Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ý  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2018
Or
¨  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Altus Midstream Company
(Exact name of registrant as specified in its charter)
Delaware
 
001-38048
 
81-4675947
(State or other jurisdiction of
incorporation)
 
(Commission File Number)
 
(I.R.S. Employer Identification
No.)
 
One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(address of principal executive offices)
 
(713) 296-6000
(Registrant’s telephone number, including area code)
Kayne Anderson Acquisition Corp.
811 Main Street, 14th Floor
Houston, Texas 77002
(Former name or former address, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act: 
Title of each class
  
Name of each exchange on which registered
Class A common stock, $0.0001 par value
  
NASDAQ Capital Market
Securities registered pursuant to Section 12(g)of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer ý Smaller reporting company ¨ Emerging growth company ý
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):   Yes ¨ No ý
The registrant’s common units were not publicly traded as of the last business day of the registrant’s most recently completed second fiscal quarter.
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2018
$
392,413,965

Number of shares of registrant’s Class A common stock, $0.0001 issued and outstanding as of January 31, 2019
74,929,305

Number of shares of registrant’s Class C common stock, $0.0001 issued and outstanding as of January 31, 2019

250,000,000


Documents Incorporated By Reference
Portions of registrant’s proxy statement relating to registrant’s 2019 annual meeting of stockholders have been incorporated by reference in Part II and Part III of this annual report on Form 10-K.



TABLE OF CONTENTS
 
Item
 
Page
 
PART I
 
 
 
 
1.
1A.
1B.
2.
3.
4.
 
 
 
 
PART II
 
 
 
 
5.
6.
7.
7A.
8.
9.
9A.
9B.
 
 
 
 
PART III
 
 
 
 
10.
11.
12.
13.
14.
 
 
 
 
PART IV
 
 
 
 
15.
16.
 


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FORWARD-LOOKING STATEMENTS AND RISK
This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, production and growth forecasts of Apache Corporation’s Alpine High field development and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:
the market prices of oil, natural gas, natural gas liquids (“NGLs”), and other products or services;
pipeline and gathering system capacity;
production rates, throughput volumes, reserve levels and development success of dedicated oil and gas fields;
economic and competitive conditions;
the availability of capital;
cash flow and the timing of expenditures;
capital expenditure and other contractual obligations;
weather conditions;
inflation rates;
the availability of goods and services;
legislative, regulatory, or policy changes;
terrorism or cyber attacks;
occurrence of property acquisitions or divestitures;
the integration of acquisitions;
a decline in oil, natural gas, and NGL production, and the impact of general economic conditions on the demand for oil, natural gas, and NGLs;
impact of environmental, health and safety, and other governmental regulations and of current or pending legislation;
environmental risks;
effects of competition;
our ability to retain key members of our senior management and key technical employees;
increases in interest rates;
our business strategy;
changes in technology;
the securities or capital markets and related risks such as general credit, liquidity, market, and interest-rate risks; and

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other factors disclosed under Item 1A — Risk Factors, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A — Quantitative and Qualitative Disclosures About Market Risk and elsewhere in this Form 10-K.
All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We disclaim any obligation to update or revise these statements unless required by securities law. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved.


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GLOSSARY OF TERMS

The following are abbreviations and definitions of certain terms used in this Annual Report on Form 10-K, and those which are commonly used in the exploration, production and midstream sectors of the oil and natural gas industry:
Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.
Bbl/d. One Bbl per day.
Bcf. One billion cubic feet of natural gas.
Btu. One British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Formation. A layer of rock which has distinct characteristics that differs from nearby rock.
MBbl. One thousand barrels of crude oil, condensate or NGLs.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. One Mcf per day.
MMBbl. One million barrels of crude oil, condensate or NGLs.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
NGLs. Natural gas liquids. Hydrocarbons found in natural gas, which may be extracted as liquefied petroleum gas and natural gasoline.
Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.



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PART I

ITEMS 1. and 2. BUSINESS AND PROPERTIES
Unless the context otherwise requires, “we,” “us,” “our,” the “Company,” “ALTM” and “Altus” refers to Altus Midstream Company and its consolidated subsidiaries. “Altus Midstream” refers to Altus Midstream LP and its consolidated subsidiaries.
Corporate History
We were originally incorporated on December 12, 2016 in Delaware under the name Kayne Anderson Acquisition Corp. (“KAAC”), for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. We completed our public offering in the second quarter of 2017, after which our securities began separate trading on the NASDAQ Capital Market.
On August 8, 2018, KAAC and our then wholly-owned subsidiary, Altus Midstream LP, a Delaware limited partnership, entered into a contribution agreement (the “Contribution Agreement”) with certain wholly-owned subsidiaries of Apache Corporation (“Apache”), including the Alpine High Entities. The Alpine High Entities comprise four Delaware limited partnerships (collectively, “Alpine High Midstream”) and their general partner (Alpine High Subsidiary GP LLC, a Delaware limited liability company), formed by Apache between May 2016 and January 2017 for the purpose of acquiring, developing, and operating midstream oil and gas assets in the Alpine High resource play and surrounding areas (“Alpine High”).
On November 9, 2018 (the “Closing Date”) and pursuant to the terms of that certain Contribution Agreement, we acquired from Apache the entire equity interests of the Alpine High Entities and options to acquire equity interests in five separate third-party pipeline projects (the “Pipeline Options”). We refer to the acquisition of the entities and the Pipeline Options as the “Business Combination.” In exchange, the consideration provided to Apache included economic voting and non-economic voting shares in KAAC, and limited partner interests in Altus Midstream.
Following the Closing Date and in connection with the closing of the Business Combination:
KAAC changed its name to Altus Midstream Company;
our wholly-owned subsidiary, Altus Midstream GP LLC, a Delaware limited liability company (“Altus Midstream GP”), is the sole general partner of Altus Midstream;
Altus Midstream Company holds a 23.1 percent controlling interest in Altus Midstream;
Altus Midstream Company operates its business through Altus Midstream and its subsidiaries, which include Alpine High Midstream; and
our Class A common stock, $0.0001 par value (“Class A Common Stock”), continued trading on the NASDAQ under the new symbol “ALTM.”
Whilst Altus (formerly KAAC) was the surviving legal entity, the Business Combination was accounted for as a reverse recapitalization. Under this method of accounting, Altus was treated as the acquired company for financial reporting purposes. As a result, the historical operations of Alpine High Midstream are deemed to be those of the Company. Thus, the financial statements and related information included in this Form 10-K reflect (i) the historical operating results of Alpine High Midstream prior to the Closing Date (ii) the net assets of Alpine High Midstream at their historical cost (iii) the consolidated results of Altus and Alpine High Midstream after the Closing Date and (iv) Altus’ equity structure for all periods presented.
For further information on our public offering, the Business Combination and our equity structure, refer to Note 2 —Recapitalization Transaction and Note 11 — Equity set forth in Part IV, Item 15 of this Form 10-K.
Business Overview
We have no independent operations or material assets outside our partnership interests in Altus Midstream, which we report on a consolidated basis. Our segment analysis and presentation is the same as that of Altus Midstream. Altus Midstream owns gas gathering, processing and transmission assets in the Permian Basin of West Texas, anchored by midstream service contracts to service Apache’s production from Alpine High. Additionally, we own, or have options to own, joint venture equity interests in a total of five Permian Basin pipelines, four of which go to various points along the Texas Gulf Coast, providing the Company with additional access to fully integrated, wellhead-to-water connectivity. All of these operations are organized into a single operating segment.

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Assets of Altus Midstream
As of December 31, 2018, Altus Midstream’s assets included approximately 111 miles of natural gas gathering pipelines, approximately 52 miles of residue gas pipelines with three market connections (with a fourth market connection expected to be in-service by the end of the first quarter of 2019), and approximately 26 miles of NGL Pipelines. Additionally, we own five rich gas processing facilities consisting of approximately 77,000 horsepower with 380 MMcf/d of rich gas processing capacity and two lean gas facilities consisting of 75,000 horsepower with 400 MMcf/d of lean gas treating capacity. Other assets include an NGL truck loading terminal with six lease automatic custody transfer (“LACT”) units and eight NGL bullet tanks with 90,000 gallon capacity per tank. Construction on the assets began in the fourth quarter of 2016, and operations commenced in the second quarter of 2017.
Joint Venture Equity Options
As part of the Business Combination, Apache contributed the Pipeline Options to Altus Midstream. The associated third-party pipeline projects are expected to be placed into service in 2019 and 2020, and each will be operated by third-party limited liability companies, as further described below. For a more in-depth discussion of the estimated capital resources, liquidity and timing associated with each joint venture equity option, please see Part II, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part IV, Item 15, Note 9 — Joint Venture Equity Interest, set forth in this Form 10-K.
Options Exercised
Gulf Coast Express Pipeline Project
On December 18, 2018 Altus Midstream exercised and closed the option with Kinder Morgan Texas Pipeline LLC (the “GCX Option”), thereby acquiring a 15 percent equity interest in the Gulf Coast Express Pipeline Project (“GCX”). Altus Midstream may acquire an additional 1 percent equity interest, provided that the Permian Highway Option has been exercised (as defined below) and certain other conditions are satisfied. This additional option expires in September 2019. GCX is a long-haul natural gas pipeline that, upon completion, is expected to have capacity of approximately 2.0 Bcf/d and will transport natural gas from the Waha area in northern Pecos County, Texas, to the Agua Dulce Hub near the Texas Gulf Coast. GCX will be operated by Kinder Morgan Texas Pipeline LLC and is expected to be operational and in-service in the fourth quarter of 2019.
EPIC Crude Oil Pipeline
In February 2019, Altus Midstream announced the exercise of the option with EPIC Pipeline LP (the “EPIC Option”) to acquire a 15 percent equity interest in the EPIC crude oil pipeline (the “EPIC Pipeline”). The transaction is anticipated to close in the first quarter of 2019.
Upon completion, the long-haul crude oil pipeline will extend from the Orla area in northern Reeves County, Texas to the Port of Corpus Christi, Texas, and is expected to have Permian Basin initial throughput capacity of approximately 590 MBbl/d. The project includes terminals in Orla, Pecos, Saragosa, Crane, Wink, Midland, Hobson and Gardendale, with Port of Corpus Christi connectivity and export access. It will service Delaware Basin, Midland Basin and Eagle Ford Shale production.
The EPIC Pipeline will be operated by EPIC Consolidated Operations, LLC (“EPIC”) and is expected to be in service in the first quarter of 2020.
Options Outstanding
Certain Pipeline Options have not yet been exercised. These options facilitate our participation in the following third-party pipeline projects:
Salt Creek NGL Pipeline;
Shin Oak Pipeline; and
Permian Highway Pipeline.
Salt Creek NGL Pipeline
We have an option to acquire a 50 percent equity interest in the Salt Creek NGL Pipeline - an intra-basin NGL pipeline. Upon completion, the pipeline is expected to be capable of transporting approximately 445 MBbl/d from our Diamond cryogenic processing complex in southwest Reeves County, Texas, and Salt Creek Midstream’s gas processing complex located in central Reeves County, Texas. The pipeline will transport NGLs to the Waha area in northern Pecos County, Texas, and will be operated by ARM Midstream Management LLC. It is expected to be operational and in service in the first quarter of 2019 and we expect

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to exercise this option in the fourth quarter of 2019 or the first quarter of 2020.
Shin Oak Pipeline
We have an option to acquire up to a 33 percent equity interest in the Shin Oak Pipeline, a long-haul NGL pipeline that, upon completion, is expected to be capable of transporting approximately 550 MBbl/d from the Orla area in northern Reeves County, Texas, through the Waha area in northern Pecos County, Texas, and on to Mont Belvieu, Texas. The Shin Oak Pipeline will be operated by Enterprise Products Operating LLC (“Enterprise Products”) and is expected to be operational and in service in the second quarter of 2019. We expect to exercise this option in the second half of 2019.
Permian Highway Pipeline
We have an option to acquire an approximate 27 percent equity interest in the Permian Highway Pipeline (the “Permian Highway Option”), a long-haul natural gas pipeline that, upon completion, is expected to have capacity of approximately 2.1 Bcf/d and will transport natural gas from the Waha area in northern Pecos County, Texas, to the Katy, Texas area, with connections to U.S. Gulf Coast and Mexico markets. The Permian Highway Pipeline will be operated by Kinder Morgan Texas Pipeline LLC and is expected to be operational and in service during the fourth quarter of 2020. We expect to exercise this option in the second half of 2019.
If the Permian Highway Pipeline is not placed into service, Apache will be required to assign to us the next option Apache executes for at least a 25 percent equity interest in an unidentified long-haul natural gas pipeline from the Permian Basin to the Texas Gulf Coast.
Altus’ Relationship with Apache
About Apache
Apache is an independent energy company that explores for, develops, and produces natural gas, crude oil, and NGLs. As a result of the Business Combination, Apache is the largest single owner of our voting common stock and also has an approximate 76.9 percent noncontrolling interest in Altus Midstream.
Additionally, as a result of the Business Combination, Apache received certain equity instruments, which may impact our ownership and the ownership interest of Altus Midstream’s limited partners. For further information on the consideration received by Apache, please refer to Note 2 — Recapitalization Transaction and Note 11 — Equity, within Part IV, Item 15 of this Form 10-K.
Apache’s Alpine High Resource Play
Our operated midstream infrastructure and facilities were built to service Apache’s production from Alpine High. Alpine High lies in the southern portion of the Delaware Basin, primarily in Reeves County, Texas. The play contains a vertical column up to 6,000 feet encompassing five geologic formations, with multiple target zones spanning the hydrocarbon phase window from dry gas to wet gas to oil. Apache has identified over 3,500 economic drilling locations in a wet gas play and over 1,000 locations in a dry gas play at Alpine High. Over the past year, Apache focused on transitioning to full-field development of the Alpine High play, optimizing spacing, patterns and completions, and building efficiencies to reduce drilling and lifting costs. During 2018, Apache drilled 100 wells at Alpine High with a 96 percent success rate, including many concept test wells drilled to verify its understanding of the play. Using data collected from strategic testing and delineation drilling, Apache is now optimizing wells drilled in Alpine High and focusing on rich gas development in 2019.
Apache has contracted takeaway capacity (through a combination of volume commitments and acreage/plant dedications) in the Permian Basin on the following third-party pipelines that are currently under construction and expected to be in operation in 2019 and 2020 as further described below:
(i)
550,000 dekatherms per day of residue gas for a 10-year term on the Gulf Coast Express Pipeline;
(ii)
500,000 dekatherms per day of residue gas for a 10-year term on the Permian Highway Pipeline;
(iii)
an acreage dedication of crude oil produced from Alpine High up to 75 MBbl/d of crude oil for a 10-year term on the EPIC Crude pipeline;
(iv)
an acreage dedication to transport NGLs produced from Alpine High to Waha for a 10-year term on the Salt Creek NGL Pipeline; and
(v)
an acreage dedication for a 10-year term on Enterprise Products’ Shin Oak NGL Pipeline to transport up to 205 MBbl/d of Alpine High produced NGLs from the Salt Creek NGL Pipeline terminus in Waha to Mont Belvieu.

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This takeaway capacity will allow greater flexibility and market optionality for Apache’s Permian Basin production, including increasing volumes from Alpine High.
Agreements with Apache
The Company and/or its consolidated subsidiaries have entered into certain agreements with Apache. Those material agreements are described in further detail below.
Midstream Service Agreements
Apache has been our only customer since operations commenced in the second quarter of 2017, although we are pursuing third-party business, which could be accommodated by existing and planned capacity. We have contracted to provide gas gathering, compression, processing, transportation, and NGL transportation services pursuant to acreage dedications provided by Apache, comprising the entire Alpine High acreage discussed above. Our revenues under these contracts are 100 percent fee-based, resulting in no direct commodity price exposure attributable to these contracts.
In addition, Apache agreed that any gas produced from Apache-operated wells located within the dedication area that is owned by other working interest owners and royalty owners is dedicated to us, so long as Apache has the right to market such gas. The agreements are effective for primary terms beginning on July 1, 2018 and ending March 31, 2032. The primary term will automatically extend for two five-year periods unless Apache provides at least nine months’ prior written notice of its election not to extend the primary term. The covenants under the agreements are intended to run with the land and will be binding on any transferee of the interests within the dedicated area.
Operational Services Agreement
Prior to the Business Combination, Apache provided operations, maintenance and management services to the Alpine High Entities, pursuant to an agreement hereby referred to as the “Services Agreement.” In accordance with the terms of that certain Services Agreement, Apache received a fixed fee per month for its overhead and indirect costs incurred on behalf of the Alpine High Entities. The Alpine High Entities had no banking or cash management activities prior to the Business Combination, and therefore all costs incurred by the Alpine High Entities were paid by Apache. In connection with the closing of the Business Combination, the Services Agreement was superseded by the COMA (as defined below).
Construction, Operations and Maintenance Agreement
In connection with the closing of the Business Combination, we entered into a construction, operations and maintenance agreement with Apache (the “COMA”), pursuant to which Apache will provide certain services related to the design, development, construction, operation, management and maintenance of our assets, on our behalf. The COMA supersedes the Services Agreement, discussed above.
Under the COMA, we will pay fees to Apache of (i) $3.0 million from November 9, 2018 through December 31, 2019, (ii) $5.0 million for the period of January 1, 2020 through December 31, 2020, (iii) $7.0 million for the period of January 1, 2021 through December 31, 2021 and (iv) $9.0 million annually, as may be increased thereafter until terminated. In addition, Apache may be reimbursed for certain internal costs and third-party costs incurred in connection with its role as service provider under the COMA.
The COMA will continue to be effective until terminated (i) upon the mutual consent of Altus and Apache, (ii) by either of Altus and Apache, at its option, upon 30 days’ prior written notice in the event Apache or an affiliate no longer owns a direct or indirect interest in at least 50 percent of the voting or other equity securities of Altus, or (iii) by Altus if Apache fails to perform any of its covenants or obligations due to willful misconduct of certain key personnel and such failure has a material adverse financial impact on Altus.
Purchase Rights and Restrictive Covenants Agreement
At the closing of the Business Combination, we and Apache entered into a purchase rights and restrictive covenants agreement (the “Purchase Rights and Restrictive Covenants Agreement”). Under the Purchase Rights and Restrictive Covenants Agreement, until the later of the five-year anniversary of the Closing and the date on which Apache and its affiliates cease to own a majority of our voting common stock, Apache is obligated to provide us with (i) the first right to pursue any opportunity (including any expansion opportunities) of Apache to acquire or invest, directly or indirectly (including equity investments), in any midstream assets or participate in any midstream opportunities located, in whole or part, within an area covering approximately 1.7 million acres in Reeves, Pecos, Brewster, Culberson and Jeff Davis Counties in Texas, and (ii) a right of first offer on certain retained midstream assets of Apache.

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Amended and Restated Agreement of Limited Partnership of Altus Midstream
At the closing of the Business Combination, the Company, Altus Midstream GP and Apache entered into the amended and restated limited partnership agreement of Altus Midstream (the “LPA”). Altus Midstream GP is the sole general partner of Altus Midstream and is ultimately responsible for all operational and administrative decisions of Altus Midstream including the day-to-day management of its business. Altus Midstream GP cannot be removed as the general partner of Altus Midstream except by its election and, subject to limited exceptions, may not transfer or assign its general partner interest. The LPA contains certain provisions intended to ensure that a one-to-one ratio is maintained, at all times and subject only to limited exceptions, between (i) the number of outstanding shares of our Class A Common Stock, and the number of common units held by us and (ii) the number of outstanding shares of Class C common stock $0.0001 par value (“Class C Common Stock”), and the number of common units held by Apache.
Lease Agreement
Concurrent with the closing of the Business Combination, Altus Midstream entered into an operating lease agreement with Apache, relating to the use of certain office buildings, warehouse and storage facilities located in Reeves County, Texas (the “Lease Agreement”). Under the terms of the Lease Agreement, Altus Midstream shall pay to Apache on a monthly basis the sum of (i) a base rental charge of $44,500 and (ii) an amount based on Apache’s estimate of the annual costs it shall incur in connection with the ownership, operation, repair, and/or maintenance of the facilities. Unpaid amounts accrue interest until settled. The initial term of the Lease Agreement is for four years and may be extended by Altus Midstream for three additional, consecutive periods of twenty-four months.
Title to Properties
Our interest in the real property on which our assets are located derives from leases, easements, rights-of-way, permits, or licenses from landowners or governmental authorities, permitting the use of such land for our operations. We believe that we have satisfactory interests in and to these lands. We have leased or acquired easements, rights-of-way, permits, or licenses in these lands without any material challenge known to us relating to the title to the land upon which our assets are located, and we believe that we have satisfactory interests in such lands. In certain situations, we elected to allow Apache to acquire easements, rights-of-way, permits, and licenses from landowners to expedite the build-out of midstream infrastructure. Other than the aforementioned Apache real property, we have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit, or license held by us or to our title to any material lease, easement, right-of-way, permit, or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits, and licenses.
Seasonality
While the results of gathering, processing, and transportation are not materially affected by seasonality, from time to time our operations and construction of assets can be impacted by inclement weather.
Competition
The business of providing gathering, compression, processing, and transportation services for natural gas and NGLs is highly competitive. We face strong competition in obtaining natural gas and NGL volumes, including from major integrated and independent exploration and production companies, interstate and intrastate pipelines, and other companies that gather, compress, treat, process, transport, or market natural gas and NGLs. Competition for supplies is primarily based on geographic location of facilities in relation to production or markets, the reputation, efficiency, and reliability of the midstream company, and the pricing arrangements offered by the midstream company. For areas where acreage is not dedicated to us, we will compete with similar enterprises in providing additional gathering, compression, processing, and transportation services in our area of operation.
Regulation
Natural Gas Pipeline Regulation
Intrastate transportation of natural gas is largely regulated by the state in which such transportation takes place. To the extent that an intrastate natural gas transportation system transports natural gas in interstate commerce, the rates, terms, and conditions of such services are subject to Federal Energy Regulatory Commission (“FERC”) jurisdiction under Section 311 of the Natural Gas Policy Act of 1978 (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates, terms, and conditions of some transportation services provided on our intrastate pipeline are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311 of the NGPA, rates charged for interstate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions for transportation service under Section 311 of the NGPA are also subject to FERC review and approval. Failure to observe the service limitations applicable to transportation services under Section 311 of the NGPA, failure to comply with the rates approved by the FERC for Section 311 of the NGPA service, and failure to comply with the terms

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and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil, and criminal remedies.

Intrastate natural gas operations in Texas are also subject to regulation by various agencies in Texas, principally the Railroad Commission of Texas (“RRC”). Our intrastate pipeline operations in Texas are also subject to the Texas Utilities Code and the Texas Natural Resources Code, as implemented by the RRC. Generally, the RRC is vested with authority to ensure that rates, operations, and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates charged for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or RRC complaint. Failure to comply with the Texas Utilities Code or the Texas Natural Resources Code can result in the imposition of administrative, civil, and criminal remedies.
Natural Gas Gathering Regulation
Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of the FERC. It
is our belief that our natural gas pipeline system meets the traditional tests the FERC has used to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and varying interpretations, so the classification and regulation of our natural gas pipeline system could be subject to change based on future determinations by the FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
In Texas, our natural gas pipeline system is subject to regulation by the RRC under the Texas Utilities Code and the Texas Natural Resources Code in the same manner as described above for intrastate pipeline transportation facilities. Our natural gas pipeline system is also subject to state ratable take and common purchaser statutes in Texas. The ratable take statute generally requires gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, the common purchaser statute generally requires gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.
Natural Gas Liquids Pipeline Regulation
Transportation services rendered by us are subject to the regulation of the RRC. The RRC has the authority to regulate our rates, though it generally has not investigated the rates or practices of intrastate pipelines in the absence of shipper complaints.
Employee Safety
We comply with the requirements of the Occupational Safety and Health Administration (“OSHA”) and comparable state laws that regulate the protection of the health and safety of workers. In addition, with respect to OSHA hazard communication standards, we believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, hazard communication, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Pipeline Safety Regulations

Some of our pipelines are subject to regulation by the U.S. Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), with respect to NGLs. Both the NGPSA and the HLPSA were amended by the Pipeline Safety Act, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“ 2011 Pipeline Safety Act”), and the Pipelines and Enhancing Safety Act of 2016. The NGPSA and HLPSA regulate safety requirements in the design, construction, operation, and maintenance of natural gas, crude oil, and NGL pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. crude oil, NGL, and natural gas transmission pipelines in high consequence areas (“HCAs”).
PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators to, among other things:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a HCA;

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improve data collection, integration, and analysis;
repair and remediate pipelines as necessary; and
implement preventive and mitigating actions.
The 2011 Pipeline Safety Act, among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, and testing to confirm the material strength of pipe operating above 30 percent of specified minimum yield strength in HCAs. Consistent with the act, PHMSA finalized rules that increased the maximum administrative civil penalties for violation of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2.0 million for a series of violations. Effective April 27, 2017, those maximum civil penalties were increased to $209,002 per violation per day, with a maximum of $2.09 million for a series of violations, to account for inflation. PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations.
PHMSA regularly revises its pipeline safety regulations. For example, in March 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. Subsequently, in October 2015, PHMSA proposed new regulations for hazardous liquid pipelines that would significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection, and repairs), regardless of the pipeline’s proximity to a HCA. The proposal also requires new reporting requirements for certain unregulated pipelines, including all gathering lines. Additional future regulatory action expanding PHMSA jurisdiction and imposing stricter integrity management requirements is likely. For example, in December 2015, the Senate Commerce Committee approved legislation that, among other things, requires PHMSA to conduct an assessment of its inspections process and integrity management programs for natural gas and hazardous liquid pipelines. The legislation would also require PHMSA to prioritize various rulemakings required by the 2011 Pipeline Safety Act and propose and finalize the rules mandated by the act. In April 2016, pursuant to one of the requirements of the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated gas transmission pipelines. The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits, and other requirements.
In addition, on January 13, 2017, PHMSA issued a pre-publication final rule that included new hazardous liquid pipeline safety regulations extending certain regulatory reporting requirements to all hazardous liquid gathering (including oil) pipelines. The final rule required additional event-driven and periodic inspections, required the use of leak detection systems on all hazardous liquid pipelines, modified repair criteria, and required certain pipelines to eventually accommodate in-line inspection tools. However, on January 24, 2017, PHMSA withdrew the final rule for further review in compliance with a regulatory freeze implemented by the Trump Administration on January 20, 2017.
On January 23, 2017, PHMSA published in the Federal Register amendments to the pipeline safety regulations to address requirements of the 2011 Pipeline Safety Act and to update and clarify certain regulatory requirements regarding notifications of accidents and incidents. The final rule also adds provisions for cost recovery for design reviews of certain new projects, renews existing special permits, and incorporates certain standards for in-line inspections and stress corrosion cracking assessments. The effective date of the final rule would have been March 24, 2017; however, the rule was also subject to the regulatory freeze implemented by the Trump Administration. PHMSA recently announced its intention to reissue both rules, with certain changes, in 2019.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We believe that our pipeline operations are in substantial compliance with applicable PHMSA and state requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our financial condition, results of operations, or cash flows.

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Environmental Matters
General
Many of the operations and activities of our pipelines, gathering systems, processing plants, and other facilities are subject to significant federal, state, and local environmental laws and regulations, the violation of which can result in administrative, civil, and criminal penalties, including civil fines, injunctions, or both. Compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including costs of planning, constructing, and operating plants, pipelines, and other facilities, as well as capital expenditures necessary to maintain or upgrade equipment and facilities. Similar costs are likely upon changes in laws or regulations and upon any future acquisition of operating assets.
Any failure to comply with applicable environmental laws and regulations, including those relating to equipment failures, and obtaining required governmental approvals, may result in the assessment of administrative, civil, or criminal penalties, imposition of investigatory or remedial activities and, in certain less common circumstances, issuance of temporary or permanent injunctions or construction or operation bans or delays. We regularly evaluate our operations and routinely review and update governmental approvals as necessary.
The continuing trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and, thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. Moreover, risks of process upsets, accidental releases, or spills are associated with possible future operations, and we cannot assure you that we will not incur significant costs and liabilities, including those relating to claims for damage to property and persons as a result of any such upsets, releases, or spills. We may be unable to pass on current or future environmental costs to our customers. A discharge or release of hydrocarbons, hazardous substances, or solid wastes into the environment could, to the extent losses related to the event are not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and to pay fines or penalties that may be assessed and the cost related to claims made by neighboring landowners and other third-parties for personal injury or damage to natural resources or property.
We believe that our operations are in substantial compliance with applicable environmental regulations, and we attempt to anticipate future regulatory requirements that might be imposed and plan accordingly. While any new or amended laws and regulations or reinterpretation of existing laws and regulations would not be expected to be any more burdensome to us than to other, similarly situated operators, there can be no assurance that future compliance with any new environmental requirements will not have an adverse effect on our financial condition, results of operations or cash flows.
Hazardous Substances and Solid Waste
Environmental laws and regulations that relate to the release of hazardous substances or solid wastes into soils, sediments, groundwater, and surface water and/or include measures to prevent and control pollution may pose the highest potential cost. These laws and regulations generally regulate the generation, storage, treatment, transportation, and disposal of solid wastes and hazardous substances and may require investigatory and corrective actions at facilities where such waste or substance may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the federal “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. Potentially responsible persons include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at an off-site location, such as a landfill. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek recovery of costs they incur from the potentially responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or solid wastes released into the environment. Although petroleum, natural gas, and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of ordinary operations, we may generate wastes that may fall within the definition of a “hazardous substance.” In addition, there are other laws and regulations that can create liability for releases of petroleum, natural gas, or NGLs. Moreover, we may be responsible under CERCLA or other laws for all or part of the costs required to clean up sites at which such substances have been released or disposed. We have not received any notification that the Company may be potentially responsible for cleanup costs under CERCLA or any analogous federal, state, or local law.

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We also generate, and may in the future generate, both hazardous and nonhazardous solid wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and/or comparable state statutes. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil, condensate, and natural gas wastes. Moreover, it is possible that some wastes we generate that are currently exempted from the definition of hazardous waste may in the future lose this exemption and be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Additionally, the Toxic Substances Control Act (“TSCA”) and analogous state laws impose requirements on the use, storage, and disposal of various chemicals and chemical substances. Changes in applicable laws or regulations may result in an increase in our capital expenditures or plant operating expenses or otherwise impose limits or restrictions on its production and operations.
Solid waste disposal practices within the oil, natural gas and NGL industries have improved over the years with the passage and implementation of various environmental laws and regulations. While we are not aware of any significant releases of hydrocarbons or other solid wastes on or under the various properties owned, leased, or operated by us, such releases may nevertheless have occurred during the prior operating history of those properties. In addition, a number of these properties may have been operated by third parties over whose operations and hydrocarbon and waste management practices we had no control. These properties and any wastes disposed thereon may be subject to the Safe Drinking Water Act, CERCLA, RCRA, TSCA, and analogous state laws. Under these laws, we could be required, alone or in participation with others, to remove or remediate previously disposed wastes or property contamination, if present, including groundwater contamination, or to take action to prevent future contamination.
Air Emissions
Our current and future operations are subject to the Clean Air Act (“CAA”) and regulations promulgated thereunder and under comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and impose various control, monitoring, and reporting requirements. Pursuant to these laws and regulations, we may be required to obtain environmental agency pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions, obtain and comply with the terms of air permits, which include various emission and operational limitations, or use specific emission control technologies to limit emissions. We likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air emission-related issues. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil, or criminal penalties and may result in the limitation or cessation of construction or operation of certain air emission sources or require us to incur additional capital expenditures. Although we can give no assurances, we believe such requirements will not have a material adverse effect on our financial condition, results of operations, or cash flows, and the requirements are not expected to be more burdensome to us than to any similarly situated company.
Effective May 15, 2012, the EPA promulgated rules under the CAA that established new air emission controls for oil and natural gas production, pipelines, and processing operations under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) programs. These rules require the control of emissions through reduced emission (or “green”) completions and establish specific new requirements regarding emissions from wet seal and reciprocating compressors, pneumatic controllers, and storage vessels at production facilities, gathering systems, boosting facilities, and onshore natural gas processing plants. In addition, the rules revised existing requirements for volatile organic compound (“VOC”) emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million and requiring the monitoring of connectors, pumps, pressure relief devices, and open-ended lines. In October 2012, several challenges to the EPA’s NSPS and NESHAPs rules for the industry were filed by various parties, including environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. The case remains in abeyance. The EPA has since revised certain aspects of the rules and has indicated that it may reconsider other aspects of the rules. Depending on the outcome of such proceedings, the rules may be further modified or rescinded or the EPA may issue new rules. The Company cannot predict the costs of compliance with any modified or newly issued rules.
In partial response to the issues raised regarding the 2012 rulemaking, the EPA published new rules in June 2016 to regulate emissions of methane and VOCs from new and modified sources in the oil and gas sector. However, in April 2017, the EPA announced that it will review this rule for new, modified, or reconstructed facilities and will initiate reconsideration proceedings to potentially revise or rescind portions of the rule. Subsequently, on May 31, 2017, the EPA issued a 90-day stay of certain requirements under the rule, but this stay was vacated by a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit on July 3, 2017 and again by an en banc D.C. Circuit on July 31, 2017. In the interim, on July 16, 2017, the EPA issued a proposed rule that would provide a two-year extension of the initial 90-day stay, but the proposed rule was never finalized. Instead, in February 2018, the EPA finalized amendments to some of the requirements, although the EPA’s reconsideration of other aspects of the rule is ongoing. Substantial uncertainty exists with respect to implementation of this methane rule. The EPA has also finalized

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a rule regarding alternative criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements across the oil and gas industry. During the Obama Administration, other federal agencies, including the Bureau of Land Management (“BLM”), PHMSA, and the Department of Energy, proposed or finalized new or more stringent regulations for the oil and gas sector in order to further reduce methane emissions. For example, the BLM adopted new rules on November 15, 2016, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. On June 15, 2017, the BLM postponed indefinitely compliance dates for certain aspects of these rules, pending judicial review, but a court subsequently enjoined the postponement. In February 2018, the BLM proposed to repeal certain of the requirements of the 2016 methane rule. Several states filed judicial challenges to the BLM’s proposed repeal. In April 2018, a federal court stayed the litigation pending finalization or withdrawal of the BLM’s February 2018 proposal. As a result of this continued regulatory focus and other factors, additional air emissions regulation of the oil and gas industry remains possible. Compliance with such rules could result in additional costs, including increased capital expenditures and operating costs for us and for other companies in its industry. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, such costs could be significant. Compliance with such rules, as well as any new state rules, may also make it more difficult for our suppliers and customers to operate, thereby reducing the volume of natural gas transported through our pipelines, which may adversely affect our business.
Climate Change

In December 2009, the EPA determined that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”) (which include methane, the major component of natural gas), present an endangerment to public health and the environment based on a conclusion that emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that emit GHGs. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore crude oil and natural gas production sources in the U.S. on an annual basis. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Because regulation of GHG emissions is relatively new, further regulatory, legislative, and judicial developments are likely to occur. Such developments in GHG initiatives may affect us and other companies operating in the oil and gas industry. In addition to these developments, certain tort claims alleging property damage have been brought against GHG emissions sources, which may increase our litigation risk for such claims. In addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement entered into force November 4, 2016, and requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. On June 1, 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or to establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments.
Federal or state legislative or regulatory initiatives that regulate or restrict emissions of GHG in areas in which we conduct business could adversely affect the availability of, or demand for, the products we store, transport, and process and, depending on the particular program adopted, could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions, and/or administer and manage a GHG emissions program. We may be unable to recover any such lost revenues or increased costs in the rates we charge our customers, and any such recovery may depend on events beyond our control, including the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial condition, results of operations, or cash flows.
Hydraulic Fracturing and Wastewater
The Federal Water Pollution Control Act (the “CWA”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including NGL-related wastes, into state waters or waters of the United States. In June 2015, the EPA and the United States Army Corps of Engineers (the “Army Corps”) finalized a rule intended to clarify the meaning of the term “waters of the United States,” which establishes the scope of regulated waters under the CWA (the “WOTUS rule”). The rule has been challenged and was stayed by federal courts. In February 2017, the Trump Administration issued an Executive Order

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directing the EPA and the Army Corps to review and, consistent with applicable law, to initiate a rulemaking to rescind or revise the WOTUS rule. The EPA and the Army Corps published a notice of intent to review and rescind or revise the rule in March 2017. In addition, the U.S. Department of Justice filed a motion with the U.S. Supreme Court in March 2017 requesting that the U.S. Supreme Court stay the suit concerning which court should hear challenges to the rule. The U.S. Supreme Court denied the motion in April 2017. In June 2017, the EPA and the Army Corps proposed a rule that would initiate the first step in a two-step process intended to review and revise the definition of “waters of the United States” consistent with President Trump’s executive order. Under the proposal, the first step would be to rescind the May 2015 final rule and put back into effect the narrower language defining “waters of the United States” under the CWA that existed prior to the WOTUS rule. The second step would be a notice-and- comment rulemaking in which the agencies will conduct a substantive reevaluation of the definition of “waters of the United States”. If upheld, the WOTUS rule will expand federal jurisdiction under the CWA and could significantly expand federal control of land and water resources across the U.S., triggering substantial additional permitting and regulatory requirements. Regulations promulgated pursuant to the CWA require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System permits and/or state permits authorizing these discharges. The CWA and analogous state laws assess administrative, civil, and criminal penalties for discharges of unauthorized pollutants into waters of the U.S. and impose substantial liability for the costs of removing spills from such waters. In addition, the CWA and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that we are in substantial compliance with CWA permitting requirements as well as the conditions imposed by our permits and that continued compliance with such existing permit conditions will not have a material effect on financial condition, results of operations, or cash flows.
It is common for our customers or suppliers to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is an important and commonly used process in the completion of wells by oil and gas producers. Hydraulic fracturing involves the injection of water, sand, and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states and localities have been initiated to require or make more stringent the permitting and other regulatory requirements for hydraulic fracturing operations of our customers and suppliers. There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, concluding that there is scientific evidence that hydraulic fracturing activities potentially can impact drinking water resources in the United States under some circumstances. This study or similar studies could spur initiatives to further regulate hydraulic fracturing. In June 2016, the EPA finalized rules prohibiting discharges of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants, but, in October 2017, the U.S. Court of Appeals for the Third Circuit granted an EPA petition for voluntary remand. The rule is currently under review. The EPA has also issued an advance notice of proposed rulemaking under the TSCA to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. Also, effective June 24, 2015, BLM adopted rules regarding well stimulation, chemical disclosures, water management, and other requirements for hydraulic fracturing on federal and Indian lands, which the BLM subsequently repealed in December 2017. The BLM’s repeal has been challenged in court.
Additional regulatory burdens in the future, whether federal, state, or local, could increase the cost of or restrict the ability of our customers or suppliers to perform hydraulic fracturing. As a result, any increased federal, state, or local regulation could reduce the volumes of crude oil and natural gas that our customers move through our gathering and processing systems, which would materially adversely affect our financial condition, results of operations, or cash flows.
Endangered Species and Migratory Birds
The Endangered Species Act of 1973 (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act of 1918 (“MBTA”). Some of Altus Midstream’s pipelines may be located in areas that are designated as habitats for endangered or threatened species or flightways for migratory birds, potentially exposing it to liability for impacts on an individual member of a species or to habitat. The ESA can also make it more difficult to secure a federal permit for a new pipeline.
As a result of a 2011 settlement agreement, the U.S. Fish and Wildlife Service (“FWS”) is required to make a determination on listing of numerous species as endangered or threatened under the ESA. The FWS agreed to complete the review by the end of the agency’s 2017 fiscal year. The agency missed the deadline but continues to review species for listing under the ESA. On July 19, 2018, the FWS announced a series of proposed changes to the rules implementing the ESA, including proposed revisions to the regulations governing interagency cooperation, listing species and delisting critical habitat, and prohibitions related to threatened wildlife and plants. The proposed revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions. It is not possible at this time to accurately predict how such changes, if adopted, would impact our operations. For more information, please read Item 1A — Risk Factors of this Form 10-K.

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In addition, the federal government recently has issued indictments under the MBTA to several oil and natural gas companies after migratory birds were found dead near their operations. However, in December 2017, the U.S. Department of the Interior issued a new opinion revoking its prior enforcement policy and concluded that an incidental take is not a violation of the MBTA.
Emerging Growth Company Status
We are an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the Jumpstart Our Business Startups (“JOBS”) Act. As such, we are eligible to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the independent registered public accounting firm attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a non-binding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. If some investors find our securities less attractive as a result, there may be a less active trading market for our securities and the prices of our securities may be more volatile.
In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We do not intend to take advantage of the benefits of this extended transition period.
We will remain an emerging growth company until the earlier of (1) the last day of the fiscal year (a) following the fifth anniversary of the completion of our initial public offering, (b) in which we have total annual gross revenue of at least $1.07 billion, or (c) in which we are deemed to be a large accelerated filer, which means the market value of our Class A Common Stock that is held by non-affiliates exceeds $700.0 million as of the prior June 30th, and (2) the date on which we have issued more than $1.0 billion in non-convertible debt securities during the prior three-year period.
Employees
We have no employees. Per the terms of the COMA, Apache will operate, maintain and administer our operations, and Apache will also provide management services.
Offices
We do not own any real estate or other physical properties materially important to our operation. Our executive office is located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. Concurrent with the closing of the Business Combination, Altus Midstream entered into the Lease Agreement with Apache, relating to the use of certain office buildings, warehouse and storage facilities located in Reeves County, Texas. Under the terms of the Lease Agreement, Altus Midstream shall pay to Apache on a monthly basis the sum of (i) a base rental charge of $44,500 and (ii) an amount based on Apache’s estimate of the annual costs it shall incur in connection with the ownership, operation, repair, and/or maintenance of the facilities. Unpaid amounts accrue interest until settled. The initial term of the Lease Agreement is for four years and may be extended by Altus Midstream for three additional, consecutive periods of twenty-four months.


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ITEM 1A. RISK FACTORS 

RISK FACTORS
The following risk factors apply to our business and operations. These risk factors are not exhaustive and investors are encouraged to perform their own investigation with respect to our business, financial condition and prospects. You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K, including matters addressed in the section entitled “Forward-Looking Statements and Risk.” We may face additional risks and uncertainties that are not presently known to us, or that we currently deem immaterial, which may also impair our business or financial condition. The following discussion should be read in conjunction with our financial statements and notes to the financial statements included herein.
Risks Related to the Business of Altus Midstream

Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Additional risks relating to our securities may be included in the prospectuses for securities we issue in the future.
We derive a substantial portion of our revenue from Apache, and our plans for growth will heavily depend on Apache’s growth in Alpine High. If Apache changes its business strategy in Alpine High, alters its current drilling and development plan on acreage dedicated to us, or otherwise significantly reduces the volumes of natural gas or NGLs with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, and cash flows would be materially and adversely affected.
All of our current commercial agreements are with Apache, and, as a result, we derive substantially all of our revenue from Apache. Going forward, we expect Apache to be a significant driver of any growth in our revenue. Accordingly, we will be subject to the operational and business risks of Apache, the most significant of which include the following:
a reduction in or slowing of Apache’s drilling and development plans for the acreage dedicated to the Company, which would directly and adversely impact demand for our midstream services;
the price, and the volatility of the price, of crude oil, natural gas, and NGLs, which could have a negative effect on Apache’s drilling and development plans for the acreage dedicated to the Company or Apache’s ability to finance its operations and drilling and completion costs relating to the acreage dedicated to us;
the availability of capital on an economic basis to fund Apache’s exploration and development activities;
drilling and operating risks, including potential environmental liabilities, associated with Apache’s operations on the acreage dedicated to the Company;
downstream processing and transportation capacity constraints and interruptions, including the failure of Apache to have sufficient contracted transportation capacity; and
adverse effects of increased or changed governmental and environmental regulation or enforcement of existing regulation.

In addition, we will be indirectly subject to the business risks of Apache generally and other factors, including, among others:
Apache’s financial condition, credit ratings, leverage, market reputation, liquidity, and cash flows;
Apache’s ability to maintain or replace its reserves;
adverse effects of governmental and environmental regulation on Apache’s upstream operations; and
losses, if any, from Apache’s pending or future litigation.

Further, we do not have control over Apache’s business decisions and operations, and Apache is under no obligation to adopt a business strategy that is favorable to us. For example, Apache may decide to allocate capital that we expect to be spent in Alpine High to other parts of its business. Thus, we will be subject to the risk of cancellation of planned development, nonperformance of commitments with respect to future dedications, and other nonpayment or nonperformance by Apache, including with respect to our commercial agreements, which do not contain minimum volume commitments. Furthermore, we cannot predict the extent to which Apache’s businesses would be impacted if conditions in the energy industry were to deteriorate nor can we estimate the

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impact such conditions would have on Apache’s ability to execute its drilling and development plan on the acreage dedicated to the Company or to perform under our commercial agreements. Any material nonpayment or nonperformance by Apache under our commercial agreements would have a significant adverse impact on our business, financial condition, results of operations, and cash flows.
The long-term commercial agreements between the Company and Apache have initial terms of approximately 14 years, through March 31, 2032, which may be extended by Apache for two five-year periods. There is no guarantee that Apache will extend these agreements beyond the initial terms or that we will be able to renew or replace these agreements on equal or better terms, or at all, upon their expiration. Our ability to renew or replace these commercial agreements following their expiration at rates sufficient to maintain the current revenues and cash flows of the Company could be adversely affected by activities beyond our control, including the activities of our competitors and Apache.
In addition to our commercial agreements with Apache, we may engage in significant business with new third-party customers or enter into material commercial contracts with customers with whom we do not have material commercial arrangements or commitments today and who may not have investment grade credit ratings. To the extent the Company derives substantial income from, or commits to capital projects to service, new or existing customers, each of the risks indicated above would apply to such arrangements and customers.
Because we have a limited operating history and have generated minimal revenues and operating cash flows, it may be difficult to evaluate our business and ability to successfully implement our business strategy.
Because of the Company’s limited operating history, the operating performance of our assets and business strategy are not yet proven. Construction of our midstream assets began in the fourth quarter of 2016, and the Company has only generated minimal revenues and operating cash flows since such time. As a result, it may be difficult for you to evaluate the Company’s business and results of operations to date and to assess our future prospects.
In addition, we may encounter risks and difficulties experienced by companies whose performance is dependent upon newly constructed assets, such as our assets failing to function as expected, higher than expected operating costs, equipment breakdown or failures, and operational errors. We may be less successful in achieving a consistent operating level capable of generating cash flows from our operations as compared to a company whose major assets have had longer operating histories. In addition, we may be less equipped to identify and address operating risks and hazards in the conduct of our business than those companies whose major assets have had longer operating histories.
If we are unable to exercise the outstanding joint venture equity options on economically acceptable terms, our future growth will be limited.
Our growth strategy includes acquiring joint venture equity interests in or benefiting from certain midstream pipeline projects pursuant to the options contributed by Apache as part of the Business Combination. If the Company is unable to exercise one or more of the options, either because we do not have adequate funds available or we are unable to obtain financing to fund the applicable exercise price on economically acceptable terms or at all, then our future growth will be limited.
In addition, from time to time, we may evaluate and seek to acquire assets or businesses that we believe complement our existing business and related assets. We may acquire assets or businesses that we plan to use in a manner materially different from their prior owners’ uses. Any acquisition involves potential risks, including:
the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;
the failure to realize expected volumes, revenues, profitability, or growth;
the failure to realize any expected synergies and cost savings;
the coordination of geographically disparate organizations, systems, and facilities;
the assumption of unknown liabilities;
the loss of customers or key employees from the acquired businesses; and
potential environmental or regulatory liabilities and title problems.


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Any assessment of these risks will be inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect our financial condition, results of operations, and cash flows. If we consummate any future acquisition, our capitalization and results of operations may change significantly.
We own or operate a portion of our business with one or more joint venture partners or in circumstances where we are not the operator, which may restrict our operational and corporate flexibility; actions taken by other partners or third-party operators may materially impact our financial position and results of operations, and we may not realize the benefits we expect to realize from a joint venture.
As is common in the midstream industry, we own or operate one or more of our properties with one or more joint venture partners, or contract with a third-party to control operations. These relationships require us to share operational and other control, or to defer to another party’s control, such that we do not have the flexibility to control the development of these properties. If we do not timely meet our financial commitments in such circumstances, our rights to participate may be adversely affected. If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator does not operate in accordance with our expectations, our costs of operations could be increased. We could also incur liability as a result of actions taken by a joint venture partner or third-party operator. Disputes between us and the other party or parties in a joint venture may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.
If we are unable to exercise the outstanding joint venture equity options as planned, or if any of the underlying pipelines experience cost overruns or do not generate the cash flows we expect after we exercise, our plans for growth will be impaired.
Our strategy to grow our business depends in part on our ability to exercise the outstanding joint venture equity options, and we can offer no assurance that we will be able to exercise the outstanding options or that, for those that have been, or will be exercised, we will be able to finance the acquisition of the underlying interests in the applicable pipelines or that those pipelines will perform as expected. Our joint venture equity interests and options pertain to pipelines that are either under construction or have not yet commenced construction. The outstanding options have conditions precedent that must be satisfied before we can exercise, some of which are outside of our control. The obligations of each of the parties to close on the exercise of the applicable option are conditioned on (i) no proceeding having been instituted that seeks to restrain, enjoin, or otherwise prohibit or make illegal the closing of such option and (ii) the exercise price having been determined in accordance with the terms of the agreement regarding such option (together, the “Option Closing Conditions”). In addition:
The obligations of each of the parties to close on the exercise of the Shin Oak Option are conditioned on (i) the NGL purchase agreement between Apache and Enterprise Products Operating LLC not being terminated and (ii) Apache not being in material breach of any provision of such NGL purchase agreement that has not been cured within the periods specified by such NGL purchase agreement.
The obligation of each of the parties to close on the exercise of the additional 1 percent GCX Option is conditioned on the unanimous approval of the members of Gulf Coast Express Pipeline LLC and the waiver of the preferential purchase rights of such members with respect to the equity interest associated with the additional 1 percent GCX Option. The obligation of Kinder Morgan Texas Pipeline LLC to close on the exercise of the additional 1 percent GCX Option is conditioned on (i) the exercise of the GCX Option in full and (ii) the exercise of the Permian Highway Option in full and, following such exercise of the Permian Highway Option, us holding less than 30 percent of the equity interests in the joint venture operator of the pipeline. In addition, the additional 1 percent GCX Option will terminate automatically upon the termination of certain transaction agreements between Apache and Gulf Coast Express Pipeline LLC.
The Permian Highway Option will terminate automatically upon the termination of any of the transportation agreements between Apache and Permian Highway Pipeline LLC.

There are no additional obligations of any of the parties to the Salt Creek NGL Pipeline Option to close other than the Option Closing Conditions. As described above, some of such conditions precedent are within the control of Apache, and we will have no ability to ensure Apache’s satisfaction of such conditions precedent. If applicable pipelines do not perform as expected, we may experience losses in relation to our joint venture equity interests or the outstanding options (if exercised).
In addition, each of the pipelines is subject to risks associated with construction delays, cost over-runs, operational hazards, environmental matters, regulatory matters, and legal matters, as well as other risks and uncertainties, many of which are beyond the control of the operator of the pipeline. If any of these risks were to materialize, our financial condition, results of operations, and cash flows could be adversely affected.

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If we exercise the outstanding options, we will be required to make significant capital contributions to the owners of the pipelines for our share of the capital expenditures spent through the date of exercise and may, from time to time, have to make additional capital contributions, both of which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
We currently own non-operating interests in certain joint ventures, and may own additional non-operating interests in joint ventures, if we are able to exercise the outstanding options. We will be required to contribute our share of the capital expenditures spent through the date of exercise, including any financing charges for certain of the outstanding options associated with our proportionate share of such capital prior to exercising the applicable option. Thereafter, we will also be required to fund our share of any remaining capital expenditures required to complete construction of the applicable pipeline. Once a pipeline is operational, as a non-operating, minority owner, we will have limited or no control over decisions to make maintenance and capital expenditures on the pipeline. To the extent that the operator of one of the pipelines decides to make additional capital expenditures for the pipeline, we could be required to contribute additional capital to maintain our ownership interest, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
We do not have any employees and rely entirely on services provided by Apache’s employees.
The Company does not have any employees and relies on Apache’s employees. We will rely on Apache’s employees to conduct our business and activities pursuant to the COMA. Apache conducts businesses and activities of its own in which we will not have an economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to us and Apache. If Apache’s employees who provide services to us do not devote sufficient attention to the management and operation of our business and activities, our business, financial condition, results of operations, and cash flows could be materially and adversely affected.
The COMA is subject to termination by us or Apache under certain circumstances, including if Apache and its affiliates no longer own a direct or indirect interest in at least 50 percent of the voting or other equity securities of the Company. Should the COMA be terminated by us or Apache, we will be required to attract and hire employees to perform the services currently performed by Apache’s employees under the COMA or otherwise contract with third parties for the provision of such services, which, in either case, could subject us to substantial additional costs, could cause significant disruptions to our business, may be on terms less favorable than the terms of the COMA, and, as a result, our financial condition, results of operations, and cash flows could be adversely affected.
The services that the Company offers require laborers skilled in multiple disciplines, such as equipment operators, mechanics, and engineers, among others. In the event that the COMA is terminated and the Company is required to attract and hire employees, our business will be dependent on our ability to recruit, retain, and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor, or the unavailability of contract resources, may lead to operating challenges, such as a lack of resources, loss of knowledge, or a lengthy time period associated with skill development. Our costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate our business. If the Company is unable to successfully attract and retain an appropriately qualified workforce, our financial condition, results of operations, or cash flows could be adversely affected.
Our executive officers and directors may face potential conflicts of interest in managing our business.
Our executive officers and certain directors are also officers or employees of Apache. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our stockholders’ best interests. In addition, these overlapping executive officers and directors allocate their time among us and Apache. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations, and financial condition.
All of our gathering and processing operations are located in Alpine High, making us vulnerable to risks associated with having revenue-producing operations concentrated in one geographic area.
Our revenue-producing operations are geographically concentrated in Alpine High of the Southern Delaware Basin of West Texas, causing us to be disproportionately exposed to risks associated with regional factors. The concentration of the Company’s operations in this region increases our exposure to unexpected events that may occur in this region, such as natural disasters. Furthermore, the Company may be exposed to increases in costs as a result of regional economic conditions and availability of goods and services. For example, we are relying on temporary power sources until local utilities can install permanent power. If

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availability of permanent power from local service providers is delayed, the Company’s results of operations could be adversely impacted. In addition, the Company relies on the availability of a skilled labor force, which could become more expensive (or at certain times, unavailable) if the labor market in the Permian Basin continues to tighten. Any one of these events has the potential to have a significant adverse impact on the Company’s operations and growth plans, decrease cash flows, increase operating and capital costs, and prevent development within originally anticipated time frames. Any of these risks could adversely affect our financial condition, results of operations, or cash flows.
We are dependent on the supply of natural gas and NGLs to our system, and any decrease in the supply of such commodities could adversely affect our financial condition, results of operations, or cash flows.
We currently generate all of our revenues under agreements with Apache’s upstream development located in Alpine High. None of these agreements contain minimum volume commitments, and, therefore, the Company’s cash flows will completely depend upon the volumes Apache produces in Alpine High for so long as Apache is our sole customer. Further, the Company may not be able to obtain additional contracts for natural gas and NGL supplies. If the Company is unable to maintain or increase the volumes on our system by accessing new supplies to offset the natural decline in our customers’ reserves, our business and financial results could be adversely affected. In addition, the Company’s future growth will depend in part upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our current supplies.
Fluctuations in energy prices can greatly affect production rates and investments by Apache and third parties in the development of new crude oil and natural gas reserves. We could see downward pressure on future drilling activity in Alpine High if commodity prices decline below current levels, which may result in lower volumes. Tax policy changes or additional regulatory restrictions on development could also have a negative impact on drilling activity, reducing supplies of product available to the Company’s system and assets. We have no control over Apache or other producers and depend on them to maintain sufficient levels of drilling activity. An ongoing decrease in the level of drilling activity or a material decrease in production in the Company’s area of operation for a prolonged period, as a result of continued depressed commodity prices or otherwise, would adversely affect our financial condition, results of operations, and cash flow.
If third-party pipelines or other facilities interconnected to our midstream systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations and cash flows could be adversely affected.
Our midstream systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport, treat or process natural gas and/or NGLs, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, and cash flows could be adversely affected.
Any decrease in the volumes that we gather, process, or transport would adversely affect our financial condition, results of operations, or cash flows.
The Company’s financial performance depends to a large extent on the volumes of natural gas and NGLs gathered, processed, and transported on our assets. Decreases in the volumes of natural gas and NGLs that we gather, processes, or transport would directly and adversely affect our financial condition, results of operations, or cash flows. These volumes can be influenced by factors beyond our control, including:
environmental or other governmental regulations;
weather conditions;
increases in storage levels of natural gas and NGLs;
increased use of alternative energy sources;
decreased demand for natural gas and NGLs;
continued fluctuation in commodity prices, including the prices of natural gas and NGLs;
economic conditions;
supply disruptions;
availability of supply connected to the Company’s systems; and
availability and adequacy of infrastructure to gather and process supply into and out of the Company’s systems.

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The volumes of natural gas and NGLs gathered, processed, and transported on the Company’s assets also depend on the production from the region that supplies our systems. Supply of natural gas and NGLs can be affected by many of the factors listed above, including commodity prices, the decision to recover or reject ethane from rich-gas processed through the Company’s rich-gas processing facilities, and weather. In order to increase throughput levels on the Company’s system, the Company must obtain new sources of natural gas and NGLs. The primary factors affecting the Company’s ability to obtain new sources of natural gas and NGLs includes (i) Apache’s drilling activity in our area of operations, (ii) the level of successful leasing, permitting, and drilling activity in our area of operation, (iii) the Company’s ability to compete for volumes from new wells, and (iv) the Company’s ability to compete successfully for volumes from sources connected to other pipelines. We have no control over the level of drilling activity in our area of operation, the amount of reserves associated with wells connected to our system, or the rate at which production from a well declines. Furthermore, the Company does not have minimum volume commitments in our current commercial agreements with Apache that would otherwise generate a minimum amount of cash in the event that Apache’s production in Alpine High declines or ceases. Likewise, the Company has no control over producers or their drilling or production decisions, which are affected by, among other things, commodity prices, the availability and cost of capital, levels of reserves, availability of drilling rigs, and other costs of production and equipment.
Apache may suspend, reduce, or terminate its obligations under its commercial agreements with us in certain circumstances, which could have a material adverse effect on our financial condition, results of operations, and cash flow.
Alpine High Gathering LP, Alpine High Processing LP, Alpine High NGL Pipeline LP, and Alpine High Pipeline LP are parties to a Gas Gathering Agreement, a Gas Processing Agreement, a NGL TSA, and a Residue Gas TSA, respectively, with Apache. Each of these agreements includes provisions that permit Apache to suspend, reduce, or terminate its obligations under the agreement if certain events occur. These events include force majeure events that would prevent the Company from performing some or all of the required services under the applicable agreement. Apache, as the counterparty under these commercial agreements, has the discretion to make such decisions, notwithstanding the fact that they may significantly and adversely affect the Company. Any such reduction, suspension, or termination of Apache’s obligations under these agreements would have a material adverse effect on our financial condition, results of operations, and cash flow.
While Apache has granted us a right of first offer to provide additional midstream services and acquire Apache’s retained midstream assets in Alpine High, Apache does not have to accept our offer if a competitor provides more attractive economic terms.
Apache has granted us a right of first offer to provide additional midstream services and acquire Apache’s retained midstream assets in Alpine High. Although Apache granted us this right of first offer, we can make no assurances that the economic terms that we offer Apache will be acceptable to Apache, and another midstream service provider or a third party may be willing to make an offer to Apache on economic terms that we are unwilling or unable to offer. Our inability to take advantage of the opportunities with respect to the right of first offer could adversely affect our growth strategy.
A significant amount of the revenue currently generated by us is from contracts with Apache that contain most favored nations rights and other consent rights, limiting flexibility to offer certain capacity to new shippers.
All of our system’s current available capacity is provided to Apache under the Gas Gathering Agreement, the Gas Processing Agreement, the NGL TSA, and the Residue Gas TSA. The Gas Gathering Agreement, the Gas Processing Agreement, and the NGL TSA contain most favored nations rights (“MFNs”) that could result in lower rates being charged to Apache in the event that any of the rates being charged to other customers are less than the similar rates charged to Apache. Triggering the MFNs in the Gas Gathering Agreement, the Gas Processing Agreement, or the NGL TSA could lead to a reduction in revenue generated by the Company, which could adversely affect the Company’s financial condition, results of operations, or cash flows. These three agreements also require Apache’s consent to offer third-party customers priority of service in the Company’s facilities that is at least equal to Apache’s priority of service. If Apache refuses to grant such consent, the Company’s ability to attract third-party customers to our midstream facilities could be negatively impacted, thereby adversely impacting our ability to grow as expected.
Without Apache’s consent, the MFNs effectively limit the Company’s flexibility in negotiating rates for some of our services with other shippers to fill excess system capacity, because triggering the MFNs contained in the Gas Gathering Agreement, the Gas Processing Agreement, or the NGL TSA would lead to a reduction in the rates that the Company charges to Apache, which would adversely affect our financial condition, results of operations, or cash flows.



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To maintain and grow our business, we are, and will be, required to make substantial capital expenditures.
In order to meet our contractual obligations under the Gas Gathering Agreement and the Gas Processing Agreement with Apache, we will have to make substantial capital investments based on Apache’s forecasted development plans in order to have facilities available to provide services at the time Apache commences production from new wells, or shortly thereafter. Apache’s plans are subject to change and there is no guarantee that facilities we build will be utilized to provide services consistent with Apache’s forecast, or at all. As a result, we could potentially incur material capital expenses that generate no return.
In order to maintain and grow our business, we will need to make substantial capital expenditures to fund growth capital expenditures as well as our share of capital expenditures associated with any of the remaining Pipeline Options and the Additional Option we exercise, if any. If we do not make sufficient or effective capital expenditures, we will be unable to maintain and grow our business, and, as a result, we may be unable to increase our cash flow over the long term. To fund our capital expenditures, we will be required to use cash from our operations, incur debt, engage in structured financing transactions, or sell additional shares of Class A Common Stock or other equity securities. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our then-current debt agreements, as well as by general economic conditions, contingencies, and uncertainties that are beyond our control. Also, due to our relationship with Apache, our ability to access the capital markets or the pricing or other terms of any capital markets transactions may be adversely affected by any impairment to the financial condition of Apache or adverse changes in Apache’s credit ratings. Any material limitation on our ability to access capital as a result of such adverse changes to Apache could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes affecting Apache could negatively impact our share price, limiting our ability to raise capital through equity issuances or debt financing, could negatively affect our ability to engage in, expand, or pursue our business activities, or could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
Additionally, the capital and global credit markets have experienced volatility and disruption in the past. In many cases during these periods, the capital markets have exerted downward pressure on equity values and reduced the credit capacity for certain companies. Much of our business is capital intensive, and our ability to grow is dependent, in part, upon our ability to access capital at rates and on terms we determine to be attractive. Similar or more severe levels of global market disruption and volatility may have an adverse effect on us or Apache resulting from, but not limited to, disruption of our or their access to capital and credit markets, difficulty in obtaining financing necessary to expand facilities or acquire assets, increased financing costs and increasingly restrictive covenants. If we or Apache are unable to access capital at competitive rates, our strategy of enhancing the earnings potential of our existing assets, including through capital-growth projects and acquisitions of complementary assets or businesses, may be affected adversely. A number of factors could affect adversely our ability to access capital, including: (i) general economic conditions; (ii) capital market conditions; (iii) market prices for natural gas, NGLs and other hydrocarbons; (iv) the overall health of the energy and related industries; (v) ability to maintain investment-grade credit ratings; (vi) share price and (vii) capital structure. If our ability to access capital becomes constrained significantly, our interest costs and cost of equity will likely increase and could affect adversely our financial condition and future results of operations.
Even if we are successful in obtaining the necessary funds to support our growth plan, the terms of such financings could limit our ability to institute a dividend to our stockholders in the future. In addition, incurring debt will cause us to incur interest expense and increase our financial leverage, and issuing additional shares of Class A Common Stock or other equity interests may result in significant stockholder dilution, which could materially decrease our ability to institute a dividend to our stockholders in the future. While the Company historically received funding from Apache, none of Apache or any of its affiliates is committed to providing any direct or indirect financial support to fund our growth.
Construction of our assets subjects us to risks of construction delays, cost over-runs, limitations on our growth, and negative effects on our financial condition, results of operations, or cash flows.
The Company is engaged in the construction of our assets, some of which will take a number of months before they begin commercial operation. The construction of these assets is complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, complying with laws, unavailability or increased cost of materials, labor disruptions, labor availability, environmental hazards, financing, accidents, weather, and other factors. Any delay in the completion of the assets could adversely affect the Company’s financial condition, results of operations, or cash flows. The construction of pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed the Company’s estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed the Company’s estimates, our liquidity and capital position could be adversely affected. We rely exclusively on Apache to provide certain services related to the design, development, construction, operation, management, and maintenance of our midstream assets on our behalf pursuant to the COMA. Although the COMA provides for certain fixed annual limits on the support services fee

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payable to Apache through 2022, there is no limit on such fees thereafter. As a result, after 2022, we may be required to pay Apache higher fees than would be available from third parties. The COMA is subject to termination by us or Apache under certain circumstances, including if Apache and its affiliates no longer own a direct or indirect interest in at least 50 percent of the voting or other equity securities of the Company. Should the COMA be terminated by us or Apache, we may be forced to contract for services previously provided under the COMA, which may be disruptive to our operations and may be on terms less favorable than the terms of the COMA, and, as a result, our financial condition, results of operations, and cash flows could be adversely affected. Additionally, the COMA provides Apache with broad discretion to enter into contracts on our behalf.
Our construction of new assets may be more expensive than anticipated, may not result in revenue increases, and may be subject to regulatory, environmental, political, legal, and economic risks that could adversely affect our financial condition, results of operations, or cash flows.
The construction of additions or modifications to the Company’s existing systems and the construction of new midstream assets (including the pipelines to which the Pipeline Options relate) involves numerous regulatory, environmental, political, and legal uncertainties beyond our control, including potential protests, tariffs on materials used in construction or operations (including steel used to construct pipelines), or legal actions by interested third parties, and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If the Company undertakes these projects, we may not be able to complete them on schedule, at the budgeted cost, or at all. Moreover, the Company’s revenues may not increase due to the successful construction of a particular project. For instance, if the Company expands a pipeline or constructs a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues promptly following completion of a project or at all. Moreover, the Company may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect the Company’s financial condition, results of operations, or cash flows. In addition, the construction of additions to the Company’s existing gathering and processing assets will generally require us to obtain new rights-of-way and permits prior to constructing new pipelines or facilities. The Company may be unable to timely obtain such rights-of-way or permits to connect new product supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for the Company to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
Performance of the Company’s operations require that we obtain and maintain a number of federal, state, and local permits, licenses, and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits, and standards require a significant amount of monitoring, record keeping, and reporting in order to demonstrate compliance with the underlying permit, license, approval limit, or standard. Noncompliance or incomplete documentation of the Company’s compliance status may result in the imposition of fines, penalties, and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval or to revoke or substantially modify an existing permit or other approval could adversely affect the Company’s ability to initiate or continue operations at the affected location or facility or the Company’s financial condition, results of operations, or cash flows.
Additionally, in order to obtain permits and renewals of permits and other approvals in the future, the Company may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate. Certain approval procedures may require preparation of archaeological surveys, endangered species studies, and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time required to prepare applications and to receive authorizations.
We do not obtain independent evaluations of hydrocarbon reserves and rely on evaluations of hydrocarbon reserves obtained by our customers; therefore, volumes that we service in the future could be less than anticipated.
The Company does not obtain independent evaluations of hydrocarbon reserves connected to our gathering systems or that we otherwise service, and we rely on reserves reports if and when provided by our customers. Accordingly, the Company does not have independent estimates of total reserves serviced by our assets or the anticipated life of such reserves. If the total reserves or estimated life of these reserves is less than the Company anticipates, in reliance on our customers’ reports, and we are unable to secure additional sources, then the volumes transported on the Company’s gathering systems or that we otherwise service in the future could be less than anticipated. A decline in such volumes could adversely affect the Company’s financial condition, results of operations, or cash flows.

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Debt we incur may limit our flexibility to obtain financing and to pursue other business opportunities.
On November 9, 2018, Altus Midstream entered into a credit agreement, which provides for a five-year revolving credit facility for general corporate purposes, with aggregate commitments of $450 million for an initial period until we have met certain requirements, following which, the aggregate commitments will equal $800 million. After the initial period, 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. Our future level of debt could have important consequences to us, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering and processing assets or exercising the Pipeline Options), or other purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities, and dividends to our stockholders in the future, if any, will be reduced by that portion of our cash flows required to make interest payments on our debt;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service any debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory, and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as not instituting a dividend (or reducing or eliminating a dividend, if already instituted), reducing or delaying our business activities, investments, or capital expenditures, selling assets, or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.
Our exposure to commodity price risk may change over time.
We currently generate all of our revenues pursuant to fee-based contracts under which we are paid based on the volumes that we gather, process, and transport, rather than the underlying value of the commodity. However, we may enter into contracts or may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of crude oil, natural gas, and NGL prices could adversely affect our financial condition, results of operations, or cash flows.
If third-party pipelines or other midstream facilities interconnected to our gathering, processing, or transportation systems become partially or fully unavailable or if the volumes we gather, process, or transport do not meet the quality requirements of the pipelines or facilities to which we connect, our cash flows could be adversely affected.
The Company’s gathering, processing, and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties. The Company’s continuing access to such third-party pipelines, processing facilities, and other midstream facilities are not within the Company’s control. These pipelines, plants, and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements, and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if the Company’s costs to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, or process product, or if the volumes the Company gathers or transports do not meet the product quality requirements of such pipelines or facilities, our cash flows could be adversely affected.
Our industry is highly competitive, and increased competitive pressure could adversely affect our financial condition, results of operations, or cash flows.
We compete with similar enterprises in our industry. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. Our competitors include large midstream companies that have greater financial resources and access to supplies of crude oil, natural gas, and NGLs than the Company. Some of these competitors may expand or construct gathering, processing, transportation, and storage systems that would create additional competition for the services the Company provides to our customers. In addition, potential customers may develop their own gathering systems instead of using the Company’s systems. Excess pipeline capacity in the region served by the Company’s intrastate pipelines could also increase competition and adversely impact our ability to renew or enter into new contracts with respect to our available capacity when existing contracts expire. The Company’s ability to renew or replace existing contracts with our customers at rates sufficient to maintain or increase current revenues and cash flows could be adversely affected by the activities of our competitors and customers. Further, natural

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gas utilized as a fuel competes with other forms of energy available to end-users, including electricity, coal, liquid fuels, and sources of alternative energy. Increased demand for such other forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, and transportation services. Although we do not have employees, Apache’s employees perform work for us pursuant to the COMA, and Apache still competes with larger midstream companies in attracting and retaining personnel, including equipment operators, mechanics, engineers, and other specialists. All of these competitive pressures could adversely affect the Company’s financial condition, results of operations, or cash flows.
In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by the Company’s systems, such as adverse economic conditions, weather, higher fuel costs, and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
Our ability to institute a dividend will depend on our ability to generate sufficient cash flow, which we may not be able to accomplish.
We may not generate sufficient cash flow to enable us to institute a dividend in the future. Our ability to institute a dividend will principally depend upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things, the volumes of natural gas and NGLs we gather and process, commodity prices, including for crude oil, and other factors impacting our financial condition, some of which are beyond our control.
We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.
The renewal or replacement of the Company’s existing contracts with our customers at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors, some of which are beyond the Company’s control, including competition from other midstream service providers and the price of, and demand for, crude oil, natural gas, and NGLs in the markets we serve. The inability of the Company to renew or replace our current or future contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.
We are exposed to the credit risk of our customers and counterparties, including Apache, and the nonpayment or nonperformance by our customers or counterparties could have an adverse effect on our financial condition, results of operations, or cash flows.
The Company is subject to risks of loss resulting from nonpayment or nonperformance by our customers or other counterparties, including Apache. Any increase in the nonpayment or nonperformance by the Company’s customers or other counterparties could adversely affect our financial condition, results of operations, or cash flows. Additionally, equity values for the Company’s customers or other counterparties may be low. The combination of a reduction of cash flow resulting from lower commodity prices, a reduction in borrowing bases under reserve-based credit facilities, and the lack of availability of debt or equity financing may result in a significant reduction in the liquidity of the Company’s customers or other counterparties and their ability to make payment or perform on their obligations to the Company. Furthermore, some of the Company’s customers or other counterparties may be leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to the Company.
In the event Apache elects to sell acreage that is dedicated to us to a third party, the third party’s financial condition could be materially worse than Apache’s, and we could be subject to the nonpayment or nonperformance by the third party.
In the event Apache elects to sell acreage that is dedicated to the Company to a third party, the third party’s financial condition could be materially worse than Apache’s. In such a case, the Company may be subject to risks of loss resulting from nonpayment or nonperformance by the third party, which risks may increase during periods of economic uncertainty. Furthermore, the third party may be subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to the Company. Any material nonpayment or nonperformance by the third party could adversely impact the business, financial condition, results of operations, and cash flows of the Company.
We are subject to regulation by multiple governmental agencies, which could adversely impact our business, results of operations, and financial condition.
The Company is subject to regulation by multiple federal, state, and local governmental agencies. Proposals and proceedings that affect the midstream industry are regularly considered by Congress, as well as by state legislatures and federal and state regulatory commissions, agencies, and courts. The Company cannot predict when or whether any such proposals or proceedings

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may become effective or the magnitude of the impact changes in laws and regulations may have on our business. However, additions to the regulatory burden on the midstream industry can increase the Company’s cost of doing business and affect our profitability.
Increased federal, state, and local legislation and regulatory initiatives, as well as government reviews relating to hydraulic fracturing, could result in increased costs and reductions or delays in crude oil, natural gas, and NGL production by our customers, including Apache, which could adversely affect our financial condition, results of operations, or cash flows.
Substantially all of the Company’s suppliers’ and customers’ crude oil, natural gas, and NGL production is developed from unconventional sources, such as deep oil or gas shales, that require hydraulic fracturing as part of the completion process. State legislatures and agencies and other political subdivisions have enacted legislation and promulgated rules to regulate hydraulic fracturing, require disclosure of hydraulic fracturing chemicals, temporarily or permanently ban hydraulic fracturing, and impose additional permit requirements and operational restrictions in certain jurisdictions or in environmentally sensitive areas. EPA and BLM have also issued rules, conducted studies, and made proposals that, if implemented, could either restrict the practice of hydraulic fracturing or subject the process to further regulation. For instance, the EPA has issued final regulations under the CAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing and adopted rules prohibiting the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The BLM also adopted new rules, effective on January 17, 2017, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. However, the status of recent and future rules and rulemaking initiatives under the current presidential administration is uncertain. For example, in June 2017, the EPA published a proposed rule to stay certain provisions of the performance standards, but elected not to finalize the stay, and instead, in February 2018, finalized amendments to some of the requirements. In addition, in December 2017, the BLM temporarily suspended some of the new venting and flaring requirements, only to have a court subsequently enjoin the suspension.
State and federal regulatory agencies also have recently focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in induced seismicity, which has resulted in some regulation at the state level. As regulatory agencies continue to study induced seismicity, additional legislative and regulatory initiatives could affect the injection well operations of the Company’s customers as well.
We cannot predict whether any additional legislation or regulations will be enacted and, if so, what the provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal, state, or local level, that could lead to delays, increased operating costs, and process prohibitions for the Company’s suppliers and customers that could reduce the volumes of natural gas and NGLs that move through our gathering systems, which could materially adversely affect our revenue and results of operations.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
We may face opposition to the construction or operation of our pipelines and facilities from various groups.
We may face opposition to the construction or operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our construction activities or operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the construction or operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that delays or interrupts the construction of assets or revenues generated by our existing operations, or which causes us to make significant expenditures not covered by insurance, could affect adversely our financial condition, results of operations, cash flows and our share price.

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If our assets (including assets acquired in the future pursuant to the Pipeline Options, if any) become subject to FERC regulation or federal, state, or local regulations or policies change, our financial condition, results of operations, and cash flows could be materially and adversely affected.
The Company’s natural gas gathering facilities are exempt from regulation by the FERC under the NGA. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. Although FERC has not made any formal determinations with respect to any of the Company’s facilities, our gathering facilities meet the traditional tests FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis. Accordingly, the classification and regulation of the Company’s gathering facilities may be subject to change based on future determinations by FERC, the courts, or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, then the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA and the rules and regulations promulgated under that statute. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect the Company’s results of operations and cash flows.
The Company’s natural gas gathering and transportation facilities are largely regulated by the RRC, and, to the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates and terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the NGPA. The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Under Section 311 of the NGPA, rates charged for interstate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions for transportation service under Section 311 of the NGPA are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently-approved rates under Section 311 of the NGPA, our business may be adversely affected. Failure to observe the service limitations applicable to transportation services under Section 311 of the NGPA, failure to comply with the rates approved by the FERC for service under Section 311 of the NGPA, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil, and criminal remedies. The Company’s natural gas transportation facilities and operations are also subject to the Texas Utilities Code and the Texas Natural Resources Code, as implemented by the RRC. Generally, the RRC is vested with authority to ensure that rates, operations, and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates the Company charges for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or RRC complaint. The Company cannot predict whether such a complaint will be filed against us or whether the RRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code or the Texas Natural Resources Code can result in the imposition of administrative, civil, and criminal remedies.
The Company’s natural gas pipeline system is also subject to state ratable take and common purchaser statutes in Texas. The ratable take statute generally requires gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, the common purchaser statute generally requires gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.
The Company’s NGL pipeline facilities do not provide interstate transportation service and are therefore not subject to FERC’s jurisdiction under Interstate Commerce Act (“ICA”). Whether an NGL shipment is in interstate commerce under the ICA depends on the fixed and persistent intent of the shipper as to the NGLs’ final destination, absent a break in the interstate movement. The Company’s NGL pipelines meet the traditional tests FERC has used to determine that a pipeline is not providing transportation service in interstate commerce subject to FERC ICA jurisdiction. However, the determination of the interstate or intrastate character of shipments on the Company’s NGL pipelines depends on the shipper’s intentions and the transportation of the NGLs outside of the Company’s system and may change over time. If FERC were to consider the status of an individual facility and the character of an NGL shipment and determine that the shipment is in interstate commerce, the rates for, and terms and conditions of, transportation services provided by such facility would be subject to regulation by FERC under the ICA. Such FERC regulation could decrease revenue, increase operating costs, and, depending on the facility in question, adversely affect the Company’s results of operations and cash flows.
If the Company fails to comply with applicable FERC-administered statutes, rules, regulations, and orders, it could be subject to substantial penalties and fines. Under the Energy Policy Act of 1992 (the “EPAct”), for instance, FERC has civil penalty authority to impose penalties for current violations of the NGA or NGPA of up to $1,213,503 per day for each violation. The maximum penalty authority established by statute has been and will continue to be adjusted periodically for inflation. FERC also has the

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power to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct. In addition, if any of the Company’s facilities were found to have provided services or otherwise operated in violation of the ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.
We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.
The pipelines the Company owns and operates are subject to stringent and complex regulation related to pipeline safety and integrity management, such as regulation by the DOT, through PHMSA, pursuant to the NGSPA, with respect to natural gas, and the HLSPA, with respect to NGLs. For instance, the DOT, through the PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. In 2016, PHMSA proposed rulemaking that would expand existing integrity management requirements to natural gas transmission and gathering lines in areas with medium population densities. A final rule has yet to be issued, although PHMSA recently announced its intention to finalize the rulemaking in 2019. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, the Company cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.
Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the RRC could result in substantial expenditures for testing, repairs, and replacement. If the Company’s pipelines fail to meet the safety standards mandated by the RRC or the DOT regulations, then the Company may be required to repair or replace sections of such pipelines or operate the pipelines at a reduced maximum allowable operating pressure, the cost of which cannot be estimated at this time.
Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on the Company’s results of operations or financial position. Because certain of the Company’s operations are located around areas that may become more populated areas, such as Alpine High, the Company may incur expenses to mitigate noise, odor, and light that may be emitted in our operations and expenses related to the appearance of our facilities. Municipal and other local or state regulations are imposing various obligations including, among other things, regulating the location of the Company’s facilities, imposing limitations on the noise levels of our facilities and requiring certain other improvements that increase the cost of our facilities. The Company is also subject to claims by neighboring landowners for nuisance related to the construction and operation of our facilities, which could subject it to damages for declines in neighboring property values due to the Company’s construction and operation of facilities.
Failure to comply with existing or new environmental laws or regulations or an accidental release of hazardous substances, hydrocarbons, or wastes into the environment may cause us to incur significant costs and liabilities.
Many of the operations and activities of the Company’s pipelines, gathering systems, processing plants, and other facilities are subject to significant federal, state, and local environmental laws and regulations, the violation of which can result in administrative, civil, and criminal penalties, including civil fines, injunctions, or both. The obligations imposed by these laws and regulations include obligations related to air emissions and the discharge of pollutants from the Company’s pipelines and other facilities and the cleanup of hazardous substances and other wastes that are or may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for treatment or disposal. These laws may impose strict, joint, and several liability for the remediation of contaminated areas. Private parties, including the owners of properties near the Company’s facilities or upon or through which our systems traverse, may also have the right to pursue legal actions to enforce compliance and to seek damages for non-compliance with environmental laws for releases of contaminants or for personal injury or property damage.
Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental laws or regulations, including, for example, legislation relating to the control of greenhouse gas emissions, or changes in existing environmental laws or regulations might adversely affect the Company’s products and activities, including processing, storage, and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect the Company’s profitability. Changes in laws or regulations could also limit the operation of the Company’s assets or adversely affect our ability to comply with applicable legal requirements or the demand for crude oil, natural gas, or NGLs, which could adversely affect our business and our profitability.

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Recent rules under the CAA imposing more stringent requirements on the oil and gas industry could cause us and our customers to incur increased capital expenditures and operating costs as well as reduce the demand for our services.
We are subject to stringent and complex regulation under the CAA, implementing regulations, and state and local equivalents, including regulations related to controls for oil and natural gas production, pipelines, and processing operations. For instance, in 2016, the EPA issued three final rules intended to curb emissions of methane, volatile organic compounds, and toxic air pollutants (such as benzene) from new, reconstructed, and modified oil and gas sources, including the rule affecting storage tanks constructed, modified, or reconstructed, (the so-called “OOOOa Rule”). In April 2017, the EPA announced its intention to reconsider certain aspects of the 2016 rules for the oil and natural gas industry in response to several petitions for reconsideration and issued a 90-day stay of the June 3, 2017 compliance deadline for the fugitive emissions monitoring requirements in the OOOOa Rule. Subsequently, on May 31, 2017, the EPA issued a 90-day stay of certain requirements under the rule, but this stay was vacated by a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit on July 3, 2017 and again by an en banc D.C. Circuit on July 31, 2017. In the interim, on July 16, 2017, the EPA issued a proposed rule that would provide a two-year extension of the initial 90-day stay. Most recently, on March 12, 2018, the EPA announced amendments to the fugitive emissions monitoring requirements, although the agency’s reconsideration of other aspects of the 2016 rule remains ongoing. Accordingly, substantial uncertainty exists with respect to implementation of this methane rule. The BLM also adopted new rules on November 15, 2016, to reduce venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. On June 15, 2017, the BLM suspended indefinitely compliance dates for certain aspects of these rules, pending judicial review, but a court subsequently enjoined the BLM’s suspension.
Additional regulation of GHG emissions from the oil and gas industry remains a possibility. These regulations could require a number of modifications to the Company’s operations, and our natural gas exploration and production suppliers’ and customers’ operations, including the installation of new equipment, which could result in significant costs, including increased capital expenditures and operating costs. The incurrence of such expenditures and costs by the Company’s suppliers and customers could result in reduced production by those suppliers and customers and thus translate into reduced demand for our services.
Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for the natural gas and NGLs services we provide.
Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the adoption of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement was signed by the United States in April 2016 and entered into force in November 2016; however, the GHG emission reductions called for by the Paris Agreement are not binding. On June 1, 2017, the current presidential administration announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or to establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Moreover, at the federal regulatory level, both the EPA and the BLM have promulgated regulations for the control of methane emissions, which also include leak detection and repair requirements, from the oil and gas industry, although the current status of those regulations is uncertain under the current presidential administration.
The EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that emit GHGs. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rule makings could adversely affect the Company’s operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore crude oil and natural gas production sources in the U.S. on an annual basis.
In addition, many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and NGLs fractionation plants, to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.

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Although it is not possible at this time to predict whether future legislation or new regulations may be adopted to address GHG emissions or how such measures would impact the Company’s business, the adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require the Company to incur additional costs to reduce emissions of GHGs associated with our operations, could adversely affect our performance of operations in the absence of any permits that may be required to regulate emission of GHGs, or could adversely affect demand for the natural gas the Company gathers, processes, or otherwise handles in connection with our services.
The ESA and the MBTA govern our operations and additional restrictions may be imposed in the future, which could have an adverse impact on our operations.
The ESA and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. FWS and state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species, which could materially restrict use of or access to federal, state, and private lands.
On July 19, 2018, the FWS announced a series of proposed changes to the rules implementing the ESA, including proposed revisions to the regulations governing interagency cooperation, listing species and delisting critical habitat, and prohibitions related to threatened wildlife and plants. The proposed revisions are intended to streamline these processes and create more flexibility for the FWS when making ESA-related decisions. It is not possible at this time to accurately predict how such changes, if adopted, would impact the Company’s operations.
Some of the Company’s operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds. In these areas, the Company may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to the Company’s activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. In addition, the FWS and state agencies regularly review species that are listing candidates, and designations of additional endangered or threatened species or critical or suitable habitat under the ESA could cause the Company to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could adversely affect our operations and financial condition.
The Company’s operations are subject to the many hazards inherent in the gathering, compressing, processing, and transporting of natural gas and NGLs, including:
damage to pipelines, related equipment, and surrounding properties caused by hurricanes, floods, fires, and other natural or anthropogenic disasters and acts of terrorism;
leaks of natural gas, NGLs, and other hydrocarbons;
induced seismicity; and
fires and explosions.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage and may result in curtailment or suspension of the Company’s related operations. The Company is not fully insured against all risks incident to our business. In accordance with typical industry practice, we have appropriate levels of business interruption and property insurance. We are not insured against all environmental accidents that might occur. If a significant accident or event occurs that is not fully insured, it could adversely affect our financial condition, results of operations, or cash flows.
We do not own in fee any of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
The Company does not own in fee any of the land on which our midstream assets have been constructed. Our only interests in these properties are rights granted under surface use agreements, rights-of-way, surface leases, or other easement rights (collectively, “Rights-of-Way”), which may limit or restrict our rights or access to or use of the surface estates. Accommodating these competing rights of the surface owners may adversely affect the operations of the Company. Apache and certain of its affiliates

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are party to certain of these Rights-of-Way. Furthermore, many of the Rights-of-Way on which the Company’s assets have been constructed are not perpetual in duration and, upon the expiration of their terms, will require us to pay a renewal fee to the applicable surface owners in order to maintain access to such Rights-of-Way. These Rights-of-Way also require compliance with certain terms and conditions in order to renew their terms, some of which may be outside of our control.
The Company is subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid Rights-of-Way or if such usage rights lapse or terminate. The Company may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. The loss of these rights, through the inability to renew Rights-of-Way or otherwise, could have a material adverse effect on the business, financial condition, results of operations, and cash flows of the Company.
A failure in our computer systems or a terrorist or cyberattack on us or third parties with whom we do business may adversely affect our ability to operate our business.
The Company is reliant on technology to conduct our business. The Company’s business is dependent upon our operational and financial computer systems to process the data necessary to conduct almost all aspects of our business, including operating our pipelines and gathering and processing facilities, recording and reporting commercial and financial transactions, and receiving and making payments. Any failure of the Company’s computer systems or those of our customers, suppliers, or others with whom we do business, including Apache, could materially disrupt the Company’s ability to operate our business. Unknown entities or groups have mounted so-called “cyberattacks” on businesses to disable or disrupt computer systems, disrupt operations, and steal funds or data. Cyberattacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt the Company’s operations and critical business functions. In addition, the Company’s pipeline systems may be targets of terrorist or environmental activist group activities that could disrupt our ability to conduct our business and have a material adverse effect on our business and results of operations. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist attacks, environmental activist group activities, or cyberattacks than other targets in the United States. The Company’s insurance may not protect us against such occurrences. Any such terrorist attack, environmental activist group activity, or cyberattack that affects the Company or our customers, suppliers, or others with whom we do business could have a material adverse effect on our business, cause it to incur a material financial loss, subject it to possible legal claims and liability, and/or damage our reputation.
Moreover, as the sophistication of cyberattacks continues to evolve, the Company may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. In addition, cyberattacks against us or others in our industry could result in additional regulations, which could lead to increased regulatory compliance costs, insurance coverage cost, or capital expenditures. The Company cannot predict the potential impact to our business or the energy industry resulting from additional regulations.
If we fail to maintain an effective system of internal controls, we may not be able to report accurately our financial results or prevent fraud. As a result, current and potential holders of our equity could lose confidence in our financial reporting, which would harm our business and cost of capital.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our equity interests.
We may become subject to the requirements of the Investment Company Act of 1940, which would limit our business operations and require us to spend significant resources to comply with such act.
The Investment Company Act of 1940 (the “Investment Company Act”) defines an “investment company” as an issuer that is engaged in the business of investing, reinvesting, owning, holding, or trading in securities and owns investment securities having a value exceeding 40 percent of the issuer’s unconsolidated assets, excluding cash items and securities issued by the federal government. If one or more of our subsidiaries exercises all or any portion of the remaining Pipeline Options, it is possible that some or all of those interests will be investment securities and that the value of those interests that are investment securities over time may exceed 40 percent of such subsidiaries’ unconsolidated assets, excluding cash and government securities, in which case such subsidiaries may meet this threshold definition of an investment company. The Investment Company Act provides certain exclusions from this definition. However, if a subsidiary relies on any one or more of these exclusions from the definition of an

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investment company and such reliance is not correct, then the subsidiary may be in violation of the Investment Company Act, the consequences of which can be significant. For example, investment companies that fail to register under the Investment Company Act are prohibited from conducting business in interstate commerce, which includes selling securities or entering into other contracts in interstate commerce. Section 47(b) of the Investment Company Act provides that a contract made in, or whose performance involves a, violation of the Investment Company Act is unenforceable by either party unless a court finds that enforcement would produce a more equitable result than non-enforcement. Similarly, a court may not deny rescission to any party seeking to rescind a contract that violates the Investment Company Act, unless the court finds that denial of rescission would produce a more equitable result than granting rescission.
If in the future the nature of any of our subsidiaries’ businesses change such that no exception to the threshold definition of investment company is available to such subsidiary, then such subsidiary may be deemed to be an investment company under the Investment Company Act. However, Rule 3a-2 of the Investment Company Act provides that inadvertent or transient investment companies will not be treated as investment companies subject to the provisions of the Investment Company Act, provided the issuer has the requisite intent to be engaged in a non-investment business, evidenced by the issuer’s business activities and an appropriate resolution of the issuer’s board of directors, within one year from the commencement of the earlier of (1) the date on which the issuer owns securities and/or cash having a value exceeding 50 percent of the value of such issuer’s total assets on either a consolidated or unconsolidated basis or (2) the date on which an issuer owns or proposes to acquire investment securities (as defined in section 3(a) of the Investment Company Act) having a value exceeding 40 percent of the value of such issuer’s total assets (exclusive of government securities and cash items) on an unconsolidated basis. If any of our subsidiaries becomes an inadvertent investment company and fails to meet the requirements of the transient investment company exemption under Rule 3a-2 of the Investment Company Act, then such subsidiary may be required to register as an investment company with the SEC.
The ramifications of becoming an investment company, both in terms of the restrictions it would have on such subsidiary and the cost of compliance, would be significant. For example, in addition to expenses related to initially registering as an investment company, the Investment Company Act also would impose various restrictions with regard to the subsidiary’s ability to enter into affiliated transactions, the diversification of its assets, and its ability to borrow money. If any of our subsidiaries became subject to the Investment Company Act at some point in the future, then the subsidiary’s ability to continue pursuing its business plan would be severely limited.
Apache owns a majority of our outstanding voting shares and thus strongly influences all of our corporate actions.
Apache or an affiliate beneficially owns approximately 79 percent of our outstanding voting common stock. As long as Apache or an affiliate owns or controls a significant percentage of our outstanding voting power, it will have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our Charter or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets, and will be able to cause or prevent a change in the composition of our board of directors or a change in control of the Company that could deprive stockholders of an opportunity to receive a premium for their common stock as part of a sale of the Company. In addition, under the Stockholders Agreement, Kayne Anderson Sponsor, LLC is entitled to nominate two directors to the board of directors of the Company until the earlier of the time that Kayne Anderson Sponsor, LLC and its affiliates own less than 1 percent of the outstanding voting common stock of the Company or the second anniversary of the date of the Stockholders Agreement. Additionally, Apache is entitled to nominate up to seven directors to our board of directors depending on its and its affiliates’ ownership of our outstanding voting common stock. In connection with the Stockholders Agreement, Apache and Kayne Anderson Sponsor, LLC have agreed to vote for the directors nominated by the other. The interests of Apache may not align with the interests of our other stockholders.
We are a “controlled company” within the meaning of the NASDAQ listing rules and, as a result, qualify for, and intend to rely on, exemptions from certain corporate governance requirements.
Apache or an affiliate controls a majority, approximately 79 percent, of our outstanding voting common stock. As a result, we are a controlled company within the meaning of the NASDAQ corporate governance standards. Under the NASDAQ listing rules, a company of which more than 50 percent of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NASDAQ corporate governance requirements, including the requirements that:
a majority of the board of directors consist of independent directors;
the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

29



the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

These requirements will not apply to us as long as we remain a controlled company, and we currently utilize and intend to continue to utilize some, if not all, of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NASDAQ.
Our only significant assets are ownership of the non-economic general partner interest and an approximate 23.1 percent limited partner interest in Altus Midstream, and such ownership may not be sufficient for Altus Midstream to make distributions or loans to us to enable us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations.
We have no direct operations and no significant assets other than the ownership of the non-economic general partner interest and an approximate 23.1 percent limited partner interest in Altus Midstream. We depend on Altus Midstream for distributions, loans, and other payments to generate the funds necessary to meet our financial obligations or to pay any dividends with respect to our Class A Common Stock. Subject to certain restrictions, Altus Midstream generally will be required to (i) make pro rata distributions to its partners, including us, on a quarterly basis in an amount at least sufficient to allow us to pay our taxes and make tax advances to its limited partners, other than us, in certain circumstances, and (ii) reimburse us for certain corporate and other overhead expenses. However, legal and contractual restrictions in agreements governing future indebtedness of Altus Midstream, as well as the financial condition and operating requirements of Altus Midstream, may limit our ability to obtain cash from Altus Midstream. The earnings from, or other available assets of, Altus Midstream may not be sufficient to make distributions or loans to us to enable us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations.
We may be required to take write-downs, write-offs, or restructuring and impairment or other charges that could have a significant negative effect on our financial condition, results of operations, and stock price, which could cause you to lose some or all of your investment.
Although we will conduct due diligence on the assets that we may acquire through the Pipeline Options, or other acquisitions that we may make from time to time, we cannot assure you that this diligence will reveal all material issues that may be present in the businesses that we acquire, that it would be possible to uncover all material issues through a customary amount of due diligence, or that factors outside of our control will not later arise. As a result, we may be forced to later write down or write off assets, restructure our operations, or incur impairment or other charges that could result in losses. Even if our due diligence successfully identifies certain risks, unexpected risks may arise, and previously known risks may materialize in a manner not consistent with our preliminary risk analysis. Even though these charges may be non-cash items and may not have an immediate impact on our liquidity, the fact that we report charges of this nature could contribute to negative market perceptions about the Company or our securities. In addition, charges of this nature may cause us to be unable to obtain future financing on favorable terms or at all.
There is no guarantee that our warrants will ever be in the money prior to their expiration, and, as such, they may expire worthless.
The exercise price for our warrants is $11.50 per share of Class A Common Stock. There is no guarantee that the public warrants will ever be in the money prior to their expiration, and, as such, the warrants may expire worthless.
Although we have registered the shares of Class A Common Stock issuable upon exercise of the warrants under the Securities Act, such registration may not be in place when an investor desires to exercise warrants, thus precluding such investor from being able to exercise its warrants except on a cashless basis and potentially causing such warrants to expire worthless.
Although we have registered the shares of Class A Common Stock issuable upon exercise of the warrants under the Securities Act, we may not be able to maintain a current prospectus relating to the Class A Common Stock issuable upon exercise of the warrants until the expiration of the warrants in accordance with the provisions of the warrant agreement. We cannot assure you that we will be able to do so if, for example, any facts or events arise which represent a fundamental change in the information set forth in such registration statement or prospectus, the financial statements contained or incorporated by reference therein are not current or correct, or the SEC issues a stop order. If the shares issuable upon exercise of the warrants are not registered under the Securities Act, we will be required to permit holders to exercise their warrants on a cashless basis. However, no warrant will be exercisable for cash or on a cashless basis, and we will not be obligated to issue any shares to holders seeking to exercise their warrants, unless the issuance of the shares upon such exercise is registered or qualified under the securities laws of the state of the exercising holder or an exemption is available. Notwithstanding the above, if our Class A Common Stock is at the time of any exercise of a warrant not listed on a national securities exchange such that it satisfies the definition of a “covered security” under Section 18(b)(1) of the Securities Act, we may, at our option, require holders of warrants who exercise their warrants to do so on

30



a “cashless basis” in accordance with Section 3(a)(9) of the Securities Act, and, in the event we so elect, we will not be required to file or maintain in effect a registration statement, but we will use our best efforts to register or qualify the shares under applicable blue sky laws to the extent an exemption is not available. In no event will we be required to net cash settle any warrant or issue securities or other compensation in exchange for the warrants in the event that we are unable to register or qualify the shares underlying the warrants under applicable state securities laws. If the issuance of the shares upon exercise of the warrants is not so registered or qualified or exempt from registration or qualification, the holder of such warrant shall not be entitled to exercise such warrant, and such warrant may have no value and expire worthless. If and when the warrants become redeemable by us, we may exercise our redemption right even if we are unable to register or qualify the underlying shares of Class A Common Stock for sale under all applicable state securities laws.
We may amend the terms of the warrants in a manner that may be adverse to holders with the approval by the holders of at least 50 percent of the then-outstanding public warrants. As a result, the exercise price of your public warrants could be increased, the exercise period could be shortened, and the number of shares of our Class A Common Stock purchasable upon exercise of a public warrant could be decreased, all without your approval.
Our public warrants were issued in connection with our initial public offering in registered form under a warrant agreement between American Stock Transfer & Trust Company, as warrant agent, and us. The warrant agreement provides that the terms of the warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least 50 percent of the then-outstanding public warrants to make any change that adversely affects the interests of the registered holders. Accordingly, we may amend the terms of the public warrants in a manner adverse to a holder if holders of at least 50 percent of the then-outstanding public warrants approve of such amendment. Although our ability to amend the terms of the public warrants with the consent of at least 50 percent of the then-outstanding public warrants is unlimited, examples of such amendments could be amendments to, among other things, increase the exercise price of the public warrants, shorten the exercise period, or decrease the number of shares of our Class A Common Stock purchasable upon exercise of a public warrant.
We may redeem unexpired warrants prior to their exercise at a time that is disadvantageous to warrant holders, thereby making their warrants worthless.
We have the ability to redeem outstanding warrants at any time prior to their expiration, at a price of $0.01 per warrant, provided that the last reported sales price of our Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within a 30 trading-day period ending on the third trading day prior to the date we send the notice of redemption to the warrant holders. If and when the warrants become redeemable by us, we may exercise our redemption right even if we are unable to register or qualify the underlying securities for sale under all applicable state securities laws. Redemption of the outstanding warrants could force the warrant holders (i) to exercise their warrants and pay the exercise price therefor at a time when it may be disadvantageous for them to do so, (ii) to sell their warrants at the then-current market price when they might otherwise wish to hold their warrants, or (iii) to accept the nominal redemption price which, at the time the outstanding warrants are called for redemption, is likely to be substantially less than the market value of their warrants. None of the private placement warrants issued to Kayne Anderson Sponsor, LLC (“Kayne Anderson Sponsor”) and Apache in connection with the Business Combination will be redeemable by us so long as they are held by Kayne Anderson Sponsor or its permitted transferees, with respect to Kayne Anderson Sponsor warrants, or Apache or its permitted transferees, with respect to the Apache warrants.
The Warrants are exercisable for our Class A Common Stock, which will, upon exercise, increase the number of shares eligible for future resale in the public market and result in dilution to our stockholders.
We have outstanding public warrants to purchase 12,577,370 shares of Class A Common Stock and private placement warrants to purchase 6,364,281 shares of Class A Common Stock. To the extent such warrants are exercised, additional shares of our Class A Common Stock will be issued, which will result in dilution to the then-existing holders of our Class A Common Stock and increase the number of shares eligible for resale in the public market. Sales of substantial numbers of such shares in the public market could adversely affect the market price of our Class A Common Stock.
In the future, Apache may receive earn-out consideration of up to 37,500,000 shares of Class A Common Stock upon the achievement of certain stock price and operational goals, which would increase the number of shares eligible for future resale in the public market and result in dilution to our stockholders.
Pursuant to the Contribution Agreement, Apache will have the right to receive earn-out consideration of up to 37,500,000 shares of Class A Common Stock if certain stock price and operational goals are achieved. To the extent such stock price or operational goals are achieved and Apache becomes entitled to receive a portion or all of the earn-out consideration, additional shares of our Class A Common Stock will be issued, which will result in dilution to the then-existing holders of our Class A

31



Common Stock and increase the number of shares eligible for resale in the public market. The shares of Class A Common Stock issuable to Apache as earn-out consideration have been registered for resale with the SEC. Sales of substantial numbers of such shares by Apache in the public market could adversely affect the market price of our Class A Common Stock.
A significant portion of our total outstanding shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our Class A Common Stock to drop significantly, even if our business is doing well.
Sales of a substantial number of shares of Class A Common Stock in the public market could occur at any time. These sales, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of our Class A Common Stock. Additionally, after May 8, 2019, Apache will have the ability to redeem or exchange its 250,000,000 Common Units for shares of Class A Common Stock on a one-for-one basis, subject to adjustments, and we have the ability to settle such redemption in cash. The Shares of Class A Common Stock issuable to Apache upon redemption or exchange of Altus Midstream Common Units have been registered for resale with the SEC. Sales of substantial numbers of such shares by Apache in the public market could adversely affect the market price of our Class A Common Stock.
If our Business Combination benefits do not meet the expectations of investors, stockholders, or financial analysts, the market price of our securities may decline.
If the benefits of our Business Combination do not meet the expectations of investors or securities analysts, the market price of our securities may decline from the prevailing level prior to the closing of our Business Combination.
In addition, fluctuations in the price of our securities could contribute to the loss of all or part of your investment. Prior to our Business Combination, there was not a public market for equity securities of the Company and the assets it now operates, and trading in the shares of our Class A Common Stock was not active. If an active market for our securities develops and continues, the trading price of our securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your investment in our securities, and our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a further decline.
Factors affecting the trading price of our securities may include:
actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us;
changes in the market’s expectations about our operating results;
success of competitors;
our operating results failing to meet the expectation of securities analysts or investors in a particular period;
changes in financial estimates and recommendations by securities analysts concerning the Company or the market in general;
operating and stock price performance of other companies that investors deem comparable to the Company;
changes in laws and regulations affecting our business;
commencement of, or involvement in, litigation involving the Company;
changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;
sales and issuances of additional equity securities in the future to fund our capital expenditures;
the volume of shares of our Class A Common Stock available for public sale;
any major change in our board of directors or management;
sales of substantial amounts of Class A Common Stock by our directors, executive officers, or significant stockholders or the perception that such sales could occur; and
general economic and political conditions such as recessions, interest rates, fuel prices, international currency fluctuations, and acts of war or terrorism.


32



Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general and NASDAQ have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks and of our securities may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to the Company could depress our stock price regardless of our business, prospects, financial conditions, or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.
Changes in laws or regulations or a failure to comply with any laws or regulations may adversely affect our business, investments, and results of operations.
We are subject to laws, regulations, and rules enacted by national, regional, and local governments. In particular, we are required to comply with certain SEC, NASDAQ, and other legal or regulatory requirements. Compliance with and monitoring of applicable laws, regulations, and rules may be difficult, time consuming, and costly. Those laws, regulations, and rules and their interpretation and application may also change from time to time, and those changes could have a material adverse effect on our business, investments, and results of operations. In addition, a failure to comply with applicable laws, regulations, and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.
Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations.
We will be subject to income taxes in the United States, and our domestic tax liabilities may be subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:
changes in the valuation of our deferred tax assets and liabilities;
expected timing and amount of the release of any tax valuation allowances;
tax effects of stock-based compensation;
costs related to intercompany restructurings;
changes in tax laws, regulations, or interpretations thereof; or
lower than anticipated future earnings in jurisdictions where we have lower statutory tax rates and higher than anticipated future earnings in jurisdictions where we have higher statutory tax rates.

In addition, we may be subject to audits of our income, franchise, sales, and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.
The Tax Cuts and Jobs Act (the “TCJA”) could adversely affect our financial condition and results of operations.
On December 22, 2017, the TCJA was signed into law, which significantly reforms the Internal Revenue Code of 1986, as amended. The TCJA, among other things, contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate, a partial limitation on the deductibility of net business interest expense, limitation of the deduction for certain net operating losses to 80 percent of current year taxable income, an indefinite net operating loss carryforward, immediate deductions for certain new investments instead of deductions for depreciation expense over time, and modification or repeal of many business deductions and credits. The presentation of our financial condition and results of operations have been recorded in accordance with GAAP, which requires the financial statement impact of the TCJA to be recorded in the period in which the TCJA was enacted. The financial statement impact of the TCJA is based on our current interpretation of the provisions contained in the TCJA and the Treasury Regulations and administrative guidance relating thereto. In the future, the Department of the Treasury and the Internal Revenue Service are expected to release additional Treasury Regulations and administrative guidance relating to the TCJA. Any significant variance of our current interpretation of this law from any future Treasury Regulations or administrative guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.

33



The JOBS Act permits “emerging growth companies” like us to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.
We qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies for as long as we continue to be an emerging growth company, including (i) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions from say-on-pay, say-on-frequency, and say-on-golden parachute voting requirements, and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. As a result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year (a) following April 4, 2022, the fifth anniversary of our initial public offering, (b) in which we have total annual gross revenue of at least $1.07 billion, or (c) in which we are deemed to be a large accelerated filer, which means the market value of our Class A Common Stock that is held by non-affiliates exceeds $700 million as of the last business day of our prior second fiscal quarter, and (ii) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period.
In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards provided in Section 7(a)(2)(B) of the Securities Act as long as we are an emerging growth company. An emerging growth company can, therefore, delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies, but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accountant standards used.
We cannot predict if investors will find our Class A Common Stock less attractive because we will rely on these exemptions. If some investors find our Class A Common Stock less attractive as a result, there may be a less active trading market for our Class A Common Stock, and our stock price may be more volatile.
Our charter designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees, or agents.
The charter provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (“Court of Chancery”) will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, or other employees to us or our stockholders, (iii) any action asserting a claim against us or any of our directors, officers, or employees of ours arising pursuant to any provision of the DGCL, the charter, or our bylaws, or (iv) any action asserting a claim against us or any of our directors, officers, or other employees that is governed by the internal affairs doctrine, in each case except for such claims as to which (a) the Court of Chancery determines that it does not have personal jurisdiction over an indispensable party, (b) exclusive jurisdiction is vested in a court or forum other than the Court of Chancery, or (c) the Court of Chancery does not have subject matter jurisdiction. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our charter described in the preceding sentence. This exclusive forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that the stockholder finds favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, or results of operations.
Our charter provides that the exclusive forum provision will be applicable to the fullest extent permitted by applicable law. Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Accordingly, our charter provides that the exclusive forum provision will not apply to suits brought to enforce any liability or duty created by the Exchange Act, the Securities Act, or any other claim for which the federal courts have exclusive jurisdiction.

34


ITEM 1B. UNRESOLVED STAFF COMMENTS

As of December 31, 2018, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

ITEM 3. LEGAL PROCEEDINGS

We are not aware of any pending or threatened legal proceedings against us at the time of the filing of this Annual Report on Form 10-K.

ITEM 4. MINE SAFETY DISCLOSURES

None.

35


PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information
Our common units (“Units”), Class A Common Stock and warrants were each traded on the NASDAQ Capital Market (“NASDAQ”) under the symbols “KAACU,” “KAAC” and “KAACW,” respectively, prior to the closing of the Business Combination. In connection with the closing of our Business Combination, our Units ceased trading, and our Class A Common Stock and warrants began trading on the NASDAQ under the symbols “ALTM” and “ALTMW,” respectively. Our Units commenced public trading on March 30, 2017, and our Class A Common Stock and warrants commenced public trading on April 27, 2017.
Our warrants ceased trading on the NASDAQ at the opening of business on December 20, 2018 and, since December 20, 2018, are quoted on the over-the-counter markets operated by OTC Markets Group under the symbol “ALTMW.” The warrants may still be exercised in accordance with their terms to purchase shares of the Company’s Class A Common Stock. The table below sets forth the high and low prices of our warrants, as reported on the OTC Marketplace, for the three-month period ended December 31, 2018. Our warrants commenced quotation on the OTC Markets on December 20, 2018, and, as a result, the quarterly information reflects only a partial quarter. Such quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.
 
Year Ended December 31, 2018
 
Warrants
 
High
 
Low
First Quarter
$

 
$

Second Quarter
$

 
$

Third Quarter
$

 
$

Fourth Quarter
$
0.74

 
$
0.63

On January 31, 2019, our Class A Common Stock had a closing price of $8.10 and our warrants had a closing price of $0.81.
Holders
On January 31, 2019, there were approximately 45 holders of record of our Class A Common Stock.
Dividends
We have not paid any cash dividends on our Class A Common Stock to date and do not intend to pay cash dividends in the foreseeable future.
Securities Authorized for Issuance Under Equity Compensation Plans
Information about our equity compensation plans is incorporated herein by reference to our definitive proxy statement for our 2019 Annual Meeting of Stockholders.
Recent Sales of Unregistered Securities
None.
Purchase of Equity Securities by the Issuer and Affiliated Purchasers
None.
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to both a broad equity market index and a published industry index. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of both the NASDAQ Composite Index and the Alerian US Midstream Energy

36


Index from April 30, 2017, through December 31, 2018. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

COMPARISON OF 20 MONTH CUMULATIVE TOTAL RETURN*
Among Altus Midstream Company, the NASDAQ Composite Index
and Alerian US Midstream Energy Index
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12747672&doc=20
* $100 invested on 5/2/17 in stock or 4/30/17 in index, including reinvestment of dividends.
Fiscal year ending December 31.
 
5/2/2017
 
2017
 
2018
Altus Midstream Company……………………
$
100.00

 
$
100.10

 
$
79.69

NASDAQ Composite…………………………
100.00

 
114.59

 
110.42

Alerian US Midstream Energy
100.00

 
93.29

 
83.11


37


ITEM 6. SELECTED FINANCIAL DATA 

The following table sets forth selected financial data of the Company for the period ended December 31, 2016 and for the years ended December 2017 and 2018. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in the Company’s consolidated financial statements set forth in Part IV, Item 15 of this Form 10-K.
 
 
Year Ended December 31,
 
Period from May 26, 2016 (Inception) through December 31,
 
 
2018
 
2017
 
2016
 
 
(In thousands, except per common share data)
Income Statement Data
 
 
 
 
 
 
Total revenues and other
 
$
78,358

 
$
15,142

 
$

Net loss including noncontrolling interest
 
(239
)
 
(18,575
)
 

Net income attributable to noncontrolling interest
 
4,149

 

 

Net loss attributable to Class A common shareholders
 
(4,388
)
 
(18,575
)
 

Earnings per share
 
 
 
 
 
 
Basic
 
$
(0.03
)
 
$
(0.30
)
 
$

Diluted
 
(0.03
)
 
(0.30
)
 

Balance Sheet
 
 
 
 
 
 
Total assets
 
$
1,857,319

 
$
705,751

 
$
155,967

Total liabilities
 
130,533

 
149,701

 
96,626

Redeemable noncontrolling interest
 
1,940,500

 

 

Total equity
 
(213,714
)
 
556,050

 
59,341

Cash Flow Data
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
Operating activities
 
$
661

 
$

 
$

Investing activities
 
(175,100
)
 

 

Financing activities
 
624,374

 

 

Non-GAAP Measures
 
 
 
 
 
 
Adjusted EBITDA (1)
 
$
7,827

 
$
(5,543
)
 
$

(1)
Adjusted EBITDA is not defined by accounting principles generally accepted in the United States (“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 definitions and reconciliations of Adjusted EBITDA most directly comparable GAAP measures, see Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.


38



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 Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Form 10-K.
Unless the context otherwise requires, “we,” “us,” “our,” the “Company,” “ALTM” and “Altus” refers to Altus Midstream Company and its consolidated subsidiaries. “Altus Midstream” refers to Altus Midstream LP and its consolidated subsidiaries.
Overview
Altus Midstream Company, through our ownership interest in Altus Midstream, owns gas gathering, processing and transmission assets in the Permian Basin of West Texas, anchored by midstream service contracts to service Apache Corporation’s (“Apache”) production from its Alpine High resource play (“Alpine High”). Additionally, we own, or have options to own, joint venture equity interests in a total of five Permian Basin pipelines (the “Pipeline Options”), four of which go to various points along the Texas Gulf Coast, providing the Company with additional access to fully integrated, wellhead-to-water connectivity. Our operations comprise one reportable segment.
We have no independent operations or material assets outside our ownership interest in Altus Midstream, which we report on a consolidated basis. As of December 31, 2018, Altus Midstream’s assets included approximately 111 miles of natural gas gathering pipelines, approximately 52 miles of residue gas pipelines with three market connections (with a fourth market connection expected to be in-service by the end of the first quarter of 2019), and approximately 26 miles of NGL Pipelines. Additionally, we own five rich gas processing facilities consisting of approximately 77,000 horsepower with 380 MMcf/d of rich gas processing capacity and two lean gas facilities consisting of 75,000 horsepower with 400 MMcf/d of lean gas treating capacity. Other assets include an NGL truck loading terminal with six lease automatic custody transfer (“LACT”) units and eight NGL bullet tanks with 90,000 gallon capacity per tank. Construction on the assets began in the fourth quarter of 2016, and operations commenced in the second quarter of 2017.
Corporate History
We were originally incorporated on December 12, 2016 in Delaware under the name Kayne Anderson Acquisition Corp. (“KAAC”), for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. We completed our public offering in the second quarter of 2017, after which our securities began separate trading on the NASDAQ Capital Market.
On August 8, 2018, KAAC and our then wholly-owned subsidiary, Altus Midstream LP, a Delaware limited partnership, entered into a contribution agreement (the “Contribution Agreement”) with certain wholly-owned subsidiaries of Apache Corporation (“Apache”), including the Alpine High Entities. The Alpine High Entities comprise four Delaware limited partnerships (collectively, “Alpine High Midstream”) and their general partner (Alpine High Subsidiary GP LLC, a Delaware limited liability company), formed by Apache between May 2016 and January 2017 for the purpose of acquiring, developing, and operating midstream oil and gas assets in Alpine High.
On November 9, 2018 (the “Closing Date”) and pursuant to the terms of that certain Contribution Agreement, we acquired from Apache, the entire equity interests of the Alpine High Entities and Pipeline Options to acquire equity interests in five separate third-party pipeline projects. We refer to the acquisition of the entities and the Pipeline Options as the “Business Combination.” In exchange, the consideration provided to Apache included economic voting and non-economic voting shares in Altus Midstream Company and limited partner interests in Altus Midstream. At the time of the Business Combination, we changed our name from Kayne Anderson Acquisition Corp. to Altus Midstream Company.
Presentation of Financial and Operating Information
Whilst Altus (formerly KAAC) was the surviving legal entity, the Business Combination was accounted for as a reverse recapitalization. Under this method of accounting, Altus was treated as the acquired company for financial reporting purposes. As a result, the historical operations of Alpine High Midstream are deemed to be those of the Company. Thus, the financial statements and related information included in this Form 10-K reflect (i) the historical operating results of Alpine High Midstream prior to the Closing Date (ii) the net assets of Alpine High Midstream at their historical cost (iii) the consolidated results of Altus and Alpine High Midstream after the Closing Date and (iv) Altus’ equity structure for all periods presented.

39



Altus Midstream Operational Assessment
We use a variety of financial and operational metrics to assess the performance of our operations and growth compared to expected plan estimates. These metrics include:
Throughput volumes and associated revenues;
Operating expenses; and
Adjusted EBITDA (as defined below).
Sources of Altus Midstream’s Revenues
Our results are driven primarily by the volume of natural gas gathered, processed, compressed, and/or transported. For the periods presented, all of our revenues were generated through fee-based agreements with Apache, a related party. The volume of natural gas that we gather or process currently depends on the production level of Apache’s assets in areas we service. Our assets have been, and continue to be, constructed to serve Apache’s development of Alpine High. The amount and pace of upstream development activity by Apache will impact our aggregate gathering and processing volumes because the production rate of natural gas wells declines over time. Additionally, other producers are also developing oil and gas plays in surrounding areas that may provide attractive opportunities to enter into third-party processing and gathering agreements. Producers’ willingness to engage in new drilling is determined by a number of factors, 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. We believe that our midstream assets are positioned in a highly economic play in one of the most active regions for oil and gas exploration and development activities in the United States.
Pursuant to the terms of existing agreements with Apache, we receive fees for gathering, processing, dehydration, compression, treating, conditioning, and transportation from acreage dedications provided by Apache. Although our current contracts are supported by acreage dedications covering Alpine High, we are pursuing new supplies of natural gas and processing arrangements with third parties to increase the throughput volume on our systems in addition to Apache’s projected development of Alpine High. For more information about our relationship with Apache, please see the section entitled Altus’ Relationship with Apache in Part I, Items 1 and 2 of this Form 10-K.
Operating expenses
Gathering, processing, and transmission
Our gathering, processing, and transmission (“GPT”) expenses primarily comprise those costs that are directly associated with the operations of our 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 our midstream assets is computed based on estimated useful lives and estimated salvage values. Also included within this expense is the accretion associated with our estimated asset retirement obligations (“ARO”). Depreciation and accretion expense is expected to increase over the next several years as additional infrastructure is built to facilitate expected volume growth.
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.
In connection with the closing of the Business Combination, the Company entered into a construction, operations and maintenance agreement with Apache (the “COMA”), pursuant to which Apache will provide certain services related to the design, development, construction, operation, management and maintenance of Altus Midstream assets, on the Company’s behalf.

40



Under the COMA, Altus Midstream will pay fees to Apache of (i) $3.0 million from November 9, 2018 through December 31, 2019, (ii) $5.0 million for the period of January 1, 2020 through December 31, 2020, (iii) $7.0 million for the period of January 1, 2021 through December 31, 2021 and (iv) $9.0 million annually, as may be increased thereafter until terminated. The annual fee was negotiated as part of the Business Combination to reimburse Apache for indirect costs of performing administrative corporate functions, including services for information technology, risk management, corporate planning, accounting, cash management, and others.
In addition, Apache may be reimbursed for certain internal costs and third-party costs directly incurred in connection with its role as service provider under the COMA. Apache records G&A costs directly associated with midstream activity, where substantially all the services are rendered for Altus Midstream, to unique midstream G&A cost centers that are subsequently charged to Altus Midstream on a monthly basis.
Prior to entering into the COMA, to reimburse Apache for certain overhead and service costs incurred on behalf of its Alpine High Entities, a monthly fee was charged to the midstream entities over the historical period upon commencement of operations. The monthly contract services fee was approximately $0.3 million per month. The fee charged was calculated based on a variety of factors, such as the estimated percentage of time spent and costs incurred by Apache to perform administrative services similar to those performed under the COMA.
Taxes other than income
Taxes other than income primarily comprise ad valorem taxes on our midstream assets. Management anticipates future increases in ad valorem taxes, in line with the construction of its midstream assets. We are also subject to gas utility taxes payable to the Railroad Commission of Texas.
Adjusted EBITDA
We define Adjusted EBITDA as net income (loss) including noncontrolling interest before interest expense, income taxes, depreciation, and accretion, and also exclude (when applicable) impairments and other items affecting comparability of results to peers. Altus’ management believes Adjusted EBITDA is useful for evaluating our operating performance and comparing results of its 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) or any other measure determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our 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 our results will be unaffected by unusual or non-recurring items. Additionally, our computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
Adjusted EBITDA is not defined in GAAP
The GAAP measures used by Altus that are most directly comparable to Adjusted EBITDA are net income (loss) including noncontrolling interest and net cash provided by (used in) operating activities. Adjusted EBITDA should not be considered as an alternative to the GAAP measures of net income (loss) including noncontrolling interest, net cash provided by (used in) operating activities or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA has important limitations as analytical tools because they exclude some, but not all, items that affect net income (loss) attributable to Altus and net cash provided by (used in) operating activities. Adjusted EBITDA should not be considered in isolation or as a substitute for analysis of Altus’ results as reported under GAAP. Altus’ definitions of Adjusted EBITDA may not be comparable to similarly titled measures of other companies in Altus’ industry, thereby diminishing its utility.
Reconciliation of non-GAAP financial measures
Altus’ management compensates for the limitations of Adjusted EBITDA as an analytical tool, by reviewing the comparable GAAP measures, understanding the differences between Adjusted EBITDA as compared to (as applicable) net income (loss) including noncontrolling interest and net cash provided by (used in) operating activities, and incorporating this knowledge into its decision-making processes. Altus believes that investors benefit from having access to the same financial measures that its management uses in evaluating operating results.

41



The following table presents a reconciliation of the GAAP financial measures of net income (loss) including noncontrolling interest and net cash provided by (used in) operating activities to the non-GAAP financial measure of Adjusted EBITDA.
 
 
Year Ended December 31,
 
Period from May 26, 2016 (Inception) through December 31,
 
 
2018
 
2017
 
2016
 
 
(In thousands)
Reconciliation of Net loss including noncontrolling interest
 
 
 
 
 
 
Net loss including noncontrolling interest
 
$
(239
)
 
$
(18,575
)
 
$

Add:
 
 
 
 
 
 
Financing costs, net
 
107

 

 

  Income tax (benefit) expense
 
(10,501
)
 
7,041

 

  Depreciation and accretion
 
20,068

 
5,991

 

Less:
 
 
 
 
 
 
  Interest income
 
1,608

 

 

Adjusted EBITDA
 
$
7,827

 
$
(5,543
)
 
$

 
 
 
 
 
 
 
Reconciliation of net cash provided by operating activities to adjusted EBITDA
 
 
 
 
 
 
Net cash provided by operating activities
 
$
661

 
$

 
$

Interest income
 
(1,608
)
 

 

Current income tax benefit
 
(1,041
)
 

 

Financing costs, net
 
107
 

 

Adjustment for non-cash transactions with Affiliate
 
4,238
 
(9,601
)
 

Changes in working capital
 
5,470
 
4,058

 

Adjusted EBITDA
 
$
7,827

 
$
(5,543
)
 
$

 
 
 
 
 
 
 
Cash Flow Data
 
 
 
 
 
 
Net cash provided by operating activities
 
$
661

 
$

 
$

Net cash used in investing activities
 
(175,100
)
 

 

Net cash provided by financing activities
 
624,374

 

 

Items Affecting Comparability of Our Financial Condition and Results of Operations
Future financial data of Altus Midstream attributable to us may not be comparable to the historical results of our operations for the periods presented due to the following reasons:
Construction of Assets

Since inception, we have invested capital to develop our assets in the Permian Basin of West Texas. Construction on the assets began in the fourth quarter of 2016, and operations commenced in the second quarter of 2017. We anticipate additional investments in the continued capital development of our midstream assets of approximately $325 million in 2019, approximately $185 million in 2020 and approximately $200 million in 2021. The investment will primarily be directed toward the construction of additional gathering, compression, processing, and transportation facilities, including three forecasted cryogenic processing plants expected to be in-service during 2019 with combined nameplate capacity of approximately 600 MMcf/d. Additional capacity will be added over the next several years to facilitate production increases from Alpine High and potential third-party volumes.

42



Joint Venture Equity Options

As part of the Business Combination, we obtained the right, but not the obligation, to exercise the Pipeline Options. Our option to enter into a 15 percent ownership stake in the Gulf Coast Express natural gas pipeline was exercised in December 2018 for $91.1 million. We expect to exercise the remaining four Pipeline Options in 2019 and early 2020, resulting in approximately $1.6 billion of total anticipated capital spending for the exercise of these options and the associated capital requirements required until the associated pipelines are in service. This includes approximately $1.3 billion in 2019 and approximately $340 million in 2020. These options provide Adjusted EBITDA upside potential as well as investment opportunity not reflected in historical results.
The following table provides additional information regarding the exercise of the Pipeline Options:
 
 
EPIC Option (1)
 
Salt Creek Option
 
Shin Oak Option
 
Permian Highway Option (2)
Expiration Date
 
February 1, 2019
 
January 31, 2020
 
60 days following in-service date
 
September 4, 2019
Option Percentage
 
15%
 
50%
 
33%
 
27%
Estimated Exercise Price(3)
 
$52 million
 
$51 million
 
$500 million
 
$232 million
(1)
Subsequent to the balance sheet date, the EPIC Option was exercised on February 1, 2019.
(2)
Upon exercising the Permian Highway Pipeline Option, the Company may acquire an additional 1 percent interest in GCX.
(3)
Estimated exercise price represents our proportionate share of capital expenditures made with respect to the applicable project prior to such exercise, plus financing charges associated with such capital expenditures (“exercise price”). There are no costs associated with exercising the Pipeline Options other than the exercise price. However, we will be required to fund our pro rata share of capital expenditures after the exercise date.
Throughput of Volumes
We currently generate all of our revenues under fee-based agreements with Apache. These agreements are expected to result in cash flow consistency and minimize our direct exposure to commodity price fluctuations because we generally do not engage in the selling, marketing, or trading of crude oil, natural gas, or NGLs. Commodity price variances indirectly impact our activities and results of operations over the long term because prices can influence production rates and investments by Apache and other third parties in the development of new crude oil and natural gas reserves. Generally, drilling and production activity will increase as crude oil, NGL and natural gas prices increase. The throughput volumes will depend primarily on the volume of natural gas produced by Apache in Alpine High. Despite projected producer economics in Alpine High, we cannot guarantee volume throughput, and our existing commercial arrangements with Apache do not provide volume commitments. We believe the Alpine High acreage dedication from Apache is an attractive alternative to a volume commitment due to the large acreage footprint containing stacked pay potential.
Operation of Assets
As assets are placed into service over the next several years, additional operating expenses are expected to trend higher given the increased capital expenditures and number of facilities being utilized. The assets currently in service are new, and over time, as anticipated, we project that maintenance and repair costs will increase as the assets age. We are also subject to operational issues caused by off-specification natural gas transported to our processing plants.
Income Taxes

Alpine High Midstream is a group of entities that are disregarded as entities separate from their regarded owner, Apache. For U.S. federal income tax purposes, Apache is a C-corporation under the Internal Revenue Code. As a result, federal taxable income associated with Alpine High Midstream has historically been included in Apache’s consolidated federal income tax return. Alpine High Midstream is also subject to the Texas margin tax and the Alpine High Midstream entities have historically been included in the Apache combined Texas margin tax return.
At the closing of the Business Combination, Apache contributed the Alpine High Entities and the Pipeline Options to Altus Midstream with the Alpine High Midstream entities now treated as disregarded entities under Altus Midstream. Altus Midstream will not be subject to U.S. federal income tax and will instead pass through its taxable income to its partners - being Apache and Altus - upon closing of the Business Combination. As a result of the change in ownership structure, Altus will record net income or loss before income taxes attributable to both the controlling and noncontrolling interest; however, Altus will only report an income tax provision associated with the Company’s investment in Altus Midstream and Altus’ corporate operations. Our management will continue to assess the Company’s ability to realize any net deferred tax assets.

43



Public Company Expenses
The Company incurs direct, incremental G&A expense as a result of being a publicly traded company, including, but not limited to, costs associated with preparing annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and other similar costs. These direct, incremental G&A expenses are expected to increase in future periods, given the change in the Company’s capital structure upon the closing of the Business Combination.

44



Results of Operations

The following table presents the Company’s results of operations for the periods presented:
 
 
Year Ended December 31,
 
Period from May 26, 2016 (Inception) through December 31,
 
 
2018
 
2017
 
2016
 
 
(In thousands)
REVENUES AND OTHER:
 
 
 
 
 
 
Midstream services — affiliate
 
$
76,750

 
$
15,142

 
$

Other
 
1,608

 

 

Total revenues and other
 
78,358

 
15,142

 

OPERATING EXPENSES:
 
 
 
 
 
 
Gathering, processing, and transmission
 
53,922

 
16,597

 

General and administrative
 
7,368

 
3,991

 

Depreciation and accretion
 
20,068

 
5,991

 

Taxes other than income
 
7,633

 
97

 

Financing costs, net
 
107

 

 

Total operating expenses
 
89,098

 
26,676

 

NET LOSS BEFORE INCOME TAXES
 
(10,740
)
 
(11,534
)
 

Current income tax benefit
 
(1,041
)
 

 

Deferred income tax (benefit) expense
 
(9,460
)
 
7,041

 

NET LOSS INCLUDING NONCONTROLLING INTEREST
 
(239
)
 
(18,575
)
 

Net income attributable to noncontrolling interest
 
4,149

 

 

NET LOSS ATTRIBUTABLE TO CLASS A COMMON SHAREHOLDERS
 
$
(4,388
)
 
$
(18,575
)
 
$

KEY PERFORMANCE METRICS:
 
 
 
 
 
 
Adjusted EBITDA (1)
 
$
7,827

 
$
(5,543
)
 
$

OPERATING DATA:
 
 
 
 
 
 
Average throughput volumes of natural gas (MMcf/d)
 
333

 
69

 

Average volumes of natural gas processed (MMcf/d)
 
333

 
69

 

(1)
Adjusted EBITDA is not defined by accounting principles generally accepted in the United States (“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 definitions and reconciliations of Adjusted EBITDA most directly comparable to GAAP measures, see the section entitled Adjusted EBITDA above.
For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2018” refer to the comparison of “2018 vs. 2017,” and any increases or decreases “for the year ended December 31, 2017” refer to the comparison of “2017 vs. 2016.”







45



Midstream Revenues
The following table summarizes the Company’s revenues for the periods presented:
 
 
Year Ended December 31,

Period from May 26, 2016 (Inception) through December 31,
 
 
2018
 
2017
 
2016
 
 
(In thousands)
REVENUES AND OTHER:
 
 
 
 
 
 
Midstream services — affiliate
 
$
76,750

 
$
15,142

 
$

Other
 
1,608

 

 

Total revenues and other
 
$
78,358

 
$
15,142

 
$

2018 vs. 2017. Midstream services revenue from affiliate increased by $61.6 million to $76.8 million for the year ended December 31, 2018, as compared to $15.1 million for the year ended December 31, 2017. The increase is solely attributed to activity ramp-up following the commencement of operations on the midstream assets in the second quarter of 2017, resulting in increased throughput volumes as Apache increased production from Alpine High. All midstream services revenues were generated through fee-based contractual arrangements with Apache. These services include gas gathering, processing, and transmission. The revenue earned from these services is directly related to the volume of natural gas and NGLs that flow through our systems, and we do not take ownership of the natural gas or NGLs handled for Apache. Other revenue is related to interest income.
2017 vs. 2016. Midstream services revenue from affiliate increased by $15.1 million for the year ended December 31, 2017, as compared to no revenues for the period ended December 31, 2016, which is commensurate with the Company achieving its first sales in 2017. The increase is solely attributed to the Company’s commencement of operations on the midstream assets in the second quarter of 2017, resulting in increased throughput volumes as Apache increased production from Alpine High. All midstream services revenues were generated through fee-based contractual arrangements with Apache. These services include gas gathering, transmission, and processing. The revenue earned from these services is directly related to the volume of natural gas and NGLs that flow through the Company’s systems, and the Company does not take ownership of the natural gas handled for Apache.
Operating Expenses
The following table summarizes the Company’s operating expenses for the periods presented:
 
 
Year Ended December 31,
 
Period from May 26, 2016 (Inception) through December 31,
 
 
2018
 
2017
 
2016
 
 
(In thousands)
Gathering, processing, and transmission
 
$
53,922

 
$
16,597

 
$

General and administrative
 
7,368

 
3,991

 

Depreciation and accretion
 
20,068

 
5,991

 

Taxes other than income
 
7,633

 
97

 

Financing costs, net
 
107

 

 

Total operating expenses
 
$
89,098

 
$
26,676

 
$

Gathering, processing, and transmission expenses
2018 vs. 2017. GPT expenses increased by $37.3 million to $53.9 million for the year ended December 31, 2018, as compared to $16.6 million for the year ended December 31, 2017, which is commensurate with activity ramp-up following the commencement of our initial operations in the second quarter of 2017. GPT expenses are expected to increase over the next several years as additional infrastructure is built to facilitate expected volume growth.

46



2017 vs. 2016. GPT expenses increased by $16.6 million to $16.6 million for the year ended December 31, 2017, as compared to no expense for the period ended December 31, 2016, which is commensurate with the commencement of the Company’s initial operations in the second quarter of 2017.
General and administrative expense
2018 vs. 2017. G&A expense increased by $3.4 million to $7.4 million for the year ended December 31, 2018, as compared to $4.0 million for the year ended December 31, 2017, which reflects the increase in overhead support services due to organizational growth, coupled with higher expenses incurred related to insurance, audit and other public filing requirements.
2017 vs. 2016. G&A expense increased by $4.0 million to $4.0 million for the year ended December 31, 2017, as compared to no G&A expense for the period ended December 31, 2016, which reflects the commencement of the Company’s operations in the second quarter of 2017.
Depreciation and accretion expense
2018 vs. 2017. Depreciation and accretion expense increased by $14.1 million to $20.1 million for the year ended December 31, 2018, as compared to $6.0 million for the year ended December 31, 2017. The increase represents the timing of placing assets into service following construction activity over the historical period. Depreciation and accretion expense is expected to increase over the next several years as additional infrastructure is built to facilitate expected volume growth.
2017 vs. 2016. Depreciation and accretion expense increased by $6.0 million to $6.0 million for the year ended December 31, 2017, as compared to no depreciation and accretion expense for the period ended December 31, 2016. The increase represents the timing of placing assets into service following construction activity over the historical period.
Taxes other than income
2018 vs. 2017. Ad valorem taxes were first assessed in the second half of 2017 and were immaterial given the start-up nature of the midstream assets. Ad valorem taxes increased by $7.5 million to $7.6 million for the year ended December 31, 2018, as compared to $0.1 million for the year ended December 31, 2017. This increase represents the higher tax assessment in the current year related to completion of construction of certain assets.
2017 vs. 2016. Ad valorem taxes were first assessed in the second half of 2017 and were immaterial given the start-up nature of the midstream assets.
Financing costs, net
Financing costs incurred during the period comprised the following:
 
 
Year Ended December 31,
 
Period from May 26, 2016 (Inception) through December 31,
 
 
2018(1)
 
2017(1)
 
2016(1)
 
 
(In thousands)
Interest expense
 
$
8,412

 
$
7,100

 
$
272

Amortization of deferred facility fees
 
107

 

 

Capitalized interest
 
(8,412
)
 
(7,100
)
 
(272
)
Total Financing costs, net
 
$
107

 
$

 
$

(1)
Prior to the Business Combination, the Company’s operations were funded entirely by contributions from Apache. Accordingly, Apache allocated a portion of interest on its corporate debt in determining capitalized interest associated with the development of Alpine High infrastructure. Refer to Note 1 — Summary of Significant Accounting Policies and Note 3 — Transactions with Affiliates in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K for further information.
2018 vs. 2017.  Net financing costs increased $0.1 million from 2017, associated with the revolving credit facility entered into by Altus Midstream in November 2018.


47



Provisions for Income Taxes
2018 vs. 2017. Income tax expense for the year ended December 31, 2018 and 2017 was a benefit of $10.5 million and an expense of $7.0 million, respectively. Income tax benefit for the year ended December 31, 2018 was primarily impacted by the change in valuation allowance, state taxes, and federal partnership income not subject to tax by the Company. Income tax expense for the year ended December 31, 2017 was primarily impacted by the change in valuation allowance, state tax expense, and deferred tax expense associated with the reduction in U.S. income tax rate from 35 percent to 21 percent. Please refer to Note 10 — Income Taxes set forth in Part IV, Item 15 of this Form 10-K for further discussion.
2017 vs. 2016. Income tax expense for the year ended December 31, 2017 was $7.0 million. There was no income tax provision in 2016. Income tax expense for the year ended December 31, 2017 was primarily impacted by the change in valuation allowance, state tax expense, and deferred tax expense associated with the reduction in U.S. income tax rate from 35.0 percent to 21 percent. Alpine High Midstream commenced operations in 2017. No income tax expense was recorded for the period ended December 31, 2016. Please refer to Note 10 — Income Taxes set forth in Part IV, Item 15 of this Form 10-K for further discussion.
Key Performance Metrics
2018 vs. 2017. Adjusted EBITDA increased by $13.4 million for the year ended December 31, 2018, primarily due to a $61.6 million increase in midstream service revenue from affiliate. These amounts were partially offset by a $37.3 million increase in GPT expenses, a $7.5 million increase in ad valorem taxes, and a $3.4 million increase in G&A expenses. Higher Adjusted EBITDA is primarily attributed to activity ramp-up following the commencement of operations on the midstream assets in the second quarter of 2017, resulting in increased throughput volumes as Apache increased production from Alpine High.
2017 vs. 2016. Adjusted EBITDA was a deficit of $5.5 million for the year ended December 31, 2017. Adjusted EBITDA was directly impacted by the Company’s commencement of operations on the midstream assets in the second quarter of 2017, and the start-up nature of initial services. The Company had no meaningful Adjusted EBITDA in 2016 as operations commenced in the second quarter of 2017.
Capital Resources and Liquidity
Altus Midstream Overview
Our plans for future infrastructure development and construction of our midstream assets, as well as the exercise of the Pipeline Options still outstanding, will require significant capital expenditures in excess of current cash on hand and operational cash flow. To date, our primary use of capital has been for the initial construction of assets. Historically, our primary source of liquidity has been capital contributions from Apache. As our operations commenced in the second quarter of 2017, limited cash from operations has been generated. While our assets are being constructed, our ongoing sources of liquidity are expected to be cash generated from operations which are anticipated to increase over time, cash on the balance sheet from the Business Combination, and cash proceeds from raising capital (such as debt or equity). Management expects throughput and processing volumes to increase considerably during this initial development phase given the production forecast for acreage that has been dedicated to us. Based on the current financial plan, we believe our operations and capital program for midstream operations will begin to generate operating cash flows in excess of investment expenditures by year-end 2021.
Altus Midstream and/or its subsidiaries anticipate using its cash position, revolving credit facility borrowing capacity (as further described below), and reinvested operating cash flow to fund its near-term capital requirements, including the capital needs upon exercising the Pipeline Options. In addition, Altus Midstream and/or its subsidiaries expect to evaluate additional sources of financing to facilitate its capital investments, including additional borrowings, preferred equity, asset-level financing, and common equity.
If we are unable to obtain funds or provide funds as needed for the planned capital expenditure program, we may not be able to finance the capital expenditures necessary to achieve our expansion plans, exercise the Pipeline Options outstanding, or maintain our business as currently conducted.
Altus Midstream Capital Requirements
During 2018, 2017, and 2016, capital spending for our assets totaled $568.5 million, $505.7 million, and $59.3 million. Prior to the Business Combination, asset expenditures in 2018, 2017, and 2016 primarily comprise investments in infrastructure for Alpine High made by Apache that were contributed to Altus Midstream.
We anticipate additional investments in the continued capital development of Altus Midstream’s assets of approximately $325 million in 2019, approximately $185 million in 2020 and approximately $200 million in 2021.The investment will primarily

48



be directed toward the construction of additional gathering, compression, processing, and transportation facilities, including three forecasted cryogenic processing plants expected to be in-service during 2019 with combined nameplate capacity of approximately 600 MMcf/d. Additional capacity will be added over the next several years to facilitate production increases from Alpine High and potential third party volumes. Operating cash flows are not expected to cover all of these capital investments.
As part of the Business Combination, we obtained the right, but not the obligation, to exercise the Pipeline Options. Our option to enter into a 15 percent ownership stake in the Gulf Coast Express natural gas pipeline was exercised in December 2018 for $91.1 million. We expect to exercise the remaining four Pipeline Options in 2019 and early 2020, resulting in approximately $1.6 billion of total anticipated capital spending for the exercise of these options and the associated capital requirements required until the associated pipelines are in service. This includes approximately $1.3 billion in 2019 and approximately $340 million in 2020.
Liquidity
Cash and cash equivalents
At December 31, 2018, we had $449.9 million 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.
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 provides aggregate commitments from a syndicate of banks of $450.0 million until (i) the consolidated net income of Altus Midstream and its restricted subsidiaries, as adjusted pursuant to the agreement (“EBITDA”), for three consecutive calendar months equals or exceeds $175.0 million on an annualized basis and (ii) Altus Midstream has raised at least $250.0 million of additional capital (such period, the “Initial Period”). Following the Initial Period, the aggregate commitments equal $800.0 million. All 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. After the Initial Period, 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, 2018, no borrowings or letters of credit were outstanding under this facility.
The Altus Midstream revolving credit facility is unsecured and is not guaranteed by the Company, Apache Corporation, or any of their respective subsidiaries.
At Altus Midstream’s option, the interest rate per annum for borrowings under its 2018 credit facility is either a base rate, as defined, plus a margin, or the London Inter-bank Offered Rate (“LIBOR”), plus a margin. Altus Midstream also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon (i) the Leverage Ratio 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 of Altus Midstream and its restricted subsidiaries for the 12-month period ending immediately before such date. At December 31, 2018, the base rate margin was 0.05 percent, the LIBOR margin was 1.05 percent, and the facility fee was 0.20 percent. A commission is payable quarterly to 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 credit agreement for Altus Midstream’s revolving credit facility 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 credit agreement, which requires it to maintain one of the following financial ratios:
during the Initial Period, a debt-to-capital ratio of not greater than 30 percent at the end of any fiscal quarter, determined by reference to (i) the consolidated indebtedness of Altus Midstream and its restricted subsidiaries to (ii) (A) the consolidated partners’ equity of Altus Midstream and its restricted subsidiaries plus (B) the consolidated indebtedness of Altus Midstream and its restricted subsidiaries; and
after the Initial Period, a Leverage Ratio of not greater than 5.00:1.00 at the end of any fiscal quarter, except that for up to one year following a qualified acquisition, the Leverage Ratio cannot exceed 5.50:1.00 at the end of any fiscal quarter.

49



There are no clauses in the agreement for Altus Midstream’s 2018 revolving credit facility that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The 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 its 2018 credit facility as of December 31, 2018.
There is no assurance that the financial condition of banks with lending commitments to Altus Midstream will not deteriorate. We closely monitor the ratings of the banks in our 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

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 our liquidity or capital resource positions.
At the close of the Business Combination, Apache was granted the right to receive contingent consideration of up to 37,500,000 shares of Class A Common Stock as follows:
i.
12,500,000 shares if, during the calendar year 2021, the aggregate gathered gas from an area of dedication in Reeves, Pecos, Culberson, and Jeff Davis Counties in Texas that are assessed a low pressure gathering fee pursuant to that certain Amended and Restated Gas Gathering Agreement, dated August 8, 2018, between Apache and Alpine High Gathering, LP is equal to or greater than 574,380 million cubic feet.
ii.
12,500,000 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 great than $14.00 for any 20 trading days within such 30-trading-day period.
iii.
12,500,000 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 $16.00 for any 20 trading days within such 30-trading-day period.
For additional information regarding these arrangements, please see Note 11 — Equity in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
Contractual Obligations
The following table summarizes the Company’s contractual obligations as of December 31, 2018. For additional information regarding these obligations, please see Note 3 — 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 Form 10-K.
Contractual Obligations (1)
 
Note
Reference
 
Total    
 
2019
 
2020-2021
 
2022-2023
 
2024 & Beyond    
 
 
(In thousands)
COMA fee(2)
 
Note 3
 
$
23,626

 
$
2,626

 
$
12,000

 
$
9,000

 
$

Credit facility fee(3)
 
Note 5
 
7,918

 
1,638

 
3,275

 
3,005

 

Operating lease obligations(4)
 
Note 3
 
2,060

 
534

 
1,068

 
458

 

Total Contractual Obligations
 
 
 
$
33,604

 
$
4,798

 
$
16,343

 
$
12,463

 
$

(1)
This table does not include the Company’s liability for dismantlement, abandonment, and restoration costs of midstream assets. For additional information regarding these liabilities, please see Note 7 — Asset Retirement Obligations in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
(2)
Amounts represent annual general and administrative fees established under the COMA for payment to Apache for certain administrative and operational support services being provided to Altus Midstream. The annual general and administrative fee cannot be increased until after the fourth anniversary of the Business Combination and will be redetermined annually thereafter.

50



(3)
Facility fee obligations are associated with the revolving credit facility’s total aggregated commitments. The fee assumes unused total commitments of $800 million for all periods presented.
(4)
Amounts include long-term lease payments to Apache under the Lease Agreement for office space, warehouse and storage facilities located in Reeves County, Texas. The obligation amount is determined on the base rental charge. The initial term of the Lease Agreement is for four years and may be extended by Altus Midstream for three additional, consecutive periods of twenty-four months.
As further described above under the section entitled Items Affecting Comparability of Our Financial Condition and Results of Operations, we obtained the Pipeline Options from Apache at the closing of the Business Combination. Upon exercising each individual option, the Company may be required to fund future capital expenditures for its equity interest share in the development of the pipeline as referenced. In December 2018, the Company exercised its option for a 15 percent equity interest in the GCX LLC Pipeline. The Company estimates it will incur $175.3 million of additional capital contributions during 2019 for its equity interest associated with the remaining construction costs in this joint venture pipeline.
Additionally, Altus has other planned capital and investment projects that are discretionary in nature, with no substantial contractual obligations made in advance of the actual expenditures. These expenditures align with the Company’s current infrastructure development plan and growth forecasts. The Company’s midstream assets are anchored by Altus Midstream’s existing fee-based 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 transportation on all volumes produced from the dedicated acreage, so long as Apache has the right to market such gas.
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 or environmental matters. As of December 31, 2018, there were no accruals or loss contingencies. 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 Form 10-K.
Insurance Program
The Company has the benefit of insurance policies that include coverage for physical damage to our assets, general liabilities, business interruption insurance, sudden and accidental pollution, and other risks. Our insurance coverage is subject to deductibles or retentions that we must satisfy prior to recovering on insurance. Additionally, our insurance is subject to policy exclusions and limitations. There is no assurance that our insurance will adequately protect us against liability from all potential consequences and damages.
Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable.

Critical Accounting Policies and Estimates

We prepare our financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, 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 identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies 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 our most critical accounting policies.
Property, Plant and Equipment 
Property, plant and equipment is stated at historical cost less accumulated depreciation. Expenditures which extend the useful lives of existing property, plant and equipment, maintain the long-term system operating capacity of our assets, or increase system throughput or capacity from current levels are capitalized. We capitalize construction-related direct labor and incremental costs, while repair and maintenance costs are expensed as incurred.
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,

51



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. The estimated lives are 30 years for plants and facilities and 40 years for pipelines.
When properties are retired or otherwise disposed of, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized as gain or loss.
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 that their carrying amounts may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the carrying amount of the asset is not expected to be recoverable from future undiscounted cash flows, an impairment may be recognized. Any impairment is measured as the excess of the carrying amount of the asset over its estimated fair value.
In assessing long-lived assets for impairments, our management evaluates changes in our business and economic conditions and their implications for recoverability of the assets’ carrying amounts. Currently all of our revenues arise from services provided to Apache. Therefore, significant downward revisions in reserve estimates or changes in future development plans by Apache, to the extent they affect our operations, may necessitate assessment of the carrying amount of our affected assets for recoverability.
Such assessment requires application of judgment regarding the use and ultimate disposition of the asset, long-range revenue and expense estimates, global and regional economic conditions, including commodity prices and drilling activity by our customers, as well as other factors affecting estimated future net cash flows. The measure of impairments to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available.
We have not recognized any impairments of long-lived assets since inception.
Income Taxes
Our operations are subject to U.S. federal and state taxation on income. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the ability to realize our deferred tax assets. If we conclude 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. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions.
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. The Company does not currently have any uncertain tax positions that would require recognition.

52


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Quantitative and Qualitative Disclosure About Market Risk
We are exposed to various market risks, including the effects of adverse changes in commodity prices and credit risk as described below.
Commodity Price Risk
Currently all of our midstream service agreements are fee-based, with no direct commodity price exposure to oil, natural gas, or NGLs. However, we are indirectly exposed to adverse changes in commodity prices through Apache and potential third-party customers’ economic decisions to develop and produce oil and natural gas from which we receive revenues for providing gathering, processing and transmission services.
Fluctuations in commodity prices also 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. Management regularly reviews our potential exposure to commodity price risk, and may periodically enter into financial or physical arrangements intended to mitigate potential volatility.
Credit Risk
We are subject to credit risk resulting from nonpayment or nonperformance by, or the insolvency or liquidation of, Apache or potential third-party customers. Any increase in the nonpayment and nonperformance by, or the insolvency or liquidation of, our customers could adversely affect our results of operations.

53


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F-31 in Part IV, Item 15 of this Form 10-K and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
On December 17, 2018, the board of directors of Altus Midstream Company, upon the recommendation of the Audit Committee of the board of directors, unanimously resolved (i) to dismiss WithumSmith+Brown, PC (“Withum”) as its independent public accountants and (ii) to engage Ernst & Young LLP (“EY”) to serve as the Company’s independent public accountants for the fiscal year ending December 31, 2018. This decision followed the consummation of the Business Combination on November 9, 2018. Please refer to the Form 8-K filed on December 17, 2018 for additional information.
There have been no disagreements with the accountants during the periods presented.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
The Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and the Company’s Chief Financial Officer and Treasurer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2018, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information we are required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to the “Report of Management on Internal Control Over Financial Reporting,” included on Page F-1 in Part IV, Item 15 of this Form 10-K.
The Company is an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the JOBS Act and is not required to comply with the independent registered public accounting firm attestation requirements of Section 404 of the Sarbanes-Oxley Act. As such, this annual report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting.
Changes in Internal Control Over Financial Reporting

During the quarter ended December 31, 2018, we implemented changes to internal control over financial reporting related to the Business Combination which closed on November 9, 2018. The modified and new controls have been designed to address risks associated with changes to the business after the completion of the Business Combination, including modifications to accounting policies and contract review controls. There were no other changes in our internal control over financial reporting during the quarter ended December 31, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.


54


PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information set forth under the captions “Election of Directors” and “Executive Officers of the Company” in the proxy statement relating to the Company’s 2019 annual meeting of shareholders (the “Proxy Statement”) is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information set forth under the captions “Executive Compensation” and “APPROVAL OF THE OMNIBUS COMPENSATION PLAN” in the Proxy Statement are incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information set forth under the captions “Securities Ownership and Principal Holders,” “Securities Authorized for Issuance Under Equity Compensation Plans” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

See Note 3 — Transactions with Affiliates of our financial statements, under Item 8 above, for information regarding payments to Apache Corporation. The information set forth under the captions “Certain Business Relationships and Transactions” and “Director Independence” in the Proxy Statement is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information set forth under the caption “Ratification of Appointment of Independent Auditors” in the Proxy Statement is incorporated herein by reference.



55


PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)
Documents included in this report:
1.
Financial Statements
 
 
 
 
 
 
 
 
 
 
 
 
2.
Financial Statement Schedules
 
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s financial statements and related notes.
3.
Exhibits
See Index to Exhibits of this report.

ITEM 16. FORM 10-K SUMMARY
None



56


SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

ALTUS MIDSTREAM COMPANY


/s/ Clay Bretches                    
Clay Bretches
Chief Executive Officer and President

Dated: February 28, 2019

POWER OF ATTORNEY
The officers and directors of Altus Midstream Company, whose signatures appear below, hereby constitute and appoint Clay Bretches and Ben C. Rodgers, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
Name
  
Title
  
Date
/s/ Clay Bretches
Clay Bretches
  
Director, Chief Executive Officer, and President
(principal executive officer)
  
February 28, 2019
/s/ Ben C. Rodgers
Ben C. Rodgers
  
Director, Chief Financial Officer, and Treasurer
 (principal financial officer)
  
February 28, 2019
/s/ Mark Borer
Mark Borer
  
Director
  
February 28, 2019
/s/ Robert W. Bourne
Robert W. Bourne
  
Director, Vice President, Business Development - Midstream and Marketing
  
February 28, 2019
/s/ Staci L. Burns
Staci L. Burns
  
Director
  
February 28, 2019
/s/ C. Doug Johnson
C. Doug Johnson
  
Director
  
February 28, 2019
/s/ D. Mark Leland
D. Mark Leland
  
Director
  
February 28, 2019
/s/ Kevin S. McCarthy
Kevin S. McCarthy
  
Director
  
February 28, 2019
/s/ W. Mark Meyer
W. Mark Meyer
  
Director, Chairman of the Board, and Senior Vice President, Energy Technology, Data Analytics & Commercial Intelligence
  
February 28, 2019
/s/ Robert S. Purgason
Robert S. Purgason
  
Director
  
February 28, 2019
/s/ Jon W. Sauer
Jon W. Sauer
  
Director, Senior Vice President
  
February 28, 2019


57


REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.
Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company’s board of directors, applicable to all Company directors and all officers of our Company.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2018.

The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit
Committee of the Company’s board of directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of Altus Midstream Company and its subsidiaries. The report of the independent auditors follows this report on page F-2.

The Company is an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the JOBS Act and is not required to comply with the independent registered public accounting firm attestation requirements of Section 404 of the Sarbanes-Oxley Act. As such, this annual report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting.


/s/ Clay Bretches

Chief Executive Officer and President

(principal executive officer)
 
/s/ Ben C. Rodgers
Chief Financial Officer and Treasurer
(principal financial officer)
 
/s/ Rebecca A. Hoyt
Senior Vice President, Chief Accounting Officer and Controller
(principal accounting officer)

Houston, Texas
February 28, 2019





F-1



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Altus Midstream Company:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Altus Midstream Company (the Company) as of December 31, 2018 and 2017, and the related consolidated statements of operations, cash flows and changes in equity and noncontrolling interest for each of the two years in the period ended December 31, 2018 and the period from inception (May 26, 2016) through December 31, 2016, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018 and the period from inception (May 26, 2016) through December 31, 2016, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2018.

Houston, Texas
February 28, 2019

F-2



ALTUS MIDSTREAM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
For the Year Ended December 31,
 
Period from May 26, 2016 (Inception) through December 31,
 
 
2018
 
2017
 
2016
 
 
(In thousands, except per common share data)
 
 
 
 
 
 
 
REVENUES AND OTHER:
 
 
 
 
 
 
Midstream services — affiliate (Note 3)
 
$
76,750

 
$
15,142

 
$

Other
 
1,608

 

 

Total revenues and other
 
78,358

 
15,142

 

OPERATING EXPENSES:
 
 
 
 
 
 
Gathering, processing, and transmission (1)
 
53,922

 
16,597

 

General and administrative (2)
 
7,368

 
3,991

 

Depreciation and accretion
 
20,068

 
5,991

 

Taxes other than income
 
7,633

 
97

 

Financing costs, net
 
107

 

 

Total operating expenses
 
89,098

 
26,676

 

NET LOSS BEFORE INCOME TAXES
 
(10,740
)
 
(11,534
)
 

Current income tax benefit
 
(1,041
)
 

 

Deferred income tax (benefit) expense
 
(9,460
)
 
7,041

 

NET LOSS INCLUDING NONCONTROLLING INTEREST
 
(239
)
 
(18,575
)
 

Net income attributable to noncontrolling interest
 
4,149

 

 

NET LOSS ATTRIBUTABLE TO CLASS A COMMON SHAREHOLDERS
 
$
(4,388
)
 
$
(18,575
)
 
$

 
 
 
 
 
 
 
NET LOSS ATTRIBUTABLE TO CLASS A COMMON SHAREHOLDERS, PER SHARE (3)
 
 
 
 
 
 
Basic
 
$
(0.03
)
 
$
(0.30
)
 
$

Diluted
 
(0.03
)
 
(0.30
)
 

WEIGHTED AVERAGE SHARES (3)
 
 
 
 
 
 
Basic
 
173,125

 
62,259

 
6,293

Diluted
 
173,125

 
62,259

 
6,293

(1)
Includes amounts of $9.1 million and $4.7 million to related parties for the year ended December 31, 2018 and 2017, respectively. Refer to Note 3 — Transactions with Affiliates.
(2)
Includes amounts of $6.5 million and $4.0 million to related parties for the year ended December 31, 2018 and 2017, respectively. Refer to Note 3 — Transactions with Affiliates.
(3)
For periods prior to the Business Combination, the number of shares has been retroactively restated to reflect the number of shares received by Apache. For further detail of the Business Combination and associated financial statement presentation, please refer to Note 1 — Summary of Significant Accounting Policies and Note 2 — Recapitalization Transaction.








The accompanying notes to consolidated financial statements are an integral part of this statement.

F-3



ALTUS MIDSTREAM COMPANY
CONSOLIDATED BALANCE SHEETS
 
 
December 31,
 
 
2018
 
2017
 
 
(In thousands, except common share data)
ASSETS
 
 
 
 
CURRENT ASSETS:
 
 
 
 
Cash and cash equivalents
 
$
449,935

 
$

Revenue receivables (Note 3)
 
10,914

 
5,422

Inventories and other
 
5,802

 
743

Prepaid assets and other
 
1,379

 

 
 
468,030

 
6,165

 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT:
 
 
 
 
Gathering, processing and transmission facilities
 
1,251,217

 
705,166

Less: Accumulated depreciation and amortization
 
(24,320
)
 
(5,580
)
 
 
1,226,897

 
699,586

 
 
 
 
 
OTHER ASSETS:
 
 
 
 
Joint venture equity interest
 
91,100

 

Deferred tax asset
 
67,558

 

Deferred charges and other
 
3,734

 

 
 
162,392

 

Total assets
 
$
1,857,319

 
$
705,751

 
 
 
 
 
LIABILITIES, NONCONTROLLING INTEREST, AND EQUITY
 
 
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
Accounts payable to Apache Corporation (Note 1)
 
$
13,595

 
$

Other current liabilities (Note 6)
 
84,926

 
124,471

 
 
98,521

 
124,471

 
 
 
 
 
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
 
 
 
 
Asset retirement obligation
 
29,369

 
18,189

Deferred tax liability
 
2,643

 
7,041

 
 
32,012

 
25,230

Total liabilities
 
130,533

 
149,701

 
 
 
 
 
COMMITMENTS AND CONTINGENCIES (Note 8)
 

 

 
 
 
 
 
Redeemable noncontrolling interest
 
1,940,500

 

 
 
 
 
 
EQUITY:
 
 
 
 
Class A Common Stock: $0.0001 par, 1,500,000,000 shares authorized, 74,929,305 shares issued and outstanding at December 31, 2018 (1)
 
7

 

Class C Common Stock: $0.0001 par, 1,500,000,000 shares authorized, 250,000,000 shares issued and outstanding at December 31, 2018 (1)
 
25

 
14

Additional paid-in capital
 

 
574,611

Accumulated deficit
 
(213,746
)
 
(18,575
)
 
 
(213,714
)
 
556,050

Total liabilities, noncontrolling interest, and equity
 
$
1,857,319

 
$
705,751

(1)
For periods prior to the Business Combination, the number of shares has been retroactively restated to reflect the number of shares received by Apache. For further detail of the Business Combination and associated financial statement presentation, please refer to Note 1 — Summary of Significant Accounting Policies and Note 2 — Recapitalization Transaction.
The accompanying notes to consolidated financial statements are an integral part of this statement.

F-4



ALTUS MIDSTREAM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
For the Year Ended December 31,
 
Period from May 26, 2016 (Inception) through December 31,
 
 
2018 (1)
 
2017 (1)
 
2016 (1)
 
 
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
 
Net loss including noncontrolling interest
 
$
(239
)
 
$
(18,575
)
 
$

Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
 
 
 
Depreciation and accretion
 
20,068

 
5,991

 

Deferred income tax (benefit) expense
 
(9,460
)
 
7,041

 

Adjustment for non-cash transactions with affiliate(1)
 
(4,238
)
 
9,601

 

Changes in operating assets and liabilities:
 
 
 
 
 
 
(Increase) decrease in inventories
 
(5,058
)
 
(743
)
 

(Increase) decrease in prepayments and other
 
(1,045
)
 

 

(Increase) decrease in revenue receivables (Note 3)
 
(5,602
)
 
(5,422
)
 

(Increase) decrease in interest receivable
 
(226
)
 

 

Increase (decrease) in accrued expenses
 
1,977

 
2,107

 

Increase (decrease) in accounts payable to affiliate
 
4,484

 

 

NET CASH PROVIDED BY OPERATING ACTIVITIES
 
661

 

 

 
 
 
 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 


 
 
 
 
Capital expenditures
 
(84,000
)
 

 

Joint venture equity interest
 
(91,100
)
 

 

NET CASH USED IN INVESTING ACTIVITIES
 
(175,100
)
 

 

CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
Recapitalization transaction (Note 2)
 
628,154

 

 

Deferred facility fees
 
(3,780
)
 

 

NET CASH PROVIDED BY FINANCING ACTIVITIES
 
624,374

 

 

 
 
 
 
 
 
 
NET INCREASE IN CASH AND CASH EQUIVALENTS
 
449,935



 

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD
 
$
449,935


$


$

Supplemental cash flow data:
 
 
 
 
 
 
Accrued capital expenditures (2)
 
$
89,810

 
$
122,364

 
$
96,626

(1)
In all periods prior to the Business Combination, the Company had no banking or cash management activities. Transactions with Apache and asset transfers to and from the Company were not settled in cash and are therefore reflected as a component of equity and redeemable noncontrolling interests on the Consolidated Balance Sheet. In addition to the above, Apache contributed its investments in gas gathering, processing and transmission facilities of approximately $484.5 million, $505.7 million, and $59.3 million that are included within equity and redeemable noncontrolling interests for the year-ended December 31, 2018, 2017 and 2016 respectively. Refer to Note 3 — Transactions with Affiliates for more information.
(2)
Includes $9.1 million of capital expenditures due to Apache, pursuant to the terms of the Construction, Operations and Maintenance Agreement entered into at the closing of the Business Combination. Refer to Note 3 — Transactions with Affiliates for more information.




The accompanying notes to consolidated financial statements are an integral part of this statement.

F-5



ALTUS MIDSTREAM COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY AND NONCONTROLLING INTEREST

 
Redeemable Noncontrolling Interest
 
 
Class A Common Stock
 
Class C Common Stock
 
Additional Paid-in Capital
 
Retained Earnings (Accumulated Deficit)
 
Total Equity
 
 
 
Shares(1)
 
Amount(1)
 
Shares(1)
 
Amount(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(In thousands)