the most significant being contract labor, equipment rentals, and chemical expenses. These savings were partially offset by higher power costs and higher repair and maintenance expenses.

General and administrative and Depreciation and accretion

General and administrative expenses were approximately $1.0 million higher in 2021 compared to 2020 primarily due to the escalating price terms under the COMA. Depreciation and accretion expense in 2021 was consistent with 2020, as the Company’s carrying value of its property, plant, and equipment assets did not meaningfully change during the comparative periods.

Impairments

During the fourth quarter of 2020, the Company sold certain of its power generators to a third party and, as a result, the remaining power generators owned by the Company were remeasured at fair value calculated based on the proceeds of such sale. This remeasurement resulted in an impairment of $1.6 million on these assets. Impairments in 2021 were insignificant.

For further discussion of these impairments, please see Note 1—Summary of Significant Accounting Policies and Note 4—Property, Plant and Equipment in the Notes to Consolidated Financial Statements included within Part IV, Item 15 of this Annual Report on Form 10-K.

33

Taxes other than income

The decrease in taxes other than income was driven by changes related to ad valorem taxes, which decreased by $1.2 million to $13.5 million for the year ended December 31, 2021, as compared to $14.7 million for the year ended December 31, 2020. The $1.2 million decrease is primarily related to a decrease in tax assessed value for the Company’s property, plant, and equipment.

Other Income (Loss) and Financing Costs, Net of Capitalized Interest

The components of other income, other loss, and financing costs, net of capitalized interest are presented below:

Unrealized derivative instrument gain (loss)

During the year ending December 31, 2021, the Company recognized an unrealized derivative instrument gain of $82.1 million in relation to an embedded exchange option identified upon the issuance and sale of Series A Cumulative Redeemable Preferred Units (the Preferred Units). The recognized unrealized loss related to this embedded feature was $36.1 million for the year ended December 31, 2020. The associated derivative liability is recorded on the consolidated balance sheet at fair value. The fair value of the embedded derivative is determined (using an income approach) by a range of factors, including expected future interest rates using the Black-Karasinski model, interest rate volatility, the Company’s imputed interest rate, the expected timing of periodic cash distributions, the expected timing of any partial redemption of the Preferred Units, the estimated timing for the potential exercise of the exchange option, and anticipated dividend yields of the Preferred Units. The value of the derivative during the year ending December 31, 2021 was primarily impacted by the expected mandatory redemption of certain of the Preferred Units on, and after, the closing of the BCP Business Combination. Refer to Note 11—Series A Cumulative Redeemable Preferred Units within Part IV, Item 15 of this Annual Report on Form 10-K for further discussion.

Income from equity method interests, net

Income from equity method interests increased by $55.0 million to $113.8 million for the year ended December 31, 2021, as compared to $58.7 million for the year ended December 31, 2020. The increase was primarily due to the Company’s 26.7 percent share of net income from the Permian Highway Pipeline, which commenced service in January 2021.

34

Impairment on equity method interests

The $160.4 million increase in impairment on equity method interests for the year ended December 31, 2021, as compared to December 31, 2020, was a result of the Company’s impairment of its interest in the EPIC Crude Oil Pipeline in the fourth quarter of 2021. Refer to Note 1—Summary of Significant Accounting Policies and Note 9—Equity Method Interests within Part IV, Item 15 of this Annual Report on Form 10-K for further discussion.

Other income

In 2020, the Company entered into a contract with a provider to supply the Company with electrical power. If the Company does not utilize all of its fixed purchase volumes under this contract, then it will receive a credit based on a market rate for the related underutilization. In February 2021, in conjunction with increased power pricing due to the Texas freeze event and underutilization of contractual electricity volumes, the Company recognized an estimated credit of approximately $9.7 million for the year ended December 31, 2021. No credits were recognized for the year ended December 31, 2020.

The remainder of the increase to other income primarily relates to the Company recording a gain on the sale of certain non-core assets of $1.2 million for the year ended December 31, 2021 compared to a loss on the sale of certain non-core assets of $2.2 million for the year ended December 31, 2020.

Financing costs, net of capitalized interest

Financing costs incurred, net of capitalized interest, includes increases in interest expense not eligible to have interest capitalized related to balances drawn on Altus Midstream’s credit facility throughout the current year. The changes to gross interest expense for the years presented is insignificant.

Provisions for income taxes

Current income tax benefit for the years ended December 31, 2021 and 2020 were a benefit of nil and $0.7 million, respectively. On March 27, 2020, the President signed into law the Coronavirus Aid, Relief and Economic Security Act (CARES Act) in response to the COVID-19 pandemic. Under the CARES Act, 100 percent of net operating losses arising in tax years beginning after December 31, 2017, and before January 1, 2021 may be carried back to each of the five preceding tax years of such loss. For the year ended December 31, 2020, the Company recorded a current income tax benefit of $0.7 million associated with a net operating loss carryback claim.

The Company recorded no deferred income tax expense for the years ended December 31, 2021 and 2020.

Please refer to Note 12—Income Taxes set forth in Part IV, Item 15 of this Annual Report on Form 10-K for further discussion.

Key Performance Metric—EBITDA

Net income before income taxes was $99.2 million for the year ended December 31, 2021, an increase of $18.2 million from a net income before income taxes of $81.0 million for the year ended December 31, 2020. The increase in net income before income taxes was primarily driven by a $118.2 million decrease to expense related to the fair value measurement of an embedded derivative at December 31, 2021, a $55.0 million increase due to higher income from the Equity Method Interest Pipelines, an increase of $12.2 million in total revenues, a $5.2 million decrease in operations and maintenance expenses, a $1.2 million decrease in impairment expense and an increase of $14.9 million in other income compared to the prior year period (as discussed above). The increases to net income were offset by a $160.4 million impairment of an equity method interest at December 31, 2021, a $14.6 million increase in costs of product sales, an $8.4 million increase in interest expense from lower capitalized interest, and a net increase of $5.1 million in transaction and various other costs of the Company.

Adjusted EBITDA increased by $92.6 million for the year ended December 31, 2021 compared to the prior year period. Adjusted EBITDA, which excludes the impacts of depreciation, accretion, impairments, and the changes to the embedded derivative, benefited from an incremental $22.3 million increase related to excluding depreciation, and interest in the Company’s proportionate share of EBITDA from the Equity Method Interest Pipelines. This amount was further benefited by a decrease of $2.4 million, in the aggregate, of various other insignificant costs of the Company.

For additional information, see the section titled Altus Midstream Operational Metrics—Adjusted EBITDA above.

35

Capital Resources and Liquidity

The Company’s primary use of capital since inception has been for the initial construction of gathering and processing assets, as well as the acquisition of the Equity Method Interest Pipelines and associated subsequent construction costs. For 2022, the Company’s primary spending requirements are anticipated to be related to the Company’s payment of a quarterly cash dividend on its Class A Common Stock as may be declared by its board of directors and payment of the Company’s quarterly distribution to the Preferred Unit limited partners.

During 2021, the Company’s primary sources of cash were distributions from the Equity Method Interest Pipelines, borrowings under the revolving credit facility, and cash generated from operations. Based on Altus’ current financial plan and related assumptions, the Company believes that cash from operations, a reduced capital program for its midstream infrastructure, and distributions from the Equity Method Interest Pipelines will generate cash flows in excess of capital expenditures and the amount required to fund the Company’s planned quarterly dividend and quarterly payments to the Preferred Unit limited partners during 2022.

Given recent crude oil price volatility and uncertain economic activity resulting from the COVID-19 pandemic and related governmental actions, the Company continues to monitor expected natural gas throughput volumes from Apache and capacity utilization of the Equity Method Interest Pipelines. Further, given the pending BCP Business Combination noted above, together with the recent price volatility and continuing economic uncertainty related to COVID-19, future projections remain dynamic. Altus’ results, including projections related to capital resources and liquidity, could be materially affected by the continuing COVID-19 pandemic and the effects of the BCP Business Combination if closed.

Altus Midstream Capital Requirements

During 2021 and 2020, capital spending for midstream infrastructure assets totaled $4.6 million and $30.0 million, respectively. Management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its midstream contracts to service Apache’s production from Alpine High and any potential third-party customers. As such, the Company expects remaining capital requirements for its existing infrastructure assets during 2022 to be minimal.

Additionally, during the years ended December 31, 2021 and 2020, the Company made cash contributions totaling $28.4 million and $327.3 million, respectively, for the Equity Method Interest Pipelines, which includes the following equity interest ownership stakes:

•a 16.0 percent interest in GCX;

•a 15.0 percent interest in EPIC;

•an approximate 26.7 percent interest in PHP; and

•a 33.0 percent interest in Shin Oak.

The Company estimates it will incur minimal capital contributions during 2022 for its equity interest in these joint venture pipelines. The Company anticipates its existing capital resources will be sufficient to fund the Company’s future capital expenditures for the Equity Method Interest Pipelines and the Company’s existing infrastructure assets. For further information on the Equity Method Interest Pipelines, refer to Note 9—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Altus Midstream Class A Common Stock Dividend and Common Units Distributions

During 2021, the Company paid an aggregate $22.5 million in dividends on the Company’s Class A Common Stock, of which $5.6 million, or $1.50 per share, was paid in each quarter of 2021. Each quarterly Class A Common Stock dividend was funded by a distribution from Altus Midstream to its common unitholders of $1.50 per Common Unit, with each quarterly distribution totaling $24.4 million, of which $5.6 million was paid to the Company and the balance was paid to Apache. For more information please refer to Note 2—Transactions with Affiliates and Note 10—Equity and Warrants in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

36

Sources and Uses of Cash

The following table presents the sources and uses of the Company’s cash and cash equivalents for the periods presented.

(1)The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this document, which include accruals.

Liquidity

The following table presents a summary of the Company’s key financial indicators at the dates presented:

Cash and cash equivalents

At December 31, 2021 and December 31, 2020, the Company had $132.0 million and $24.2 million, respectively, in cash and cash equivalents. The majority of the cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt

As of December 31, 2021 and December 31, 2020, the Company had debt outstanding totaling $657.0 million and $624.0 million, respectively.

37

Available credit facilities

In November 2018, Altus Midstream entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream’s two, one year extension options). The agreement for this revolving credit facility, as amended (the Amended Credit Agreement), provides aggregate commitments from a syndicate of banks of $800.0 million. The aggregate commitments include a letter of credit subfacility of up to $100.0 million and a swingline loan subfacility of up to $100.0 million. Altus Midstream may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of December 31, 2021 there were $657.0 million of borrowings and a $2.0 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624.0 million of borrowings and no letters of credit outstanding under this facility.

Altus Midstream’s revolving credit facility is unsecured and is not guaranteed by the Company, Apache, APA Corporation or any of their respective subsidiaries.

At Altus Midstream’s option, the interest rate per annum for borrowings under this amended credit facility is either a base rate, as defined, plus a margin, or the London Interbank Offered Rate (LIBOR), plus a margin. Altus Midstream also pays quarterly a facility fee at a rate per annum on total commitments. The margins and the facility fee vary based upon (i) the Leverage Ratio (as defined below) until Altus Midstream has a senior long-term debt rating and (ii) such senior long-term debt rating once it exists. The Leverage Ratio is the ratio of (1) the consolidated indebtedness of Altus Midstream and its restricted subsidiaries to (2) EBITDA (as defined in the Amended Credit Agreement) of Altus Midstream and its restricted subsidiaries for the 12-month period ending immediately before the determination date. At December 31, 2021, the base rate margin was 0.05 percent, the LIBOR margin was 1.05 percent, and the facility fee was 0.20 percent. In addition, a commission is payable quarterly to the lenders on the face amount of each outstanding letter of credit at a per annum rate equal to the LIBOR margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.

The Amended Credit Agreement contains restrictive covenants that may limit the ability of Altus Midstream and its restricted subsidiaries to, among other things, incur additional indebtedness or guaranty indebtedness, sell assets, make investments in unrestricted subsidiaries, enter into mergers, make certain payments and distributions, incur liens on certain property securing indebtedness, and engage in certain other transactions without the prior consent of the lenders. Altus Midstream also is subject to a financial covenant under the Amended Credit Agreement, which requires it to maintain a Leverage Ratio not exceeding 5.00:1.00 at the end of any fiscal quarter, starting with the quarter ended December 31, 2019, except that during the period of up to one year following a qualified acquisition, the Leverage Ratio cannot exceed 5.50:1.00 at the end of any fiscal quarter. Unless the Leverage Ratio is less than or equal to 4.00:1.00, the Amended Credit Agreement limits distributions in respect of Altus Midstream LP’s capital to $30 million per calendar year until either (i) the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the Amended Credit Agreement, for three consecutive calendar months equals or exceeds $350.0 million on an annualized basis or (ii) Altus Midstream LP has a specified senior long-term debt rating; in addition, before the occurrence of one of those two events, the Leverage Ratio must be less than or equal to 5.00:1.00. In no event can any distribution be made that would, after giving effect to it on a pro forma basis, result in a Leverage Ratio greater than (i) 5.00:1.00 or (ii) for a specified period after a qualifying acquisition, 5.50:1.00. The Leverage Ratio as of December 31, 2021 was less than 4.00:1.00.

The terms of Altus Midstream’s Preferred Units also contain certain restrictions on distributions on Altus Midstream LP’s Common Units, including the Common Units held by the Company, and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 11—Series A Cumulative Redeemable Preferred Units in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K for further information. In addition, the amount of any cash distributions to Altus Midstream LP by any entity in which it has an interest accounted for by the equity method is subject to such entity’s compliance with the terms of any debt or other agreements by which it may be bound, which in turn may impact the amount of funds available for distribution by Altus Midstream LP to its partners.

There are no clauses in the Amended Credit Agreement that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The Amended Credit Agreement has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreement allows the lenders to accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if Altus Midstream or any of its restricted subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments if Altus Midstream undergoes a specified change in control or has specified pension plan liabilities in excess of the stated threshold. Altus Midstream was in compliance with the terms of the Amended Credit Agreement as of December 31, 2021.

38

There is no assurance that the financial condition of banks with lending commitments to Altus Midstream will not deteriorate. Altus closely monitors the ratings of the banks in the Company’s bank group. Having a large bank group allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.

Series A Cumulative Redeemable Preferred Units

On June 12, 2019, Altus Midstream issued and sold the Preferred Units in a private offering exempt from the registration requirements of the Securities Act (the Closing). The Closing occurred pursuant to a Preferred Unit Purchase Agreement among Altus Midstream, the Company, and the purchasers party thereto, dated as of May 8, 2019. A total of 625,000 Preferred Units were sold at a price of $1,000 per Preferred Unit, for an aggregate issue price of $625.0 million. Altus Midstream received approximately $611.2 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. These proceeds were used to fund ongoing capital contributions related to Altus’ Equity Method Interest Pipelines and repayment of outstanding principal on the revolving credit facility (discussed above).

At the Closing, the partners of Altus Midstream entered into a second amended and restated agreement of limited partnership of Altus Midstream LP (the Amended LPA). The Amended LPA provides the terms of the Preferred Units, including the distribution rate, redemption rights, and rights to exchange the Preferred Units for shares of the Company’s Class A Common Stock, as well as rights of holders of the Preferred Units to approve certain partnership business, financial, and governance-related matters. The Preferred Units have a perpetual term, unless redeemed or exchanged as described below. Pursuant to the Amended LPA:

•The Preferred Units entitle the holders thereof to receive quarterly distributions at a rate of 7 percent per annum, commencing with the quarter ended June 30, 2019. The rate increases to 10 percent per annum after the fifth anniversary of Closing and upon the occurrence of specified events. For any quarter ending on or prior to December 31, 2020, Altus Midstream could elect to pay distributions on the Preferred Units in-kind and did so in respect of quarters ended on and before March 31, 2020.

•The Preferred Units are redeemable at Altus Midstream’s option at any time in cash at a redemption price (the Redemption Price) equal to (a) the greater of (i) an 11.5 percent internal rate of return (increasing to 13.75 percent after the fifth anniversary of Closing), and (ii) a 1.3x multiple of invested capital plus (b) if applicable, the value of any accrued and unpaid distributions. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream and certain other events, including certain asset dispositions. The Company and Altus Midstream remained subsidiaries of Apache upon consummation of the January 2022 direct exchange by the Company and Apache under the Amended LPA, pursuant to which the Company succeeded to Apache’s 12.5 million Common Units, issued an additional 12.5 million shares of Class A Common Stock to Apache, and cancelled Apache’s 12.5 million shares of Class C Common Stock (as further discussed in Note 10—Equity and Warrants in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K).

•The Preferred Units will be exchangeable for shares of the Company’s Class A Common Stock at the option of the Preferred Unit holders after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of Class A Common Stock equal to the Redemption Price divided by the volume-weighted average trading price of the Class A Common Stock on the Nasdaq Global Select Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount.

•Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream’s Common Units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation.

•Altus Midstream is restricted from declaring or making cash distributions on its Common Units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Common Units are limited to $650.0 million of cash from ordinary course of operations if permitted under Altus Midstream’s Amended Credit Agreement. Cash distributions on, and redemptions of, Common Units also are subject to satisfaction of leverage ratio requirements specified in the Amended LPA.

Distributions not paid in accordance with the terms of the Amended LPA attract an additional percentage per annum, cumulative to the distribution rates noted above. Altus Midstream’s ability to exercise or satisfy redemption options in cash or pay quarterly distributions is predicated upon Altus Midstream’s ability to generate sufficient cash from operations in addition to the availability of borrowing capacity under its existing revolving credit facility.

39

Since the Preferred Units could be exchangeable for a number of shares of Class A Common Stock equal to 20 percent or more of the Company’s outstanding voting power, the Company submitted the potential issuance of such shares for approval of its stockholders (the Stockholder Approval) at its annual stockholder meeting in 2020 and obtained Stockholder Approval.

Off-Balance Sheet Arrangements

Other than the arrangements described herein, the Company has not entered into any transactions, agreements, or other contractual arrangements with unconsolidated entities that are reasonably likely to materially affect its liquidity or capital resource positions.

At the close of the Altus Combination, Apache was granted the right to receive contingent consideration of up to 1,250,000 shares of Class A Common Stock as follows:

•625,000 shares if the per share closing price of the Class A Common Stock as reported by Nasdaq during any 30-day-trading period ending prior to the fifth anniversary of the Closing Date is equal to or greater than $280.00 for any 20 trading days within such 30-trading-day period.

•625,000 shares if the per share closing price of the Class A Common Stock as reported by Nasdaq during any 30-trading-day period ending prior to the fifth anniversary of the Closing Date is equal to or greater than $320.00 for any 20 trading days within such 30-trading-day period.

All share amounts referenced above have been retrospectively restated to reflect the Company’s reverse stock split, which was effected June 30, 2020. For additional information regarding these arrangements, please see Note 10—Equity and Warrants in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Contractual Obligations

Altus Midstream exercised four of the Company’s five Pipeline Options acquired from Apache at the closing of the Altus Combination. The fifth option to acquire interest in the Salt Creek NGL pipeline was not exercised, and expired during 2020. The Company may be required to fund its proportionate share of future capital expenditures for its equity interest share in the development of the pipelines as referenced. The Company estimates it will incur minimal capital contributions during 2022 for its equity interests.

The Company’s midstream assets service Altus Midstream’s revenue agreements, which are underpinned by acreage dedications covering Alpine High. There are no minimum volume or firm transportation commitments. Pursuant to these agreements, Altus Midstream is obligated to perform low and high pressure gathering, processing, dehydration, compression, treating, conditioning, and transmission on all volumes produced from the dedicated acreage, so long as Apache has the right to market such gas. Although Altus believes its existing gathering, processing, and transmission infrastructure is expected to provide capacity levels capable of fulfilling its midstream contracts to service Apache’s production and additional third-party customers, current capital spending may be increased in future periods if additional cryogenic processing capacity is needed, commensurate with any forecasted throughput increases.

During the fourth quarter of 2020, the Company entered into a three year fixed-rate power contract with a third-party. The Company estimates its minimum obligation will be $4.7 million and $3.6 million for 2022 and 2023, respectively. The actual amount incurred will vary based on usage.

Altus Midstream may also be subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation, regulatory, or environmental matters. As of December 31, 2021, there were no accruals or loss contingencies related to such matters. For a detailed discussion of the Company’s environmental and legal contingencies, please see Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

40

For additional information regarding the Company’s obligations, please see Note 2—Transactions with Affiliates, Note 5—Debt and Financing Costs, and Note 8—Commitments and Contingencies in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Insurance Program

The Company has the benefit of insurance policies that include coverage for physical damage to assets, general liabilities, business interruption insurance, sudden and accidental pollution, and other risks. Altus’ insurance coverage is subject to deductibles or retentions that Altus must satisfy prior to recovering on insurance. Additionally, the insurance coverage is subject to policy exclusions and limitations. There is no assurance that insurance coverage will adequately protect the Company against liability from all potential consequences and damages.

Future insurance coverage for the industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable.

Critical Accounting Estimates

Altus prepares its financial statements and the accompanying notes in conformity with GAAP, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. Altus identifies certain accounting policies involving estimation as critical based on, among other things, their impact on the portrayal of Altus’ financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of each of the critical accounting policies. The following is a discussion of Altus’ most critical accounting estimates.

Property, Plant, and Equipment

When assets are placed into service, management makes estimates with respect to useful lives and salvage values that management believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand in the area. Depreciation is computed over the asset’s estimated useful life using the straight-line method based on estimated useful lives and asset salvage values.

Impairment of Long-lived Assets

Long-lived assets used in operations, including gathering, processing, and transmission facilities, are evaluated for potential impairment when events or changes in circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset may not be recovered, the asset is assessed for impairment through an established process in which changes to significant assumptions such as service prices, throughput volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of the impaired assets is assessed by management using the income approach.

Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of key factors and assumptions including estimates of forecasted throughput volumes, operating expenses, commercial development and capital costs, inflation expectations, discount rates, and other variables. Management also evaluates changes in Altus’ business and economic conditions and their implications on future development plans and ultimate disposition of the assets. Global and regional economic conditions, including commodity prices and drilling activity by third party customers, may also affect estimated future cash flows.

41

The final measure of impairment to be recognized, if any, depends upon management’s calculation using the income approach; however, management does consider other factors in determining the asset’s fair value including indicative values at which similar assets were transferred in recent market transactions, if such data is available. Although the Company bases its fair value measurement of each asset group on assumptions it believes to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimates. Negative revisions in throughput estimates, increases in future operating and capital costs, divestitures of significant components of an asset group, or sustained market deterioration in the oil and gas industry could lead to further reductions in expected future cash flows and possibly additional impairments in future periods.

Altus recorded impairments on its gathering, processing, and transmission assets and other fixed assets during 2021, 2020 and 2019. For discussion of these impairments, see Note 1—Summary of Significant Accounting Policies and Note 4—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements included in within Part IV, Item 15 of this Annual Report on Form 10-K.

Impairment of Equity Method Interests

Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.

Altus recorded an impairment charge on its equity method interest in EPIC during the fourth quarter of 2021. The fair value of the impaired interest was determined using the income approach. The income approach first considered Altus’ estimates of future throughput volumes, tariff rates, and costs. These assumptions were applied to develop future operating cash flow projections that were then discounted using a discount rate believed to be consistent with that which would be applied by market participants. The amount arrived at using this approach was then considered against EPIC’s debt and the carrying value of Altus’ investment in EPIC as of December 31, 2021, resulting in the fourth quarter impairment charge. Altus has classified this nonrecurring fair value measurement as Level 3 in the fair value hierarchy. Please refer to Note 9—Equity Method Interests, within Part IV, Item 15 of this Annual Report on Form 10-K for further details of the Company’s equity method interests. Negative revisions in future estimates of throughput volumes, revenue assumptions or costs related to the Company’s equity method interests could lead to further impairments of such interests in future periods.

Income Taxes

Altus’ operations are subject to U.S. federal and state taxation on income. The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the Company’s financial statements and tax returns. Altus routinely assesses the ability to realize its deferred tax assets. If Altus concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. The Company recorded a full valuation allowance against its deferred tax asset as of December 31, 2021 and December 31, 2020.

The Company regularly assesses and, if required, establishes accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions where the Company operates. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, case law, and any new legislation. There was no material change in the Company’s uncertain tax positions in the period.

Fair Value Measurements — Preferred Units Embedded Derivative

As noted in the discussion related to the Preferred Units above, the fair value of the embedded derivative is determined by a range of factors, including expected future interest rates using the Black-Karasinski model, the Company’s imputed interest rate, interest rate volatility, the expected timing of periodic cash distributions, the estimated timing for the potential exercise of the exchange option, any anticipated early redemptions of the Preferred Units, and anticipated dividend yields of the Preferred Units. The value of the unrealized derivative liability during the year ended December 31, 2021 decreased by $82.1 million, primarily driven by a current year assumption that a portion of the Preferred Units will be redeemed before the holders of the Preferred Units could theoretically exercise their exchange option. Absent any changes to assumptions regarding the timing of redemptions in general, a one percent increase in the expected imputed interest rate assumption would significantly increase the

42

value of the embedded derivative liability at any period end, while a one percent decrease would lead a similar decrease in value.

A summary of key assumptions used to value this instrument at December 31, 2021 and 2020 is included below:

(1)A 1% change in either direction of the interest rate volatility assumption in any period would not have a significant effect on the valuation of the embedded feature.

Refer to Note 11—Series A Cumulative Redeemable Preferred Units within Part IV, Item 15 of this Annual Report on Form 10-K for further discussion.

43