What changed in this filing

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Item 2. Management’s Discussion and Analysis

2022-05-10 compared with 2021-11-05 · 290 added, 334 removed, 33 unchanged (95% of the section changed)

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read together with the Company’s consolidated financial statements and accompanying notes included under Part I, Item 1, “Consolidated Financial Statements” of this Quarterly Report on Form 10-Q, as well as the Company’s consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020 (Form 10-K).

Capitalized terms used but not defined herein shall have the meaning ascribed to such terms in the Form 10-K.

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 September 30, 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 September 30, 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 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.

The following discussion and analysis addresses the results of our operations for the three month period ended March 31, 2022, as compared to our results of operations for the three month period ended March 31, 2021.

In addition, the discussion and analysis addresses our liquidity, financial condition and other matters for these periods.

The previously announced merger of ALTM and BCP and their respective consolidated subsidiaries closed on February 22, 2022.

As the Transaction was determined to be a reverse merger, BCP was considered the accounting acquirer and ALTM was considered the legal acquirer.

Therefore, BCP’s net assets, carrying at historical value, were presented as the predecessor to the Company’s historical financial statements and the comparable period presented herein reflects the results of operations of BCP for the three months ended March 31, 2021.

The results of operations of ALTM is reflected within the Company’s Condensed Consolidated Financial Statements from the Closing Date through March 31, 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.

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 previously announced 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 of the equity interests in BCP and its consolidated subsidiaries, to the Partnership;

and (ii) in exchange for such contribution, the Partnership issued 50,000,000 Common Units and the Company issued 50,000,000 shares of the Company’s Class C Common Stock to Contributor.

The Company’s 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 owns approximately 75% of the issued and outstanding Common Stock, (ii) Apache Midstream owns approximately 20% of the issued and outstanding Common Stock, and (iii) the Company’s remaining stockholders own 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 note that a secondary offering of 4 million Apache shares was closed during March of 2022, reducing Apache’s ownership to 13% as of March 31, 2022.

The Transaction also brought in additional volume capacity from ALTM for the Midstream Logistic segment, including 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 NGLs pipelines.

The increase volume capacity has contributed to the increase in operating revenue for the three months ended March 31, 2022 compared to the same period in 2021.

The Company, through its subsidiaries, owns gas gathering, processing, and transmission assets in the Permian Basin of West Texas and provides comprehensive gathering, transportation, compression, processing, and treating services for companies that produce NGLs, natural gas, crude, and water.

Our core capabilities serve a variety of service offerings across multiple streams, 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.

We have four plant sites in operation across more than 1,300 miles of pipeline in the ground in four counties in the Southern Delaware Basin.

Our Operations

Upon Closing, the Company evaluated the Company and ALTM’s respective reporting segment activities and then 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 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 and our Delaware Link Pipeline, which is currently under commercialization.

The pipelines transport crude oil, natural gas, and NGLs along the Texas Gulf Coast.

Midstream Logistics

The Midstream Logistics segment provides gas gathering and processing services with approximately 1,200 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 billion cubic feet per day (“Bcf/d”):

the East Toyah complex (460 MMcf/d), the Pecos Bend complex (540 MMcf/d), the Pecos complex (260 MMcf/d), the Sierra Grande complex (60 MMcf/d), and Diamond Cryogenic complex (600 MMcf/d).

Current residue gas outlets include the El Paso Natural Gas Pipeline, Energy Transfer Comanche Trail Pipeline, ONEOK Roadrunner Pipeline, and Energy Transfer Oasis Pipeline.

NGLs outlets include Energy Transfer’s Lone Star NGL Pipeline, Targa’s Grand Prix NGL Pipeline, and Enterprise’s Shin Oak NGL Pipeline.

The Midstream Logistics segment also includes crude oil gathering, stabilization, and storage services throughout the Texas Delaware Basin.

Crude gathering assets are centralized at the Caprock Stampede Terminal and the Pinnacle Sierra Grande Terminal.

The system includes approximately 200 miles of gathering pipeline and 90,000 barrels of crude storage.

The crude facilities have connections for takeaway transportation into Plains’ 285 Central Station and State Line and Oryx’s Orla & Central Mentone facilities.

In addition, this segment includes water gathering and disposal assets located in northern Reeves County, Texas which are included in the Midstream Logistics segment.

The system includes approximately 70 miles of gathering pipeline and approximately 500,000 barrels per day of permitted disposal capacity at 16 active and permitted disposal wells.

Pipeline Transportation

The Pipeline Transportation segment consists of four EMI pipelines in the Permian Basin with access to various points along the Texas Gulf Coast and the Delaware Link Pipeline, which is currently under construction.

EMI pipelines include the following:

• An approximate 53.3% equity interest in 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 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.

• A 16% equity interest in the Gulf Coast Express Pipeline (“GCX”), which is owned and operated by Kinder Morgan Texas Pipeline, LLC (“Kinder Morgan”).

GCX transports natural gas from the Permian Basin 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 33% 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 in an all-stock transaction.

BCP is the parent company of EagleClaw Midstream, which includes EagleClaw Midstream Ventures, the Caprock Midstream and Pinnacle Midstream businesses, and a 26.7% interest in the Permian Highway Pipeline.

As consideration for the transaction, the Company will issue 50 million Class C common shares (and Altus Midstream will issue corresponding 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 2022 following completion of customary closing conditions, including approval by the Company’s shareholders and regulatory reviews.

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 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.

Altus has no upcoming debt maturities, and the term of its revolving credit facility extends through November of 2023.

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 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 I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

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;

• 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 business combination transaction with BCP 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.

The circumstances that existed when the original agreement was signed have changed dramatically, and the updated terms may help to attract new business from both Apache, our existing customer, and 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 business combination with BCP, a midstream company that has existing commitments with various third-party customers.

Costs and Expenses

Costs of product sales

Costs of product sales represent purchases of NGLs from a third party, which the Company then owns, controls and processes, prior to ultimate sale to customers.

These costs 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 I of this Quarterly Report on Form 10-Q for further information.

Taxes other than income

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

• A 15% 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 early 2020, with initial throughput capacity of approximately 600 MBbl/d.

Factors Affecting Our Business

The Significance of Crude Oil and Producer Volumes on Our Revenues, Cost of Sales and Gross Margin

The Company’s assets include more than 1,300 miles of NGLs, natural gas, condensate, produced water, and crude oil pipelines as well as 2 Bcf/d of natural gas processing capacity as of March 31, 2022.

Most of the gas gathered and processed by the Company is associated gas included in the oil stream, making producers’ oil break-even prices the primary driver of activity.

The average price of WTI crude oil was $95.01/bbl during the first quarter of 2022.

If crude prices were to fall below producers’ break-even prices for a prolonged period of time, drilling activity and volumes might decline and might have a negative impact on our business.

In addition, because the Company’s Pipeline Transportation segment provides NGLs

transmission service through its EMI pipelines, a decrease in natural gas and NGL price will have an adverse impact on the Company’s results of operations as it may lead to lower natural gas production and thus lower volumes of NGLs transported.

The average natural gas price was $4.59/MMBtu during the first quarter of 2022.

For additional risk factors that affect the Company’s business, please refer to Item 1A - Risk Factors .

Recent Developments

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 COVID-19 pandemics 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 result from the conflict would have a highly uncertain impact on the U.S.

economy, which in turn, might affect our business and operations adversely.

The Company continues to monitor commodity price closely and may enter into commodity price hedge from time to time as necessary to mitigate the volatility risk.

The annual rate of inflation in the United States hit 8.5% in March 2022, the highest in more than three decades, as measured by the Consumer Price Index.

We expect that inflation in 2022 will modestly increase our operating costs and the overall cost of capital projects we undertake.

Inflation, combined with other economic factors has caused drilling and completion costs to increase over 20% from the prior year, which affects our customers and the wells they bring on line.

In addition, the Federal Reserve has tightened its monetary policy by approving a half-percentage-point interest rate hike in May 2022 to maintain the federal funds rate in a target range of 0.75% - 1.0%.

Furthermore, the Chairman of the Federal Reserve signaled that the Federal Reserve would continue to take necessary action to bring inflation down and to ensure price stability, including continued rate increases.

Increased interest rates will 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.

Supply Chain Considerations

During 2021 and the first quarter of 2022 challenging supply chain issues have emerged that will continue at least through the balance of 2022.

Supply chains generally are being strained given the pick up in economic activity as the global economy reemerges from the COVID-19 pandemic.

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.

Comprehensive Refinancing

During the second quarter of 2022, the Company plans to enter into transactions to comprehensively refinance our long term debt and minimize ongoing exposure to the Federal Reserve’s decision to raise interest rates to combat the impacts of inflation and the market instability caused by the Russian conflict with Ukraine.

Key Performance Metrics

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.

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 investment, equity in earnings from investments recorded using the equity method, stock-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;

• 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 (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.

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.

1 unchanged sentence

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.

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 (loss) including noncontrolling interests to the non-GAAP financial measure of Adjusted EBITDA.

Three Months Ended September 30, Nine Months Ended September 30,

2021 2020 (1)

(In thousands)

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.

Three Months Ended March 31,*

Reconciliation of net income including noncontrolling interests to Adjusted EBITDA

(In thousands)

Net income including noncontrolling interests

Financing costs, net of capitalized interest 2,674 413 7,887 978

Depreciation and accretion 4,085 4,008 12,094 11,984

Impairments — — 441 —

Unrealized derivative instrument loss — 3,533 — 76,102

Equity method interests Adjusted EBITDA 50,109 29,952 138,405 81,869

Other 325 — 781 290

Gain on sale of assets 194 — 470 76

Unrealized derivative instrument gain 4,010 — 18,487 —

Income from equity method interests, net 32,479 15,987 82,633 47,541

Warrants valuation adjustment 664 209 222 1,668

Income tax benefit — — — 696

Other 1 — 3 11

Interest expense

Gain on redemption of mandatorily redeemable Preferred Units

Income tax expense

Depreciation and amortization

Amortization of contract costs

Proportionate EMI EBITDA

Share-based compensation

Loss on sale of assets

Loss (gain) on debt extinguishment

Unrealized loss on derivatives

Derivative loss due to Winter Storm Uri

Integration Costs

Transaction Costs

Other one-time cost or amortization

Interest and other income

Equity income from unconsolidated affiliates

Adjusted EBITDA

(1) This period presented has been revised to reflect the Company’s fair value change of its underlying warrants.

Refer to Note 1—Summary of Significant Accounting Policies , see the section titled Revision of Previously Issued Consolidated Financial Statements for Immaterial Adjustment for further information.

* 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-Q basis of presentation in Note 1—Description of the Organization an d Summary of Significant Accounting Policies, for further information on the Company’s basis of presentation.

NM - not meaningful

Adjusted EBITDA increased by $22.2 million, or 19%, to $140.8 million for the three months ended March 31, 2022, compared to $118.6 million for the same period in 2021.

The increase was primarily driven by an increase in net income including noncontrolling interest of $3.3 million and increases in add back related to the Company’s proportionate share of its EMI pipelines’ EBITDA, integration costs, share-based compensation, transaction costs, depreciation and amortization expense and interest expense, as a result of the Transaction closed in February 2022.

The increase was partially offset by an increase in EMI pipelines income of $16.6 million, resulting from the three additional EMI pipelines entities through the Transaction, as well as a decrease in add back related to derivative loss due to Winter Storm Uri of $13.5 million as there was no add back related to extreme weather in the first quarter of 2022, nor was there elevated pricing which also resulted from Winter Storm Uri.

The 2022 Adjusted EBITDA presented in the above table does not include any expected synergies including ad valorem taxes, operating expenses and corporate G&A, which will be recognized over the course of 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 equity method investments and other non-recurring items.

Following table presents segment adjustment EBITDA for the three months ended March 31, 2022 and 2021.

Also refer to Note 17—Segments in the Notes to our Condensed Consolidated Financial Statements in this Form 10-Q for reconciliation of segment adjusted EBITDA to net income including noncontrolling interests.

Three Months Ended March 31,*

(In thousands)

Midstream Logistics

Pipeline Transportation

Corporate and Other (1)

Total segment 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-Q basis of presentation in Note 1—Description of the Organization and Summary of Significant Accounting Policies, for further information on the Company’s financial statement consolidation.

(1) 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.

Midstream Logistics segment adjusted EBITDA decreased by $2.9 million, or 3%, to $102.9 million for the three months ended March 31, 2022, compared to $105.8 million for the same period in 2021.

The decrease was primarily driven by no similar Winter Storm Uri event in the first quarter of 2022.

For example, derivative loss due to Winter Storm Uri of $13.5 million was added back to segment adjusted EBITDA for first quarter of 2021, but no similar add back recorded in the first quarter of 2022.

The decrease was partially offset by an increase in segment net income including noncontrolling interests of $1.0 million and increases in depreciation and amortization expense, integration cost and income tax expense add backs of $5.1 million, $4.1 million and $0.5 million, respectively, in relation to the Transaction closed in February 2022.

Pipeline Transportation segment adjusted EBITDA increased by $25.1 million, or 164%, to $40.4 million for the three months ended March 31, 2022, compared to $15.3 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 three months ended March 31, 2021, the Company only held a 26.67% interest in PHP.

Table of Con tents

Results of Operations

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

Three Months Ended September 30, Nine Months Ended September 30,

2021 2020 (1)

Three Months Ended March 31,*

(In thousands)

Midstream services revenue — affiliate $ 34,548 $ 38,869 $ 98,544 $ 111,252

Product sales — third parties — 1,303 5,743 1,900

Service revenue

Product revenue

Other revenue

Total revenues

COSTS AND EXPENSES:

Costs of product sales — 1,177 5,344 1,693

Operations and maintenance 9,642 8,960 24,384 29,059

Operating costs and expenses:

Costs of sales (exclusive of depreciation and amortization)

Operating expense

Ad valorem taxes

General and administrative

Depreciation and accretion 4,085 4,008 12,094 11,984

Impairments — — 441 —

Taxes other than income 2,811 4,143 10,431 10,933

Total costs and expenses 19,958 21,224 63,044 63,771

Depreciation and amortization

Loss on disposal of assets

Total operating costs and expenses

Operating income

Unrealized derivative instrument gain (loss) 4,010 (3,533) 18,487 (76,102)

Income from equity method interests, net 32,479 15,987 82,633 47,541

Warrants valuation adjustment 664 209 222 1,668

Other 620 — 11,321 (346)

Total other income (loss) 37,773 12,663 112,663 (27,239)

Financing costs, net of capitalized interest 2,674 413 7,887 978

NET INCOME BEFORE INCOME TAXES 49,689 31,198 146,019 21,164

Current income tax benefit — — — (696)

Other income (expense):

Interest and other income

Gain on Preferred Units redemption

Unrealized loss on derivatives

Interest expense

Equity in earnings of unconsolidated affiliate

Total other income (expense), net

Income before income tax

Current income tax expense

Net income including noncontrolling interests

Net income attributable to Preferred Unit limited partners 29,166 19,332 72,662 56,358

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS 20,523 11,866 73,357 (34,498)

Net income (loss) attributable to Apache limited partner 15,279 8,970 56,270 (28,361)

NET INCOME (LOSS) ATTRIBUTABLE TO CLASS A COMMON SHAREHOLDERS $ 5,244 $ 2,896 $ 17,087 $ (6,137)

KEY PERFORMANCE METRICS:

Adjusted EBITDA (2)

$ 69,534 $ 52,908 $ 203,812 $ 143,091

OPERATING DATA:

Average throughput volumes of natural gas (MMcf/d) 452 531 447 514

(1) This period presented has been revised to reflect the Company’s fair value change of its underlying warrants.

(2) 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.

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 the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020, and Part I, Item 3—Quantitative and Qualitative Disclosures About Market Risk of this Quarterly Report on Form 10-Q, for further discussion.

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

Three Months Ended September 30, Nine Months Ended September 30,

2021 2020 2021 2020

(In thousands)

Midstream services revenue — affiliate $ 34,548 $ 38,869 $ 98,544 $ 111,252

Product sales — third parties — 1,303 5,743 1,900

Total revenues $ 34,548 $ 40,172 $ 104,287 $ 113,152

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 natural gas liquid volumes that flow through its systems.

During the periods presented, Altus did not own or take title to the affiliate volumes that were processed through its systems.

For more details, please refer to Note 3—Revenue Recognition in the Notes to Consolidated Financial Statements set forth in Part I of this Quarterly Report on Form 10-Q for further information.

Three months ended September 30, 2021 as compared to three months ended September 30, 2020

Midstream services revenue from affiliate decreased by $4.4 million to $34.5 million for the three months ended September 30, 2021, as compared to $38.9 million for the three months ended September 30, 2020.

The decrease was primarily driven by lower throughput of natural gas volumes from Apache.

The $1.3 million in product sales revenues during the three months ended September 30, 2020 were generated from NGLs and condensates purchased and processed by Altus from a third party and subsequently sold to non-affiliated customers.

No revenues from such sales occurred during the three months ended September 30, 2021.

Nine months ended September 30, 2021 as compared to nine months ended September 30, 2020

Midstream services revenue from affiliate decreased by $12.8 million to $98.5 million for the nine months ended September 30, 2021, as compared to $111.3 million for the nine months ended September 30, 2020.

The decrease was primarily driven by lower throughput of natural gas volumes from Apache.

The $3.8 million increase in product sales revenues during the nine months ended September 30, 2021, as compared to the nine months ended September 30, 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.

Costs and Expenses

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

Three Months Ended September 30, Nine Months Ended September 30,

2021 2020 2021 2020

(In thousands)

Costs of product sales $ — $ 1,177 $ 5,344 $ 1,693

Operations and maintenance 9,642 8,960 24,384 29,059

General and administrative 3,420 2,936 10,350 10,102

Depreciation and accretion 4,085 4,008 12,094 11,984

Impairments — — 441 —

Taxes other than income 2,811 4,143 10,431 10,933

Total costs and expenses $ 19,958 $ 21,224 $ 63,044 $ 63,771

Three months ended September 30, 2021 as compared to three months ended September 30, 2020

Costs of product sales

The $1.2 million in costs of product sales during the three months ended September 30, 2020 represent purchases of NGLs from a third-party, which were used to support the product sales to third parties discussed above.

No costs of product sales were incurred during the three months ended September 30, 2021.

Operations and maintenance

Operations and maintenance expenses were consistent period over period, increasing by approximately $0.6 million to $9.6 million for the three months ended September 30, 2021, as compared to $9.0 million for the three months ended September 30, 2020.

General and administrative

G&A expense was consistent period over period, increasing by $0.5 million to $3.4 million for the three months ended September 30, 2021, as compared to $2.9 million for the three months ended September 30, 2020.

Taxes other than income

The decrease in taxes other than income was driven by ad valorem taxes, which decreased by $1.3 million to $2.7 million for the three months ended September 30, 2021, as compared to $4.1 million for the three months ended September 30, 2020.

The $1.3 million overall decrease is primarily related to a decrease in tax assessed value for the Company’s property, plant, and equipment.

Nine months ended September 30, 2021 as compared to nine months ended September 30, 2020

Costs of product sales

The $3.7 million increase in costs of product sales during the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020, was driven by higher volumes of purchases of NGLs from a third-party, which were used to support the product sales to third parties discussed above.

Operations and maintenance

Operations and maintenance expenses decreased by $4.7 million to $24.4 million for the nine months ended September 30, 2021, as compared to $29.1 million for the nine months ended September 30, 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.

* 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-Q basis of presentation in Note 1—Description of the Organization and Summary of Significant Accounting Policies, for further information on the Company’s presentation.

NM - Not meaningful

For the three months ended March 31, 2022, revenue increased $109.1 million, or 74%, to $257.2 million, compared to $148.1 million for the same period in 2021.

The increase was primarily driven by period to period increases in gathered and processed volumes, as well as similar increases in residue, condensate and NGL volumes sold.

Service revenue

Service revenue consists of service fees paid to us by our 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 three months ended March 31, 2022, increased by $12.8 million, or 19%, to $80.4 million, compared to $67.7 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 280.0 Mcf per day and 280.5 Mcf per day, respectively, of which 164.0 Mcf per day and 124.3 Mcf per day are a result of new operations acquired through the Transaction.

Service revenues are included entirely in the Midstream Logistics segment.

Table of Con tents

Product revenue

Product revenue consists of commodity sales (including condensate, natural gas residue, and NGLs).

Product revenue for the three months ended March 31, 2022, increased by $94.9 million, or 119%, to $174.9 million, compared to $80.0 million for the same period in 2021, primarily due to period over period increases in NGL and condensate prices combined with increased sales volumes of these liquids and natural gas residue.

NGL prices increased $18.27 per barrel or 64% and condensate prices increased $35.18 per barrel or 95%.

NGL and condensate sales volumes increased 1.8 million barrels or 27%.

Similarly, natural gas residue sales volumes increased 1.8 million MMBtu or 25%.

Partially offsetting these increases was a period over period decrease in natural gas prices of $0.35 per MMBtu or 7%.

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 three months ended March 31, 2022, cost of sales increased $83.3 million, or 225%, to $120.3 million, compared to $37.0 million for the same period in 2021.

The increase was primarily driven by the period to period increase in NGL prices and NGL and natural gas 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 $14.3 million, or 92%, to 29.9 million for the three months ended March 31, 2022, compared to 15.6 million for the same period in 2021.

Of the total increase, $3.5 million was driven by the new operations acquired through the Transaction.

The remaining increase was primarily driven by higher period over period electricity costs of $9.4 million and merger integration costs of $1.4 million.

The higher electricity costs were 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.

General and administrative

G&A expense was consistent period over period, increasing by $0.3 million to $10.4 million for the nine months ended September 30, 2021, as compared to $10.1 million for the nine months ended September 30, 2020.

Taxes other than income

The $0.5 million decrease in taxes other than income for the comparative periods was driven by ad valorem taxes, which decreased by $0.5 million to $10.2 million for the nine months ended September 30, 2021, as compared to $10.7 million for the nine months ended September 30, 2020.

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:

Three Months Ended September 30, Nine Months Ended September 30,

2021 2020 (1)

(In thousands)

Unrealized derivative instrument gain (loss) $ 4,010 $ (3,533) $ 18,487 $ (76,102)

Income from equity method interests, net 32,479 15,987 82,633 47,541

Warrants valuation adjustment 664 209 222 1,668

Other 620 — 11,321 (346)

Total other income (loss) $ 37,773 $ 12,663 $ 112,663 $ (27,239)

Interest expense $ 2,382 $ 2,133 $ 7,012 $ 7,498

Amortization of deferred facility fees 292 292 875 857

Capitalized interest — (2,012) — (7,377)

Total Financing costs, net of capitalized interest $ 2,674 $ 413 $ 7,887 $ 978

(1) This period presented has been revised to reflect the Company’s fair value change of its underlying warrants.

Unrealized derivative instrument gain (loss)

During the three and nine months ended September 30, 2021, the Company recognized an unrealized derivative instrument gain of $4.0 million and $18.5 million, respectively, in relation to an embedded exchange option identified upon the issuance and sale of Series A Cumulative Redeemable Preferred Units (the Preferred Units).

The unrealized loss related to this embedded feature was $3.5 million and $76.1 million for the three and nine months ended September 30, 2020, respectively.

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 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 three and nine months ended September 30, 2021 was primarily impacted by expected future interest rates.

Refer to Note 13—Fair Value Measurements within Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q for further discussion.

Income from equity method interests, net

Income from equity method interests increased $16.5 million and $35.1 million for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 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.

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 nine months ended September 30, 2021.

No credits were recognized for the three months ended September 30, 2021 or for the three and nine months ended September 30, 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 quarter.

The changes to gross interest expense for the periods presented was insignificant.

Key Performance Metric—EBITDA

Three months ended September 30, 2021 as compared to three months ended September 30, 2020

Net income before income taxes was $49.7 million for the three months ended September 30, 2021, an increase of $18.5 million from net income before income taxes of $31.2 million for the three months ended September 30, 2020.

The increase in net income before income taxes was primarily driven by a $16.5 million increase in income from the Equity Method Interest Pipelines, a $7.5 million decrease to expense related to the fair value measurement of an embedded derivative at September 30, 2021, and a $2.4 million net decrease of various other individually insignificant costs.

The increases to net income were offset by a $5.6 million decrease in total revenues and a $2.3 million increase in interest expense.

Adjusted EBITDA increased by $16.6 million for the three months ended September 30, 2021 compared to the prior year period.

Adjusted EBITDA, which excludes the impacts of depreciation, accretion, impairments, interest expense, and the changes to the embedded derivative noted above, benefited from an incremental $3.7 million increase, primarily driven by Permian Highway Pipeline being placed in service in January 2021.

Nine months ended September 30, 2021 as compared to nine months ended September 30, 2020

Net income before income taxes was $146.0 million for the nine months ended September 30, 2021, an increase of $124.8 million from net income before income taxes of $21.2 million for the nine months ended September 30, 2020.

The increase in net income before income taxes was primarily driven by a $94.6 million decrease to expense related to the fair value measurement of an embedded derivative at September 30, 2021, a $35.1 million increase in income from the Equity Method Interest Pipelines, an $11.8 million increase of other income primarily related to a power credit, and a $4.7 million decrease in operations and maintenance expenses.

The increases to net income were offset by an $8.9 million decrease in total revenue, a $3.7 million increase in costs of product of sales, a $6.9 million increase in interest expense, and a $1.8 million net increase of various other costs.

Adjusted EBITDA increased by $60.7 million for the nine months ended September 30, 2021 compared to the prior year period.

Adjusted EBITDA, which excludes the impacts of depreciation, accretion, impairments, interest expense, and the changes to the embedded derivative noted above, benefited from an incremental $21.4 million increase, primarily due to Permian Highway Pipeline being placed in service in January 2021.

This amount was further benefited by an insignificant decrease, in the aggregate, of $1.6 million of various other costs of the Company.

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

General and administrative (“G&A”) expense increased by $17.1 million, or 304%, to $22.8 million for the three months ended March 31, 2022, compared to $5.6 million for the same period in 2021.

The increase was primarily driven by acquisition and integration costs of $10.4 million incurred in relation to the Transaction closed in February 2022 and share-based compensation recognized of $6.1 million, both of which are in connection with the Transaction and are non-recurring expenses.

Other Income (Expense)

Equity in earnings of unconsolidated affiliate

Income from EMI pipelines increased by $16.6 million, or 146% to $27.9 million for the three months ended March 31, 2022, compared to $11.4 million for the same period in 2021.

The increase was primarily due to acquisition of new EMI pipelines and additional equity interest in the Company’s existing EMI pipeline, PHP, through the Transaction closed in February 2022 and due to higher earnings.

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 2021, the Company’s primary capital spending requirements are anticipated to be related to equity contributions associated with its proportionate share of capital calls relating to the Equity Method Interest Pipelines, and the Company’s payment of a quarterly cash dividend on its Class A common stock as may be declared by its Board of Directors.

During the nine months ended September 30, 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 during 2021.

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, as noted above, the Company recently announced approval of a business combination with BCP.

Given pending business combination, 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 business combination if closed.

Altus Midstream Capital Requirements

During the nine months ended September 30, 2021 and 2020, capital spending for midstream infrastructure assets totaled $3.3 million and $29.5 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 additional third-party customers.

As such, the Company expects remaining capital requirements for its existing infrastructure assets during 2021 to be minimal.

Additionally, during the nine months ended September 30, 2021 and 2020, the Company made cash contributions totaling $27.3 million and $286.2 million, respectively, to 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;

• a 33.0 percent interest in Shin Oak.

The Company estimates it will incur minimal capital contributions of between $2 million to $4 million for its equity interest in these joint venture pipelines for the remainder of 2021.

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’ existing infrastructure assets.

For further information on the Equity Method Interest Pipelines, refer to Note 8—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part I of this Quarterly Report on Form 10-Q.

Altus Midstream Class A Common Stock Dividend and Common Units Distributions

In the first, second, and third quarters of 2021, the Company made payments of $24.4 million, per quarter, related to its quarterly dividend program.

For more information please refer to Note 2—Transactions with Affiliates and Note 9—Equity in the Notes to Consolidated Financial Statements set forth in Part I, of this Quarterly Report on Form 10-Q.

On November 2, 2021, the Company’s Board of Directors declared a cash dividend of $1.50 per share on the Company’s Class A Common Stock, totaling $5.6 million, to be paid on December 30, 2021, to stockholders of record as of the close of business on November 30, 2021.

The Class A Common Stock dividend will be funded by a distribution from Altus Midstream to its common unitholders of $1.50 per Common Unit, totaling $24.4 million, of which $5.6 million is payable to the Company and the balance is payable to Apache.

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 of 1933, as amended (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.

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 in-kind and did so in respect of quarters ended on and before March 31, 2020.

For further information on the Preferred Units, refer to Note 10—Series A Cumulative Redeemable Preferred Units in the Notes to Consolidated Financial Statements set forth in Part I of this Quarterly Report on Form 10-Q.

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.

For the Nine Months Ended

September 30,

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 are anticipated to be related to integration 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 dividend on its Class A Common Stock and Common Units as may be declared by its Board of Directors and cash payment upon redemption of remaining mandatorily redeemable Preferred Units.

Table of Con tents

During the three months ended March 31, 2022, the Company’s primary sources of cash were distributions from the EMI pipelines, borrowings under the revolving credit facility, and cash generated from operations.

Based on the Company’s current financial plan and related assumptions including the Reinvestment Agreement, the Company believes that cash from operations, a reduced capital program for its midstream infrastructure, 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 and redemption of mandatorily redeemable Preferred Units during 2022.

Given recent crude oil price volatility and uncertain economic activity resulting from inflation, increased interest rates, the armed conflict in Ukraine and related governmental actions, the Company continues to monitor expected natural gas throughput volumes and capacity utilization of the EMI pipelines.

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 three months ended March 31, 2022 and 2021, capital spending for midstream infrastructure assets totaled $29.2 million and $19.8 million, respectively.

Management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its midstream contracts to service its customers.

During the three months ended March 31, 2022, the Company made no cash contributions to its EMI pipelines compared to $20.5 million contributed to an EMI pipeline in the same period of 2021.

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.

For further information on EMIs, refer to Note 9—Equity Method Investments in the Notes to our Condensed Consolidated Financial Statements in this Form 10-Q.

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

For the Three Months Ended March 31,

(In thousands)

Sources of cash and cash equivalents:

Proceeds from revolving credit facility $ 33,000 $ 184,000

Proceeds from sale of assets 1,687 7,629

Capital distributions from equity method interests 30,051 14,235

Net cash provided by operating activities 158,395 137,447

Total Sources of Cash and Cash Equivalents 223,133 343,311

Uses of cash and cash equivalents:

Capital expenditures (1)

(3,268) (29,540)

Distributions paid to Preferred Unit limited partners (34,686) (11,562)

Distributions paid to Apache limited partner (56,250) —

Dividends paid (16,859) —

Contributions to equity method interests (27,270) (286,227)

Finance lease payments — (11,789)

Deferred facility fees — (816)

Capitalized interest paid — (7,377)

Total Uses of Cash and Cash Equivalents (138,333) (347,311)

Increase (decrease) in cash and cash equivalents $ 84,800 $ (4,000)

(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.

Cash provided by operating activities

Cash used in investing activities

Cash (used in) provided by financing activities

Operating Activities .

Net cash provided by operating activities increased by $56.8 million for the three months ended March 31, 2022 compared with the same period in 2021.

The change in the operating cash flows reflected an increase in net income including noncontrolling interests of $3.3 million, an increase of adjustments related to non-cash items of $12.4 million and an increase in cash provided by changes in working capital of $41.1 million.

Period over period increase in cash provided by operating activities was primarily driven by new operation acquired through the Transaction.

Investing Activities .

Net cash used in investing activities decreased by $21.7 million for the three months ended March 31, 2022 compared with the same period in 2021 as the Company did not make any contribution to the EMI pipelines during first quarter of 2022.

The decrease was also driven by the cash inflow of $13.4 million acquired through the acquisition closed in February 2022.

The decrease was partially offset by an increase in cash outflows of $9.5 million for higher capital expenditures on gathering, processing and transmission systems expansion.

Financing Activities .

Net cash used in financing activities increased by $90.9 million for the three months ended March 31, 2022 compared with the same period in 2021.

The change was primarily due to redemption of mandatorily redeemable Preferred Units of $60.7 million, an increase of $13.9 million in principal payments on long-term debt and a reduction in equity contribution received of $14.9 million.

Table of Con tents

Dividend and Distribution Reinvestment Agreement

On February 22, 2022, the Company entered into a Dividend and Distribution Reinvestment Agreement (the “Reinvestment Agreement”) with the Partnership, APA Corporation, Apache Midstream, Buzzard Midstream LLC, a Delaware limited liability company and controlled affiliate of ISQ Global Infrastructure Fund II L.P., BCP Raptor Aggregator, LP, a Delaware limited partnership and controlled affiliate of Blackstone Capital Partners VII L.P.

and Blackstone Energy Partners II L.P., BC Permian Pipeline Aggregator LP, BX Permian Pipeline Aggregator LP, a Delaware limited partnership and controlled affiliate of Blackstone Capital Partners VII L.P.

and Blackstone Energy Partners II L.P., Contributor, and certain other individuals associated with Contributor (collectively, the “Reinvestment Holders”).

The Reinvestment Agreement obligates each Reinvestment Holder to reinvest in shares of Class A Common Stock at least 20% of all distributions on Common Units or dividends on shares of Class A Common Stock held by such Reinvestment Holder immediately after the Closing, including shares of Class A Common Stock received at a later date in exchange for Common Units held immediately after Closing.

The Reinvestment Agreement provides the audit committee of the Board with the authority to at any time increase the percentage of the mandatory dividend reinvestment to up to 100% of such distributions or dividends or decrease such percentage to not less than 20%.

The mandatory obligations of each Reinvestment Holder will continue from Closing until the earliest of (i) March 31, 2024, (ii) the date dividends and distributions are paid by the Company and the Partnership, respectively, in respect of the quarter ending December 31, 2023, and (iii) such other date determined by the audit committee of the Board.

All shares of Class A Common Stock issued pursuant to the Reinvestment Agreement will be issued at a 3% discount to the volume-weighted average price of the Class A Common Stock for the five trading days immediately preceding, but excluding, the dividend or distribution payment date.

The Reinvestment Agreement also provides an obligation for the Company to establish a dividend reinvestment plan that provides all other holders of Class A Common Stock the optional right to reinvest all or part of any dividends on shares of Class A Common Stock held by such holder on substantially the same terms as the Reinvestment Holders.

On April 4, 2022, the Company filed a Registration Statement on Form S-3 related to the Reinvestment Agreement and the establishment of the Plan for all other holders.

On Feb 22, 2022, the audit committee recommended to the Board of the Company and the Board approved that the dividends to be paid on shares held by the Reinvestment Holders will be paid in newly issued Class A shares for each quarterly dividend for the calendar year 2022.

The foregoing description of the Reinvestment Agreement is a summary only and is qualified in its entirety by reference to the Reinvestment Agreement, a copy of which is attached as Exhibit 10.2 to this Quarterly Report on Form 10-Q and is incorporated herein by reference.

Class A Common Stock Dividend

On April 19, 2022, the Company’s Board of Directors declared a cash dividend of $1.50 per share on the Company’s Class A Common Stock which will be payable to stockholders on May 17, 2022.

Please refer to Note 10—Equity and Warrants for additional information.

Common Units Distribution

Pursuant to the Contribution Agreement, in connection with the Closing, (i) Contributor contributed all of the equity interests of the Contributed Entities to the Partnership;

and (ii) in exchange for such contribution, the Partnership issued 50,000,000 common units representing limited partner interests in the Partnership and the Company issued 50,000,000 shares of the Company’s Class C common stock, par value $0.0001 per share, to Contributor.

For further information on the Preferred Units, refer to Note 10—Equity and Warrants in the Notes to our Condensed Consolidated Financial Statements in this Form 10-Q.

In the first quarter of 2022, the Company, through its ownership of the general partner of the Partnership, declared a distribution of $1.50 per Common Unit from the Partnership to the holders of Common Units.

Please refer to Note 10—Equity and Warrants for additional information.

Series A Cumulative Redeemable Preferred Units

The Partnership 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 Preferred Units are exchangeable for shares of the Company’s Class A Common Stock at the option of the Preferred Unit holders upon the occurrence of specified events, unless otherwise redeemed by the Company.

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The Preferred Units entitle the holders to receive quarterly distributions at a rate of seven percent per annum, commencing with the quarter ended June 30, 2019.

The rate increases to 10 percent per annum upon the occurrence of specified events.

On the Closing Date of the Transaction, the Company effectuated the Third Amended and Restated Agreement of Limited Partnership of the Partnership (“Partnership LPA”), which among other things, provides for mandatory redemptions by the Partnership of 50,000 Preferred Units at or prior to each of the six-, twelve- and eighteen-month anniversaries of the effectiveness from the Partnership LPA, for an aggregate of 150,000 Preferred Units over such eighteen-month period.

The Company intends to redeem the Preferred Units by year end 2022.

For further information on the Preferred Units, refer to Note 11—Series A Cumulative Redeemable Preferred Units in the Notes to our Condensed Consolidated Financial Statements in this Form 10-Q.

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

September 30, 2021 December 31, 2020

(In thousands)

Cash and cash equivalents

Total debt 657,000 624,000

Available committed borrowing capacity

Cash and cash equivalents

As of September 30, 2021 and December 31, 2020, the Company had $109.0 million and $24.2 million, respectively, in cash and cash equivalents.

As of March 31, 2022 and December 31, 2021, the Company had $17.6 million and $18.7 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.

Total Debt and 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 September 30, 2021, there were $657.0 million of borrowings and a $2.0 million of letter of credit outstanding under this facility.

As of December 31, 2020, there were $624.0 million of borrowings and no letters of credit were 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 September 30, 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 September 30, 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 10—Series A Cumulative Redeemable Preferred Units in the Notes to Consolidated Financial Statements set forth in Part I of this Quarterly Report on Form 10-Q 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 September 30, 2021.

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.

There is no assurance that the financial condition of banks with lending commitments to 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.

Contractual Obligations

Long-term debt obligation and related interest payments.

We have contractual obligations for principal and interest payments on our term loans.

See Note 6—Debt and Financing Costs in the Notes our Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Under certain of our transportation services agreements with third party pipelines to transport natural gas and NGLs with current contract terms from 2021 to 2031, if we fail to ship a minimum throughput volume during any year, then we will pay a deficiency payment for transportation based on the volume shortfall up to the MVC amount.

The Company has made no historical shortfall payments through March 31, 2022.

Off-Balance Sheet Arrangements

Other than the arrangements described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020, the Company has not entered into any transactions, agreements, or other contractual arrangements with unconsolidated entities that are reasonably likely to materially affect the Company’s liquidity or capital resource positions.

Other than the arrangements described in Exhibit 99.6 to the Company’s Current Report on Form 8-K filed on February 28, 2022, the Company has not entered into any transactions, agreements, or other contractual arrangements with unconsolidated entities that are reasonably likely to materially affect the Company’s liquidity or capital resource positions.

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Critical Accounting Policies

The Company’s significant accounting policies (refer to Summary of Significant Accounting Policie s in Exhibit 99.4 to the Company’s Current Report on Form 8-K filed on February 28, 2022) are fundamental to understanding our results of operations and financial condition.

Some accounting policies, by their nature, are inherently subject to estimation techniques, valuation assumptions and other subjective assessments and may require significant judgments in applying complex accounting principles to individual transactions, where actual results could differ materially from the Company’s estimates.

The Company has procedures and processes in place to facilitate making these judgments.

In addition, certain accounting policies are more likely than others to have a critical effect on the Company’s Condensed Consolidated Financial Statements, and may apply to areas of relatively greater business importance.

The following accounting policies are critical to the Company’s Condensed Consolidated Financial Statements:

• Revenue recognition,

• Use of estimates,

• Business combination,

• Fair value measurement, and

• Impairment of long-lived assets.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis