Annual Report (10-k)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)


☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the year ended December 31, 2019


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission File Number: 001-38083

Magnolia Oil & Gas Corporation

(Exact Name of Registrant as Specified in its Charter)



Delaware		81-5365682
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Nine Greenway Plaza, Suite 1300		77046
Houston,	Texas	77046
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 842-9050



Securities registered pursuant to section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, par value $0.0001	MGY	New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒

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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an 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	☐	Small reporting company	☐

		Emerging growth company	☐

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 ☒

The aggregate market value of the common stock held by non‑affiliates of the registrant as of June 28, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $1.3 billion based on the closing price on that day on the New York Stock Exchange.

As of February 24, 2020, there were 167,331,253 shares of Class A Common Stock, $0.0001 par value per share, and 85,789,814 shares of Class B Common Stock, $0.0001 par value per share, outstanding.

Documents Incorporated By Reference

Portions of the registrant’s definitive proxy statement for the 2020 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates, are incorporated by reference into Part III of this Annual Report on Form 10-K.

Table of Contents



		Page
Definitions of Certain Terms and Conventions Used Herein		1
Cautionary Statement Concerning Forward-Looking Statements		2

	PART I.
Items 1 and 2.	Business and Properties	4
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	26
Item 3.	Legal Proceedings	26
Item 4.	Mine Safety Disclosures	26

	PART II.
Item 5.	Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	28
Item 6.	Selected Financial Data	29
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 8.	Financial Statements and Supplementary Data	41
Item 9.	Changes in Disagreements with Accountants on Accounting and Financial Disclosure	80
Item 9A.	Controls and Procedures	80
Item 9B.	Other Information	81

	PART III.
Item 10.	Directors, Executive Officers and Corporate Governance	81
Item 11.	Executive Compensation	81
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	81
Item 13.	Certain Relationships and Related Transactions, and Director Independence	81
Item 14.	Principal Accounting Fees and Services	82

	PART IV.
Item 15.	Exhibits and Financial Statement Schedules	82
Item 16.	Form 10-K Summary	85

Signatures		85

DEFINITIONS OF CERTAIN TERMS AND CONVENTIONS USED HEREIN

The following are abbreviations and definitions of certain terms used in this document, some of which are commonly used in the oil and gas industry:

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, natural gas liquids, or water.

“Bbls/d.” Stock tank barrels per day.

“Bcf.” billion cubic feet of natural gas.

“boe.” Barrels of oil equivalent. One boe is equal to one Bbl, six thousand cubic feet of natural gas, or 42 gallons of natural gas liquids. Based on approximate energy equivalency.

“boe/d.” Barrels of oil equivalent per day.

“British Thermal Unit or Btu.” The quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

“DD&A.” Depletion, depreciation, and amortization.

“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry well.” A well that is determined to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

“Exploratory well.” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

“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.

“Gross acres or gross wells.” Gross acres or gross wells are the total acres or wells in which all or part of the working interest is owned.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“MBbls.” One thousand barrels of crude oil, condensate or NGLs.

“Mboe/d.” Thousand barrels of oil equivalent per day.

“Mcf.” One thousand cubic feet of natural gas.

“Mcf/d.” Thousand cubic feet of natural gas per day.

“MMboe.” Million barrels of oil equivalent.

“MMBtu.” One million British thermal units.

“MMBtu/d.” Million British thermal units per day.

“MMcf.” One million cubic feet of natural gas.

“NGL” or “NGLs.” Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as purity products such as ethane, propane, isobutane and normal butane, and natural gasoline.

“Net acres or net wells.” The sum of fractional working interests owned in gross acres or gross wells.

“NYMEX.” The New York Mercantile Exchange.

“Productive well.” A well that is found to be mechanically capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves.” The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Standardized measure.” Discounted future net cash flows estimated by applying the twelve month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months to the estimated future production of year‑end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period‑end costs to determine pre‑tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre‑tax cash inflows over Magnolia’s tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, natural gas, and NGLs regardless of whether such acreage contains proved reserves.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Working interest.” The right granted to the lessee of a property to explore for, to produce, and to own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“WTI.” West Texas Intermediate light sweet crude oil.

FORWARD-LOOKING STATEMENTS

This report 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 the Company’s 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 the beliefs of management, as well as assumptions made by, and information currently available to, the Company’s management. 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 Magnolia believes that the expectations reflected in such forward-looking statements are reasonable, the Company can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, Magnolia’s assumptions about:


•	the market prices of oil, natural gas, natural gas liquids (“NGLs”), and other products or services;


•	the supply and demand for oil, natural gas, NGLs, and other products or services;


•	production and reserve levels;


•	drilling risks;


•	economic and competitive conditions;


•	the availability of capital resources;


•	capital expenditures and other contractual obligations;


•	weather conditions;


•	inflation rates;


•	the availability of goods and services;


•	legislative, regulatory, or policy changes;


•	cyber attacks;


•	occurrence of property acquisitions or divestitures;


•	the integration of acquisitions;


•	the securities or capital markets and related risks such as general credit, liquidity, market, and interest-rate risks; and


•	other factors disclosed under Items 1 and 2 - Business and Properties, 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 Annual Report on Form 10-K.

All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are

expressly qualified in their entirety by the cautionary statements. Except as required by law, Magnolia assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.

PART I

Items 1 and 2. Business and Properties

Overview

Magnolia Oil & Gas Corporation (the “Company” or “Magnolia”) is a Delaware corporation formed in February 2017 as a special purpose acquisition company under the name TPG Pace Energy Holdings Corp. for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization, or similar business combination with one or more businesses.

On July 31, 2018 (the “Closing Date”), Magnolia consummated its initial business combination (the “Business Combination”) through its acquisition of certain oil and natural gas assets in the Karnes County portion of the Eagle Ford Shale in South Texas (the “Karnes County Assets” and, such business, the “Karnes County Business”), certain oil and natural gas assets in the Giddings Field of the Austin Chalk (the “Giddings Assets”), and a 35.0% membership interest in Ironwood Eagle Ford Midstream, LLC, which owns an Eagle Ford gathering system, each with certain affiliates of EnerVest Ltd. (“EnerVest”). As of December 31, 2019, Magnolia owned a 66.1% interest in Magnolia Oil & Gas Parent LLC (“Magnolia LLC”), which owns the assets acquired in the Business Combination.

In connection with the Business Combination, Magnolia entered into a Services Agreement (the “Services Agreement”) with EnerVest Operating L.L.C. (“EVOC”), an affiliate of EnerVest, pursuant to which EVOC operates Magnolia’s assets under the direction of Magnolia’s management by providing services substantially identical to the services historically provided by EVOC in operating the assets Magnolia acquired in the Business Combination, including administrative, back office, and day-to-day field-level services reasonably necessary to operate the Company’s business, subject to certain exceptions.

In connection with the Business Combination, the Company has been identified as the acquirer for accounting purposes and the Karnes County Business was deemed to be the accounting predecessor (“Predecessor”). For the periods on or after the Business Combination, the Company, including the combination of the Karnes County Business, the Giddings Assets, and the Ironwood Interests, is the accounting successor (“Successor”). The Business Combination was accounted for using the acquisition method of accounting and the Successor financial statements reflect a new basis of accounting based on the fair value of the net assets acquired. As a result of the application of the acquisition method of accounting, the Company’s consolidated and combined financial statements and certain presentations are separated into two distinct periods to indicate the different ownership and accounting basis between the periods presented, the period before the consummation of the Business Combination, which includes the year ended December 31, 2017 (the “2017 Predecessor Period”) and the period from January 1, 2018 to July 30, 2018 (the “2018 Predecessor Period” and, together with the 2017 Predecessor Period, the “Predecessor Period”); and the period on and after the consummation of the Business Combination, from the Closing Date to December 31, 2018 (the “2018 Successor Period”), and the year ended December 31, 2019 (the “2019 Successor Period” and, together with the 2018 Successor Period, the “Successor Period”).

Available Information

Magnolia’s principal executive offices are located at Nine Greenway Plaza Suite 1300, Houston, Texas 77046. Magnolia’s website is located at www.magnoliaoilgas.com.

Magnolia furnishes or files with the Securities and Exchange Commission (the “SEC”) its Annual Reports on Form 10‑K, its Quarterly Reports on Form 10‑Q, and its Current Reports on Form 8‑K. Magnolia makes these documents available free of charge at www.magnoliaoilgas.com under the “Investors” tab as soon as reasonably practicable after they are filed or furnished with the SEC. Information on Magnolia’s website is not incorporated into this Annual Report on Form 10‑K or any of the Company’s other filings with the SEC.

Magnolia’s Class A Common Stock, par value $0.0001 per share (“Class A Common Stock”), is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “MGY.”

Segment Information and Geographic Area

Operating segments are defined under accounting principles generally accepted in the United States of America (“GAAP”) as components of an enterprise that engage in activities from which it may earn revenues and incur expenses and for which separate financial information is available and regularly evaluated for the purpose of allocating resources and assessing performance.

Based on Magnolia’s organization and management, the Company operates in one reportable segment engaged in the acquisition, development, exploration, and production of oil and natural gas properties located in the United States. All of Magnolia’s operations are conducted in one geographic area of the United States. Magnolia’s oil and natural gas properties are located primarily in Karnes County and the Giddings Field in South Texas, where the Company primarily targets the Eagle Ford Shale and the Austin Chalk formation. Additional data and discussion are provided in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

Properties

As of December 31, 2019, Magnolia’s assets consisted of a total leasehold position of 670,787 gross (450,854 net) acres, including 39,998 gross (22,088 net) acres in Karnes, Gonzales, DeWitt, and Atascosa Counties, Texas and 630,789 gross (428,766 net) acres in the Giddings Field. As of December 31, 2019, Magnolia had 1,630 gross (1,141 net) wells with total production of 66.8 Mboe/d for the year ended December 31, 2019. As of December 31, 2019, Magnolia was running a one-rig program for the Karnes County Assets and a one-rig program for the Giddings Assets. Approximately 52.8%, 28.2%, and 19.0% of production from Magnolia’s assets was attributable to oil, natural gas, and NGLs, respectively, for the year ended December 31, 2019.

The Karnes County Assets are primarily located in Karnes County, Texas, in the core of the Eagle Ford Shale. The acreage comprising the Karnes County Assets also includes the Austin Chalk formation overlying the Eagle Ford Shale. The Austin Chalk formation has shown itself to be an independent reservoir from the Eagle Ford Shale and represents a very attractive development target. The Karnes County Assets include a well-known, low-risk acreage position that has been developed with a focus on maximizing returns and improving operational efficiencies.

The Giddings Assets are primarily located in Brazos, Fayette, Lee, Grimes, and Washington Counties, Texas. The Austin Chalk formation produces along a northeast-to-southwest trend that is approximately parallel to the Texas Gulf Coast. There are several notable producing fields along the Austin Chalk trend, the largest of which is the Giddings Field. The Giddings Field has seen two major drilling cycles. The first cycle began in the late 1970s and into the early 1980s and consisted primarily of vertical well drilling. The second cycle ran through much of the 1990s and involved primarily horizontal well drilling. The wells included in the Giddings Assets have historically targeted the lower third of the Austin Chalk formation. Recent improvements in drilling and completion technologies have unlocked new development opportunities in the Giddings Field. Wells drilled over the past two years have helped to substantiate the strong economic viability of new drilling activity across the field. Future development results may allow for further expansion of existing location inventory throughout the leasehold.

Reserve Data

Estimated Proved Reserves

The estimates of Magnolia’s proved oil and gas reserves included in this Annual Report on Form 10-K are as of December 31, 2019. The majority of the Company’s proved reserves volumes, approximately 96%, are based on evaluations prepared by the independent petroleum engineering firm of Miller and Lents, in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Miller and Lents was selected for its historical experience and expertise in evaluating hydrocarbon resources.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time. Oil and gas prices applied in estimating proved reserves are determined using an unweighted arithmetic average of the first-day-of-the-month price for the reporting period.

Proved reserves are sub-divided into two categories, proved developed and proved undeveloped. Proved developed reserves include volumes that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required and there is management commitment to commence the development within a reasonable

timeframe. All of Magnolia’s proved undeveloped reserves, as of December 31, 2019, that are included in this Annual Report are planned to be developed within one year of first reporting.

The technical and economic data used to estimate proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data, well data, historical price and cost information, and property ownership interests. This technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, decline curve methods, volumetric analysis, and assessment of analogues, are applied to estimate proved reserves.

The proved developed reserves per well are estimated by applying performance analysis and decline curve methods. For proved developed wells that lack adequate production history, reserves were estimated using performance-based type curves and offset location analogues. Proved undeveloped reserves are estimated by using a combination of geologic and engineering data for planned drilling locations. Performance data along with log and core data was used to delineate consistent, continuous reservoir and performance characteristics in core areas of development to identify areas of technical certainty that meets the criteria for proved reserves. Performance based type curves are applied to forecast proved undeveloped well performance.

Preparation of Oil and Gas Reserve Information

Magnolia’s Director of Reserves, Peter Corbeil, is the technical person primarily responsible for overseeing the internal reserves estimation process. Mr. Corbeil has 20 years of oil and gas industry experience in reservoir engineering, reserves assessment, field development, and technical management. His experience prior to joining Magnolia includes tenures in the corporate reserve groups at three large and diversified oil and gas companies. He holds a Bachelor of Engineering degree and a Master of Business Administration degree and is a member of the Society of Petroleum Engineers.

The Director of Reserves works closely with EVOC’s petroleum engineers and geoscience professionals to ensure the integrity, accuracy, and timeliness of the data furnished to Miller and Lents for the preparation of their reserve reports. Periodically, Magnolia’s internal staff and EVOC’s technical teams meet with the independent reserves engineers to review properties, methods, and assumptions used to prepare reserve estimates for Magnolia’s assets.

The reserve reports were prepared by Miller and Lents’ team of geologists and reservoir engineers who integrate geological, geophysical, engineering and economic data to produce reserve estimates and economic forecasts. The process to prepare Magnolia’s proved reserves as of December 31, 2019 was supervised by Katie M. Reinaker, Senior Vice President and an officer of Miller and Lents. Ms. Reinaker is a professionally qualified licensed Professional Engineer in the State of Texas with more than 10 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

Reserves estimation involves a degree of uncertainty and estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas, and NGLs that are ultimately recovered. Estimates of economically recoverable oil, natural gas, NGLs, and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, future production rates, and costs. Please read “Risk Factors” in Item 1A in this Annual Report on Form 10-K.

Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves of Magnolia as of December 31, 2019. This table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a ratio of six Mcf to one Bbl. This ratio is not reflective of the current price ratio between the two products. The proved undeveloped reserves volumes in the table below are expected to be converted to proved developed reserves within one year.



	December 31, 2019
	Oil (MMBbls)	Natural Gas (Bcf)	NGLs (MMBbls)	Total (MMboe)
Proved reserves
Total proved developed	40.3	165.8	18.9	86.8
Total proved undeveloped	12.3	31.4	5.0	22.5
Total proved reserves	52.6	197.2	23.9	109.3

Development of Proved Undeveloped Reserves

As of December 31, 2019, the proved undeveloped reserves volumes are expected to be converted to proved developed reserves within one year. The following table summarizes the changes in Magnolia’s proved undeveloped reserves during the year ended December 31, 2019:



	Total (MMboe)
Proved undeveloped reserves at January 1, 2019	24.0
Conversions into proved developed reserves	(20.4	)
Extensions	15.7
Acquisitions	2.6
Revisions of previous estimates	0.6
Proved undeveloped reserves at December 31, 2019	22.5

As of December 31, 2019, Magnolia’s assets contained approximately 22.5 MMboe of proved undeveloped reserves, consisting of 12.3 MMBbls of oil, 31.4 Bcf of natural gas, and 5.0 MMBbls of NGLs. The Company’s total estimated proved undeveloped reserves decreased 1.5 MMboe during the year ended December 31, 2019. Magnolia converted 20.4 MMboe of proved undeveloped reserves to proved developed reserves as a result of the drilling activities completed during 2019. Extension adds of 15.7 MMboe were a result of the planned drilling program for the Karnes County Assets and the Giddings Assets. Acquisitions related to purchases of acreage in the Company’s Karnes County Assets resulted in an increase in proved undeveloped reserves of approximately 2.6 MMboe. Revisions of 0.6 MMboe to proved undeveloped reserves were comprised of a 2.2 MMboe positive revision related to infill drilling in the Karnes County Assets that was partially offset by downward revisions of approximately 1.6 MMboe related to technical updates, lower commodity prices, and an updated well schedule to optimize development activity.

During the year ended December 31, 2019, Magnolia incurred costs of approximately $158.8 million to convert the reserves associated with 40 of its net proved undeveloped locations to 20.4 MMboe of proved developed reserves.

Drilling Statistics

The following table describes new development and exploratory wells drilled within Magnolia’s assets during the years ended December 31, 2019, 2018, and 2017. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found, or economic value. A dry well is a well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well. A productive well is a well that is found to be mechanically capable of producing hydrocarbons in sufficient quantities. Completion refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. As of December 31, 2019, 84 gross (34 net) wells were in various stages of completion. As of December 31, 2019, Magnolia was running a one-rig program for the Karnes County Assets and a one-rig program for the Giddings Assets.



	Successor		Predecessor and Giddings Assets
	Year Ended December 31, 2019	July 31, 2018 Through December 31, 2018	January 1, 2018 Through July 30, 2018	Year Ended December 31, 2017
Net exploratory wells
Productive	—	—	—	—
Dry	—	—	—	—
	—	—	—	—
Net development wells
Productive	76	25	42	58
Dry	—	—	—	—
	76	25	42	58
Net total wells
Productive	76	25	42	58
Dry	—	—	—	—
Total	76	25	42	58

Productive Oil and Gas Wells

Productive wells consist of producing wells and wells mechanically capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which Magnolia owns a working interest, and net wells are the sum of the fractional working interests of gross wells. The following table sets forth information relating to the productive wells in which Magnolia owned a working interest as of December 31, 2019.



		Year Ended December 31, 2019
Oil
Gross		1,179
Net		752

Gas
Gross		451
Net		389

Total
Gross		1,630
Net		1,141

Production, Pricing, and Lease Operating Cost Data

The following table describes, for each of the last three fiscal years, oil, natural gas, and NGL production volumes, average lease operating costs per boe (including transportation costs, but excluding severance and other taxes), and average sales prices related to Magnolia’s operations:



	Successor				Predecessor and Giddings Assets
	Year Ended December 31, 2019		July 31, 2018 Through December 31, 2018		January 1, 2018 Through July 30, 2018		Year Ended December 31, 2017
Production
Crude oil (MMBbls)	12.9		5.1		6.4		7.8
Natural gas (Bcf)	41.3		14.1		13.5		16.8
Natural gas liquids (MMBbls)	4.6		1.9		1.7		2.0

Average lease operating cost per boe	$	5.28	$	4.83	$	5.42	$	5.28

Average sale price
Crude oil (MMBbls)	$	60.00	$	67.37	$	69.14	$	49.03
Natural gas (Bcf)	2.27		3.04		2.82		2.94
Natural gas liquids (MMBbls)	15.17		25.93		25.99		21.80

Gross and Net Undeveloped and Developed Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which Magnolia held an interest as of December 31, 2019:



		December 31, 2019
Undeveloped acreage
Gross		65,984
Net		47,298

Developed acreage
Gross		604,803
Net		403,556

Total acreage
Gross		670,787
Net		450,854

Undeveloped Acreage Expirations

As of December 31, 2019, Magnolia’s total net undeveloped acres across its assets that will expire in 2020, 2021, and 2022 are 1,129 acres, 6,610 acres, and 3,109 acres, respectively, unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed. There are no expirations after 2022.

Delivery Commitments

Magnolia has a long term contract with the commitment to deliver a fixed minimum sales volume of oil production from the Karnes County Assets. This contract requires Magnolia to deliver approximately 7,988 MBbls for the period from 2020 through 2021. In addition, the Giddings Assets are subject to a contract with a third-party midstream company that provides for firm pipeline transportation for a portion of the natural gas produced from the Giddings Assets. Under this contract, Magnolia currently has reserved firm capacity of up to 30,000 MMBtu/d, which amount Magnolia has the right to reduce during the term of the agreement based on current capacity requirements. This contract requires Magnolia to pay a pipeline demand fee for the reserved capacity amount. Magnolia expects to fulfill both of these commitments with existing proved developed and proved undeveloped reserves, which are regularly monitored to ensure sufficient availability. In addition, Magnolia monitors current production, anticipated future production, and future development plans in order to meet its commitments.

Operations

General

Pursuant to the Services Agreement entered into in connection with the Business Combination, EVOC, under the direction of Magnolia’s management, has provided services to Magnolia since the Business Combination substantially identical to the services historically provided by EVOC, including all administrative, back office and day-to-day field-level services reasonably necessary to operate Magnolia’s business and its assets, subject to certain exceptions.

Facilities

Production facilities related to Magnolia’s assets are located near producing wells and consist of storage tanks, two-phase and/or three-phase separation equipment, flowlines, metering equipment, and safety systems. Predominant artificial lift methods include gas lift, rod pump lift, and plunger lift.

Magnolia’s assets include a 35.0% ownership interest in an oil and gas gathering system operated by Ironwood Eagle Ford Midstream, LLC, which allows gas and oil production to be delivered and sold to various intrastate and interstate markets, or to various crude oil refining markets on a competitive pricing basis. The majority of gas production related to the Karnes County Assets is currently processed to collect NGLs. The Karnes County Assets also include a saltwater disposal well, which currently handles a portion of water production from the Karnes County Assets.

The Giddings Assets include access to gas gathering systems, which allows production to be delivered to third-party gas processors. The majority of gas production related to the Giddings Assets is currently processed to collect NGLs. Produced gas can be sold to various intrastate and interstate markets on a competitive pricing basis. The Giddings Assets also include a saltwater disposal well that handles a small portion of water production from the Giddings Assets.

Marketing and Customers

For the year ended December 31, 2019, two customers accounted for 43.3% and 18.5%, respectively, of the combined oil, natural gas, and NGL revenue. For the 2018 Successor Period, two customers accounted for 42.2% and 19.1%, respectively, of the combined oil, natural gas, and NGL revenue. For the 2018 Predecessor Period, three customers accounted for 47.6%, 14.5%, and 12.2%, respectively, of the combined oil, natural gas, and NGL revenues. For the 2017 Predecessor Period, four customers accounted for 28.8%, 22.3%, 18.9%, and 10.2%, respectively, of the combined oil, natural gas, and NGL revenues.

No other purchaser accounted for 10% or more of Magnolia’s revenue on a combined basis in each respective period. The loss of any of the purchasers above could adversely affect Magnolia’s revenues in the short term. Please see “Risk Factors” in Item 1A in this Annual Report on Form 10-K for more information.

Magnolia gathers and processes a portion of the natural gas production from the Giddings Assets under acreage dedications with two third-party midstream companies. The gas plant residue volumes are sold either to the gas processor or various third parties utilizing the firm transportation agreement described under “Delivery Commitments” in this item (“Items 1 and 2. Business and Properties”). The NGL production extracted from the Giddings Assets is sold to third parties pursuant to purchase agreements with varying terms. Magnolia sells the majority of the oil production from the Giddings Assets to two third parties at market prices, with such purchasers generally transporting such production from the lease via trucks. The remainder of the oil, natural gas, and NGL production from the Giddings Assets is sold to various third-party purchasers at market prices, typically under contracts with terms of twelve months or less.

In addition, Magnolia sells the natural gas production from the Karnes County Assets to various third parties pursuant to the terms of multiple gas processing and purchase contracts of varying terms. Such natural gas production is gathered and processed under agreements with terms ranging from month-to-month to the life of the applicable lease agreements. Magnolia is subject to the terms of a crude oil gathering agreement with Ironwood Eagle Ford Midstream, LLC that expires in July 2027, which provides an outlet for Magnolia to sell oil production from the Karnes County Assets to third-party purchasers at market prices. The remaining oil production is generally transported from the lease via trucks. The remainder of the oil, natural gas, and NGL production from the Karnes County Assets is sold to various third-party purchasers at market prices, typically under contracts with terms of twelve months or less. The NGL production from the Karnes County Assets is primarily sold to midstream gas processors in the Eagle Ford area.

Competition

The oil and natural gas industry is a highly competitive environment and Magnolia competes with both major integrated and other independent oil and natural gas companies in all aspects of the Company’s business to explore, develop, and operate its properties and market its production. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of Magnolia’s competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the proximity and capacity of natural gas pipelines and other transportation facilities, and overall economic conditions. Magnolia also faces indirect competition from alternative energy sources, including wind, solar, and electric power. Magnolia’s ability to acquire additional prospects and to find and develop reserves in the future will depend on the Company’s ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Environmental, Health and Safety Matters

Oil and natural gas operations are substantially affected by federal, state, and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes, and numerous other laws and regulations. All of the jurisdictions in which Magnolia’s assets are located have statutory provisions regulating the development and production of oil and natural gas. These laws and regulations can impose recordkeeping, monitoring, and reporting requirements or other operational constraints on the Company’s business, including operational controls for minimizing pollution, costs to remediate releases of regulated substances, including crude oil, into the environment, or costs to remediate sites to which the Company sent regulated substances for disposal. In some cases, these laws can impose strict liability for the entire cost of clean-up on any responsible party without regard to negligence or fault and impose liability on the Company for the conduct of others (such as prior owners or operators of Magnolia’s assets) or conditions others have caused, or for the Company’s acts that complied with all applicable requirements when they were performed. The Company could incur capital, operating, maintenance, and remediation expenditures as a result of environmental laws and regulations. New laws have been enacted, and regulations are being adopted by various regulatory agencies on a continuing basis, and the costs of compliance with these new laws and regulations can only be broadly appraised until their implementation becomes more defined.

Air and Climate Change

Environmental advocacy groups and regulatory agencies in the United States and other countries have focused considerable attention on the emissions of carbon dioxide, methane, and other greenhouse gases (“GHG”) and their potential role in climate change. The federal Clean Air Act (the “CAA”) and comparable state laws restrict the emission of air pollutants from many sources through the imposition of air emissions standards, construction and operating permitting programs, and other compliance requirements. These requirements may result in increased operating costs as a result of the need to install emission control devices or increased emission monitoring and reporting requirements. For example, the U.S. Environmental Protection Agency (the “EPA”) has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of Magnolia’s assets. Separately, in June 2016, the EPA published performance standards that establish new controls, known as Subpart OOOOa, for emissions of methane from new, modified, or reconstructed sources in the oil and natural gas sector, including production, processing, transmission, and storage activities. Please see “Risk Factors” in Item 1A in this Annual Report on Form 10-K for further discussion of risks related to climate change and the regulation of methane emissions and GHGs.

Separately, the EPA finalized a more stringent National Ambient Air Quality Standard (“NAAQS”) for ozone in October 2015 and completed attainment/nonattainment designations in 2018. State implementation of the revised NAAQs in the areas in which Magnolia operates could result in increased costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. Failure to comply with air quality regulations may also result in administrative, civil, and/or criminal penalties for non-compliance.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is regularly used by operators of Magnolia’s assets. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the U.S. Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. 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 also finalized rules under the CWA in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

At the state level, several states have adopted, or are considering, legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, the Texas Railroad Commission has adopted a “well integrity rule,” which updated the requirements for drilling, putting pipe down, and cementing wells. The rule also imposes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic fracturing activities in particular.

Compliance with existing laws has not had a material adverse effect on operations related to Magnolia’s assets, but if new or far more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Magnolia’s assets are located, operators could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

Water

The federal Clean Water Act (“CWA”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In September 2015, the EPA and the U.S. Army Corps of Engineers (“Corps”) issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction under the CWA with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands (the “WOTUS rule”). However, following the change in presidential administrations, there have been several attempts to modify this rule. For example, on January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrows the definition of “waters of the United States” relative to the prior 2015 rulemaking. Legal challenges to the new rule are expected, and multiple challenges to the EPA’s

prior rulemaking remain pending. To the extent any final rule expands the scope of the CWA’s jurisdiction, Magnolia could face increased permitting costs and project delays.

In addition, Magnolia may be required under the CWA to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control, and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation and Liability Act (the “CERCLA”), also known as the “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 are considered responsible for the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and persons that disposed or arranged for the disposal or the transportation for disposal of the hazardous substances at the site where the release occurred.

The Resources Conservation and Recovery Act (the “RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment, and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the development or production of crude oil, natural gas, or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. It is, however, possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Due to the government shutdown, the deadline was extended, and in April 2019, the EPA signed a determination that revision of the regulations is not necessary at this time. However, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters, and related wastes could result in an increase in the costs to manage and dispose of generated wastes

Endangered Species Act

The Endangered Species Act (the “ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause increased costs arising from species protection measures or could result in limitations on development activities that could have an adverse impact on the ability to develop and produce reserves within Magnolia’s assets. If a portion of Magnolia’s assets were to be designated as a critical or suitable habitat, it could adversely impact the value of its assets.

OSHA

Magnolia is subject to the requirements of the Occupational Health and Safety Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. Violations can result in civil or criminal penalties as well as required abatement. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, and comparable state statutes and any implementing regulations require that Magnolia organizes and/or discloses information about hazardous materials used or produced in its operations and that this information be provided to employees, state and local governmental authorities, and citizens.

Related Permits and Authorizations

Many environmental laws require permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and require maintaining these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which could in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations related to Magnolia’s assets.

Employees

As of December 31, 2019, Magnolia had approximately 45 full-time employees. Additionally, pursuant to the Services Agreement, EVOC and its employees provide Magnolia with day-to-day services reasonably necessary to operate its assets. Magnolia is not a party to any collective bargaining agreements and has not experienced any strikes or work stoppages. Magnolia considers its relations with its employees to be satisfactory.

Item 1A. Risk Factors

The nature of Magnolia’s business activities subjects the Company to certain hazards and risks. The following risks and uncertainties, together with other information set forth in this Annual Report on Form 10-K, should be carefully considered by current and future investors in the Company’s securities. These risks and uncertainties are not the only ones Magnolia faces. Additional risks and uncertainties presently unknown to Magnolia, or currently deemed immaterial, also may impair the Company’s business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect the Company’s business, its financial condition, and the results of Magnolia’s operations, which in turn could negatively impact the value of the Company’s securities.

Oil, natural gas, and NGL prices are volatile. A sustained period of low oil, natural gas, and NGL prices could adversely affect Magnolia’s business, financial condition, results of operations, and ability to meet its expenditure obligations and financial commitments.

The prices Magnolia receives for its oil, natural gas, and NGL production will heavily influence its revenue, profitability, access to capital, future rate of growth, and the carrying value of its properties. Oil, natural gas, and NGLs are commodities, and their prices may fluctuate widely in response to market uncertainty and to relatively minor changes in the supply of and demand for oil, natural gas, and NGLs. Historically, oil, natural gas, and NGL prices have been volatile. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane, and natural gasoline, each of which has different uses and pricing characteristics, have suffered significant recent declines in realized prices. The prices Magnolia receives for its production and the levels of Magnolia’s production, depend on numerous factors beyond Magnolia’s control, which include the following:


•	worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas, and NGLs;


•	the price and quantity of foreign imports of oil, natural gas, and NGLs;


•	political and economic conditions in or affecting other producing regions or countries, including the Middle East, Africa, South America, and Russia;


•	actions of the Organization of the Petroleum Exporting Countries, its members, and other state- controlled oil companies relating to oil price and production controls;


•	the level of global exploration, development, and production;


•	the level of global inventories;


•	prevailing prices on local price indexes in the areas in which Magnolia operates;


•	the proximity, capacity, cost, and availability of gathering and transportation facilities;


•	localized and global supply, demand fundamentals, and transportation availability; the cost of exploring for, developing, producing, and transporting reserves;


•	weather conditions and natural disasters;


•	technological advances affecting energy consumption;


•	the price and availability of alternative fuels;


•	expectations about future commodity prices;


•	events that impact global market demand; and


•	U.S. federal, state, local, and non-U.S. governmental regulation and taxes.

Lower commodity prices may reduce Magnolia’s cash flow and borrowing ability. If Magnolia is unable to obtain needed capital or financing on satisfactory terms, its ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserves volumes due to economic limits. In addition, sustained periods with lower oil and natural gas prices may adversely affect drilling economics and Magnolia’s ability to raise capital, which may require it to re-evaluate and postpone or eliminate its development program, and result in the reduction of some proved undeveloped reserves and related standardized measure. If Magnolia is required to curtail its drilling program, Magnolia may be unable to hold leases that are scheduled to expire, which may further reduce reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect Magnolia’s future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.

Magnolia has not entered into hedging arrangements with respect to the oil, natural gas, and NGL production from its properties, and Magnolia will be exposed to the impact of decreases in the price of oil, natural gas, and NGLs.

Magnolia has not entered into hedging arrangements to establish, in advance, a price for the sale of the oil, natural gas, and NGLs it produces. As a result, Magnolia will not be protected against decreases in such prices, and if such prices decrease significantly, Magnolia’s business, results of operations, and cash flow may be materially adversely affected.

Magnolia’s development projects and acquisitions require substantial capital expenditures. Magnolia may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in its ability to access or grow production and reserves.

The oil and natural gas industry is capital-intensive. Magnolia makes, and expects to continue to make, substantial capital expenditures related to development and acquisition projects. Magnolia has funded, and expects to continue to fund, its capital budget with cash generated by operations and potentially through borrowings under Magnolia’s secured reserve-based revolving credit facility (the “RBL Facility”). However, Magnolia’s financing needs may require it to alter or increase its capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that an additional portion of cash flow from operations be used for the payment of interest and principal on its indebtedness, thereby further reducing its ability to use cash flow from operations to fund working capital, capital expenditures, and acquisitions. The issuance of additional equity securities would be dilutive to existing stockholders. The actual amount and timing of future capital expenditures may differ materially from estimates as a result of, among other things: commodity prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological, and competitive developments. A reduction in commodity prices from current levels may result in a decrease in actual capital expenditures, which would negatively impact Magnolia’s ability to grow production.

Magnolia’s cash flow from operations and access to capital is subject to a number of variables, including:


•	the prices at which Magnolia’s production is sold;


•	proved reserves;


•	the amount of hydrocarbons Magnolia is able to produce from its wells;


•	Magnolia’s ability to acquire, locate, and produce new reserves;


•	the amount of Magnolia’s operating expenses;


•	Magnolia’s ability to borrow under the RBL Facility;


•	restrictions in the instruments governing Magnolia’s debt, and Magnolia’s ability to incur additional indebtedness; and


•	Magnolia’s ability to access the capital markets.

If Magnolia’s revenues or the borrowing base under the RBL Facility decrease as a result of lower oil, natural gas, and NGL prices, operational difficulties, declines in reserves or for any other reason, Magnolia may have limited ability to obtain the capital necessary to sustain operations at current levels. If additional capital is needed, Magnolia may not be able to obtain debt or equity financing on terms acceptable to it, if at all. If cash flow generated by Magnolia’s operations or available borrowings under the RBL Facility are insufficient to meet its capital requirements, the failure to obtain additional financing could result in a curtailment of the development of Magnolia’s properties, which in turn could lead to a decline in reserves and production and could materially and adversely affect Magnolia’s business, financial condition, and results of operations. If Magnolia incurs additional indebtedness, the operational risks that Magnolia faces could intensify, and Magnolia may be unable to service its existing debt service obligations.

Part of Magnolia’s business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Magnolia’s operations involve utilizing some of the latest drilling and completion (“D&C”) techniques. The difficulties Magnolia faces drilling horizontal wells include:


•	landing its wellbore in the desired drilling zone;


•	staying in the desired drilling zone while drilling horizontally through the formation;


•	running its casing the entire length of the wellbore; and


•	being able to run tools and other equipment consistently through the horizontal wellbore.

Difficulties that Magnolia faces while completing its wells include the following:


•	the ability to fracture stimulate the planned number of stages;


•	the ability to run tools the entire length of the wellbore during completion operations; and


•	the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

Use of new technologies may not prove successful and could result in significant cost overruns or delays or reductions in production, and, in extreme cases, the abandonment of a well. In addition, certain of the new techniques may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer and emerging formations and areas have limited or no production history and, consequently, Magnolia may be more limited in assessing future drilling results in these areas. If its drilling results are less than anticipated, the return on investment for a particular project may not be as attractive as anticipated, and Magnolia could incur material write-downs of unevaluated properties, and the value of undeveloped acreage could decline in the future.

For example, potential complications associated with the new D&C techniques that Magnolia utilizes may cause Magnolia to be unable to develop its assets in line with current expectations and projections. Further, Magnolia’s recent well results may not be indicative of its future well results.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect Magnolia’s business, financial condition, or results of operations.

Magnolia’s future financial condition and results of operations will depend on the success of its development, production, and acquisition activities, which are subject to numerous risks beyond its control, including the risk that drilling will not result in commercially viable oil and natural gas production.

Magnolia’s decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analysis, production data, and engineering studies, which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Crude oil, natural gas, and NGL reserves are estimates, and actual recoveries may vary significantly.” In addition, the cost of drilling, completing, and operating wells is often uncertain.

Further, many factors may curtail, delay, or cancel scheduled drilling projects, including:


•	delays imposed by, or resulting from, permitting activities, compliance with regulatory requirements, including limitations on wastewater disposal, emission of greenhouse gases (“GHGs”), and hydraulic fracturing;


•	pressure or irregularities in geological formations;


•	sustained periods of low oil and natural gas prices;


•	shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;


•	equipment failures, accidents, or other unexpected operational events;


•	lack of available gathering facilities or delays in construction of gathering facilities;


•	lack of available capacity on interconnecting transmission pipelines;


•	adverse weather conditions;


•	issues related to compliance with environmental regulations;


•	environmental or safety hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases, or other pollutants into the surface and subsurface environment;


•	limited availability of financing on acceptable terms;


•	title issues; and


•	other market limitations in Magnolia’s industry.

Crude oil, natural gas, and NGL reserves are estimates, and actual recoveries may vary significantly.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. In order to prepare the reserve estimates, Magnolia must project production rates and timing of development expenditures. The Company must also analyze available geological, geophysical, production, and engineering data. The extent, quality, and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. Magnolia cannot assure you that its management team’s assumptions with respect to projected production and/or the timing of development expenditures will not materially change in subsequent periods. Magnolia’s management team and board may determine to secure and deploy development capital at a faster or slower pace than currently assumed.

Actual future production, oil prices, natural gas prices, NGL prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves may vary from Magnolia’s estimates. For instance, initial production rates reported by Magnolia or other operators may not be indicative of future or long-term production rates, recovery efficiencies may be worse than expected, and production declines may be greater than anticipated and may be more rapid and irregular when compared

to initial production rates. In addition, estimates of proved reserves may be adjusted to reflect additional production history, results of development activities, current commodity prices, and other existing factors. Any significant variance could materially affect the estimated quantities and present value of reserves. Moreover, there can be no assurance that reserves will ultimately be produced or that proved undeveloped reserves will be developed within the periods anticipated.

Actual future prices and costs may differ materially from those used in the present value estimate. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

The standardized measure of estimated reserves may not be an accurate estimate of the current fair value of estimated oil and natural gas reserves.

The standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. The standardized measure requires historical twelve-month pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, and it also may not reflect the actual costs that will be required to produce or develop the oil and natural gas properties. In addition, the sellers in the Business Combination were generally not subject to U.S. federal, state, or local income taxes other than certain state franchise taxes. Magnolia is subject to U.S. federal, state, and local income taxes. As a result, estimates included in this Annual Report on Form 10-K of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of estimated reserves included in this Annual Report on Form 10-K should not be construed as accurate estimates of the current fair value of such proved reserves.

Properties Magnolia has acquired or will acquire may not produce as projected, and Magnolia may be unable to determine reserve potential, identify liabilities associated with such properties, or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires Magnolia to assess reservoir and infrastructure characteristics, including recoverable reserves, future oil and gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, Magnolia performs a review of the subject properties that it believes to be generally consistent with industry practices. Such assessments are inexact and inherently uncertain. For these reasons, the properties Magnolia has acquired or will acquire may not produce as expected. In connection with the assessments, Magnolia performs a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of due diligence, Magnolia may not review every well, pipeline, or associated facility. Magnolia cannot necessarily observe structural and environmental problems, such as groundwater contamination, when a review is performed. Magnolia may be unable to obtain or successfully enforce contractual indemnities from the seller for liabilities created prior to Magnolia’s purchase of the property. Magnolia may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with its expectations. Additionally, the success of future acquisitions will depend on Magnolia’s ability to integrate effectively the then-acquired business into its then-existing operations. The process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of managerial and financial resources. Magnolia’s failure to achieve consolidation savings, to incorporate the additionally acquired assets into its then-existing operations successfully, or to minimize any unforeseen operational difficulties, or the failure to acquire future assets at all, could have a material adverse effect on its financial condition and results of operations.

Because Magnolia has a limited operating history, it may be difficult to evaluate its ability to successfully implement its business strategy.

Because of Magnolia’s limited operating history, the operating performance of its future assets and business strategy are not yet proven. As a result, it may be difficult to evaluate Magnolia’s business and results of operations to date and to assess its future prospects. In addition, Magnolia may encounter risks and difficulties experienced by companies whose performance is dependent upon recently acquired assets, such as failing to operate its assets as expected, higher than expected operating costs, equipment breakdown or failures, and operational errors. Further, Magnolia’s assets are operated on a day-to-day basis by EVOC’s employees pursuant to the Services Agreement, and Magnolia may be less involved in the day-to-day operations of the assets. As a result of the foregoing, Magnolia may be less successful in achieving a consistent operating level capable of generating cash flows from operations as compared to a company that has had a longer operating history. In addition, Magnolia may be less equipped to identify and address operating risks and hazards in the conduct of its business than those companies that have had longer operating histories.

Magnolia is not the operator on all of its acreage or drilling locations, and, therefore, is not able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets and could be liable for certain financial obligations of the operators or any of its contractors to the extent such operator or contractor is unable to satisfy such obligations.

Magnolia conducts many of its exploration and production operations through joint operating agreements with other parties under which the Company may not control decisions, either because the Company does not have a controlling interest or is not an operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with Magnolia’s, and therefore decisions may be made that are not what the Company believes are in its best interest. Moreover, parties to these agreements may be unable or unwilling to meet their economic or other obligations, and Magnolia may be required to fulfill those obligations alone. In either case, the value of Magnolia’s investment may be adversely affected.

Magnolia’s use of a contract operator to operate its assets may adversely affect Magnolia’s business.

EVOC provides certain oil and gas operating services, including providing operating services for the substantial majority of Magnolia’s assets under the Services Agreement, the term of which extends through at least October 29, 2020, subject to possible earlier termination. There can be no assurance that Magnolia’s use of an experienced contract operator will make its operations successful. For example, EV Energy Partners, L.P., an entity that EVOC previously provided operating services for, entered bankruptcy in April of 2018. Magnolia cannot be certain that its use of EVOC to provide contract operating services will continue to be economical or that EVOC will be able or willing to provide similar or additional services to Magnolia during or after the term of the Services Agreement. In addition, other factors may exist that materially and adversely affect Magnolia’s future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures, negating the benefits of low operating costs.

Adverse weather conditions may negatively affect Magnolia’s operating results and ability to conduct drilling activities.

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production, and difficulties in the transportation of oil, natural gas, and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on revenues, which will in turn negatively affect cash flow from operations.

Magnolia’s operations are substantially dependent on the availability of water. Restrictions on its ability to obtain water may have an adverse effect on its financial condition, results of operations, and cash flows.

Water is an essential component of oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in the areas where Magnolia’s assets are located in past years. These drought conditions have led governmental authorities to restrict the use of water, subject to their jurisdiction, for hydraulic fracturing to protect local water supplies. If Magnolia is unable to obtain water to use in operations, it may be unable to economically produce oil and natural gas, which could have a material and adverse effect on its financial condition, results of operations, and cash flows.

Magnolia’s producing properties are predominantly located in South Texas, making Magnolia vulnerable to risks associated with operating in a limited geographic area.

Substantially all of Magnolia’s producing properties are geographically concentrated in the Karnes County portion of the Eagle Ford Shale in South Texas and the Giddings Field of the Austin Chalk. As a result, Magnolia may be disproportionately exposed to various factors, including, among others: (i) the impact of regional supply and demand factors, (ii) delays or interruptions of production from wells in such areas caused by governmental regulation, (iii) processing or transportation capacity constraints, (iv) market limitations, (v) availability of equipment and personnel, (vi) water shortages or other drought related conditions, or (vii) interruption of the processing or transportation of oil, natural gas, or NGLs. The concentration of Magnolia’s assets in a limited geographic area also increases its exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents, or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs, and prevent development of lease inventory before expirations. Any of the risks described above could have a material adverse effect on Magnolia’s business, financial condition, results of operations, and cash flow.

The marketability of Magnolia’s production is dependent upon transportation and other facilities, certain of which it does not control. If these facilities are unavailable, Magnolia’s operations could be interrupted and its revenues reduced.

The marketability of Magnolia’s oil and natural gas production depend in part upon the availability, proximity, and capacity of transportation facilities owned by third parties. Oil production is generally transported by gathering systems, including, with respect to the Karnes County Assets, the gathering system owned by Ironwood Eagle Ford Midstream, LLC. The remaining oil is generally then transported by the purchaser by truck. Natural gas production is generally transported by third-party gathering lines and, with respect to natural gas production from the Karnes County Assets, by the gathering system owned by Ironwood Eagle Ford Midstream, LLC. Magnolia does not control all of the trucks and transportation facilities used to transport production from the properties, and access to them may be limited or denied. Insufficient production from wells to support the construction of pipeline facilities by purchasers or a significant disruption in the availability of Magnolia’s or third-party transportation facilities or other production facilities could adversely impact

Magnolia’s ability to deliver to market or produce oil and natural gas and thereby cause a significant interruption in Magnolia’s operations. If, in the future, Magnolia is unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, it may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from Magnolia’s fields, would materially and adversely affect its financial condition and results of operations.

Magnolia may incur losses as a result of title defects in the properties in which it invests.

The existence of a material title deficiency can render a lease worthless and adversely affect Magnolia’s results of operations and financial condition. While Magnolia typically obtains title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case Magnolia may lose the lease and the right to produce all or a portion of the minerals under the property. Additionally, if an examination of the title history of a property reveals that an oil or natural gas lease or other developed right has been purchased in error from a person who is not the owner of the mineral interest desired, Magnolia’s interest would substantially decline in value. In such cases, the amount paid for such oil or natural gas lease or leases would be lost.

The development of proved undeveloped reserves may take longer and may require higher levels of capital expenditures than anticipated. Therefore, proved undeveloped reserves may not be ultimately developed or produced.

As of December 31, 2019, Magnolia’s assets contained 22.5 MMboe of proved undeveloped reserves consisting of 12.3 MMBbls of oil, 31.4 Bcf of natural gas, and 5.0 MMBbls of NGLs. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than anticipated. Magnolia’s ability to fund these expenditures is subject to a number of risks. Magnolia may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in its ability to access or grow production and reserves. Delays in the development of reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of the proved undeveloped reserves and future net revenues estimated for such reserves, and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause Magnolia to have to reclassify proved undeveloped reserves as unproved reserves. Furthermore, there is no certainty that Magnolia will be able to convert proved undeveloped reserves to developed reserves, or that undeveloped reserves will be economically viable or technically feasible to produce.

Certain factors could require Magnolia to write-down the carrying values of its properties, including commodity prices decreasing to a level such that future undiscounted cash flows from its properties are less than their carrying value.

Accounting rules require that Magnolia periodically review the carrying value of its properties for possible impairment. Based on prevailing commodity prices, specific market factors, circumstances at the time of prospective impairment reviews, the continuing evaluation of development plans, production data, economics, and other factors, Magnolia may be required to write-down the carrying value of its properties. A write-down constitutes a non-cash impairment charge to earnings. Commodity prices have been cyclical, settling as low as $46.92 per barrel for oil on the WTI spot price and $1.75 per MMBtu on the Henry Hub spot price for natural gas in 2019. Likewise, NGLs have seen significant volatility in realized prices. Further declines in commodity prices may adversely affect proved reserve values, which would likely result in a proved property impairment of Magnolia’s properties, which could have a material adverse effect on results of operations for the periods in which such charges are taken. Magnolia could experience material write-downs as a result of lower commodity prices or other factors, including low production results or high lease operating expenses, capital expenditures, or transportation fees.

Unless Magnolia replaces its reserves with new reserves and develops those new reserves, its reserves and production will decline, which would adversely affect future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless Magnolia conducts successful ongoing exploration and development activities or continually acquires properties containing proved reserves, proved reserves will decline as those reserves are produced. Magnolia’s future reserves and production, and therefore future cash flow and results of operations, are highly dependent on Magnolia’s success in efficiently developing current reserves and economically finding or acquiring additional recoverable reserves. Magnolia may not be able to develop, find, or acquire sufficient additional reserves to replace future production. If Magnolia is unable to replace such production, the value of its reserves will decrease, and its business, financial condition, and results of operations would be materially and adversely affected.

Magnolia depends upon a small number of significant purchasers for the sale of most of its oil, natural gas, and NGL production. The loss of one or more of such purchasers could, among other factors, limit Magnolia’s access to suitable markets for the oil, natural gas, and NGLs it produces.

Magnolia normally sells its production to a relatively small number of customers, as is customary in the oil and natural gas

business. In 2019, there were two purchasers who accounted for an aggregate 62% of the total revenue attributable to Magnolia’s assets. The loss of any significant purchaser could adversely affect Magnolia’s revenues in the short term. Magnolia expects to depend upon these or other significant purchasers for the sale of most of its oil and natural gas production. Magnolia cannot ensure that it will continue to have ready access to suitable markets for its future oil and natural gas production.

Magnolia may not be able to generate sufficient cash to service all of its indebtedness and may be forced to take other actions to satisfy debt obligations, which may not be successful.

Magnolia’s ability to make scheduled payments on or to refinance its indebtedness obligations, including the RBL Facility and the 6.0% Senior Notes due 2026 (the “2026 Senior Notes”), depends on Magnolia’s financial condition and operating performance, which are subject to prevailing economic and competitive conditions, industry cycles and certain financial, business and other factors affecting Magnolia’s operations, many of which are beyond Magnolia’s control. Magnolia may not be able to maintain a level of cash flow from operating activities sufficient to permit Magnolia to pay the principal, premium, if any, and interest on its indebtedness. Failure to make required payments on its indebtedness will result in an event of default under the agreement governing the applicable indebtedness, entitling the requisite lenders of such indebtedness to accelerate the payment of obligations thereunder and to exercise other remedies, including in respect of collateral (if any) securing such indebtedness. As of December 31, 2019, the Company had $400.0 million of principal debt related to the 2026 Senior Notes outstanding and no outstanding borrowings related to the RBL Facility and $550.0 million of borrowing capacity of the RBL Facility.

If Magnolia’s cash flow and capital resources are insufficient to fund debt service obligations, Magnolia may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital, or restructure or refinance existing indebtedness. Magnolia’s ability to restructure or refinance indebtedness will depend on the condition of the capital markets and its financial condition at such time. Any refinancing of indebtedness may be at higher interest rates and may require Magnolia to comply with more onerous covenants, which could further restrict business operations. The terms of Magnolia’s existing or future debt instruments may restrict it from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely harm its ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, Magnolia could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The RBL Facility and the indenture governing the 2026 Senior Notes limit Magnolia’s ability to dispose of assets and use the proceeds from such dispositions. Magnolia may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit Magnolia to meet scheduled debt service obligations.

Restrictions in Magnolia’s existing and future debt agreements could limit Magnolia’s growth and ability to engage in certain activities.

Magnolia’s ability to meet its expenses and debt obligations and comply with the covenants and restrictions contained therein will depend on its future performance, which will be affected by financial, business, economic, industry, regulatory, and other factors, many of which are beyond Magnolia’s control. If market or other economic conditions deteriorate, Magnolia’s ability to comply with these covenants may be impaired. For example, Magnolia’s RBL Facility requires Magnolia to maintain quarterly compliance with a leverage and current ratio and the satisfaction of certain conditions, including the absence of defaults and events of default thereunder, to borrow money. Magnolia’s debt agreements also restrict the payment of dividends and distributions by certain of its subsidiaries to it, which could affect its access to cash. In addition, Magnolia’s ability to comply with the financial and other restrictive covenants in the agreements governing its indebtedness will be affected by the levels of cash flow from operations, future events, and other circumstances beyond Magnolia’s control. Breach of these covenants or restrictions will result in a default under Magnolia’s debt agreements, which if not cured or waived within the applicable grace period (if any), would permit the acceleration of all indebtedness outstanding thereunder by the requisite holders of such indebtedness. Upon acceleration, the indebtedness would become immediately due and payable, together with accrued and unpaid interest, and any commitments of a lender to make further loans to Magnolia may terminate. Even if new financing were then available, it may not be on terms that are acceptable to Magnolia. In addition to accelerating the indebtedness, the requisite group of affected lenders may exercise remedies upon the incurrence of an event of default, including through foreclosure, in respect of the collateral securing any such secured financing arrangements. Moreover, any subsequent replacement of Magnolia’s financing arrangements may require it to comply with more restrictive covenants, which could further restrict business operations.

Any significant reduction in Magnolia’s borrowing base under the RBL Facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact Magnolia’s ability to fund its operations.

The RBL Facility limits the amounts Magnolia can borrow up to a borrowing base amount, which the lenders determine, in good faith, in accordance with their respective usual and customary oil and gas lending criteria, based upon the loan value of the proved oil and gas reserves located within the geographic boundaries of the United States included in the most recent reserve report provided to the lenders. As of December 31, 2019, the Company had $550.0 million of borrowing base capacity of the RBL Facility.

The RBL Facility requires periodic borrowing base redeterminations based on reserve reports. Additionally, the borrowing base is subject to unscheduled reductions due to certain issuances of new junior lien indebtedness, unsecured indebtedness or subordinated indebtedness, certain sales or acquisitions of borrowing base properties, or early monetizations or terminations of certain hedge or swap positions. An unscheduled redetermination may also be requested by the requisite lenders under the RBL Facility, once within a twelve month period, or by Magnolia, twice within a twelve month period. A reduced borrowing base could render Magnolia unable to access adequate funding under the RBL Facility. Additionally, if the aggregate amount outstanding under the RBL Facility exceeds the borrowing base at any time, Magnolia would be required to repay any indebtedness in excess of the borrowing base or to provide mortgages on additional borrowing base properties to eliminate such excess. As a result of a mandatory prepayment and/or reduced access to funds under the RBL Facility, Magnolia may be unable to implement its drilling and development plan, make acquisitions, or otherwise carry out business plans, which would have a material adverse effect on its financial condition and results of operations.

Magnolia’s operations are subject to environmental and occupational health and safety laws and regulations that may expose the Company to significant costs and liabilities.

Magnolia’s operations are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of the Company’s operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to Magnolia’s operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities, and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from the Company’s operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties.

Certain environmental laws impose strict joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. Magnolia may be required to remediate contaminated properties currently or formerly operated by the Company or facilities of third parties that received waste generated by the Companies.

Magnolia may incur substantial losses and be subject to substantial liability claims as a result of operations. Additionally, Magnolia may not be insured for, or insurance may be inadequate to protect Magnolia against, these risks.

Magnolia is not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect its business, financial condition, or results of operations.

Magnolia’s development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:


•	environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas, or other pollution into the environment, including groundwater, air, and shoreline contamination, or the presence of endangered or threatened species;


•	abnormally pressured formations;


•	mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;


•	fires, explosions, and ruptures of pipelines;


•	personal injuries and death;


•	natural disasters; and


•	terrorist attacks targeting oil and natural gas related facilities and infrastructure.

Any of these events could adversely affect Magnolia’s ability to conduct operations or result in substantial loss as a result of claims for:


•	injury or loss of life;


•	damage to and destruction of property, natural resources, and equipment;


•	pollution and other environmental damage;


•	regulatory investigations and penalties; and


•	repair and remediation costs.

Magnolia may elect not to obtain insurance for any or all of these risks if it believes that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on business, financial condition, and results of operations.

Properties that Magnolia decides to drill may not yield oil or natural gas in commercially viable quantities.

Properties that Magnolia decides to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect its results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable Magnolia to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. Magnolia cannot ensure that the analogies drawn from available data from other wells, more fully explored prospects or producing fields will be applicable to its drilling prospects. Further, Magnolia’s drilling operations may be curtailed, delayed, or canceled as a result of numerous factors, including:


•	unexpected drilling conditions;


•	title issues;


•	pressure or lost circulation in formations;


•	equipment failures or accidents;


•	adverse weather conditions;


•	compliance with environmental and other governmental or contractual requirements; and


•	increases in the cost of, and shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment, and services.

Magnolia may be unable to make additional attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt its business and hinder its ability to grow.

In the future, Magnolia may make acquisitions of assets or businesses that are expected to complement or expand the Company’s current business. However, there is no guarantee that Magnolia will be able to identify attractive acquisition opportunities. In the event it is able to identify attractive acquisition opportunities, Magnolia may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause Magnolia to refrain from, completing acquisitions.

The success of completed acquisitions will depend on Magnolia’s ability to effectively integrate the acquired business into its existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of its managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that it will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets. Magnolia’s failure to achieve consolidation savings, to integrate the acquired businesses and assets into its then-existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on its financial condition and results of operations.

Certain of Magnolia’s properties are subject to land use restrictions, which could limit the manner in which Magnolia conducts business.

Certain of Magnolia’s properties are subject to land use restrictions, including city ordinances, which could limit the manner in which Magnolia conducts business. Such restrictions could affect, among other things, access to and the permissible uses of facilities as well as the manner in which Magnolia produces oil and natural gas and may restrict or prohibit drilling in general. The costs incurred to comply with such restrictions may be significant in nature, and Magnolia may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from the drilling of wells.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel, and oilfield services could adversely affect Magnolia’s ability to execute its development plans within its budget and on a timely basis.

The demand for drilling rigs, pipe, and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil, natural gas, and NGL prices, causing periodic shortages of supplies and needed personnel. Magnolia’s operations are concentrated in areas in which oilfield activity levels have increased rapidly, and as a result, demand for such drilling rigs, equipment, and personnel, as well as access to transportation, processing, and refining facilities in these areas, have increased, as have the costs for those items. To the extent that commodity prices improve in the future, the demand for and prices of these goods and services are likely to increase, and Magnolia could encounter delays in securing, or an inability to secure, the personnel, equipment, power, services, resources, and facilities access necessary for it to resume or increase Magnolia’s development activities, which could result in production volumes being below its forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on cash flow and profitability. Furthermore, if it is unable to secure a sufficient number of drilling rigs at reasonable costs, Magnolia may not be able to drill all of its acreage before its leases expire.

Magnolia could experience periods of higher costs if commodity prices rise. These increases could reduce profitability, cash flow, and ability to complete development activities as planned.

Historically, capital and operating costs have risen during periods of increasing oil, natural gas, and NGL prices. These cost increases have resulted from a variety of factors that Magnolia will be unable to control, such as increases in the cost of electricity, steel, and other raw materials; increased demand for labor, services, and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and natural gas industry in recent periods have led to declining costs of some drilling equipment, materials, and supplies. However, such costs may rise faster than increases in Magnolia’s revenue if commodity prices rise, thereby negatively impacting its profitability, cash flow, and ability to complete development activities as scheduled and on budget.

Magnolia may be involved in legal proceedings that could result in substantial liabilities.

Like many oil and gas companies, from time to time, Magnolia expects to be involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of its business. Such legal proceedings are inherently uncertain, and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on Magnolia because of legal costs, diversion of management, other personnel, and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties, or sanctions, as well as judgments, consent decrees, or orders requiring a change in its business practices, which could materially and adversely affect its business, operating results, and financial condition. Accruals for such liability, penalties, or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas produced by Magnolia, while potential physical effects of climate change could disrupt production and cause it to incur significant costs in preparing for or responding to those effects.

The EPA has determined that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment and has adopted regulations pursuant to the CAA to reduce GHG emissions from various sources.

The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which will include certain of Magnolia’s operations. These reporting requirements cover all segments of the oil and natural gas industry, including gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. Separately, in June 2016, the EPA published the Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Reconsideration that establish new controls, known as Subpart OOOOa, for emissions of methane from new, modified, or reconstructed sources in the oil and gas sector (“the 2016 OOOOa”). Following the change in presidential administration, there have been attempts to modify these regulations. Most recently, in August 2019, the EPA proposed amendments to the 2016 standards that, among other things, would rescind methane-specific requirements applicable to sources in the oil and natural gas industry but retain emissions limits for volatile organic compounds. Legal challenges to any final rulemaking that rescinds the 2016 standards are expected. As a result, Magnolia cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements.

Although there has been no federal legislation to reduce GHG emissions, a number of states have developed programs that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes, or encouraging the use of renewable energy or alternative low-carbon fuels. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. 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. For example, in April 2016, the United States signed the Paris Agreement, which includes nonbinding pledges to limit or reduce future emissions. In November 2019, the United States formally initiated the one year withdrawal from the agreement but may later choose to rejoin the Paris Agreement or enter into a future international agreement related to GHGs. However, the terms on which the United States may reenter the Paris Agreement, or a separately negotiated agreement, are unclear at this time.

Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced by Magnolia and lower the value of its reserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or eliminating their investment in oil, natural gas, and NGL activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Additionally, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive industries. Separately, activists may also pursue other means of curtailing oil and gas operations, such as through litigation. The Company continually monitors the global

climate change agenda initiatives, including stakeholder concerns, and responds accordingly based on its assessment of such initiatives on its business.

A negative shift in investor or shareholder sentiment of the oil and gas industry could adversely affect Magnolia’s business and ability to raise debt and equity capital.

Certain segments of the investor community have developed negative sentiment towards investing in the oil and gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments, and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to reduce or stop financing oil and gas and related infrastructure projects.

In addition, shareholder activism has been recently increasing in the oil and gas industry, and shareholders may attempt to effect changes to Magnolia’s business or governance, whether by shareholder proposals, public campaigns, proxy solicitations, or otherwise. Such actions could adversely impact the Company’s business by distracting management and other personnel from their primary responsibilities, require the Company to incur increased costs, and/or result in reputational harm.

Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including Magnolia’s. This may also potentially result in a reduction of available capital funding for potential development projects, impacting the Company’s future financial results.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays in the completion of oil and natural gas wells, and adversely affect Magnolia’s production.

The hydraulic fracturing process involves the injection of water, proppants, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. It is typically done at substantial depths in formations with low permeability. Magnolia routinely uses fracturing techniques in the U.S. and other regions to expand the available space for natural gas and oil to migrate toward the wellbore. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but certain federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA finalized regulations under the CWA in June 2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Separately, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.

From time to time the U.S. Congress has considered proposals to regulate hydraulic fracturing under the SDWA. While, to date, those proposals have not been enacted, several states have already enacted or are otherwise considering legislation to regulate hydraulic fracturing practices through more stringent permitting, fluid disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Hydraulic fracturing of wells and subsurface water disposal via injection wells are also under public and governmental scrutiny due to potential environmental and physical impacts, including possible contamination of groundwater and drinking water and possible links to seismic events. In addition, some municipalities have significantly limited or prohibited drilling activities and/or hydraulic fracturing or are considering doing so. Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas in which the Company conducts business could result in increased compliance costs or additional operating restrictions in the U.S.

Competition in the oil and natural gas industry is intense, making it more difficult for Magnolia to acquire properties, market oil or natural gas, and secure trained personnel.

Magnolia’s ability to acquire additional prospects and to find and develop reserves in the future will depend on its ability to evaluate and select suitable properties for acquisitions and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many other oil and natural gas companies possess and employ greater financial, technical, and personnel resources than Magnolia. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for, and purchase a greater number of properties and prospects than Magnolia’s financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than Magnolia will able to offer. The cost to attract and retain qualified personnel has historically continually increased due to competition and may increase substantially in the future. Magnolia may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel, and raising additional capital, which could have a material adverse effect on its business.

The loss of senior management or technical personnel could adversely affect operations.

Magnolia depends on the services of its senior management and technical personnel. Magnolia does not maintain, nor does Magnolia plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of its senior management could have a material adverse effect on its business, financial condition, and results of operations. Magnolia is also dependent, in part, upon EVOC’s technical personnel in connection with operating its assets pursuant to the Services Agreement. A loss by EVOC of its technical personnel could adversely affect Magnolia’s business and results of operations.

Magnolia may not be able to keep pace with technological developments in its industry.

The oil and natural gas industry is characterized by rapid and significant technological advancement and the introduction of new products and services using new technologies. As others use or develop new technologies, Magnolia may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial cost. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before Magnolia can. Magnolia may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies it expects to use were to become obsolete, Magnolia’s business, financial condition, or results of operations could be materially and adversely affected.

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm Magnolia’s business may occur and not be detected.

Magnolia’s management does not expect that Magnolia’s internal and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in Magnolia have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Magnolia is also dependent, in part, upon EVOC’s internal and disclosure controls in connection with operating its assets pursuant to the Services Agreement. A failure of Magnolia’s or EVOC’s controls and procedures to detect error or fraud could seriously harm Magnolia’s business and results of operations.

Magnolia’s business could be adversely affected by security threats, including cyber security threats, and related disruptions.

Magnolia relies heavily on its information systems, and the availability and integrity of these systems is essential to conducting Magnolia’s business and operations. Technical system flaws, power loss, cyber security risks, including cyber or phishing-attacks, unauthorized access, malicious software, data privacy breaches by employees or others with authorized access, ransomware, and other cyber security issues could compromise Magnolia’s computer and telecommunications systems and result in disruptions to the Company’s business operations or the access, disclosure, or loss of Company data and proprietary information. Additionally, as a producer of natural gas and oil, Magnolia faces various security threats that could render its information or systems unusable, and threats to the security of its facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing and other facilities, refineries

and pipelines. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information, facilities, infrastructure, and systems essential to its business and operations, as well as data corruption, communication interruptions, or other disruptions to its operations, which, in turn, could have a material adverse effect on its business, financial position, results of operations, and cash flows.

Magnolia’s implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for its information, systems, facilities, and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. Magnolia is also dependent, in part, upon EVOC’s information systems in connection with operating its assets pursuant to the Services Agreement. A failure in the security of EVOC’s information systems could seriously harm Magnolia’s business and results of operations.

Magnolia is subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If the Company fails to comply with the requirements of Section 404 or if the Company or its auditors identify and report material weaknesses in internal control over financial reporting, Magnolia’s investors may lose confidence in the Company’s reported information and Magnolia’s stock price may be negatively affected.

Magnolia is required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). Section 404 requires that the Company documents and tests its internal control over financial reporting and issues the management’s assessment of the Company’s internal control over financial reporting. This section also requires that the Company’s independent registered public accounting firm issue an attestation report on such internal control. If Magnolia fails to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if the Company or its auditors identify and report material weaknesses in Magnolia’s internal control over financial reporting, the accuracy and timeliness of the filing of the Company’s annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in Magnolia’s reported financial information, which could have a negative effect on the trading price of the Company’s Class A Common Stock. In addition, a material weakness in the effectiveness of the Company’s internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce Magnolia’s ability to obtain financing, and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on the Company’s business, results of operations, and financial condition.

Risks Related to Magnolia’s Class A Common Stock and Capital Structure

Magnolia is a holding company. Magnolia’s sole material asset is its equity interest in Magnolia LLC, and Magnolia is accordingly dependent upon distributions from Magnolia LLC to pay taxes and cover its corporate and other overhead expenses.

Magnolia is a holding company and has no material assets other than its equity interest in Magnolia LLC. Magnolia has no independent means of generating revenue. To the extent Magnolia LLC has available cash, Magnolia intends to cause Magnolia LLC to make (i) generally pro rata distributions to its unitholders, including Magnolia, in an amount at least sufficient to allow Magnolia to pay its taxes and (ii) non-pro rata payments to Magnolia to reimburse it for its corporate and other overhead expenses. To the extent that Magnolia needs funds and Magnolia LLC or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any financing arrangements, or are otherwise unable to provide such funds, Magnolia’s liquidity and financial condition could be materially adversely affected.

Magnolia’s second amended and restated certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of Magnolia’s Class A Common Stock.

Magnolia’s second amended and restated certificate of incorporation authorizes its board of directors to issue preferred stock without stockholder approval. If Magnolia’s board of directors elects to issue preferred stock, it could be more difficult for a third-party to acquire Magnolia. In addition, some provisions of Magnolia’s second amended and restated certificate of incorporation and its bylaws could make it more difficult for a third-party to acquire control of Magnolia, even if the change of control would be beneficial to its stockholders, including:


•	limitations on the removal of directors;


•	limitations on the ability of Magnolia’s stockholders to call special meetings;


•	providing that the board of directors is expressly authorized to adopt, or to alter or repeal Magnolia’s bylaws; and


•	establishing advance notice and certain information requirements for nominations for election to its board of directors and for proposing matters that can be acted upon by stockholders at stockholder meetings.

In addition, certain change of control events may have the effect of accelerating any payments due under Magnolia’s RBL Facility, and could, in certain defined circumstances, require Magnolia to make an offer to repurchase its outstanding Senior Notes and/

or result in the acceleration of payments required by the indenture governing its outstanding notes, which could be substantial and accordingly serve as a disincentive to a potential acquirer of the Company.

Future sales of Magnolia’s Class A Common Stock in the public market, or the perception that such sales may occur, could reduce Magnolia’s stock price, and any additional capital raised by Magnolia through the sale of equity or convertible securities may dilute your ownership in the Company.

Magnolia may sell additional shares of Class A Common Stock or securities convertible into shares of its Class A Common Stock in subsequent offerings. Magnolia cannot predict the size of future issuances of its Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that such future issuances will have on the market price of its Class A Common Stock. Sales of substantial amounts of Magnolia’s Class A Common Stock (including shares issued in connection with an acquisition or in connection with Magnolia’s existing or future equity compensation plans), or the perception that such sales could occur, may adversely affect prevailing market prices of its Class A Common Stock.

Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of Magnolia’s income or other tax returns could adversely affect its financial condition and results of operations.

Magnolia is subject to taxes by U.S. federal, state, and local tax authorities. Magnolia’s future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:


•	changes in the valuation of Magnolia’s 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; or


•	changes in tax laws, regulations, or interpretations thereof.

In addition, Magnolia may be subject to audits of its income, sales, and other transaction taxes by U.S. federal, state, and local taxing authorities. Outcomes from these audits could have an adverse effect on the Company’s financial condition and results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not currently expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

Item 4. Mine Safety Disclosures

Not applicable.

Information About Magnolia’s Executive Officers and Directors

The following table sets forth, as of February 26, 2020, the names, ages, and positions held by Magnolia’s executive officers and directors:



Name	Age	Position
Stephen I. Chazen	73	Chairman, President and Chief Executive Officer
Christopher G. Stavros	56	Executive Vice President and Chief Financial Officer
Timothy D. Yang	48	Executive Vice President, General Counsel, and Corporate Secretary
Steve F. Millican	44	Senior Vice President, Operations
Arcilia C. Acosta	54	Director
Angela M Busch	53	Director
Edward P. Djerejian	80	Director
James R. Larson	70	Director
Michael G. MacDougall	49	Director
Dan F. Smith	73	Director
John B. Walker	74	Director

Stephen “Steve” I. Chazen has served as Magnolia’s President and Chief Executive Officer since February 2017 and has served as Chairman of the Board since the completion of the Company’s initial public offering in May 2017. Prior to joining Magnolia, Mr. Chazen was Chief Executive Officer of Occidental Petroleum Corporation (“Occidental”), whose principal businesses consist of oil and gas, chemical and midstream, and marketing segments, a position he held from May 2011 until his retirement in April 2016, and was a member of Occidental’s board of directors of Occidental from 2010 to 2017.

Christopher G. Stavros serves as Magnolia’s Executive Vice President and Chief Financial Officer, a position he has held since the closing of the Business Combination. Prior to joining the Company, Mr. Stavros was Chief Financial Officer of Occidental from 2014 to 2017, having previously served in various investor relations and treasury roles at Occidental since 2005.

Timothy D. Yang joined Magnolia as Executive Vice President, General Counsel, and Corporate Secretary in September 2018. Prior to joining Magnolia, Mr. Yang served as General Counsel and Corporate Secretary of Newfield Exploration Company, an independent exploration and production company, from July 2015 through September 2018, and as General Counsel, Chief Compliance Officer, and Secretary of Sabine Oil & Gas Corporation from February 2013 to July 2015.

Steve F. Millican serves as Senior Vice President, Operations for Magnolia, a position he has held since November 2018. Prior to joining the Company, Mr. Millican was Senior Vice President and General Manager of the South Texas Region for EnerVest Operating Company since July 2016, and he held various reservoir engineering positions at EnerVest from 2008 to 2016.

Arcilia C. Acosta is the President and Chief Executive Officer of CARCON Industries & Construction, specializing in commercial, institutional, and transportation construction, and is also the Chief Executive Officer and controlling principal of STL Engineers.

Angela M. Busch currently serves as the Executive Vice President of Corporate and Business Development for Ecolab Inc., a global leader in water, hygiene, and energy technologies and services, where she is responsible for acquisitions, divestitures, and alliances in support of Ecolab’s strategic objectives related to its global portfolio of business and activities.

Edward P. Djerejian served in the U.S. Foreign Service for eight presidents, from John F. Kennedy in 1962 to William J. Clinton in 1994. After his retirement from government service in 1994, he became, and currently serves as, the director of the James A. Baker III Institute for Public Policy at Rice University, a premier nonpartisan public policy think tank.

James R. Larson has served as an independent director of CSI Compressco GP Inc. and general partner of CSI Compressco L.P., a provider of compression services and equipment for natural gas and oil production, gathering, transportation, processing, and storage, as Chairman of its Audit Committee since July 2011, and as a member of its Conflicts Committee since April 2012. Mr. Larson retired in January 2006 from his position as senior vice president of Anadarko Petroleum Corporation (“Anadarko”), an independent exploration and production company, and he held various tax and financial positions within Anadarko after joining the company in 1981.

Michael G. MacDougall is a senior partner of TPG Global, LLC, a leading global alternative asset firm, the Managing Partner of TPG Pace Energy, and the co-Managing Partner of TPG Energy Solutions.

Dan F. Smith is a retired Chief Executive Officer of Lyondell Chemical Company (“Lyondell”), which operated in the chemicals, polymers and fuels business segments, and its wholly owned subsidiaries Millennium Chemicals Inc. and Equistar Chemicals, LP., a

position he held from December 1996 until his retirement in December 2007. Mr. Smith is currently a director of Orion Engineered Carbons, S.A., Kraton Corp., and the general partner of Valerus Compression Services, L.P. (doing business as Axip Energy Services, L.P.).

John B. Walker has served as the Chief Executive Officer of EnerVest, Ltd since 1992. EnerVest has more than $5.0 billion in assets with an interest in more than 30,000 wells across 14 states.

PART II

Item 5. Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

(a) Market Information

Magnolia’s Class A Common Stock are currently traded on the NYSE under the ticker symbol “MGY.” Through July 30, 2018, Magnolia’s Class A Common Stock and warrants were listed under the symbols “TPGE” and “TPGE.W,” respectively. On July 31, 2018, the Company delisted the units offered in its initial public offering, each consisting of one share of Class A Common Stock and one-third of a warrant, which were listed under the symbol “TPGE.U,” and the units ceased to trade. In July 2019, the Company exchanged all of its public and private warrants, which, in the case of the public warrants, were listed under the symbol “MGY.WS,” for Class A Common Stock, and the warrants ceased to trade.

(b) Holders

At February 24, 2020, there were 48 holders of record of Magnolia’s separately traded Class A Common Stock, and 5 holders of record of the Company’s Class B Common Stock, par value $0.0001 per share (“Class B Common Stock”).

The following table sets forth the Company’s share repurchase activities for each period presented.



Period	Number of Shares of Class A Common Stock Purchased	Average Price Paid per Share		Total Number of Common Shares Purchased as Part of Publicly Announced Program ⁽¹⁾	Maximum Number of Common Shares that May Yet be Purchased Under the Program
October 1, 2019 - October 31, 2019	50,000	$	11.10	50,000	9,000,000
November 1, 2019 - November 30, 2019	—	—		—	9,000,000
December 1, 2019 - December 31, 2019⁽²⁾	—	—		—	9,000,000
Total	50,000	$	11.10	50,000	9,000,000


(1)	In August 2019, the Company’s board of directors authorized a share repurchase program of up to 10 million shares of Class A Common Stock. The program does not require purchases to be made within a particular time frame.

(2)

On December 18, 2019, outside of the share repurchase program, Magnolia LLC repurchased and subsequently canceled 6.0 million units representing limited liability company interests in Magnolia LLC with an equal number of shares of corresponding Class B Common Stock for a cash consideration of $69.1 million at an average price of $11.52 per share. There is no public market for the Class B Common Stock. For further detail, see Note 13 - Stockholders’ Equity in the Notes to the Consolidated and Combined Financial Statements in this Annual Report on Form 10-K.

(d) Comparative Stock Performance

The performance graph below compares the cumulative total stockholder return for the Company’s Class A Common Stock to that of the Standard and Poor’s, (“S&P”), 500 Index and the S&P 500 Oil & Gas Exploration and Production Index for the Successor Period. “Cumulative total return” means the change in share price of the Company’s Class A Common Stock during the measurement period divided by the share price at the beginning of the measurement period. The graph assumes an investment of $100 was made in the Company’s Class A Common Stock and in each of the S&P 500 Index and the S&P 500 Oil & Gas Exploration and Production Index on June 26, 2017, which is when the Class A Common Stock and warrants comprising the units offered in Magnolia’s initial public offering began separate trading.

Note: The stock price performance of Magnolia’s Class A Common Stock is not necessarily indicative of future performance.

The above information under the caption “Comparative Stock Performance” shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act except to the extent that Magnolia specifically requests that such information be treated as “soliciting material” or specifically incorporate such information by reference into such a filing.

Item 6. Selected Financial Data

The following table sets forth selected financial data of the Company over the five-year period ended December 31, 2019. The below data is split into three distinct periods: the period after the Business Combination, which includes the year ended December 31, 2019, referred to as the 2019 Successor Period and the period from July 31, 2018 to December 31, 2018, referred to as the 2018 Successor Period; the period before the Business Combination derived from the audited historical combined financial statements of the Karnes County Business, which includes period from January 1, 2018 to July 30, 2018, referred to as the 2018 Predecessor Period, the year ended 2017, referred to as the 2017 Predecessor Period, the year ended December 2016, and the period from October 1, 2015 to December 31, 2015; and the period from January 1, 2015 to September 30, 2015 derived from the audited historical financial statements of the predecessor to the Karnes County Business (the “AM Assets”).

This information should be read in connection with, and is qualified in its entirety by, the more detailed information in the Company’s financial statements set forth in this Annual Report on Form 10-K. Certain amounts for prior years have been reclassified to

conform to the current presentation. Factors that materially affect the comparability of this information are disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Item 7 of this Annual Report on Form 10-K.



	Successor						Predecessor											AM Assets
(In thousands, except per share data)	Year Ended December 31, 2019			July 31, 2018 Through December 31, 2018			January 1, 2018 Through July 30, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016			October 1, 2015 Through December 31, 2015		January 1, 2015 Through September 30, 2015
Income Statement Data
Revenues	$	936,142		$	433,218		$	449,186		$	403,194		$	110,926		$	6,187	$	20,177
Operating expenses	808,640			319,260			211,382			213,183			82,067			5,432		23,031
Operating income	127,502			113,958			237,804			190,011			28,859			755		(2,854		)
Other income (expense)	(27,737		)	(20,055		)	(17,466		)	(8,396		)	(6,715		)	1,558		(41		)
Income tax expense	14,760			11,455			1,785			2,741			673			58		32
NET INCOME	85,005			82,448			$	218,553		$	178,874		$	21,471		$	2,255	$	(2,927	)
LESS: Net income attributable to noncontrolling interest	34,809			43,353
NET INCOME ATTRIBUTABLE TO MAGNOLIA	50,196			39,095
LESS: Non-cash deemed dividend related to warrant exchange	2,763			—
NET INCOME ATTRIBUTABLE TO CLASS A COMMON STOCK	$	47,433		$	39,095
Basic	$	0.29		$	0.25
Diluted	$	0.28		$	0.25
Weighted average number of common shares outstanding
Basic	161,886			154,527
Diluted	167,047			158,232



	Successor				Predecessor
(In thousands)	December 31, 2019		December 31, 2018		December 31, 2017		December 31, 2016		December 31, 2015
Balance Sheet Data
Total assets	$	3,466,406	$	3,433,523	$	1,688,974	$	1,427,368	$	125,995
Long-term debt	389,835		388,635		—		—		—
Total equity	$	2,728,529	$	2,707,955	$	1,597,838	$	1,361,918	$	121,485

For a discussion of significant acquisitions, see Note 3 - Acquisitions in the Notes to the Consolidated and Combined Financial Statements in this Annual Report on Form 10-K.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Company’s consolidated and combined financial statements and the related notes thereto.

This section of this Form 10-K generally discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. Discussions of 2017 items and year-to-year comparisons between 2018 and 2017 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

Overview

Magnolia’s business model was designed with a primary objective to generate stock market value over the long term. The Company’s strategy is to establish a company whose characteristics would demonstrate a certain basic set of criteria that appeal to generalist investors and to generate growing earnings per share over time, high operating and full cycle margins, and maintain a very strong balance sheet with a low amount of leverage.

On July 31, 2018 (the “Closing Date”), the Company and Magnolia Oil & Gas Parent LLC (“Magnolia LLC”), as applicable, consummated the acquisition of: (i) certain right, title, and interest in certain oil and natural gas assets located primarily in the Karnes County portion of the Eagle Ford Shale in South Texas (the “Karnes County Assets”) pursuant to that certain Contribution and Merger Agreement (as subsequently amended, the “Karnes County Contribution Agreement”), by and among the Company, Magnolia LLC, and certain affiliates (the “Karnes County Contributors”) of EnerVest Ltd. (“EnerVest”); (ii) certain right, title, and interest in certain oil and natural gas assets located primarily in the Giddings Field of the Austin Chalk (the “Giddings Assets”) pursuant to that certain Purchase and Sale Agreement (the “Giddings Purchase Agreement”) by and among Magnolia LLC and certain affiliates of EnerVest (the “Giddings Sellers”); and (iii) a 35% membership interest (the “Ironwood Interests”) in Ironwood Eagle Ford Midstream, LLC, a Texas limited liability company, which owns an Eagle Ford gathering system, pursuant to that certain Membership Interest Purchase Agreement, by and among Magnolia LLC and certain affiliates of EnerVest (the “Ironwood Sellers”) (collectively, the “Business Combination”).

In connection with the consummation of the Business Combination, on July 31, 2018, the Karnes County Contributors received 83.9 million shares of Class B Common Stock, par value $0.0001 per share (“Class B Common Stock”), 31.8 million shares of Class A Common Stock, par value $0.0001 per share (“Class A Common Stock”), and approximately $911.5 million in cash; the Giddings Sellers received approximately $282.7 million in cash; and the Ironwood Sellers received $25.0 million in cash. On March 29, 2019, Magnolia and EnerVest consummated the final settlement of the Business Combination, with Magnolia LLC receiving a net cash payment of $4.3 million in cash and the Karnes County Contributors forfeiting to Magnolia 0.5 million shares of Class A Common Stock and 1.6 million shares of Class B Common Stock (and a corresponding number of units representing limited liability company interest in Magnolia LLC (“Magnolia LLC Units”) to Magnolia LLC).

In accordance with accounting principles generally accepted in the United States of America (“GAAP”), the Company has been identified as the acquirer in the Business Combination and the Karnes County Business was deemed to be the accounting “Predecessor”. References to the “Successor” refer to the Company on or after the date of the Business Combination, including the combination of the Karnes County Business, the Giddings Assets, and the Ironwood Interests. The Business Combination was accounted for using the acquisition method of accounting and the Successor financial statements reflect a new basis of accounting based on the fair value of net assets acquired. As a result of the application of the acquisition method of accounting, the Company’s consolidated and combined financial statements and certain presentations of information therein are separated into two distinct periods to indicate the different ownership and accounting basis between the periods presented, the period before the consummation of the Business Combination, which includes the year ended December 31, 2017 (the “2017 Predecessor Period”) and the period from January 1, 2018 to July 30, 2018 (the “2018 Predecessor Period”); and the period after the Business Combination, which includes the period from July 31, 2018 to December 31, 2018 (the “2018 Successor Period”) and the year ended December 31, 2019 (the “2019 Successor Period”).

The Company operates in one reportable segment and is engaged in the acquisition, development, exploration, and production of oil and natural gas properties located in the United States. The Company's oil and natural gas properties are located primarily in Karnes County and the Giddings Field in South Texas, where the Company primarily targets the Eagle Ford Shale and the Austin Chalk formations.

As of December 31, 2019, Magnolia’s assets in South Texas included 39,998 gross (22,088 net) acres in Karnes, Gonzales, DeWitt, and Atascosa counties and 630,789 gross (428,766 net) acres in the Giddings Field. As of December 31, 2019, Magnolia held an interest in approximately 1,630 gross (1,141 net) wells, with total production of 66.8 thousand barrels of oil equivalent per day (“Mboe/d”) for the year ended December 31, 2019. In the fourth quarter of 2019, Magnolia operated two drilling rigs across its acreage, one rig in Karnes County and one rig in the Giddings Field.

Magnolia recognized net income attributable to Class A Common Stock of $47.4 million, or $0.28 diluted common share, for the year ended December 31, 2019. Net income attributable to Class A Common Stock for the year ended December 31, 2019 was reduced by $2.8 million related to the non-cash deemed dividend as a result of a warrant exchange for Class A Common Stock. Magnolia also recognized net income of $85.0 million, which includes noncontrolling interest of $34.8 million related to the Class B Common Stock held by certain affiliates of EnerVest for the year ended December 31, 2019.

In July 2019, the Company exchanged all of its warrants for an aggregate of 9.2 million shares of Class A Common Stock. For more information, see Note 13 - Stockholders’ Equity in the Company’s consolidated financial statements included in this Annual Report on Form 10-K.

On August 5, 2019, the Company’s board of directors authorized a share repurchase program of up to 10 million shares. The program does not require purchases to be made within a particular timeframe. During the year ended December 31, 2019, the Company repurchased 1.0 million shares at a weighted average price of $10.28, for a total cost of approximately $10.3 million.

On December 18, 2019, outside of the share repurchase program, Magnolia LLC repurchased and subsequently canceled 6.0 million Magnolia LLC Units with an equal number of shares of corresponding Class B Common Stock for $69.1 million of cash consideration (the “Class B Common Stock Repurchase”). As a result of the Class B Common Stock Repurchase, the Company’s ownership in Magnolia LLC increased from 64.6% to 66.1% and the Karnes County Contributors’ ownership of Magnolia LLC decreased from 35.4% to 33.9%.

Results of Operations

Factors Affecting the Comparability of the Historical Financial Results

The 2018 Successor Period financial statements and the 2019 Successor Period financial statements reflect a new basis of accounting for the assets acquired and liabilities assumed by the Company in the Business Combination that is based on their fair value. As a result, the statement of operations subsequent to the Business Combination includes depreciation and amortization expense on Magnolia’s property, plant, and equipment balances made under the new basis of accounting. Therefore, the Company’s financial information prior to the Business Combination may not be comparable to its financial information subsequent to the Business Combination. Certain other items of income and expense may not be comparable as a result of the following factors:


•	For the periods prior to July 31, 2018, the results of operations reflect the results of solely the Predecessor, which, as described above, consists of only the results of the Karnes County Business, including, as applicable, its ownership of the Ironwood Interests, when the Predecessor was not owned by the Company, and do not include the results of the Giddings Assets;

•

The results of operations of the Predecessor were not previously accounted for as the results of operations of a stand-alone legal entity, and accordingly have been carved out, as appropriate, for the periods presented. The results of operations of the Predecessor therefore include a portion of indirect costs for salaries and benefits, depreciation, rent, accounting, legal services, and other expenses. In addition to the allocation of indirect costs, the results of operations reflect certain agreements executed by the Karnes County Contributors for the benefit of the Predecessor, including price risk management instruments. For more information, please see Note 1 - Description of Business and Basis of Presentation in the Notes to the Consolidated and Combined Financial Statements in this Annual Report on Form 10-K. These allocations may not be indicative of the cost of future operations or the amount of future allocations;


•	The Predecessor completed the acquisition of certain assets from GulfTex Energy III, L.P. and GulfTex Energy IV, L.P. on March 1, 2018 during the Predecessor Period, and accordingly the results of operations of the Predecessor reflect the impact of the assets acquired in that acquisition only from their respective acquisition date;

•

As a corporation, the Company is subject to U.S. federal income taxes at a statutory rate of 21% of pretax earnings whereas the Karnes County Contributors were treated as partnerships for income tax purposes. As a result, items of income, expense, gains, and losses flowed through to the owners of the Karnes County Contributors and were taxed at the owner level. Accordingly, no U.S. tax provision for federal income taxes is included in the financial statements of the Predecessor;


•	On August 31, 2018, the Company acquired substantially all of the South Texas assets of Harvest Oil & Gas Corporation (the “Harvest Acquisition”) for approximately $133.3 million in cash and 4.2 million shares of the Company’s Class A Common Stock. The Harvest Acquisition added an undivided working interest across a portion of the Karnes County Assets and all of the Giddings Assets;


•	On February 5, 2019, Magnolia Operating formed a joint venture, Highlander Oil & Gas Holdings LLC, to complete the acquisition of a 72% working interest in the Eocene-Tuscaloosa Zone, Ultra Deep Structure gas well located in St. Martin Parish, Louisiana (the “Highlander Well”); and

•

The financial results for the 2019 Successor Period and the 2018 Successor Period reflect the adoption of ASU No. 2014-09, Revenue from Contracts with Customers, which the Company adopted on December 31, 2018 and applied to all periods presented in the 2019 Successor Period and the 2018 Successor Period. The Predecessor Period continues to be reported under the accounting standards in effect for that period.

As a result of the factors listed above, the combined historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018

Oil, Natural Gas and Natural Gas Liquids Sales Revenues. The following table provides the components of Magnolia’s revenues for the periods indicated, as well as each period’s respective average prices and production volumes. This table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a ratio of six Mcf to one barrel. This ratio may not be reflective of the current price ratio between the two products.



	Successor				Predecessor
(In thousands, except per unit data)	Year Ended December 31, 2019		July 31, 2018 Through December 31, 2018		January 1, 2018 Through July 30, 2018
Production:
Oil (MBbls)	12,867		5,078		5,755
Natural gas (MMcf)	41,272		14,136		7,595
NGLs (MBbls)	4,643		1,857		1,097
Total (Mboe)	24,389		9,291		8,118

Average daily production:
Oil (Bbls/d)	35,252		33,190		27,146
Natural gas (Mcf/d)	113,074		92,392		35,825
NGLs (Bbls/d)	12,721		12,137		5,175
Total (boe/d)	66,819		60,725		38,292

Revenues:
Oil revenues	$	771,981	$	342,093	$	399,124
Natural gas revenues	93,745		42,979		22,135
Natural gas liquids revenues	70,416		48,146		27,927
Total revenues	$	936,142	$	433,218	$	449,186

Average Price:
Oil (per barrel)	$	60.00	$	67.37	$	69.35
Natural gas (per Mcf)	2.27		3.04		2.91
NGLs (per barrel)	15.17		25.93		25.46

Oil revenues were 82%, 79%, and 89% of the Company’s total revenues for the 2019 Successor Period, the 2018 Successor Period, and the 2018 Predecessor Period, respectively. Oil production was 53%, 55%, and 71% of total production volume for the 2019 Successor Period, the 2018 Successor Period, and the 2018 Predecessor Period, respectively. The 2019 Successor Period oil revenues were $30.8 million higher than the combined 2018 Successor Period and 2018 Predecessor Period due to 19% higher production partially offset by a 12% decrease in average prices. The 2,034 MBbls higher volumes in the 2019 Successor Period compared to the combined 2018 Successor Period and 2018 Predecessor Period are attributable to the inclusion of the Giddings Assets, recent acquisitions, and continued development.

Natural gas revenues were 10%, 10%, and 5% of the Company's total revenues for the 2019 Successor Period, the 2018 Successor Period, and the 2018 Predecessor Period, respectively. Natural gas production was 28%, 25%, and 16% of total production volume for the 2019 Successor Period, the 2018 Successor Period, and the 2018 Predecessor Period, respectively. 2019 Successor Period natural gas revenues were $28.6 million higher than the combined 2018 Successor Period and 2018 Predecessor Period due to 19,541 MMcf, or 90%, higher natural gas production primarily attributable to the Successor’s inclusion of the Giddings Assets and the acquisition of the Highlander Well, partially offset by a 24% decrease in average prices.

Natural gas liquids (“NGLs”) revenues were 8%, 11%, and 6% of the Company’s total revenues for the 2019 Successor Period, the 2018 Successor Period, and the 2018 Predecessor Period, respectively. NGL production was 19%, 20%, and 14% of total production volume for the 2019 Successor Period, the 2018 Successor Period, and the 2018 Predecessor Period, respectively. 2019 Successor Period natural gas liquids revenues were $5.7 million lower than the combined 2018 Successor Period and 2018 Predecessor Period due to a

41% decrease in average prices partially offset by 57%, or 1,689 MBbls, higher production. The higher production volumes are primarily attributable to the Successor’s inclusion of the Giddings Assets, recent acquisitions, and continued development.

Operating Expenses and Other Income (Expense). The following table summarizes the Company’s operating expenses and other income (expense) for the periods indicated.



	Successor						Predecessor
(In thousands, except per unit data)	Year Ended December 31, 2019			July 31, 2018 Through December 31, 2018			January 1, 2018 Through July 30, 2018
Operating Expenses:
Lease operating expenses	$	93,788		$	30,753		$	23,513
Gathering, transportation, and processing	34,924			14,445			12,929
Taxes other than income	53,728			23,170			23,763
Exploration expenses	12,741			11,882			492
Asset retirement obligations accretion	5,512			1,668			104
Depreciation, depletion and amortization	523,572			177,890			137,871
Amortization of intangible assets	14,505			6,044			—
General and administrative expenses	69,432			28,801			12,710
Transaction related costs	438			24,607			—
Total operating costs and expenses	$	808,640		$	319,260		$	211,382

Other Income (Expense):
Income from equity method investee	$	857		$	773		$	711
Interest expense, net	(28,356		)	(12,454		)	—
Loss on derivatives, net	—			—			(18,127		)
Other expense, net	(238		)	(8,374		)	(50		)
Total other expense	$	(27,737	)	$	(20,055	)	$	(17,466	)

Average Operating Costs per boe:
Lease operating expenses	$	3.85		$	3.31		$	2.90
Gathering, transportation, and processing	1.43			1.55			1.59
Taxes other than income	2.20			2.49			2.93
Exploration costs	0.52			1.28			0.06
Asset retirement obligation accretion	0.23			0.18			0.01
Depreciation, depletion and amortization	21.47			19.15			16.98
Amortization of intangible assets	0.59			0.65			—
General and administrative expenses	2.85			3.10			1.57
Transaction related costs	0.02			2.65			—

Lease operating expenses are the costs incurred in the operation of producing properties, including expenses for utilities, direct labor, water disposal, workover rigs, workover expenses, materials, and supplies. The 2019 Successor Period lease operating expenses were $39.5 million higher than the combined 2018 Successor Period and 2018 Predecessor Period primarily due to the inclusion of the Giddings Assets, recent acquisitions, and continued development. The higher per boe cost in the 2019 Successor Period compared to the combined 2018 Successor Period and 2018 Predecessor Period was primarily due to higher fixed costs per boe in the Giddings area.

Gathering, transportation, and processing costs are costs incurred to deliver oil, natural gas, and NGLs to the market. Cost levels of these expenses can vary based on the volume of oil, natural gas, and NGLs produced as well as the cost of commodity processing. The 2019 Successor Period gathering, transportation, and processing costs were $7.6 million higher than the combined 2018 Successor Period and 2018 Predecessor Period primarily due to the inclusion of the Giddings Assets as the Giddings Assets produce more gas than the Karnes County Assets and require more gathering, transportation, and processing than the Karnes County Assets. The lower cost per boe in the 2019 Successor Period compared to the combined 2018 Successor Period and 2018 Predecessor Period was primarily attributable to the adoption of the new revenue recognition requirements that were not retroactively applied to the 2018 Predecessor Period.

Taxes other than income include production and ad valorem taxes. These taxes are based on rates primarily established by state and local taxing authorities. Production taxes are based on the market value of production. Ad valorem taxes are based on the fair market value of the mineral interests or business assets. The 2019 Successor Period taxes other than income were $6.8 million higher than the combined 2018 Successor Period and 2018 Predecessor Period primarily due to an increase in revenues. The lower costs per boe in the 2019 Successor Period compared to the combined 2018 Successor Period and 2018 Predecessor Period were primarily due to the inclusion of the Giddings Assets as the Giddings Assets incur lower production taxes.

Exploration costs are geological and geophysical costs that include seismic surveying costs, costs of unsuccessful exploratory dry wells, costs of expired or abandoned leases, and delay rentals. The 2019 Successor Period exploration costs were $0.4 million higher than the combined 2018 Successor Period and 2018 Predecessor Period due to an increase in seismic surveying costs, but $0.19 lower on a boe basis as a result of higher volumes attributable to the inclusion of the Giddings Assets.

Asset retirement obligation accretion during the 2019 Successor Period was higher than the combined 2018 Successor and 2018 Predecessor Period. The 2019 Successor Period asset retirement obligation accretion was driven by the inclusion of the Giddings Assets. This resulted in higher accretion expense in the 2019 Successor Period of $0.23 per boe.

Depreciation, depletion and amortization (“DD&A”) during the 2019 Successor Period was $207.8 million higher than the combined 2018 Successor Period and 2018 Predecessor Period. The 2019 Successor Period DD&A and DD&A rate per boe were higher than the combined 2018 Successor Period and 2018 Predecessor Period mostly due to Magnolia’s higher property, plant, and equipment balances recorded as a result of the new basis of accounting related to the Business Combination, recent acquisitions, and decrease in proved reserves. The Predecessor’s reserves were based on a five-year development plan, whereas the vast majority of the Successor’s proved undeveloped reserves are planned to be developed within one year.

In connection with the close of the Business Combination, the Company recorded an estimated cost of $44.4 million for a non-compete agreement entered into with certain affiliates of EnerVest on the Closing Date as “Amortization of intangible assets” on the Company’s consolidated balance sheet. The 2019 Successor Period amortization of intangible assets was $8.5 million higher than the 2018 Successor Period due to twelve months of amortization in the 2019 Successor Period as compared to approximately five months of amortization in the 2018 Successor Period. These intangible assets have a definite life and are subject to amortization utilizing the straight-line method over their economic life, currently estimated to be two and one half to four years. There was no amortization of intangible assets in the 2018 Predecessor Period.

General and administrative (“G&A”) expenses during the 2019 Successor Period were $27.9 million higher than the combined 2018 Successor Period and 2018 Predecessor Period primarily due to the Successor incurring certain additional G&A expenses related to fees payable to EnerVest Operating L.L.C. (“EVOC”) under the Services Agreement as well as increased salaries and wages and stock-based compensation costs.

Transaction related costs are costs incurred related to the execution of the Business Combination and Harvest Acquisition, including legal fees, advisory fees, consulting fees, accounting fees, employee placement fees, and other transaction and facilitation costs. The 2019 Successor Period transaction related costs were $24.2 million lower than the 2018 Successor Period, as the majority of the Business Combination costs were incurred during the 2018 Successor Period.

Interest expense incurred in the 2019 Successor Period and 2018 Successor Period is due to interest and amortization of debt issuance costs related to the Company’s 6.0% Senior Notes due 2026 (the “2026 Senior Notes”) and the Company’s secured reserve-based revolving credit facility (the “RBL Facility”). The 2019 Successor Period interest expense incurred was higher than the 2018 Successor Period due to twelve months of expense in the 2019 Successor Period as compared to approximately five months of expense incurred in the 2018 Successor Period.

Loss on derivatives, net was $18.1 million for the 2018 Predecessor Period. Magnolia has not engaged in any hedging activities during the 2019 Successor Period or the 2018 Successor Period with respect to the commodity price risk to which the Company is exposed.

Other expense of $0.2 million in the 2019 Successor Period was lower compared to $8.4 million in the 2018 Successor Period as the 2018 Successor Period included a loss of $6.7 million related to the difference in fair market value of the Gidding Purchase Agreement earnout as recorded in the Business Combination and the payment made to fully settle the earnout agreement on September 28, 2018.

Liquidity and Capital Resources

Magnolia’s primary sources of liquidity and capital have been from cash flows from operations and, at the close of the Business Combination, issuances of equity and debt securities. The Company’s primary uses of cash have been for acquisitions of oil and natural gas properties and related assets, development of the Company’s oil and natural gas properties, and general working capital needs.

Magnolia believes that cash on hand, cash flows generated from operations, and the borrowings available under the RBL Facility will be adequate to fund Magnolia’s capital budget, including any share repurchases, and satisfy the Company’s short-term liquidity needs.

The Company may also utilize borrowings under other various financing sources available to Magnolia, including the issuance of equity or debt securities through public offerings or private placements, to fund Magnolia’s acquisitions and long-term liquidity needs. Magnolia’s ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and the Company’s financial condition.

As of December 31, 2019, the Company had $400.0 million of principal debt related to the 2026 Senior Notes outstanding and no outstanding borrowings related to the RBL Facility. As of December 31, 2019, the Company has $732.6 million of liquidity comprised of the $550.0 million of borrowing base capacity of the RBL Facility and $182.6 million of cash and cash equivalents. As of December 31, 2019, the Company’s Adjusted Consolidated Net Tangible Asset, as calculated in accordance with the Company’s Indenture relating to its 2026 Senior Notes, was approximately $2.6 billion.

Cash and Cash Equivalents

At December 31, 2019, Magnolia had $182.6 million of cash and cash equivalents. The Company’s cash and cash equivalents are maintained with various financial institutions in the United States. Deposits with these institutions may exceed the amount of insurance provided on such deposits. However, the Company regularly monitors the financial stability of its financial institutions and believes that the Company is not exposed to any significant default risk.

Sources and Uses of Cash and Cash Equivalents

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



	Successor						Predecessor
(In thousands)	Year Ended December 31, 2019			July 31, 2018 Through December 31, 2018			January 1, 2018 Through July 30, 2018			Year Ended December 31, 2017
Sources of cash and cash equivalents
Net cash provided by operating activities	$	647,619		$	305,470		$	284,812		$	257,371
Issuance of common stock	—			355,000			—			—
Proceeds from issuance of debt	—			400,000			—			—
Proceeds withdrawn from Trust Account	—			656,078			—			—
Other	7,301			—			62,641			57,046
	$	654,920		$	1,716,548		$	347,453		$	314,417
Uses of cash and cash equivalents:
Acquisition of EnerVest properties	$	4,250		$	(1,219,217	)	$	—		$	—
Acquisitions, other	(93,221		)	(146,532		)	(150,139		)	(58,653		)
Additions to oil and natural gas properties	(435,035		)	(141,619		)	(197,314		)	(247,426		)
Payment of Contingent Consideration	—			(26,000		)	—			—
Repayments of deferred underwriting compensation	—			(22,750		)	—			—
Cash paid for debt issuance costs	—			(23,336		)	—			—
Class A Common Stock repurchase	(10,277		)	—			—			—
Class B Common Stock repurchase	(69,093		)	—			—			—
Other	(4,669		)	(1,359		)	—			(8,338		)
	(608,045		)	(1,580,813		)	(347,453		)	(314,417		)
Increase in cash and cash equivalents	$	46,875		$	135,735		$	—		$	—

Sources of Cash and Cash Equivalents

Business Combination

The primary source of cash for the Business Combination in the 2018 Successor Period were from proceeds withdrawn from Trust account of $656.1 million related to the Company’s May 2017 initial public offering, the issuance of common stock of $355.0 million, and proceeds from issuance of the 2026 Senior Notes. See Overview of this Item 7 for more information on the Business Combination.

Net Cash Provided by Operating Activities

Operating cash flows are the Company’s primary source of liquidity and are impacted, in the short term and long term, by oil and natural gas prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of certain non-cash expenses such as DD&A, asset retirement obligation accretion, and deferred income tax expense.

Net cash provided by operating activities totaled $647.6 million, $305.5 million, $284.8 million, and $257.4 million for the 2019 Successor Period, the 2018 Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively. Cash provided by operating activities was positively impacted by the inclusion of the Giddings Assets in the 2019 Successor Period but was partially offset by interest expense payments, EnerVest service fee payments, and higher production tax payments. The 2018 Successor Period includes $24.6 million related to one-time transaction costs associated with the Business Combination and exploration expenses of $11.9 million primarily related to a one-time purchase of a seismic license continuation.

Uses of Cash and Cash Equivalents

Business Combination

The primary use of cash in the 2018 Successor Period was the acquisition of EnerVest properties, which included an aggregate of approximately $1.2 billion in cash, cash paid for debt issuance costs of $23.3 million, and the payment of a deferred underwriting compensation of approximately $22.8 million.

Other Acquisitions

During the 2019 Successor Period, the Company completed leasehold and property acquisitions of $93.2 million, comprised of the Highlander acquisition and other acquisitions of additional oil and gas assets primarily located in Karnes County. The Company incurred $146.5 million during the 2018 Successor Period related to acquisitions, the largest of which was the Harvest Acquisition. The 2018 Predecessor Period activity of $150.1 million is comprised of the acquisition by the Predecessor of certain oil and natural gas properties in the Eagle Ford Shale.

Additions to Oil and Natural Gas Properties

The following table sets forth the Company’s capital expenditures for the 2019 Successor Period:



(In thousands)	Year Ended December 31, 2019
Drilling and completion	$	416,353
Leasehold acquisition costs	10,003
Total capital expenditures	$	426,356

As of December 31, 2019, Magnolia was running a one-rig program for the Karnes County Assets and a one-rig program for the Giddings Assets. The activity in the 2019 Successor Period was largely driven by the number of operated and non-operated drilling rigs. The number of operated drilling rigs is largely dependent on commodity prices and the Company’s strategy of maintaining spending within 60% of adjusted EBITDAX.

Payment of Contingent Consideration

Pursuant to the Giddings Purchase Agreement, during the 2018 Successor Period, the Company paid the Giddings Sellers a cash payment of $26.0 million to fully settle the earnout obligation.

Capital Requirements

Repurchase of Class A Common Stock

On August 5, 2019, the Company’s board of directors authorized a share repurchase program of up to 10 million shares. The program does not require purchases to be made within a particular timeframe and whether the Company undertakes these additional repurchases is ultimately subject to numerous considerations, market conditions, and other factors. During the 2019 Successor Period, the Company repurchased 1.0 million shares at a weighted average price of $10.28, for a total cost of approximately $10.3 million.

Repurchase and Cancellation of Magnolia LLC Units and Class B Common Stock

Contractual Obligations

As of December 31, 2019, amounts due under the Company’s contractual obligations were as follows:



Contractual Obligations (In thousands)	Total		Less than 1 Year		2021-2022		2023-2024		More than 5 years
On-balance Sheet:
Debt, at face value	$	400,000	$	—	$	—	$	—	$	400,000
Interest payments⁽¹⁾	175,494		26,097		52,182		49,215		48,000
Off-balance sheet:
Purchase obligation ⁽²⁾	3,417		1,060		1,474		883		—
Operating lease obligations ⁽³⁾	9,851		2,647		3,159		2,310		1,735
Service fee commitment ⁽⁴⁾	19,636		19,636		—		—		—
Total contractual obligations	$	608,398	$	49,440	$	56,815	$	52,408	$	449,735


(1)	Interest payments include cash payments and estimated commitment fees on long-term debt obligations.


(2)	Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with firm transportation contracts and IT-related service commitments.


(3)	Amounts include long-term lease payments for office space, vehicles, equipment related to exploration, development, and production activities, as well as long-term obligations expected to be incurred for leases commencing in 2020.

(4)

Represents amounts due under the Company’s Service Agreement with EVOC. The annual services fee may be (a) increased or decreased to account for asset acquisitions and dispositions of assets, (b) increased to account for an increase in the rig count attributable to the assets and (c) decreased if the Company must perform any of such services itself because EVOC is unable or fails to do so. The term of the Services Agreement is through July 30, 2023, but the Services Agreement is subject to termination by either party after October 29, 2020.

Off-Balance Sheet Arrangements

As of December 31, 2019, there were no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Magnolia prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. Magnolia identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of Magnolia’s 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 Magnolia’s most critical accounting policies and estimates.

Reserves Estimates

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating conditions, and government regulations.

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within the Company’s development plan.

Despite the inherent imprecision in these engineering estimates, Magnolia’s reserves are used throughout the Company’s financial statements. For example, since Magnolia uses the units-of-production method to amortize its oil and gas properties, the quantity of reserves could significantly impact Magnolia’s DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for Magnolia’s supplemental oil and gas disclosures.

Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future. Operating costs, production and ad valorem taxes, and future development costs are based on current costs with no escalation. Actual costs may be materially higher or lower than the costs utilized in the estimate.

Magnolia has elected not to disclose probable and possible reserves or reserve estimates in this filing.

Impairments

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

Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, discount rates, and other variables. Key assumptions used in developing a discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative, and capital costs adjusted for inflation. The resulting future cash flows are discounted using a discount rate believed to be consistent with those applied by market participants.

Although the fair value estimate of each asset group is based on assumptions the Company believes to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. The Company has not incurred a proved property impairment. However, the continuous decline in commodity prices may adversely affect proved reserves values which would likely result in a proved property impairment. Negative revisions of estimated reserves quantities, increases in future cost estimates, or divestiture of a significant component of the asset group could also lead to a reduction in expected future cash flows and possibly an impairment of long-lived assets in future periods.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

For variable rate debt, interest rate changes generally do not affect the fair market value of such debt, but do impact future earnings and cash flows, assuming other factors are held constant. The Company is subject to market risk exposure related to changes in interest rates on borrowings under the RBL Facility. Interest on borrowings under the RBL Facility is based on the LIBOR rate or alternative base rate plus an applicable margin as stated in the agreement. At December 31, 2019, the Company had no borrowings outstanding under the RBL Facility.

Commodity Price Risk

The Company has not engaged in, and does not expect to engage in, any hedging activities with respect to the market risk to which it is exposed.

Magnolia’s primary market risk exposure is to the prices it receives for its oil, natural gas, and NGL production. The prices the Company ultimately realizes for its oil, natural gas, and NGLs are based on a number of variables, including prevailing index prices attributable to the Company’s production and certain differentials to those index prices. Pricing for oil, natural gas, and NGLs has historically been volatile and unpredictable, and this volatility is expected to continue in the future. The prices the Company receives for production depend on factors outside of its control, including physical markets, supply and demand, financial markets, and national and international policies. A $1.00 per barrel increase (decrease) in the weighted average oil price for the year ended December 31, 2019 would have increased (decreased) the Company’s revenues by approximately $12.9 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the year ended December 31, 2019 would have increased (decreased) Magnolia’s revenues by approximately $4.1 million on an annualized basis.

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors Magnolia Oil & Gas Corporation:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Magnolia Oil & Gas Corporation and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the year ended December 31, 2019 and for the period from July 31, 2018 to December 31, 2018 (Successor Period), and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the year ended December 31, 2019 and for the period from July 31, 2018 to December 31, 2018 (Successor Period), in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the 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 consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Assessment of the impact of estimated oil and gas reserves on depreciation expense related to proved oil and gas properties

As discussed in Note 2 to the consolidated financial statements, the Company depreciates its proved oil and gas properties using the units-of-production method. Under such method, capitalized costs are depreciated over total estimated proved oil and gas reserves. For the year ended December 31, 2019, the Company recorded depreciation, depletion and amortization expense of $523,572 thousand. The estimation of proved oil and gas reserves requires the expertise of independent reservoir engineering specialists, who take into consideration forecasted production, operating and capital cost assumptions, and historical oil and gas prices inclusive of market differentials. The Company engages independent reservoir engineering specialists to estimate proved oil and gas reserves, which are an input to the calculation of depreciation.

We identified the assessment of the impact of estimated oil and gas reserves on depreciation expense related to proved oil and gas properties as a critical audit matter. Complex auditor judgment was required in evaluating the Company’s estimate of proved oil and gas reserves. Auditor judgment was also required to evaluate the assumptions used by the Company related to forecasted production, operating and capital costs, and historical oil and gas prices inclusive of market differentials.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s depreciation process, including controls over the estimation of proved oil and gas reserves. We evaluated the competence, capabilities, and objectivity of the independent reservoir engineering specialists engaged by the

Company, who estimated the proved oil and gas reserves. We analyzed and assessed the determination of depreciation expense for compliance with industry and regulatory standards. We assessed compliance of the methodology used by the Company’s independent reservoir engineering specialists to estimate proved oil and gas reserves with industry and regulatory standards. We compared the forecasted production used by the Company’s independent reservoir engineering specialists to historical production rates. We evaluated the operating cost assumptions used by the Company’s independent reservoir engineering specialists by comparing them to historical costs. We evaluated the capital cost assumptions used by the Company’s independent reservoir engineering specialists by comparing them to historical costs. We compared the historical oil and gas prices used by the Company’s independent reservoir engineering specialists to publicly available prices and tested the relevant market differentials. We read and considered the report of the Company’s independent reservoir engineering specialists in connection with our evaluation of the Company’s reserve estimates.

Evaluation of the assessment of triggering events related to the impairment of proved oil and gas properties

As discussed in Note 2 to the consolidated financial statements, when circumstances indicate that proved oil and gas properties may be impaired, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets. The Company identifies those circumstances by analyzing indicators for possible triggers of impairment, such as significant decreases in forecasted commodity prices, significant increases in capital or operating costs and reservoir performance, which includes forecasted oil and gas reserves and forecasted production. The oil and natural gas properties balance as of December 31, 2019 was $3,815,221 thousand, which includes the proved oil and natural gas properties balance of $2,863,666 thousand.

We identified the evaluation of the assessment of triggering events related to the impairment of proved oil and gas properties as a critical audit matter. There was a high degree of subjective auditor judgment necessary to assess forecasted commodity prices, forecasted oil and gas reserves, and forecasted capital and operating costs used by the Company in their assessment.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s assessment of indicators for possible triggers of impairment, including controls related to forecasted commodity prices, forecasted oil and gas reserves and forecasted capital and operating costs. We compared forecasted commodity prices to publicly available market information. We evaluated the competence, capabilities, and objectivity of the Company’s independent reservoir engineering specialists engaged by the Company who estimated oil and gas reserves. We compared the Company’s forecasted production and forecasted capital and operating costs to historical results.

/s/ KPMG LLP

We have served as the Company’s auditor since 2017.

Houston, Texas

February 26, 2020

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Magnolia Oil & Gas Corporation:

Opinion on Internal Control Over Financial Reporting

We have audited Magnolia Oil & Gas Corporation and subsidiaries (the Company) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the year ended December 31, 2019 and for the period from July 31, 2018 to December 31, 2018 (Successor Period), and the related notes (collectively, the consolidated financial statements), and our report dated February 26, 2020 expressed, an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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.

/s/ KPMG LLP

Houston, Texas

February 26, 2020

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors of

Magnolia Oil and Gas Corporation

Houston, Texas

Opinion on the Financial Statements

We have audited the accompanying combined statements of operations, changes in parents’ net investment, and cash flows of certain oil and natural gas properties (the “Karnes County Business” or “Predecessor”) previously owned by EnerVest Energy Institutional Fund XIV-A, L.P., EnerVest Energy Institutional Fund XIV-C, L.P., EnerVest Energy Institutional Fund XIV-WIC, L.P., EnerVest Energy Institutional Fund XIV-2A, L.P. and EnerVest Energy Institutional Fund XIV-3A, L.P. (together the “Karnes County Contributors”, all of which are under the common management of EnerVest Ltd., as general partner), which were contributed on July 31, 2018 as part of a contribution and merger agreement between the Karnes County Contributors and Magnolia Oil & Gas Corporation and Magnolia Oil & Gas Parent LLC (formerly TPG Pace Energy Holdings Corp. and TPG Pace Energy Parent LLC), for the period from January 1, 2018 to July 30, 2018, and for the year ended December 31, 2017, and the related notes to the combined financial statements (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the results of operations and cash flows of the Karnes County Business for the period from January 1, 2018 to July 30, 2018 and for the year ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of management. Our responsibility is to express an opinion on the Karnes County Business’ 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 Karnes County Business 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 Karnes County Business 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 Karnes County Business’ 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.

Emphasis of Matter

As discussed in Note 1 to the financial statements, the Karnes County Business includes allocations of certain costs from the Karnes County Contributors. These costs may not be reflective of the actual level of costs which would have been incurred had the Karnes County Business operated as a separate entity apart from the Karnes County Contributors. As a result, historical financial information is not necessarily indicative of what the Karnes County Business’ combined results of operations and cash flows will be in the future.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2019

We have served as the Karnes County Business’ auditor since 2014.

Magnolia Oil & Gas Corporation

Consolidated Balance Sheets

(In thousands)



	Successor
	December 31, 2019			December 31, 2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	182,633		$	135,758
Accounts receivable	105,775			140,284
Drilling advances	299			12,259
Other current assets	4,511			4,058
Total current assets	293,218			292,359
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties	3,815,221			3,250,742
Other	3,087			360
Accumulated depreciation, depletion and amortization	(701,551		)	(177,898		)
Total property, plant and equipment, net	3,116,757			3,073,204
OTHER ASSETS
Deferred financing costs, net	8,390			10,731
Equity method investment	19,730			18,873
Intangible assets, net	23,851			38,356
Other long-term assets	4,460			—
TOTAL ASSETS	$	3,466,406		$	3,433,523
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	79,428		$	76,302
Other current liabilities (Note 7)	95,780			121,059
Total current liabilities	175,208			197,361
LONG-TERM LIABILITIES
Long-term debt, net	389,835			388,635
Asset retirement obligations, net of current	93,524			84,979
Deferred taxes, net	77,834			54,593
Other long-term liabilities	1,476			—
Total long-term liabilities	562,669			528,207
COMMITMENTS AND CONTINGENCIES (Note 11)
STOCKHOLDERS’ EQUITY
Class A Common Stock, $0.0001 par value, 1,300,000 shares authorized, 168,318 shares issued and 167,318 shares outstanding in 2019 and 156,333 shares issued and outstanding in 2018	17			16
Class B Common Stock, $0.0001 par value, 225,000 shares authorized, 85,790 and 93,346 shares issued and outstanding in 2019 and 2018, respectively	9			9
Additional paid-in capital	1,703,362			1,641,237
Treasury Stock, at cost, 1,000 shares in 2019	(10,277		)	—
Retained earnings	82,940			35,507
Noncontrolling interest	952,478			1,031,186
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,466,406		$	3,433,523

The accompanying notes are an integral part to these consolidated and combined financial statements.

Magnolia Oil & Gas Corporation

Consolidated and Combined Statements of Operations

(In thousands, except per share data)



	Successor						Predecessor
	Year Ended December 31, 2019			July 31, 2018 Through December 31, 2018			January 1, 2018 Through July 30, 2018			Year Ended December 31, 2017
REVENUES
Oil revenues	$	771,981		$	342,093		$	399,124		$	350,204
Natural gas revenues	93,745			42,979			22,135			25,916
Natural gas liquids revenues	70,416			48,146			27,927			27,074
Total revenues	936,142			433,218			449,186			403,194
OPERATING EXPENSES
Lease operating expenses	93,788			30,753			23,513			27,520
Gathering, transportation, and processing	34,924			14,445			12,929			16,259
Taxes other than income	53,728			23,170			23,763			20,193
Exploration expense	12,741			11,882			492			700
Asset retirement obligation accretion	5,512			1,668			104			232
Depreciation, depletion and amortization	523,572			177,890			137,871			129,711
Amortization of intangible assets	14,505			6,044			—			—
General and administrative expenses	69,432			28,801			12,710			18,568
Transaction related costs	438			24,607			—			—
Total operating costs and expenses	808,640			319,260			211,382			213,183
OPERATING INCOME	127,502			113,958			237,804			190,011
OTHER INCOME (EXPENSE)
Income from equity method investee	857			773			711			113
Interest expense, net	(28,356		)	(12,454		)	—			—
Loss on derivatives, net	—			—			(18,127		)	(8,488		)
Other income (expense), net	(238		)	(8,374		)	(50		)	(21		)
Total other income (expense)	(27,737		)	(20,055		)	(17,466		)	(8,396		)
INCOME BEFORE INCOME TAXES	99,765			93,903			220,338			181,615
Income tax expense	14,760			11,455			1,785			2,741
NET INCOME	85,005			82,448			$	218,553		$	178,874
LESS: Net income attributable to noncontrolling interest	34,809			43,353
NET INCOME ATTRIBUTABLE TO MAGNOLIA	50,196			39,095
LESS: Non-cash deemed dividend related to warrant exchange	2,763			—
NET INCOME ATTRIBUTABLE TO CLASS A COMMON STOCK	$	47,433		$	39,095
NET INCOME PER SHARE OF CLASS A COMMON STOCK
Basic	$	0.29		$	0.25
Diluted	$	0.28		$	0.25
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic	161,886			154,527
Diluted	167,047			158,232

The accompanying notes are an integral part of these consolidated and combined financial statements.

Magnolia Oil & Gas Corporation

Combined Statement of Changes in Parents’ Net Investment

(In thousands)



	Predecessor
BALANCE, January 1, 2017	$	1,361,918
Parents’ contribution, net	57,046
Net income	178,874
Balance – December 31, 2017	$	1,597,838
Parents’ contribution, net	62,641
Net income	218,553
Balance – July 30, 2018	$	1,879,032

The accompanying notes are an integral part of these consolidated and combined financial statements.

Magnolia Oil & Gas Corporation

Consolidated Statements of Changes in Stockholders’ Equity

(In thousands)



	Successor
	Class A Common Stock				Class B Common Stock			Class F Common Stock					Additional Paid In Capital			Retained Earnings			Total Stockholders’ Equity			Noncontrolling Interest			Total Equity
	Shares		Value		Shares	Value		Shares		Value
Balance, July 30, 2018	3,052		$	—	—	$	—	16,250		$	2		$	8,370		$	(3,588	)	$	4,784		$	—		$	4,784
Class A Common Stock released from possible redemption	61,948		6		—	—		—		—			619,473			—			619,479			—			619,479
Class A Common Stock redeemed	(1	)	—		—	—		—		—			(9		)	—			(9		)	—			(9		)
Conversion of Common Stock from Class F to Class A at closing of Business Combination	16,250		2		—	—		(16,250	)	(2		)	—			—			—			—			—
Common stock issued as part of the Business Combination	31,791		3		83,939	9		—		—			391,017			—			391,029			1,032,455			1,423,484
Common stock issued in private placement	35,500		4		—	—		—		—			354,996			—			355,000			—			355,000
Earnout consideration issued as part for the Business Combination	—		—		—	—		—		—			41,371			—			41,371			108,329			149,700
Non-compete consideration	—		—		—	—		—		—			44,400			—			44,400			—			44,400
Changes in ownership interest adjustment	—		—		—	—		—		—			206,966			—			206,966			(206,966		)	—
Changes in deferred tax liability	—		—		—	—		—		—			(52,787		)	—			(52,787		)	—			(52,787		)
Balance, July 31, 2018	148,540		$	15	83,939	$	9	—		$	—		$	1,613,797		$	(3,588	)	$	1,610,233		$	933,818		$	2,544,051
Issuance of earnout share consideration Tranche I	1,244		—		3,256	—		—		—			—			—			—			—			—
Issuance of earnout share consideration Tranche II	1,244		—		3,256	—		—		—			—			—			—			—			—
Issuance of earnout share consideration Tranche III	1,105		—		2,895	—		—		—			—			—			—			—			—
Common stock issued in connection with Harvest Acquisition	4,200		1		—	—		—		—			58,211			—			58,212			—			58,212
Stock based compensation expense	—		—		—	—		—		—			1,851			—			1,851			—			1,851
Net income	—		—		—	—		—		—			—			39,095			39,095			43,353			82,448
Changes in ownership interest adjustment	—		—		—	—		—		—			(54,015		)	—			(54,015		)	54,015			—
Changes in deferred tax liability	—		—		—	—		—		—			21,393			—			21,393			—			21,393
Balance, December 31, 2018	156,333		$	16	93,346	$	9	—		$	—		$	1,641,237		$	35,507		$	1,676,769		$	1,031,186		$	2,707,955

The accompanying notes are an integral part to these consolidated and combined financial statements.

Magnolia Oil & Gas Corporation

Consolidated Statements of Changes in Stockholders’ Equity

(In thousands)



	Successor
	Class A Common Stock				Class B Common Stock				Additional Paid In Capital			Treasury Stock				Retained Earnings			Total Stockholders’ Equity			Noncontrolling Interest			Total Equity
	Shares		Value		Shares		Value					Shares	Value
Balance, December 31, 2018	156,333		$	16	93,346		$	9	$	1,641,237		—	$	—		$	35,507		$	1,676,769		$	1,031,186		$	2,707,955
Stock based compensation expense, net of forfeitures	—		—		—		—		11,089			—	—			—			11,089			—			11,089
Changes in ownership interest adjustment and in deferred tax liability	—		—		—		—		23,679			—	—			—			23,679			(32,659		)	(8,980		)
Common stock issued in connection with acquisition	3,055		—		—		—		33,693			—	—			—			33,693			—			33,693
Final settlement adjustment related to Business Combination	(496	)	—		(1,556	)	—		(6,095		)	—	—			—			(6,095		)	(19,150		)	(25,245		)
Common stock issued in connection with warrants exchange	9,179		1		—		—		530			—	—			(2,763		)	(2,232		)	—			(2,232		)
Common stock issued related to stock based compensation, net	248		—		—		—		(771		)	—	—			—			(771		)	—			(771		)
Class A Common Stock repurchase	—		—		—		—		—			1,000	(10,277		)	—			(10,277		)	—			(10,277		)
Class B Common Stock repurchase	—		—		(6,000	)	—		—			—	—			—			—			(69,093		)	(69,093		)
Contributions from noncontrolling interest owners	—		—		—		—		—			—	—			—			—			8,809			8,809
Distributions to noncontrolling interest owners	—		—		—		—		—			—	—			—			—			(1,424		)	(1,424		)
Net income	—		—		—		—		—			—	—			50,196			50,196			34,809			85,005
Balance, December 31, 2019	168,319		$	17	85,790		$	9	$	1,703,362		1,000	$	(10,277	)	$	82,940		$	1,776,051		$	952,478		$	2,728,529

The accompanying notes are an integral part to these consolidated and combined financial statements.

Magnolia Oil & Gas Corporation

Consolidated and Combined Statements of Cash Flows (In thousands)



	Successor						Predecessor
	Year Ended December 31, 2019			July 31, 2018 Through December 31, 2018			January 1, 2018 Through July 30, 2018			Year Ended December 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	85,005		$	82,448		$	218,553		$	178,874
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	523,572			177,890			137,871			129,711
Amortization of intangible assets	14,505			6,044			—			—
Exploration expense, non-cash	1,154			567			—			—
Asset retirement obligations accretion expense	5,512			1,668			104			232
Amortization of deferred financing costs	3,541			1,461			—			—
Loss on derivatives, net	—			—			18,127			8,488
Cash settlements of matured derivative contracts	—			—			(27,617		)	(1,097		)
Deferred taxes	14,261			12,128			324			2,052
Contingent consideration change in fair value	—			6,700			—			—
Stock based compensation	11,089			1,851			—			—
Other	(677		)	(773		)	(796		)	(397		)
Changes in operating assets and liabilities:
Accounts receivable	7,952			(50,610		)	(61,405		)	(70,822		)
Prepaid expenses and other assets	357			(2,533		)	—			—
Accounts payable	(6,834		)	25,041			36			10,522
Drilling advances	11,960			(9,559		)	—			—
Other assets and liabilities, net	(23,778		)	53,147			(385		)	(192		)
Net cash provided by operating activities	647,619			305,470			284,812			257,371
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds withdrawn from Trust Account	—			656,078			—			—
Acquisition of EnerVest properties	4,250			(1,219,217		)	—			—
Acquisitions, other	(93,221		)	(146,532		)	(150,139		)	(58,653		)
Additions to oil and natural gas properties	(435,035		)	(141,619		)	(197,314		)	(247,426		)
Purchase of and contributions to equity method investment	—			—			—			(8,338		)
Payment of Contingent Consideration	—			(26,000		)	—			—
Other investing	(242		)	(350		)	—			—
Net cash used in investing activities	(524,248		)	(877,640		)	(347,453		)	(314,417		)
CASH FLOW FROM FINANCING ACTIVITIES
Parents’ contribution, net	—			—			62,641			57,046
Contributions from noncontrolling interest owners	7,301			—			—			—
Distributions to noncontrolling interest owners	(1,424		)	—			—			—
Issuance of common stock	—			355,000			—			—
Proceeds from issuance of long term debt	—			400,000			—			—
Repayments of deferred underwriting compensation	—			(22,750		)	—			—
Cash paid for debt issuance costs	—			(23,336		)	—			—
Class A Common Stock repurchase	(10,277		)	—			—			—
Class B Common Stock repurchase	(69,093		)	—			—			—
Other financing activities	(3,003		)	(1,009		)	—			—
Net cash provided by (used in) financing activities	(76,496		)	707,905			62,641			57,046

NET CHANGE IN CASH AND CASH EQUIVALENTS	46,875			135,735			—			—
Cash and cash equivalents – Beginning of period	135,758			23			—			—
Cash and cash equivalents – End of period	$	182,633		$	135,758		$	—		$	—

The accompanying notes are an integral part of these consolidated and combined financial statements.

Magnolia Oil & Gas Corporation

Notes to Consolidated and Combined Financial Statements

1. Description of Business and Basis of Presentation

Organization and nature of operations

Magnolia is an independent oil and natural gas company engaged in the acquisition, development, exploration, and production of oil, natural gas, and natural gas liquid (“NGL”) reserves. The Company’s oil and natural gas properties are located primarily in Karnes County and the Giddings Field in South Texas, where the Company targets the Eagle Ford Shale and Austin Chalk formations. Magnolia’s objective is to generate stock market value over the long term through consistent organic production growth, high full cycle operating margins, an efficient capital program with short economic paybacks, significant free cash flow after capital expenditures, and effective reinvestment of free cash flow.

Magnolia Oil & Gas Corporation (the “Company” or “Magnolia”) was incorporated in Delaware on February 14, 2017.

On March 15, 2018, the Company formed three wholly owned subsidiaries: Magnolia Oil & Gas Parent LLC (“Magnolia LLC”), Magnolia Oil & Gas Intermediate LLC (“Magnolia Intermediate”), and Magnolia Oil & Gas Operating LLC (“Magnolia Operating”), all of which are Delaware limited liability companies formed in contemplation of the Business Combination (as defined herein).

Business Combination

On July 31, 2018 (the “Closing Date”), the Company and Magnolia LLC consummated the acquisition of the following:

•

certain right, title, and interest in certain oil and natural gas assets located primarily in the Karnes County portion of the Eagle Ford Shale in South Texas (the “Karnes County Assets” and, such business the “Karnes County Business”) pursuant to that certain Contribution and Merger Agreement (as subsequently amended, the “Karnes County Contribution Agreement”), by and among the Company, Magnolia LLC, and certain affiliates (the “Karnes County Contributors”) of EnerVest Ltd. (“EnerVest”);


•	certain right, title, and interest in certain oil and natural gas assets located primarily in the Giddings Field of the Austin Chalk (the “Giddings Assets”) pursuant to that certain Purchase and Sale Agreement (the “Giddings Purchase Agreement”) by and among Magnolia LLC and certain affiliates of EnerVest (the “Giddings Sellers”); and

•

a 35% membership interest (the “Ironwood Interests”) in Ironwood Eagle Ford Midstream LLC (“Ironwood”), a Texas limited liability company, which owns an Eagle Ford gathering system, pursuant to that certain Membership Interest Purchase Agreement (together with the transactions contemplated by the Karnes County Contribution Agreement and the Giddings Purchase Agreement, the “Business Combination Agreements,” and the transactions contemplated thereby, the “Business Combination”), by and among Magnolia LLC and certain affiliates of EnerVest (the “Ironwood Sellers”).

The Company consummated the Business Combination for an aggregate consideration of approximately $1.2 billion in cash, 31.8 million shares of the Company’s Class A Common Stock, par value $0.0001 per share (the “Class A Common Stock”), 83.9 million shares of the Company’s Class B Common Stock, par value $0.0001 per share (the “Class B Common Stock”), and a corresponding number of units in Magnolia LLC (the “Magnolia LLC Units”), as well as certain earnout rights payable in a combination of cash and additional equity securities in the Company. In connection with the Business Combination, Magnolia issued and sold 35.5 million shares of Class A Common Stock in a private placement to certain qualified institutional buyers and accredited investors for gross proceeds of $355.0 million (the “PIPE Investment”). In addition, Magnolia Operating and Magnolia Oil & Gas Finance Corp., a wholly owned subsidiary of Magnolia Operating (“Finance Corp.” and, together with Magnolia Operating, the “Issuers”), issued and sold $400.0 million aggregate principal amount of 6.0% Senior Notes due 2026 (the “2026 Senior Notes”). The proceeds of the PIPE Investment and the offering of 2026 Senior Notes were used to fund a portion of the cash consideration required to effect the Business Combination.

Basis of Presentation

In accordance with accounting principles generally accepted in the United States of America (“GAAP”), the Company was the acquirer in the Business Combination and the Karnes County Business, the Giddings Assets, and the Ironwood Interests were the acquirees. The Karnes County Business including, as applicable, its ownership of the Ironwood Interests, was deemed the “Predecessor” for periods prior to the Business Combination, and does not include the consolidation of the Company and the Giddings Assets. Although the Karnes County Contributors are not under common control, each were managed by the same managing general partner, EnerVest, and as such, the Predecessor financial statements have been presented on a combined basis for financial reporting purposes.

For the periods on or after the Business Combination, the Company, including the combination of the Karnes County Business, the Giddings Assets, and the Ironwood Interests, is the accounting successor (“Successor”). The financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the Business Combination, which includes the year ended December 31, 2017 (the “2017 Predecessor Period”) and the period from January 1, 2018 to July 30, 2018 (the “2018 Predecessor Period”); and the period after the Business Combination, which includes the period from July 31, 2018 to December 31, 2018 (the “2018 Successor Period”) and the year ended December 31, 2019 (the “2019 Successor Period”). The Business Combination was accounted for using the acquisition method of accounting and the Successor financial statements reflect a new basis of accounting that is based on the fair value of assets acquired and liabilities assumed. As a result of the inclusion of the Giddings Assets, the new basis of accounting, and certain other items that affect comparability, the Company’s financial information prior to the Business Combination is not comparable to its financial information subsequent to the Business Combination.

The assets, liabilities, revenues, expenses, and cash flows related to the Karnes County Business were not previously separately accounted for as a standalone legal entity and have been carved out of the overall assets, liabilities, revenues, expenses, and cash flows from the Karnes County Contributors as appropriate. In addition, Parents’ Net Investment represents the Karnes County Contributors’ interest in the recorded net assets of the Karnes County Business and represents the cumulative net investment of the Karnes County Contributors’ in the Karnes County Business through the dates presented, inclusive of cumulative operating results.

The Karnes County Contributors utilized EnerVest’s centralized processes and systems for its treasury services and the Karnes County Business’ cash activity was commingled with other oil and gas assets that were not part of the Business Combination. As such, the net results of the cash transactions between the Karnes County Business and the Karnes County Contributors are reflected as Parents’ contributions and distributions in the accompanying Combined Statement of Changes in Parents’ Net Investment.

The Predecessor financial statements also include a portion of indirect costs for salaries and benefits, rent, accounting, legal services, and other expenses. In addition to the allocation of indirect costs, the financial statements reflect certain agreements executed by the Karnes County Contributors for the benefit of the Karnes County Business, including price risk management instruments. The allocations methodologies for significant allocated items include:

Corporate G&A - EnerVest, as managing general partner of the Karnes County Contributors, provided management, accounting, and advisory services to the Karnes County Contributors in exchange for a quarterly management fee based on the Karnes County Contributors’ investor commitments, which were used, in part, to acquire the Karnes County Business as well as other oil and natural gas properties that were not part of the Business Combination. As such, the management fee was allocated to the Karnes County Business using a ratio of asset acquisitions value to total asset acquisitions completed by the Karnes County Contributors, for the Predecessor Period.

Derivatives - Certain Karnes County Contributors entered into financial instruments to manage the Karnes County Business’ exposure to changes in commodity prices for the Karnes County Business as well as other oil and natural gas properties that were not part of the Business Combination, on a combined basis. The commodity derivative activity was allocated to the Karnes County Business using a ratio of expected crude oil and condensate, NGLs, and natural gas volumes produced, on an equivalents basis, by the Karnes County Business to the Karnes County Contributors’ total expected crude oil and condensate, NGLs, and natural gas produced, on an equivalents basis, for the Predecessor Period.

Indebtedness - The Karnes County Business did not historically have outstanding indebtedness, but its oil and natural gas properties were collateral to various credit facilities held by the Karnes County Contributors and/or EnerVest. Amounts outstanding on these credit facilities have not been allocated to the Karnes County Business as they were not directly attributable to the Karnes County Business.

Management believes the allocation methodologies used are reasonable and result in an allocation of the indirect costs and other items to operate the Karnes County Business as if it were a stand-alone entity. These allocations, however, may not be indicative of the cost of future operations or the amount of future allocations. Direct costs were included at the historical amounts related to each reported period.

The accompanying consolidated and combined financial statements have been prepared in accordance with GAAP and in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”).

2. Summary of Significant Accounting Policies

Principles of Consolidation (Successor)

The consolidated financial statements have been prepared in accordance with GAAP. Certain reclassifications of prior period financial statements have been made to conform to current reporting practices. The consolidated financial statements include the accounts of the Company and its subsidiaries after elimination of intercompany transactions and balances. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The Company reflects a noncontrolling interest representing the interest owned by the Karnes County Contributors through their ownership of Magnolia LLC Units in the consolidated financial statements. The noncontrolling interest is presented as a component of equity. See Note 13—Stockholders’ Equity for further discussion of noncontrolling interest.

Variable Interest Entities

Magnolia LLC is a variable interest entity (“VIE”). The Company determined that it is the primary beneficiary of Magnolia LLC as the Company is the sole managing member and has the power to direct the activities most significant to Magnolia LLC’s economic performance as well as the obligation to absorb losses and receive benefits that are potentially significant. At December 31, 2019, the Company had an approximate 66.1% economic interest in Magnolia LLC and 100% of Magnolia LLC’s assets, liabilities, and results of operations are consolidated in the Company’s consolidated financial statements contained herein. At December 31, 2019, the Karnes County Contributors had approximately 33.9% economic interest in Magnolia LLC; however, the Karnes County Contributors have disproportionately fewer voting rights, and are shown as noncontrolling interest holders of Magnolia LLC. See Note 13—Stockholders’ Equity for further discussion of noncontrolling interest.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates, and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities, the assessment of asset retirement obligations, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows, and the estimates of fair value for long-lived assets.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and short-term, highly liquid investments that are readily convertible to cash. Cash and cash equivalents were approximately $182.6 million and $135.8 million at December 31, 2019, and December 31, 2018, respectively.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts. The carrying amount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. The Company’s receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. The Company had no allowance for doubtful accounts as of December 31, 2019 or December 31, 2018.

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

Unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Unproved properties are assessed for impairment based on the Company’s current exploration plans. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as impairment of unsuccessful leases, are included in “Exploration expense” in the consolidated and combined statements of operations.

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized costs for exploratory and development wells is the sum of proved developed reserves only. Estimated future abandonment costs, net of salvage values, are included in the depreciable cost.

Oil and gas properties are grouped for depreciation in accordance with the Accounting Standards Codification (“ASC”) ASC 932 “Extractive Activities—Oil and Gas” (“ASC 932”). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

When circumstances indicate that proved oil and gas properties may be impaired, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves, and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820, “Fair Value Measurements” (“ASC 820”). If applicable, the Company may utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants.

Asset Retirement Costs and Obligations

Asset retirement obligations (“ARO”) represent the present value of the estimated cash flows expected to be incurred to plug, abandon, and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment, and remediation costs, well life, inflation, and credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset using the unit of production method and is included in “Depreciation, depletion and amortization” in the Company’s consolidated and combined statements of operations. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized.

To estimate the fair value of an asset retirement obligation, the Company employs a present value technique, which reflects certain assumptions, including its credit‑adjusted risk‑free interest rate, inflation rate, the estimated settlement date of the liability, and the estimated cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability and related long lived asset.

Intangible Assets (Successor)

Concurrent with the closing of the Business Combination, the Company and EnerVest entered into a non-compete agreement (the “Non-Compete”) pursuant to which EnerVest and certain of its affiliates are restricted from competing with the Company in certain counties comprising the Eagle Ford Shale. The Company recorded an estimated cost of $44.4 million for the Non-Compete as intangible assets on the consolidated balance sheet of the Successor. These intangible assets have a definite life and are subject to amortization utilizing the straight-line method over their economic life, currently estimated to be two and one half to four years. Magnolia assesses intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment is recognized in the consolidated statements of operations if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. For the year ended December 31, 2019, no impairment was recorded. For more discussion on the Non-Compete, refer to Note 6 - Intangible Assets.

Fair Value Measurements

ASC 820 establishes a fair value hierarchy that prioritizes and ranks the level of observability of inputs used to measure investments at fair value. The observability of inputs is impacted by a number of factors, including the type of investment, characteristics specific to the investment, market conditions, and other factors. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level I measurements) and the lowest priority to unobservable inputs (Level III measurements). Investments with readily available quoted prices or for which fair value can be measured from quoted prices in active markets will typically have a higher degree of input observability and a lesser degree of judgment applied in determining fair value.

The three levels of the fair value hierarchy under ASC 820 are as follows:

Level I—Quoted prices (unadjusted) in active markets for identical investments at the measurement date are used.

Level II—Pricing inputs are other than quoted prices included within Level I that are observable for the investment, either directly or indirectly. Level II pricing inputs include quoted prices for similar investments in active markets, quoted prices for identical or similar investments in markets that are not active, inputs other than quoted prices that are observable for the investment, and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level III—Pricing inputs are unobservable and include situations where there is little, if any, market activity for the investment. The inputs used in determination of fair value require significant judgment and estimation.

In some cases, the inputs used to measure fair value might fall within different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the investment is categorized in its entirety is determined based on the lowest level input that is significant to the investment. Assessing the significance of a particular input to the valuation of an investment in its entirety requires judgment and considers factors specific to the investment. The categorization of an investment within the hierarchy is based upon the pricing transparency of the investment and does not necessarily correspond to the perceived risk of that investment.

Equity Method Investment

The Company accounts for its investment in Ironwood using the equity method of accounting. Accordingly, the Company recognizes its proportionate share of Ironwood’s net income in the consolidated and combined statements of operations as “Income from equity method investee.” Any distributions by Ironwood would decrease the Company’s investment in Ironwood. The Company evaluates its investment in Ironwood for potential impairment whenever events or changes in circumstances indicate that there may be a loss in the value of Ironwood that was other than temporary.

Income Taxes (Predecessor)

The Karnes County Contributors, on behalf of the Predecessor, had elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains, and losses flowed through to the partners and were taxed at the partner level. Accordingly, no tax provision for federal income taxes was included in the financial statements. The Predecessor was subject to the Texas margin tax, which is considered a state income tax, and was included in “Income Tax Expense” on the statements of operations. The Predecessor recorded state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.

The Predecessor analyzed each income tax position using a two-step process. A determination was first made as to whether it was more likely than not that the income tax position would be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position was expected to meet the more likely than not criteria, the benefit recorded in the combined financial statements equaled the largest amount that was greater than 50% likely to be realized upon its ultimate settlement.

The Predecessor considered its exposure for uncertain tax positions at the state tax level and did not record any liabilities for uncertain tax positions for the year ended December 31, 2017. The Predecessor recorded income tax, related interest, and penalties, if any, as a component of income tax expense. The Predecessor did not incur any interest or penalties on income for the period from January 1, 2018 to July 30, 2018 or during the year ended December 31, 2017. None of the Karnes County Contributors’ state tax returns are currently under examination by the relevant authorities.

Income Taxes (Successor)

Under ASC 740, “Income Taxes,” deferred tax assets and liabilities are recognized for the expected future tax consequences attributable to net operating losses, tax credits, and temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of the enactment date. Valuation allowances are established when it is more likely than not that some or all of the deferred tax assets will not be realized.

The Company reports a liability or a reduction of deferred tax assets for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. When applicable, the Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense.

Derivatives (Predecessor)

The Karnes County Contributors, on behalf of the Predecessor, monitored the exposure to various business risks, including commodity price risk, and used derivatives to manage the impact of certain of these risks. The Karnes County Contributors used energy derivatives for mitigating risk resulting from fluctuations in the market price of oil, natural gas, and NGLs, and their policies did not permit the use of derivatives for speculative purposes.

The Predecessor elected not to designate its derivatives as hedging instruments. Changes in the fair value of derivatives were recorded immediately to earnings as “Loss on derivatives, net” in the combined statement of operations.

Purchase Price Allocation

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill.

The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets, liabilities, and tax-related carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

When estimating the fair values of assets acquired and liabilities assumed, the Company must apply various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, the Company prepares estimates of crude oil and natural gas reserves. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future.

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Refer to Note 11 - Commitments and Contingencies for additional information.

Revenue Recognition (Predecessor)

Oil, natural gas, and NGL revenues were recognized when production was sold to a purchaser at a fixed or determinable price, when delivery had occurred and title had transferred, and collectability of the revenue was reasonably assured. The Predecessor followed the sales method of accounting for revenues. Under this method of accounting, revenues were recognized based on volumes sold, which may have differed from the volumes entitled based on the Karnes County Business’ working interest. There were no material gas imbalances during the periods presented.

Revenue Recognition (Successor)

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU and the associated subsequent amendments (collectively, “ASC 606”), superseded virtually all of the revenue recognition guidance in GAAP by requiring companies to recognize revenue using a five-step model. The core principle of the five-step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Magnolia adopted this standard on December 31, 2018 for all Successor Periods using a modified retrospective approach.

There were no significant changes to the timing of revenue recognized for sales of production as a result of ASC 606. However, the new guidance resulted in certain changes to the classification of processing and other fees between revenue and gathering, transportation, and processing expense. The amounts reclassified are immaterial to the financial statements and Predecessor Periods have not been restated and continue to be reported under the accounting standards in effect for those periods. Adoption of the new standard is not anticipated to have a material impact on the Company’s net earnings on an ongoing basis.

Magnolia’s revenues include the sale of crude oil, natural gas, and NGLs. Oil, natural gas, and NGL sales are recognized as revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, natural gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, million Btu of natural gas, gallon of NGLs, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.

The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area. For oil contracts, the Company generally records sales based on the net amount received.

For natural gas contracts, the Company generally records wet gas sales (which consists of natural gas and NGLs based on end products after processing) at the wellhead or inlet of the gas processing plant (i.e., the point of control transfer) as revenues net of gathering, transportation, and processing expenses if the processor is the customer and there is no redelivery of commodities to the Company at the tailgate of the plant. Conversely, the Company generally records residual natural gas and NGL sales at the tailgate of the plant (i.e., the point of control transfer) on a gross basis along with the associated gathering, transportation, and processing expenses if the processor is a service provider and there is redelivery of one or several commodities to the Company at the tailgate of the plant. The facts and circumstances of an arrangement are considered and judgment is often required in making this determination. For processing contracts that require noncash consideration in exchange for processing services, the Company recognizes revenue and an equal gathering, transportation, and processing expense for commodities transferred to the service provider.

Customers are invoiced once the Company’s performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 days. There are no judgments that significantly affect the amount or timing of revenue from contracts with customers. Accordingly, the Company’s product sales contracts do not give rise to material contract assets or contract liabilities.

The Company’s receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. Receivables from contracts with customers totaled $100.4 million as of December 31, 2019 and $100.1 million as of December 31, 2018. Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts. The Company routinely assesses the collectability of all material trade and other receivables. The Company’s receivables consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. The Company had no allowance for doubtful accounts as of December 31, 2019 or December 31, 2018.

The Company has concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors and has reflected this disaggregation of revenue on the Company’s consolidated and combined statements of operations for all periods presented.

Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Company’s right to payment, and transfer of legal title.

The Company does not disclose the value of unsatisfied performance obligations for contracts as all contracts have either an original expected length of one year or less, or the entire future consideration is variable and allocated entirely to a wholly unsatisfied performance obligation.

Net Income Per Share of Common Stock (Successor)

The Company’s basic earnings per share (“EPS”) is computed based on the weighted average number of shares of Class A Common Stock outstanding for the period. Diluted EPS includes the effect of the Company’s outstanding restricted stock units (“RSUs”), performance stock units (“PSUs”), warrants exchanged for Class A Common Stock and exchanges or repurchases of Class B Common Stock if the inclusion of these items is dilutive. Refer to Note 15 - Earnings Per Share for additional information and the calculation of EPS.

Stock Based Compensation (Successor)

Magnolia has established a long-term incentive plan for certain employees and directors that allows for granting RSUs and PSUs. RSUs granted are valued on the date of the grant using the quoted market price of Magnolia's Class A Common Stock. PSUs granted are based on the grant date fair value determined using Monte Carlo simulations, which use a probabilistic approach for estimating the fair value of the awards. Both RSUs and PSUs are expensed on a straight-line basis over the requisite service period. The Company records expense associated with the fair value of stock based compensation under the fair value recognition provisions of ASC Topic 718, “Compensation-Stock Compensation” and that expense is included within “General and administrative expenses” in the accompanying consolidated and combined statements of operations. The Company accounts for forfeitures as they occur. These plans and related accounting policies are defined and described more fully in Note 14 - Stock Based Compensation.

Leases

In February 2016, the FASB issued ASU No. 2016-02, Leases, which requires lessees to recognize a right-of-use asset and a lease liability on their balance sheet for all leases, including operating leases, with a term of greater than 12 months. In July 2018, the FASB issued ASU 2018-11, which adds a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The Company elected the package of transition practical expedients provided by the new standard that allow the Company to not reassess under the new standard its prior conclusions about lease identification, classification related to contracts that commenced prior to adoption, and to apply the standard prospectively to all new or modified land easements and rights-of-way. The Company has also elected a policy to not recognize right of use assets and lease liabilities related to short-term leases. The Company has lease agreements with lease and non-lease components, which are generally accounted for as a single lease component.

Magnolia adopted this standard on January 1, 2019 and recognized right of use assets and lease liabilities for certain commitments primarily related to real estate, vehicles, and field equipment, while prior reporting periods are presented in accordance with historical accounting treatment under ASC Topic 840, Leases (“ASC 840”). The Company determines if an arrangement is a lease at inception. Operating leases are included in other long-term assets, other current liabilities, and other long-term liabilities in Magnolia’s consolidated balance sheet as of December 31, 2019. Operating lease right-of-use (“ROU”) assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. Magnolia’s lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. Lease expenses for lease payments are recognized on a straight-line basis over the lease term. For more information, refer to Note 10 - Leases.

Recent Accounting Pronouncements

In June 2016 the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The standard requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standard is effective for the Company in the first quarter of 2020. The Company has evaluated the new standard and does not believe the adoption will have a material impact on the Company’s consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in the update align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. The Company early adopted ASU 2018-15 effective April 1, 2019, with prospective application. The adoption did not have a material impact on the Company’s consolidated financial statements.

3. Acquisitions

Acquisitions (Successor)

EnerVest Business Combination

As discussed in Note 1 - Description of Business and Basis of Presentation, on July 31, 2018, the Company consummated the Business Combination contemplated by the Business Combination Agreements. The Business Combination Agreements and the Business Combination were approved by the Company’s stockholders on July 17, 2018. At the closing of the Business Combination, the Karnes County Contributors received 83.9 million shares of the Company’s Class B Common Stock and an equivalent number of Magnolia LLC Units, which, together, are exchangeable on a one-for-one basis for shares of the Company’s Class A Common Stock, subject to certain conditions; 31.8 million shares of Class A Common Stock; and approximately $911.5 million in cash. The Giddings Sellers received approximately $282.7 million in cash. The Ironwood Sellers received $25.0 million in cash in exchange for the Ironwood Interests. On March 29, 2019, Magnolia and EnerVest consummated the final settlement pursuant to the Karnes County Contribution Agreement and as otherwise agreed to by the parties, with Magnolia receiving a net cash payment of $4.3 million and the Karnes County Contributors forfeiting to Magnolia 0.5 million shares of Class A Common Stock and 1.6 million shares of Class B Common Stock (and forfeiting a corresponding number of Magnolia LLC Units to Magnolia LLC).

The Business Combination has been accounted for using the acquisition method. The acquisition method of accounting is based on ASC 805 “Business Combinations,” and uses the fair value concepts defined in ASC 820. ASC 805 requires, among other things, that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by the Company.

Contingent Consideration

Pursuant to the Karnes County Contribution Agreement, for a period of five years following the Closing Date, the Karnes County Contributors were entitled to receive an aggregate of up to 13.0 million additional shares of Class A Common Stock or shares of Class B Common Stock (and a corresponding number of Magnolia LLC Units) based on certain EBITDA and free cash flow or stock price thresholds. As of December 31, 2018, the Company had met the defined stock price thresholds and, as a result, the Company had issued an aggregate of 3.6 million additional shares of Class A Common Stock and 9.4 million additional shares of Class B Common Stock (and a corresponding number of Magnolia LLC Units) to the Karnes County Contributors.

Pursuant to the Giddings Purchase Agreement, until December 31, 2021, the Giddings Sellers were entitled to receive an aggregate of up to $47.0 million in cash earnout payments based on certain net revenue thresholds. On September 28, 2018, the Company paid the Giddings Sellers a cash payment of $26.0 million to fully settle the earnout obligation.

The purchase consideration for the Business Combination was as follows:



(In thousands)
Purchase Consideration:
Cash consideration	$	1,214,966
Stock consideration ⁽¹⁾	1,398,238
Fair value of contingent earnout purchase consideration⁽²⁾	169,000
Total purchase price consideration	$	2,782,204

(1)

At closing of the Business Combination, the Karnes County Contributors received 83.9 million shares of Class B Common Stock (and a corresponding number of Magnolia LLC Units) and 31.8 million shares of Class A Common Stock. On March 29, 2019, Magnolia and EnerVest consummated the final settlement pursuant to the Karnes County Contribution Agreement as agreed to by the parties, with the Karnes County Contributors forfeiting an aggregate of 2.1 million shares of Class A and Class B Common Stock to Magnolia (and a corresponding number of Magnolia LLC Units).

(2)

Pursuant to ASC 805, ASC 480, “Distinguishing Liabilities from Equity,” and ASC 815, “Derivatives and Hedging,” the Karnes County earnout consideration was valued at fair value as of the Closing Date and was classified in stockholders’ equity. The Giddings earnout was valued at fair value as of the Closing Date and was classified as a liability. The fair value of the earnouts was determined using the Monte Carlo simulation valuation method based on Level 3 inputs in the fair value hierarchy.

The following table summarizes the allocation of the purchase consideration to the assets acquired and liabilities assumed on the acquisition date:



(In thousands)
Fair value of assets acquired
Accounts receivable	$	61,790
Other current assets	2,853
Oil and natural gas properties ⁽¹⁾	2,813,140
Ironwood equity investment	18,100
Total fair value of assets acquired	2,895,883
Fair value of liabilities assumed
Accounts payable and other current liabilities	(65,908		)
Asset retirement obligations	(34,132		)
Deferred tax liability	(13,639		)
Fair value of net assets acquired	$	2,782,204

(1)

The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate.

The Company incurred $24.8 million in transaction costs associated with the Business Combination. The Company also incurred a total of $23.5 million of debt issuance costs in connection with the consummation of the Business Combination related to the establishment of the RBL Facility (as defined herein) and the issuance of the 2026 Senior Notes.

Unaudited Pro Forma Operating Results

The following unaudited pro forma combined financial information has been prepared as if the Business Combination and other related transactions had taken place on January 1, 2017.

The information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including depletion of the Company’s fair-valued proved oil and gas properties, and the estimated tax impacts of the pro forma adjustments. Additionally, pro forma net income attributable to Class A Common Stock excludes $34.3 million of transaction related costs, $11.0 million related to a one-time purchase of a seismic license continuation, and a $6.7 million loss related to the settlement of the Giddings earnout obligation.

The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Business Combination taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.



	(Unaudited Pro Forma)
(In thousands, except per share data)	Year Ended December 31, 2018		Year Ended December 31, 2017
Total revenues	$	978,431	$	555,714
Net income attributable to Class A Common Stock	188,934		70,491
Net income per share - basic	1.22		0.54
Net income per share - diluted	1.19		0.51

Non-Compete

On the Closing Date, the Company and EnerVest, separate and apart from the Business Combination, entered into the Non-Compete restricting EnerVest and certain of its affiliates from competing with the Company in certain counties comprising the Eagle Ford Shale following the Closing Date. An affiliate of EnerVest will have the right to receive 4.0 million shares of Class A Common Stock issuable in two tranches of 2.0 million shares in two and one half and four years from the Closing Date provided EnerVest does not compete with Magnolia in the Eagle Ford Shale until the later of July 31, 2022 or the date the Services Agreement with EnerVest Operating, LLC (“EVOC”), a wholly owned subsidiary of EnerVest, (the “Services Agreement”), is terminated. For more discussion on the Non-Compete, refer to Note 6 - Intangible Assets.

Harvest Acquisition

On August 31, 2018, the Company completed the acquisition of substantially all of Harvest Oil & Gas Corporation’s South Texas assets for approximately $133.3 million in cash and 4.2 million shares of Class A Common Stock for a total consideration of $191.5 million. The acquisition added an undivided working interest across a portion of Magnolia’s existing Karnes County Assets and all of the Company’s existing Giddings Assets. On March 14, 2019, Magnolia consummated the final settlement with Harvest receiving a cash payment of $1.4 million. The transaction was accounted for as a business combination.

The following table summarizes the allocation of the purchase consideration to the assets acquired and liabilities assumed:



(In thousands)
Fair value of assets acquired
Other current assets	$	1,290
Oil and natural gas properties ⁽¹⁾	201,337
Total fair value of assets acquired	202,627
Fair value of liabilities assumed
Asset retirement obligations and other current liabilities	(9,666		)
Fair value of net assets acquired	$	192,961

(1)

Certain Other Acquisitions


•	On May 31, 2019, the Company completed the acquisition of certain oil and gas assets located in the Company’s Karnes County Assets for approximately $36.3 million in cash, subject to customary closing adjustments, and approximately 3.1 million shares of the Company’s Class A Common Stock. The transaction was accounted for as an asset acquisition.

•

On February 5, 2019, Magnolia Operating formed a joint venture, Highlander Oil & Gas Holdings LLC (“Highlander”), to complete the acquisition of a 72% working interest in the Eocene-Tuscaloosa Zone, Ultra Deep Structure gas well located in St. Martin Parish, Louisiana and 31.1 million royalty trust units in the Gulf Coast Ultra Deep Royalty Trust from McMoRan Oil & Gas, LLC. Highlander paid cash consideration of $50.9 million, for such interests. MGY Louisiana LLC, a wholly owned subsidiary of Magnolia Operating, holds approximately 85% of the units in Highlander. The transaction was accounted for as an asset acquisition.

Acquisitions (Predecessor)

GulfTex Acquisition

On March 1, 2018, the Predecessor acquired certain oil and natural gas properties located in the Eagle Ford Shale from GulfTex Energy III, L.P. and GulfTex Energy IV, L.P. for an adjusted purchase price of approximately $150.1 million, net of customary closing adjustments (the “GulfTex Acquisition”).

The recognized fair value of identifiable assets and acquired liabilities assumed in connection with the GulfTex Acquisition, is as follows:



(In thousands)
Purchase price allocation:
Accounts receivable	$	10,501
Proved oil and natural gas properties	118,572
Unproved oil and natural gas properties	22,802
Accounts payable and accrued liabilities	(1,679		)
Asset retirement obligations	(57		)
	$	150,139

BlackBrush Acquisition

On January 31, 2017, the Predecessor acquired assets from BlackBrush Karnes Properties, LLC for aggregate consideration of approximately $58.7 million, net of customary closing adjustments (the “BlackBrush Acquisition”).

The recognized fair value of identifiable assets and acquired liabilities assumed in connection with the BlackBrush Acquisition is as follows:



(In thousands)
Purchase price allocation:
Accounts receivable	$	2,193
Proved oil and natural gas properties	57,263
Unproved oil and natural gas properties	1,552
Accounts payable and accrued liabilities	(2,244		)
Asset retirement obligations	(111		)
	$	58,653

4. Fair Value Measurements

Certain of the Company’s assets and liabilities are carried at fair value and measured either on a recurring or non-recurring basis. The Company’s fair value measurements are based either on actual market data or assumptions that other market participants would use in pricing an asset or liability in an orderly transaction, using the valuation hierarchy prescribed by GAAP under ASC 820.

The three levels of the fair value hierarchy under ASC 820 are as follows:

Level I - Quoted prices (unadjusted) in active markets for identical investments at the measurement date are used.

Level II - Pricing inputs are other than quoted prices included within Level I that are observable for the investment, either directly or indirectly. Level II pricing inputs include quoted prices for similar investments in active markets, quoted prices for identical or similar investments in markets that are not active, inputs other than quoted prices that are observable for the investment, and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level III - Pricing inputs are unobservable and include situations where there is little, if any, market activity for the investment. The inputs used in determination of fair value require significant judgment and estimation.

Fair Values - Recurring (Predecessor)

The Predecessor’s derivatives consisted of over-the-counter contracts that were not traded on a public exchange. As the fair value of these derivatives was based on inputs using market prices obtained from independent brokers or determined using quantitative models that used as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third-party pricing services, brokers and market transactions, the Predecessor categorized these derivatives as Level 2. The Predecessor valued these derivatives using the income approach using inputs such as the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves. Estimates of fair value were determined at discrete points in time based on relevant market data. Furthermore, fair values were adjusted to reflect the credit risk inherent in the transaction, which may have included amounts to reflect counterparty credit quality and/or the effect of the Predecessor’s creditworthiness.

Fair Values - Nonrecurring

The fair value measurements of assets acquired and liabilities assumed in a business combination are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market, and therefore, represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties includes estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. Refer to Note 3 - Acquisitions for additional information.

Deemed Dividend

In July 2019, the Company issued an aggregate of 9.2 million shares of Class A Common Stock in exchange for all of its warrants. The difference in fair value between the Class A Common Stock issued and the warrants exchanged was recorded as a non-cash deemed dividend for the incremental value provided to the holders of the warrants. The fair value of the non-cash deemed dividend related to the warrant exchange was determined based on unadjusted quoted prices in an active market, which are considered a Level 1 input in the fair value hierarchy. Refer to Note 13 - Stockholders’ Equity for additional information.

Debt Obligations

The carrying value and fair value of the financial instrument that is not carried at fair value in the accompanying consolidated balance sheet as of December 31, 2019 is as follows:



	December 31, 2019
(In thousands)	Carrying Value		Fair Value
Long-term debt	$	389,835	$	412,000

The fair value of the 2026 Senior Notes at December 31, 2019 was based on unadjusted quoted prices in an active market, which are considered a Level 1 input in the fair value hierarchy.

The Company has other financial instruments consisting primarily of receivables, payables, and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in the business combinations and asset retirement obligations.

5. Derivative Instruments and Hedging Activities (Predecessor)

The Company’s activities expose it to risks associated with changes in the market price of oil, natural gas, and NGLs. As such, future earnings are subject to fluctuation due to changes in the market price of oil, natural gas, and NGLs. The Company has not engaged in any hedging activities and does not expect to engage in any hedging activities with respect to the market risk to which the Company is exposed. The Karnes County Contributors, on behalf of the Predecessor, used derivatives to reduce the risk of volatility in the prices of oil, natural gas, and NGLs and their policies did not permit the use of derivatives for speculative purposes.

The Predecessor elected not to designate any of its derivatives as hedging instruments. Accordingly, changes in the fair value of the Predecessor's derivatives were recorded immediately to earnings as “Gain (loss) on derivatives, net” in the combined statement of operations. During the period from January 1 through July 30, 2018 and the year ended December 31, 2017, the Predecessor incurred a loss on derivatives of $18.1 million and $8.5 million, respectively. During the period from January 1, 2018 through July 30, 2018, the Predecessor terminated substantially all of its derivative contracts which, together with regular monthly settlements, resulted in total cash settlement payments of $27.6 million.

6. Intangible Assets

Non-Compete Agreement

On the Closing Date, the Company and EnerVest, separate and apart from the Business Combination, entered into the Non-Compete, which prohibits EnerVest and certain of its affiliates from competing with the Company in the Eagle Ford Shale (the “Market Area”) until the later of July 31, 2022 or the date the Services Agreement is terminated. Under the Non-Compete, an affiliate of EnerVest will have the right to receive 4.0 million shares of Class A Common Stock in two tranches of 2.0 million shares in two and one half and four years from the Closing Date provided EnerVest does not compete in the Market Area.

The Company recorded an estimated cost of $44.4 million for the Non-Compete as intangible assets on the Company’s consolidated balance sheet. These intangible assets have a definite life and are subject to amortization utilizing the straight-line method over their economic life, currently estimated to be two and one half to four years. The Company includes the amortization in “Amortization of intangible assets” on the Company’s consolidated and combined statements of operations.



(In thousands)	December 31, 2019
Non-compete intangible assets	$	44,400
Accumulated amortization	(20,549		)
Intangible assets, net	$	23,851
Weighted average amortization period (in years)	3.25

7. Other Current Liabilities

The following table provides detail of the Company’s other current liabilities for the periods presented:



(In thousands)	December 31, 2019		December 31, 2018
Accrued capital expenditures	$	40,722	$	50,633
Accrued general and administrative expenditures	9,753		17,551
Accrued interest	10,000		10,067
Other	35,305		42,808
Total other current liabilities	$	95,780	$	121,059

8. Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations for the periods presented:



	Successor						Predecessor
(In thousands)	Year Ended December 31, 2019			July 31, 2018 Through December 31, 2018			January 1, 2018 Through July 30, 2018			Year Ended December 31, 2017
Asset retirement obligations, beginning of period	$	85,983		$	—		$	3,929		$	2,421
Revisions to estimates	69			39,584			—			805
Liabilities incurred and assumed	7,082			44,897			553			774
Liabilities settled	(3,104		)	(166		)	(85		)	(303		)
Accretion expense	5,512			1,668			104			232
Asset retirement obligations, end of period	$	95,542		$	85,983		$	4,501		$	3,929

Asset retirement obligations reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable local, state, and federal laws. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liability, a corresponding offsetting adjustment is made to the oil and natural gas property balance.

9. Long Term Debt

The Company’s debt is comprised of the following:



(In thousands)	December 31, 2019
Revolving credit facility	$	—
6.0% Senior Notes due 2026	400,000
Total long-term debt	400,000

Less: Unamortized deferred financing cost	(10,165		)
Total debt, net	$	389,835

Credit Facility

In connection with the consummation of the Business Combination, Magnolia Operating entered into a senior secured reserve-based revolving credit facility (the “RBL Facility”) among Magnolia Operating, as borrower, Magnolia Intermediate, as its holding company, the banks, financial institutions, and other lending institutions from time to time party thereto, as lenders, the other parties from time to time party thereto and Citibank, N.A., as administrative agent, collateral agent, issuing bank, and swingline lender, providing for maximum commitments in an aggregate principal amount of $1.0 billion with a letter of credit facility with a $100.0 million sublimit. The borrowing base as of December 31, 2019 was $550.0 million. The RBL Facility is guaranteed by certain parent companies and subsidiaries of Magnolia LLC and is collateralized by certain of Magnolia Operating’s oil and natural gas properties and has a borrowing base subject to semi-annual redetermination.

Borrowings under the RBL Facility bear interest, at Magnolia Operating’s option, at a rate per annum equal to either the LIBOR rate or the alternative base rate plus the applicable margin. Additionally, Magnolia Operating is required to pay a commitment fee quarterly in arrears in respect of unused commitments under the RBL Facility. The applicable margin and the commitment fee rate are calculated based upon the utilization levels of the RBL Facility as a percentage of the borrowing base then in effect.

The RBL Facility contains certain affirmative and negative covenants customary for financings of this type, including compliance with a leverage ratio of less than 4.00 to 1.00 and, if the leverage ratio is in excess of 3.00 to 1.00, a current ratio of greater than 1.00 to 1.00. As of December 31, 2019, the Company was in compliance with all covenants under the RBL Facility.

Deferred financing costs incurred in connection with securing the RBL Facility were $11.7 million, which are amortized on a straight-line basis over a period of five years and included in “Interest expense, net” in the Company’s consolidated and combined statements of operations. The Company recognized interest expense of $4.5 million and $1.9 million during the year ended December 31, 2019 and the 2018 Successor Period, respectively, related to the RBL Facility. The unamortized portion of the deferred financing costs are included in “Deferred financing costs, net” on the accompanying consolidated balance sheet as of December 31, 2019.

The Company did not have any outstanding borrowings under its RBL Facility as of December 31, 2019.

2026 Senior Notes

On the Closing Date, the Issuers issued and sold $400.0 million aggregate principal amount of 2026 Senior Notes. The 2026 Senior Notes were issued under the Indenture, dated as of the Closing Date (the “Indenture”), by and among the Issuers and Deutsche Bank Trust Company Americas, as trustee. The 2026 Senior Notes are guaranteed on a senior unsecured basis by the Company, Magnolia Operating, and Magnolia Intermediate and may be guaranteed by certain future subsidiaries of the Company. The 2026 Senior Notes will mature on August 1, 2026 and bear interest at the rate of 6.0% per annum.

At any time prior to August 1, 2021, the Issuers may, on any one or more occasions, redeem all or a part of the 2026 Senior Notes at a redemption price equal to 100% of the principal amount of the 2026 Senior Notes redeemed, plus a “make whole” premium on accrued and unpaid interest, if any, to, but excluding, the date of redemption. After August 1, 2021, the Issuers may redeem all or a part of the Notes based on principal plus a set premium, as set forth in the Indenture, including any accrued and unpaid interest.

The Company incurred $11.8 million of deferred financing costs related to the issuance of the 2026 Senior Notes, which were capitalized, are amortized using the effective interest method over the term of the 2026 Senior Notes and are included in “Interest expense, net” in the Company’s consolidated and combined statements of operations. The unamortized portion of the deferred financing costs is included as a reduction to the carrying value of the 2026 Senior Notes, which have been recorded as “Long-term debt, net” on the consolidated balance sheet as of December 31, 2019. The Company recognized interest expense of $25.2 million and $10.5 million for the year ended December 31, 2019 and the 2018 Successor Period, respectively, related to the 2026 Senior Notes.

Affiliate Guarantors

Certain subsidiaries of the Company are guarantors under the terms of its 2026 Senior Notes and RBL Facility. The parent guarantees may be released upon the request of Magnolia Operating. Magnolia’s consolidated and combined financial statements reflect the financial position of these subsidiary guarantors. As the parent company, Magnolia has no independent operations. The guarantees are full and unconditional (except for customary release provisions) and joint and several. There are restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to the Company.

10. Leases

Magnolia’s leases primarily consist of real estate, vehicles, and field equipment. The Company’s leases have remaining lease terms of up to 8 years, some of which include options to renew or terminate the lease. The exercise of lease renewal options is at the Company’s sole discretion. Magnolia’s lease agreements do not contain any residual value guarantees or restrictive covenants.

As most of Magnolia’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company used the incremental borrowing rate on January 1, 2019, for operating leases that commenced prior to that date.



(In thousands)	December 31, 2019
Operating Leases
Operating lease assets	$	4,035

Operating lease liabilities - current	$	2,550
Operating lease liabilities - long-term	1,476
Total operating lease liabilities	$	4,026

Weighted average remaining lease term (in years)	1.9
Weighted average discount rate	3.8		%

For the year ended December 31, 2019, the Company incurred $2.8 million of lease costs for operating leases included on the Company’s consolidated balance sheet, $26.9 million for short-term lease costs, and $3.2 million for variable lease costs. Cash paid for amounts included in the measurement of lease liabilities in operating cash flows from operating leases for the year ended December 31, 2019 is $2.8 million.

Maturities of lease liabilities as of December 31, 2019 under the scope of ASC 842 are as follows:



(In thousands)
Maturity of Lease Liabilities ⁽¹⁾	Operating Leases
2020	$	2,647
2021	1,170
2022	165
2023	98
2024	43
After 2024	48
Total lease payments	$	4,171
Less: Interest	(145		)
Present value of lease liabilities	$	4,026


(1)	As of December 31, 2018, minimum future contractual payments for long-term operating leases under the scope of ASC 840 were $881 thousand in 2019, $646 thousand in 2020, $198 thousand in 2021, $14 thousand in 2022, $15 thousand in 2023 and $63 thousand thereafter.

11. Commitments and Contingencies

Legal Matters

The Company is involved in disputes or legal actions in the ordinary course of business. For example, certain of the Karnes County Contributors and the Company have been named as defendants in a lawsuit where the plaintiffs claim to be entitled to a minority working interest in certain Karnes County Business properties. The litigation is in the pre-trial stage. The exposure related to this litigation is currently not reasonably estimable. The Karnes County Contributors retained all such liability in connection with the Business Combination. At December 31, 2019, the Company does not believe the outcome of any such disputes or legal actions will have a material effect on its consolidated and combined statements of operations, balance sheet, or cash flows. No amounts were accrued with respect to outstanding litigation at December 31, 2019 or December 31, 2018.

Environmental Matters

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state, local laws, and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks.

Commitments

At December 31, 2019, contractual obligations for long-term operating leases and purchase obligations are as follows:



Net Minimum Commitments (In thousands)	Total		2020		2021-2022		2023-2024		2025 & Beyond
Purchase obligations ⁽¹⁾	$	3,417	$	1,060	$	1,474	$	883	$	—
Operating lease obligations ⁽²⁾	9,851		2,647		3,159		2,310		1,735
Total Net Minimum Commitments	$	13,268	$	3,707	$	4,633	$	3,193	$	1,735

(1)

Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with firm transportation contracts and IT-related service commitments. The costs incurred under these obligations were $1.5 million, $0.7 million, and $0.5 million for the 2019 Successor Period, the combined 2018 Successor Period and 2018 Predecessor Period, and the 2017 Predecessor Period, respectively.


(2)	Amounts include long-term lease payments for office space, vehicles, equipment related to exploration, development, and production activities, as well as long-term obligations expected to be incurred for leases commencing in 2020. Refer to Note 10 - Leases for additional information.

Risks and Uncertainties

The Company’s revenue, profitability, and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which depend on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments, and competition from other energy sources. Oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future.

12. Income Taxes

The Company’s income tax provision consists of the following components:



	Successor					Predecessor
(In thousands)	Year Ended December 31, 2019		July 31, 2018 Through December 31, 2018			January 1, 2018 Through July 30, 2018		Year Ended December 31, 2017
Current:
Federal	$	—	$	(1,054	)	$	—	$	—
State	499		381			1,461		689
	499		(673		)	1,461		689
Deferred:
Federal	13,817		11,431			—		—
State	444		697			324		2,052
	14,261		12,128			324		2,052
Total provision	$	14,760	$	11,455		$	1,785	$	2,741

The Company is subject to U.S. federal income tax, the margin tax in the state of Texas, and Louisiana corporate income tax. As of December 31, 2019, the Company did not have an accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. Interest and penalties related to uncertain tax positions are reported in income tax expense. As of December 31, 2019, no amounts have been incurred for income tax uncertainties or interest and penalties. The Company is currently not aware of any issues under review that could result in significant payments, accruals, or material deviation from its position. The Company’s tax years since its formation remain subject to possible income tax examinations by its major taxing authorities for all periods. The Company’s annual effective tax rate as of December 31, 2019 and December 31, 2018, was 14.8% and 12.2%, respectively. The primary differences between the annual effective tax rate and the statutory rate of 21.0% are primarily related to income attributable to noncontrolling interest and state taxes.

The Karnes County Contributors, on behalf of the Predecessor, had elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains, and losses flowed through to the partners and were taxed at the partner level. Accordingly, no tax provision for federal income taxes was included in the financial statements. The Predecessor recorded state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.

A reconciliation of the statutory federal income tax expense to the income tax expense or benefit from continuing operations provided at December 31, 2019, is as follows:



	Successor						Predecessor
(In thousands)	Year Ended December 31, 2019			July 31, 2018 Through December 31, 2018			January 1, 2018 Through July 30, 2018		Year Ended December 31, 2017
Income tax expense at the federal statutory rate	$	20,966		$	19,706		$	—	$	—
State income tax expense, net of federal income tax benefits	847			1,028			1,785		2,741
Noncontrolling interest in partnerships	(7,309		)	(9,103		)	—		—
Other	256			(176		)	—		—
Income tax expense	$	14,760		$	11,455		$	1,785	$	2,741

The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities are presented below:



	Successor
(In thousands)	December 31, 2019			December 31, 2018
Deferred tax assets:
Net operating loss carryforwards	$	1,274		$	7,336
Capitalized transaction costs	3,185			6,677
Other assets	—			102
Total deferred tax assets	4,459			14,115
Deferred tax liabilities:
Investment in partnership	(76,260		)	(63,110		)
Oil and natural gas properties	(6,033		)	(5,598		)
Total deferred tax liabilities	(82,293		)	(68,708		)

Net deferred tax asset liabilities	$	(77,834	)	$	(54,593	)

As of December 31, 2019, the Company had $6.0 million of U.S. federal net operating loss, which has an indefinite carryforward.

The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating loss carry forwards. A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. As of December 31, 2019, we have no valuation allowance because the Company thinks it is more likely than not that it’s deferred tax assets will be realized. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years.

13. Stockholders’ Equity

Class A Common Stock

In connection with the closing of the Business Combination, the Company increased the number of authorized shares of Class A Common Stock to 1.3 billion. At December 31, 2019, there were 168.3 million shares issued and 167.3 million shares outstanding of Class A Common Stock. The holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters and are entitled one vote for each share held.

There is no cumulative voting with respect to the election of directors, which results in the holders of more than 50% of the shares being able to elect all of the directors, subject to voting obligations under the Stockholder Agreement (defined herein). In the event of a liquidation, dissolution, or winding up of the Company, the common stockholders are entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the common stock. The holders of the Class A Common Stock have no preemptive or other subscription rights, and there are no sinking fund provisions applicable to such shares.

Class B Common Stock

In connection with the closing of the Business Combination, the Company authorized 225.0 million shares of Class B Common Stock. At December 31, 2019, there were 85.8 million shares of Class B Common Stock issued and outstanding. Holders of Class B Common Stock vote together as a single class with holders of Class A Common Stock on all matters properly submitted to a vote of the stockholders. The holders of Class B Common Stock generally have the right to exchange all or a portion of their Class B Common Stock, together with an equal number of Magnolia LLC Units, for the same number of shares of Class A Common Stock or, at Magnolia LLC’s option, an equivalent amount of cash. Upon the future redemption or exchange of Magnolia LLC Units held by any holder of Class B Common Stock, a corresponding number of shares of Class B Common Stock held by such holder of Class B Common Stock will be canceled. In the event of a liquidation, dissolution, or winding up of the Company, the common stockholders are entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the common stock. The holders of the Class B Common Stock have no preemptive or other subscription rights, and there are no sinking fund provisions applicable to such shares.

Warrants

On June 7, 2019, the Company commenced an exchange offer (the “Offer”) and consent solicitation (the “Consent Solicitation”), pursuant to which the Company (1) offered to holders of its warrants the opportunity to receive 0.29 shares of Class A Common Stock in exchange for each warrant validly tendered and (2) solicited the consent from the holders of its warrants to approve an amendment to the Company’s existing warrant agreement, by and between the Company and Continental Stock Transfer & Trust Company, to amend the agreement to provide the Company with the right to require any holder of the Company’s warrants to exchange their warrants for Class A Common Stock at an exchange ratio of 0.261 shares of Class A Common Stock for each whole warrant (the “Warrant Amendment”). Pursuant to the Offer, certain of the Company’s warrant holders, including directors and executive officers, agreed to tender their warrants and provide the corresponding consent to the Warrant Amendment in the Consent Solicitation by entering into the Tender and Support Agreement (as defined below).

The Offer and Consent Solicitation expired on July 5, 2019. In connection with the closing of the Offer on July 10, 2019 and the subsequent exercise of the Company’s right to exchange all remaining warrants on July 25, 2019, the Company issued an aggregate of 9.2 million shares of Class A Common Stock in exchange for all of its 31.7 million warrants outstanding, which consisted of 21.7 million public warrants and 10.0 million private placement warrants.

As the fair value of the warrants exchanged in the Offer was less than the fair value of the Class A Common Stock issued, the Company recorded a non-cash deemed dividend of $2.8 million for the incremental value provided to the warrant holders. The fair value of warrants and the Class A Common Stock was determined using unadjusted quoted prices in an active market, a Level 1 fair value input. The Company capitalized $2.2 million of expenses related to the Offer within additional paid-in capital.

Share Repurchase Program

On August 5, 2019, the Company’s board of directors authorized a share repurchase program of up to 10 million shares of Class A Common Stock. The program does not require purchases to be made within a particular timeframe. As of December 31, 2019, the Company had repurchased 1.0 million shares of Class A Common Stock at a weighted average price of $10.28, for a total cost of approximately $10.3 million.

Noncontrolling Interest

Noncontrolling interest in Magnolia’s consolidated subsidiaries include amounts attributable to Magnolia LLC Units that were issued to the Karnes County Contributors in connection with the Business Combination. The noncontrolling interest percentage is affected by various equity transactions such as issuances of Class A Common Stock, the conversion of Class B Common Stock to Class A Common Stock, or cancellation of Class B Common Stock. In the first quarter of 2019, Magnolia Operating formed a joint venture, in which MGY Louisiana LLC, a wholly owned subsidiary of Magnolia Operating, holds approximately 85% of the units, with the remaining 15% attributable to noncontrolling interest.

On December 18, 2019, Magnolia LLC repurchased and subsequently canceled 6.0 million Magnolia LLC Units with an equal number of shares of corresponding Class B Common Stock for $69.1 million of cash consideration (the “Class B Common Stock Repurchase”). As a result of the Class B Common Stock Repurchase, the Company’s ownership in Magnolia LLC increased from 64.6% to 66.1% and the Karnes County Contributors’ ownership of Magnolia LLC decreased from 35.4% to 33.9%.

14. Stock Based Compensation

On October 8, 2018, the Company’s board of directors adopted the “Magnolia Oil & Gas Corporation Long Term Incentive Plan” (the “Plan”), effective as of July 17, 2018. A total of 11.8 million shares of Class A Common Stock have been authorized for issuance under the Plan. The Company grants stock based compensation awards in the form of RSUs and PSUs to eligible employees and directors to enhance the Company and its affiliates’ ability to attract, retain, and motivate persons who make important contributions to the Company and its affiliates by providing these individuals with equity ownership opportunities. Shares issued as a result of awards granted under the Plan are generally new shares of Class A Common Stock.

Stock based compensation expense is recognized net of forfeitures within “General and administrative expenses” on the consolidated and combined statements of operations and was $11.1 million for the year ended December 31, 2019 and $1.9 million for the 2018 Successor Period. The Company has elected to account for forfeitures of awards granted under the Plan as they occur in determining compensation expense.

Restricted Stock Units

The Company grants service-based RSU awards to employees and non-employee directors, which generally vest ratably over a three-year service period, in the case of awards to employees, and vest in full after one year, in the case of awards to directors. RSUs represent the right to receive shares of Class A Common Stock at the end of the vesting period equal to the number of RSUs that vest. RSUs are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient ceases to be an employee or director of the Company for any reason prior to vesting of the award. Compensation expense for the service-based RSU awards is based upon the grant date market value of the award and such costs are recorded on a straight-line basis over the requisite service period for each separately vesting portion of the award, as if the award was, in-substance, multiple awards. Unrecognized compensation expense related to unvested RSUs at December 31, 2019 was $10.4 million, which the Company expects to recognize over a weighted average period of 1.9 years.

The table below summarizes RSU activity for the year ended December 31, 2019:



	Restricted Stock Units		Weighted Average Grant Date Fair Value
Unvested RSUs, beginning of period	807,431		$	13.97
Granted	604,328		12.28
Vested	(310,225	)	14.25
Forfeited	(1,633	)	11.05
Unvested RSUs, end of period	1,099,901		$	12.97

Performance Stock Units

During the year ended December 31, 2019, the Company granted PSUs to certain employees. Each PSU, to the extent earned, represents the contingent right to receive one share of Class A Common Stock and the awardee may earn between zero and 150% of the target number of PSUs granted based on the total shareholder return (“TSR”) of the Class A Common Stock relative to the TSR achieved by a specific industry peer group over a three-year performance period, the last day of which is also the vesting date. In addition to the TSR conditions, vesting of the PSUs is subject to the awardee’s continued employment through the date of settlement of the PSUs, which will occur within 60 days following the end of the performance period. Unrecognized compensation expense related to unvested PSUs at December 31, 2019 was $6.0 million, which the Company expects to recognize over a weighted average period of 1.8 years.

The table below summarizes PSU activity for the year ended December 31, 2019:



	Performance Stock Units		Weighted Average Grant Date Fair Value
Unvested PSUs, beginning of period	475,312		$	14.58
Granted	267,482		13.87
Vested	(41,666	)	14.58
Forfeited	—		—
Unvested PSUs, end of period	701,128		$	14.31

The grant date fair value of the PSUs granted during the year ended December 31, 2019 was $3.7 million, calculated using a Monte Carlo simulation. The following table summarizes the assumptions used to calculate the grant date fair value of these PSUs.



	Grant Date Fair Value Assumptions
Expected term (in years)	2.85 - 2.67
Expected volatility	33.61% - 31.58%
Risk-free interest rate	2.48% - 2.29%

15. Earnings Per Share

A reconciliation of the numerators and denominators of the basic and diluted per share computations follows. No such computation is necessary for the Predecessor Period as the Predecessor was not previously accounted for as a standalone legal entity and did not have publicly traded securities.



(In thousands, except per share data)	Year Ended December 31, 2019		July 31, 2018 Through December 31, 2018
Basic:
Net income attributable to Class A Common Stock	$	47,433	$	39,095
Weighted average number of common shares outstanding during the period - basic	161,886		154,527
Net income per share of Class A Common Stock - basic	$	0.29	$	0.25

Diluted:
Net income attributable to Class A Common Stock	$	47,433	$	39,095
Weighted average number of common shares outstanding during the period - basic	161,886		154,527
Add: Dilutive effect warrants, stock based compensation, and other	5,161		3,705
Weighted average number of common shares outstanding during the period - diluted	167,047		158,232
Net income per share of Class A Common Stock - diluted	$	0.28	$	0.25

The calculation for weighted average shares reflects shares outstanding over the reporting period based on the actual number of days the shares were outstanding. The Company excluded 92.0 million and 90.9 million of weighted average shares of Class A Common Stock issuable upon conversion of the Class B Common Stock (and the corresponding Magnolia LLC Units) for the year ended December 31, 2019 and the 2018 Successor Period, respectively, as the effect was anti-dilutive.

16. Related Party Transactions

As of December 31, 2019, EnerVest Energy Institutional Fund XIV-A, L.P., a Delaware limited partnership, and EnerVest Energy Institutional Fund XIV-C, L.P., a Delaware limited partnership, both of which are part of the Karnes County Contributors, each held more than 10% of the Company’s common stock and qualified as principal owners of the Company, as defined in ASC 850, “Related Party Disclosures.”

Amended and Restated Limited Liability Company Agreement of Magnolia LLC

On the Closing Date, the Company, Magnolia LLC, and certain of the Karnes County Contributors entered into Magnolia LLC’s amended and restated limited liability company agreement, which sets forth, among other things, the rights and obligations of the holders of units in Magnolia LLC. Under the Magnolia LLC Agreement, the Company is the sole managing member of Magnolia LLC.

Registration Rights Agreement

At the closing of the Business Combination, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with TPG Pace Energy Sponsor LLC, a Delaware limited liability company (“TPG Pace”), the Karnes County Contributors, and the Company’s four independent directors prior to the Business Combination (collectively, the “Holders”), pursuant to which the Company is obligated, subject to the terms thereof and in the manner contemplated thereby, to register for resale under the Securities Act all or any portion of the shares of Class A Common Stock that the Holders held as of July 31, 2018 and that they may have acquired or might acquire thereafter, including upon conversion, exchange, or redemption of any other security therefor. Under the Registration Rights Agreement, Holders also have “piggyback” registration rights exercisable at any time that allow them to include the shares of Class A Common Stock that they own in certain registrations initiated by the Company.

Pursuant to the Registration Rights Agreement, the Company has filed and taken effective two registration statements on Form S-3, each of which registered, among others, the offering by the Holders of the shares of Class A Common Stock included therein.

Stockholder Agreement

On the Closing Date, the Company, TPG Pace, and the Karnes County Contributors entered into the Stockholder Agreement (the “Stockholder Agreement”), under which the Karnes County Contributors are entitled to nominate two directors, one of whom shall be independent under the listing rules of the New York Stock Exchange, the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Sarbanes-Oxley Act of 2002, for appointment to the board of directors of the Company (the “Board”) so long as they collectively own at least 15% of the outstanding shares of Class A Common Stock and Class B Common Stock, (on a fully diluted basis, including equity securities exercisable into common stock, and on a combined basis), and one director so long as they collectively own at least 2% of the outstanding shares of Class A Common Stock and Class B Common Stock (on a fully diluted basis, including equity securities exercisable into common stock, and on a combined basis). The Karnes County Contributors are collectively entitled to appoint one director to each committee of the Board (subject to applicable laws and stock exchange rules). Furthermore, TPG Pace was entitled to certain director nomination rights under the Stockholder Agreement, but those rights ceased following a distribution by TPG Pace of its shares in August 2019.

Class B Common Stock Repurchase

As part of the Class B Common Stock Repurchase, EnerVest Energy Institutional Fund XIV-A, L.P. received $45.7 million in cash and surrendered 4.0 million Magnolia LLC Units with an equal number of shares of corresponding Class B Common Stock. Subsequently, Magnolia LLC canceled the surrendered Magnolia LLC Units and a corresponding number of shares of Class B Common Stock.

Contingent Consideration

Pursuant to the Karnes County Contribution Agreement, for a period of five years following the Closing Date, the Company agreed to issue or cause to be issued to the Karnes County Contributors additional equity in the Company and Magnolia LLC upon satisfaction of certain EBITDA and free cash flow or stock price thresholds in three tranches. As of December 31, 2018, the Company had met the defined stock price thresholds and had issued an aggregate of 3.6 million additional shares of Class A Common Stock and 9.4 million additional shares of Class B Common Stock to the Karnes County Contributors and had caused Magnolia LLC to issue 9.4 million additional Magnolia LLC Units to the Karnes County Contributors.

Tender and Support Agreement

Pursuant to the Offer, certain of the Company’s warrant holders, including directors and executive officers, agreed to tender their warrants by entering into the tender and support agreement, dated as of June 7, 2019, by and between the Company and such holders (the “Tender and Support Agreement”). See Note 13 - Stockholders’ Equity for more information.

Predecessor Transactions

EnerVest, as managing general partner of the Karnes County Contributors, provided management, accounting, and advisory services to the Karnes County Contributors in exchange for a quarterly management fee based on the Karnes County Contributors' investor commitments. The management fees incurred were allocated to the Predecessor using a ratio of asset acquisitions value to total asset acquisitions completed by the Karnes County Contributors. The management fees and other costs allocated to the Predecessor and included in “General and administrative expenses” in the combined statements of operations were $11.0 million for the 2018 Predecessor Period and $17.2 million for the year ended December 31, 2017.

The Karnes County Contributors also entered into operating agreements with EVOC to act as contract operator of the Predecessor’s oil and natural gas wells. The Predecessor reimbursed EVOC for direct expenses incurred. A majority of such expenses were charged on an actual basis (i.e., no mark-up or subsidy to EVOC). These costs are included in “Lease operating expenses” in the combined statements of operations in the 2018 Predecessor Period and the 2017 Predecessor Period. Additionally, in its role as contract operator, EVOC collected proceeds from oil, natural gas, and NGL sales and distributed them to the Predecessor and other working interest owners.

17. Major Customers

Successor

For the year ended December 31, 2019, two customers, including their subsidiaries, accounted for 43.3% and 18.5%, respectively, of the combined oil, natural gas, and natural gas liquids revenue. For the 2018 Successor Period, two customers, including their subsidiaries, accounted for 42.2% and 19.1%, respectively, of the combined oil, natural gas, and natural gas liquids revenue. The Company is exposed

to credit risk in the event of nonpayment by counterparties. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate.

Predecessor

For the 2018 Predecessor Period, three customers accounted for 47.6%, 14.5%, and 12.2% respectively, of the combined oil, natural gas, and natural gas liquids revenues. For the 2017 Predecessor Period, four customers accounted for 28.8%, 22.3%, 18.9%, and 10.2% respectively, of the combined oil, natural gas, and natural gas liquids revenues.

18. Supplemental Cash Flow Information

Supplemental cash flow disclosures are presented below:



	Successor				Predecessor
(In thousands)	Year Ended December 31, 2019		July 31, 2018 Through December 31, 2018		January 1, 2018 Through July 30, 2018		Year Ended December 31, 2017
Supplemental non-cash operating activity:
Cash paid for income taxes	$	390	$	—	$	336	$	43
Cash paid for interest	26,226		889		—		—
Supplemental non-cash investing and financing activity:
Accruals or liabilities for capital expenditures	$	40,722	$	50,633	$	38,028	$	53,274
Contributions of assets to purchase equity method investment	—		—		—		450
Contingent Consideration issued in Business Combination	—		149,700		—		—
Non-Compete agreement entered into in Business Combination	—		44,400		—		—
Equity issuances in connection with acquisitions	33,693		1,481,692		—		—
Non-cash deemed dividend related to warrant exchange	2,763		—		—		—
Supplemental non-cash lease operating activity:
Right-of-use assets obtained in exchange for operating lease obligations	$	6,720	$	—	$	—	$	—

19. Subsequent Events

On February 21, 2020, Magnolia closed an acquisition in Karnes and DeWitt counties for a total cash consideration of $71.3 million, subject to customary closing adjustments.

Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited)

Capitalized Costs

The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below:



	Successor
(In thousands)	December 31, 2019			December 31, 2018
Proved properties	$	2,863,666		$	2,054,285
Unproved properties	951,555			1,196,457
Total proved and unproved properties	3,815,221			3,250,742
Accumulated depreciation, depletion and amortization	(701,155		)	(177,897		)
Net capitalized costs	$	3,114,066		$	3,072,845

Costs Incurred For Oil and Natural Gas Producing Activities

The following table sets forth the costs incurred in the Company’s oil and gas production, exploration, and development activities:



	Successor				Predecessor
(In thousands)	Year Ended December 31, 2019		July 31, 2018 Through December 31, 2018		January 1, 2018 Through July 30, 2018		Year Ended December 31, 2017
Acquisition costs:
Proved properties	$	106,489	$	1,617,131	$	118,572	$	57,263
Unproved properties	29,208		1,400,302		22,802		1,552
Exploration and development costs	441,482		245,017		183,130		251,454
Total	$	577,179	$	3,262,450	$	324,504	$	310,269

Oil and Gas Reserve Quantities

The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and natural gas producing activities and SEC rules for oil and natural gas reporting reserves estimation and disclosure.

The majority of the Company’s 2019 Successor Period proved reserves volumes, approximately 96%, are based on evaluations prepared by the independent petroleum engineering firm of Miller and Lents, in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The following table summarizes the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for the year ended December 31, 2019, the 2018 Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period. The following prices, as adjusted for transportation, quality, and basis differentials, were used in the calculation of the standardized measure of discounted future net cash flows (“Standardized Measure”):



	Successor				Predecessor
	Year Ended December 31, 2019		July 31, 2018 Through December 31, 2018		January 1, 2018 Through July 30, 2018		Year Ended December 31, 2017

Oil (per Bbl)	$	59.99	$	67.61	$	63.37	$	51.34
Gas (per Mcf)	2.25		2.78		2.84		2.98
NGLs (per Bbl)	15.73		26.25		23.74		27.32

The table below presents a summary of changes in the Company’s proved reserves. The Predecessor’s reserves are based on a five year development plan, whereas all of the Successor’s proved undeveloped reserves, as of December 31, 2019, are planned to be developed within one year.



	Successor
	Year Ended December 31, 2019								July 31, 2018 Through December 31, 2018
	Crude Oil (MMBbls)		Natural Gas (Bcf)		Natural Gas Liquids (MMBbls)		Total (MMboe)		Crude Oil (MMBbls)		Natural Gas (Bcf)		Natural Gas Liquids (MMBbls)		Total (MMboe)
Total proved reserves:
Beginning of period	50.6		176.1		20.6		100.5		44.2		136.8		17.4		84.3
Extensions and discoveries	12.6		40.4		6.9		26.3		12.9		25.6		3.8		21.0
Revisions of previous estimates	(1.9	)	(0.3	)	0.3		(1.7	)	(4.9	)	2.6		(1.4	)	(5.9	)
Purchases of reserves in place	4.2		22.3		0.7		8.6		3.5		25.2		2.7		10.4
Production	(12.9	)	(41.3	)	(4.6	)	(24.4	)	(5.1	)	(14.1	)	(1.9	)	(9.3	)
End of period	52.6		197.2		23.9		109.3		50.6		176.1		20.6		100.5

Proved developed reserves:
Beginning of period	35.2		149.0		16.5		76.5		34.3		117.8		14.4		68.3
End of period	40.3		165.8		18.9		86.8		35.2		149.0		16.5		76.5
Proved undeveloped reserves:
Beginning of period	15.4		27.1		4.1		24.0		9.9		19.0		3.0		16.1
End of period	12.3		31.4		5.0		22.5		15.4		27.1		4.1		24.0

	Predecessor
	January 1, 2018 Through July 30, 2018								Year Ended December 31, 2017
	Crude Oil (MMBbls)		Natural Gas (Bcf)		Natural Gas Liquids (MMBbls)		Total (MMboe)		Crude Oil (MMBbls)		Natural Gas (Bcf)		Natural Gas Liquids (MMBbls)		Total (MMboe)
Total proved reserves:
Beginning of period	91.7		148.2		21.4		137.8		87.2		165.3		23.4		138.2
Extensions and discoveries	3.9		8.7		1.3		6.7		27.6		53.4		7.6		44.1
Revisions of previous estimates	(14.5	)	(22.2	)	(2.7	)	(20.9	)	(20.3	)	(69.6	)	(9.5	)	(41.4	)
Purchases of reserves in place	6.1		7.9		1.2		8.6		4.4		7.7		1.2		6.8
Production	(5.8	)	(7.6	)	(1.1	)	(8.2	)	(7.2	)	(8.6	)	(1.3	)	(9.9	)
End of period	81.4		135.0		20.1		124.0		91.7		148.2		21.4		137.8

Proved developed reserves:
Beginning of period	28.0		52.3		7.5		44.2		21.1		46.8		6.6		35.4
End of period	29.5		57.1		8.5		47.5		28.0		52.3		7.5		44.2
Proved undeveloped reserves:
Beginning of period	63.7		95.9		13.9		93.6		66.1		118.5		16.8		102.8
End of period	51.9		77.9		11.6		76.5		63.7		95.9		13.9		93.6

For the 2019 Successor Period, extensions and discoveries contributed approximately 26.3 MMboe to proved reserves. This was primarily driven by new well locations at the Company’s Karnes and Giddings operations that extended the proved areas. Additionally, the Company had a downward revision of 1.7 MMboe. The impact of the lower year-end 2019 SEC-basis price, compared to year-end 2018, results in approximately a 5.5 MMboe downward revision. This was partially offset by an upward technical revision of approximately 0.7 MMboe due to improved well performance for the Giddings and Highlander fields and the addition of 3.1 MMboe related to infill drilling in the Karnes field. Acquisitions of approximately 8.6 MMboe during 2019 were related to the purchase of the Highlander asset and other purchases in the Karnes area.

During the 2018 Successor Period, extensions and discoveries contributed 21.0 MMboe to proved reserves primarily due to additions from successful drilling and completion activity and continual refinement of the development program. Additionally, the 2018

Successor Period had net negative revisions of 5.9 MMboe primarily due to performance based revisions. The 2018 Successor Period added 10.4 MMboe of proved reserves primarily related to the Harvest Acquisition.

The 2018 Predecessor Period had net negative revisions of 20.9 MMboe, which were primarily due to 15.0 MMboe of negative revisions attributable to a reduced development forecast in line with anticipated operated and non-operated drilling activity that caused a number of proved undeveloped locations to be reclassified to unproved by falling outside the five year SEC window and 6.0 MMboe of negative revisions related to higher workover activity from offset development. Additionally, for the 2018 Predecessor Period, extensions contributed 6.7 MMboe due to the addition of replacement reserves within the five year SEC window and added 8.6 MMboe related to the acquisition of the GulfTex Assets.

For the year ended December 31, 2017, extensions and discoveries contributed 44.1 MMboe in the Predecessor proved reserves and is attributable to successful drilling and completion activities and formation of new drilling units.

Additionally, the Predecessor had net negative revisions of 41.4 MMboe, which was primarily due to a decrease of 28.7 MMboe due to lower than expected well results as well as production forecasts being reduced to account for downtime on offset producing wells as a result of increased completion activity. As of December 31, 2016, certain wells were expected with reasonable certainty to perform in line with the historical type curve reflected in the Predecessor’s reserve estimates, but certain of the wells drilled by the Karnes County Contributors, and other operators during 2017, ultimately generated lower than expected results, leading to certain changes to the Predecessor’s reserve model, including type curves used for various areas, resulting in negative revisions to both the Predecessor’s proved developed reserves and proved undeveloped reserves.

The negative revisions also included the Predecessor’s reclassification from proved undeveloped reserves to unproved reserves of 6.8 MMboe primarily due to the fact that several wells became uneconomic as a result of changes in expenses and development costs coupled with lower production forecasts. The remaining 8.9 MMboe of negative revisions to the Predecessor were primarily attributable to increases in drilling and completion costs, increased operating expenses associated with improved commodity prices, and increasing industry activity.

The negative revisions to the Predecessor were partially offset by positive revisions of 3.0 MMboe attributable to higher commodity prices, related to previously uneconomic proved undeveloped reserves of 2.6 MMboe as well as existing proved undeveloped reserves of 0.4 MMboe.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. The vast majority of the proved undeveloped reserves volumes in the Successor Periods are expected to be converted to proved developed reserves within one year, which may not be comparable to other oil and natural gas companies. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.

The following table presents the Company’s standardized measure of discounted future net cash flows:



	Successor						Predecessor
(In thousands)	December 31, 2019			December 31, 2018			July 30, 2018			December 31, 2017
Future cash inflows	$	3,983,118		$	4,451,628		$	6,020,768		$	5,410,210
Future production costs	(1,365,745		)	(1,463,023		)	(1,773,608		)	(1,510,903		)
Future development costs	(254,211		)	(260,057		)	(835,632		)	(1,009,922		)
Future income tax expenses	(88,566		)	(96,311		)	(31,609		)	(28,404		)
Future net cash flows	2,274,596			2,632,237			3,379,919			2,860,981
10% discount to reflect timing of cash flows	(649,128		)	(754,709		)	(1,122,055		)	(1,096,819		)
Standardized measure of discounted future net cash flows	$	1,625,468		$	1,877,528		$	2,257,864		$	1,764,162

The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows:



	Successor
(In thousands)	Year Ended December 31, 2019			July 31, 2018 Through December 31, 2018
Standardized measure of discounted future net cash flows, beginning of period	$	1,877,528		$	1,457,656
Sales of oil, natural gas, and NGLs produced during the period	(753,740		)	(364,850		)
Purchases of minerals in place	145,076			141,585
Extensions, discoveries, and improved recovery	463,101			429,295
Changes in estimated future development costs	14,749			1,372
Net change in prices and production costs	(356,055		)	223,177
Development costs incurred during the period	162,350			98,407
Revisions in quantity estimates	(21,157		)	(87,852		)
Accretion of discount	195,457			61,237
Net change in income taxes	21,547			(65,004		)
Net change in timing of production and other	(123,388		)	(17,495		)
Standardized measure of discounted future net cash flows, end of period	$	1,625,468		$	1,877,528


	Predecessor
(In thousands)	January 1, 2018 Through July 30, 2018			Year Ended December 31, 2017
Standardized measure of discounted future net cash flows, beginning of period	$	1,764,162		$	1,250,553
Sales of oil, natural gas, and NGLs produced during the period	(388,982		)	(339,222		)
Purchases of minerals in place	150,622			71,822
Extensions, discoveries, and improved recovery	125,067			565,171
Development costs incurred during the period	144,273			234,100
Net change in prices and production costs	552,761			668,850
Changes in estimated future development costs	(39,154		)	(11,136		)
Revisions in quantity estimates	(201,417		)	(797,957		)
Accretion of discount	103,931			126,368
Net change in income taxes	(2,817		)	(4,387		)
Net change in timing of production and other	49,418			—
Standardized measure of discounted future net cash flows, end of period	$	2,257,864		$	1,764,162

Selected Quarterly Financial Data (Unaudited)



	Successor
	Quarter Ended
(In thousands)	March 31, 2019			June 30, 2019			September 30, 2019			December 31, 2019

Revenues	$	218,674		$	242,958		$	244,799		$	229,709
Operating expenses	185,159			199,326			217,130			207,025
Operating income	33,515			43,632			27,669			22,684
Other income (expense)	(7,027		)	(7,184		)	(6,783		)	(6,742		)
Income tax expense	3,775			5,145			3,529			2,311
NET INCOME	22,713			31,303			17,357			13,631
LESS: Net income attributable to noncontrolling interest	9,687			12,797			6,810			5,516
NET INCOME ATTRIBUTABLE TO MAGNOLIA	13,026			18,506			10,547			8,115
LESS: Non-cash deemed dividend related to warrant exchange	—			—			2,763			—
NET INCOME ATTRIBUTABLE TO CLASS A COMMON STOCK	$	13,026		$	18,506		$	7,784		$	8,115
NET INCOME PER SHARE OF CLASS A COMMON STOCK
Basic	$	0.08		$	0.12		$	0.05		$	0.05
Diluted	$	0.08		$	0.12		$	0.05		$	0.05



	Predecessor								Successor
(In thousands)	Quarter Ended March 31, 2018			Quarter Ended June 30, 2018			July 1, 2018 Through July 30, 2018		July 31, 2018 Through September 30, 2018			Quarter Ended December 31, 2018

Revenues	$	172,312		$	199,987		$	76,887	$	178,163		$	255,055
Operating expenses	79,800			98,655			32,927		138,315			180,945
Operating income	92,512			101,332			43,960		39,848			74,110
Other income (expense)	(6,700		)	(14,310		)	3,544		(11,671		)	(8,384		)
Income tax expense	446			573			766		3,537			7,918
NET INCOME	$	85,366		$	86,449		$	46,738	24,640			57,808
LESS: Net income attributable to noncontrolling interest									18,466			24,887
NET INCOME ATTRIBUTABLE TO CLASS A COMMON STOCK									$	6,174		$	32,921
NET INCOME PER SHARE OF CLASS A COMMON STOCK
Basic									$	0.04		$	0.21
Diluted									$	0.04		$	0.21

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, Magnolia has evaluated, under the supervision and with the participation of the Company’s management, including Magnolia’s principal executive officer and principal financial officer, the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as

of the end of the fiscal year covered by this Annual Report on Form 10-K. Based on such evaluation, Magnolia’s principal executive officer and principal financial officer have concluded that as of such date, its disclosure controls and procedures were effective. The Company’s disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by it in reports that it files under the Exchange Act is accumulated and communicated to management, including the Company’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC.

Management’s Annual Report on Internal Control over Financial Reporting

Management is responsible for designing, implementing, and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a- 15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, using the criteria in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management believes that the Company’s internal control over financial reporting was effective as of December 31, 2019.

This Annual Report on Form 10-K includes an attestation report of KPMG LLP, the Company’s independent registered public accounting firm, on the Company’s internal control over financial reporting as of December 31, 2019, which is included in this Annual Report on Form 10-K.

Changes in Internal Control Over Financial Reporting

There were no changes in the system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. Other Information

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required in response to this item will be set forth in Magnolia's Definitive Proxy Statement, to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K and is incorporated herein by reference.

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accounting Fees and Services

PART IV

Item 15. Exhibits and Financial Statements Schedules



(a)(1) The following financial statements are included in Part II, Item 8 of this Annual Report on Form 10-K:		Page

Consolidated Balance Sheets as of December 31, 2019 and 2018		45
Consolidated and Combined Statements of Operations for the year ended December 31, 2019, the periods July 31, 2018 through December 31, 2018 and January 1, 2018 through July 30, 2018, and the year ended December 31, 2017		46
Combined Statement of Changes in Parents’ Net Investment for the year ended December 31, 2017 and the period January 1, 2018 through July 30, 2018		47
Consolidated Statements of Changes in Stockholders’ Equity for the period July 30, 2018 through December 31, 2018 and the year ended December 31, 2019		48
Consolidated and Combined Statements of Cash Flows for the year ended December 31, 2019, the periods July 31, 2018 through December 31, 2018 and January 1, 2018 through July 30, 2018, and the year ended December 31, 2017.		50
Notes to Consolidated and Combined Financial Statements for the year ended December 31, 2019, the periods July 31, 2018 through December 31, 2018 and January 1, 2018 through July 30, 2018, and the year ended December 31, 2017.		51

(2) Financial Statement Schedules
Financial statement schedules have been omitted because they either are not required, not applicable, or the information required to be presented is including in the Company’s financial statements and related notes.
(3) Exhibits



Exhibit Number		Description

2.1*†		Contribution and Merger Agreement, dated as of March 20, 2018, by and among TPG Pace Energy Holdings Corp., TPG Pace Energy Parent LLC, EnerVest Energy Institutional Fund XIV-A, L.P., EnerVest Energy Institutional Fund XIV-WIC, L.P., EnerVest Energy Institutional Fund XIV-2A, L.P., and EnerVest Energy Institutional Fund XIV-3A, L.P. and EnerVest Energy Institutional Fund XIV-C, L.P. (incorporated herein by reference to Exhibit 2.1 filed with the Current Report on Form 8-K, as amended, filed on March 20, 2018 (File No. 001-38083)).

2.2*†		Amendment No. 1 to the Contribution and Merger Agreement, dated May 10, 2018, by and among TPG Pace Energy Holdings Corp., TPG Pace Energy Parent, LLC, EnerVest Energy Institutional Fund XIV-A, L.P., EnerVest Energy Institutional Fund XIV-WIC, L.P., EnerVest Energy Institutional Fund XIV-2A, L.P., EnerVest Energy Institutional Fund XIV-3A, L.P. and EnerVest Energy Institutional Fund XIV-C, L.P. (incorporated herein by reference to Exhibit 2.2 filed with the Quarterly Report on Form 10-Q filed on May 14, 2018 (File No. 001-38083)).

2.3*†		Amendment No. 2 to the Contribution and Merger Agreement, dated June 27, 2018, by and among TPG Pace Energy Holdings Corp., TPG Pace Energy Parent, LLC, EnerVest Energy Institutional Fund XIV-A, L.P., EnerVest Energy Institutional Fund XIV-WIC, L.P., EnerVest Energy Institutional Fund XIV-2A, L.P., EnerVest Energy Institutional Fund XIV-3A, L.P. and EnerVest Energy Institutional Fund XIV-C, L.P. (incorporated by reference to Exhibit 2.3 filed with the Quarterly Report on Form 10-Q filed on August 14, 2018 (File No. 001-38083)).

2.4*†		Purchase and Sale Agreement, dated as of March 20, 2018, by and among TPG Pace Energy Parent LLC, EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P., EnerVest Holding, L.P., and EnerVest Wachovia Co-Investment Partnership, L.P. (incorporated herein by reference to Exhibit 2.2 filed with the Current Report on Form 8-K, as amended, filed on March 20, 2018 (File No. 001-38083)).

2.5*†		Membership Interest Purchase Agreement, dated as of March 20, 2018, by and among TPG Pace Energy Parent LLC, EnerVest Energy Institutional Fund XIV-A, L.P., EnerVest Energy Institutional Fund XIV-WIC, L.P. and EnerVest Energy Institutional Fund XIV-C, L.P. (incorporated herein by reference to Exhibit 2.3 filed with the Current Report on Form 8-K, as amended, filed on March 20, 2018 (File No. 001-38083)).

2.6*†		Amendment No. 1 to the Purchase and Sale Agreement, dated September 28, 2018, by and among EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, LP., EnerVest Holding, L.P., EnerVest Wachovia Co-Investment Partnership, L.P. (incorporated herein by reference to Exhibit 2.6 filed with the Quarterly Report on Form 10-Q filed on November 13, 2018 (File No. 001-38083)).



Exhibit Number		Description

3.1*		Second Amended and Restated Certificate of Incorporation of the Company, dated as of July 31, 2018 (incorporated herein by reference to Exhibit 3.1 filed with the Current Report on Form 8-K filed on August 6, 2018 (File No. 001-38083)).

3.2*		Bylaws of the Company (incorporated herein by reference to Exhibit 3.3 filed with the Registration Statement on Form S-1 filed on April 17, 2017 (File No. 333-217338)).

4.1*		Specimen Class A Common Stock Certificate (incorporated herein by reference to Exhibit 4.2 filed with the Registration Statement on Form S-1 filed on April 17, 2017 (File No. 333-217338)).

4.2*		Indenture, dated as of July 31, 2018, by and among Magnolia Oil & Gas Operating LLC, Magnolia Oil & Gas Finance Corp. and Deutsche Bank Trust Company Americas, as trustee (incorporated herein by reference to Exhibit 4.1 filed with the Current Report on Form 8-K, filed on August 6, 2018 (File No. 001-38083)).

4.3*		Registration Rights Agreement, dated as of July 31, 2018, by and among Magnolia Oil & Gas Corporation, EnerVest Energy Institutional Fund XIV-A, L.P., EnerVest Energy Institutional Fund XIV-WIC, L.P., EnerVest Energy Institutional Fund XIV-2A,L.P., EnerVest Energy Institutional Fund XIV-3A, L.P., EnerVest Energy Institutional Fund XIV-C, L.P., TPG Pace Energy Sponsor, LLC, Arcilia Acosta, Edward Djerejian, Chad Leat and Dan F. Smith (incorporated herein by reference to Exhibit 4.2 filed with the Current Report on Form 8-K, filed on August 6, 2018 (File No. 001-38083)).

4.4*		First Amendment to Registration Rights Agreement, dated as of February 25, 2019, by and among Magnolia Oil & Gas Corporation, EnerVest Energy Institutional Fund XIV-A, L.P., EnerVest Energy Institutional Fund XIV-WIC, L.P., EnerVest Energy Institutional Fund XIV-2A,L.P., EnerVest Energy Institutional Fund XIV-3A, L.P., EnerVest Energy Institutional Fund XIV-C, L.P., EnerVest Energy Institutional Fund XIV-C-AIV, L.P. TPG Pace Energy Sponsor Successor, LLC, Peterson Capital Partners, L.P., Miller Creek Investments, LLC and Stephen Chazen.

4.5*		Stockholder Agreement, dated as of July 31, 2018, by and among Magnolia Oil & Gas Corporation, EnerVest Energy Institutional Fund XIV-A, L.P., EnerVest Energy Institutional Fund XIV-WIC, L.P., EnerVest Energy Institutional Fund XIV-2A,L.P., EnerVest Energy Institutional Fund XIV-3A, L.P., EnerVest Energy Institutional Fund XIV-C, L.P. and TPG Pace Energy Sponsor, LLC (incorporated herein by reference to Exhibit 4.3 filed with the Current Report on Form 8-K, filed on August 6, 2018 (File No. 001-38083)).

4.6*		Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended.

10.1*		Credit Agreement, dated as of July 31, 2018, by and among Magnolia Oil & Gas Intermediate LLC (f/k/a TPG Pace Energy Intermediate LLC), Magnolia Oil & Gas Operating LLC, the lenders from time to time party thereto, Citibank, N.A., as administrative agent and collateral agent, as the swingline lender and an issuing bank and each other issuing bank from time to time party thereto (incorporated herein by reference to Exhibit 10.1 filed with the Current Report on Form 8-K/A, filed on August 6, 2018 (File No. 001-38083)).

10.2*		Amended and Restated Limited Liability Company Agreement of Magnolia Oil & Gas Parent LLC, dated as of July 31, 2018 (incorporated herein by reference to Exhibit 10.2 filed with the Current Report on Form 8-K/A, filed on August 6, 2018 (File No. 001-38083)).

10.3*		Services Agreement, by and between Magnolia Oil & Gas Corporation and EnerVest Operating L.L.C., dated as of July 31, 2018 (incorporated herein by reference to Exhibit 10.5 filed with the Current Report on Form 8-K/A, filed on August 6, 2018 (File No. 001-38083)).

10.4*		Non-Competition Agreement, by and between Magnolia Oil & Gas Corporation and EnerVest Ltd., dated as of July 31, 2018 (incorporated herein by reference to Exhibit 10.3 filed with the Current Report on Form 8-K/A, filed on August 6, 2018 (File No. 001-38083)).

10.5*††		Form of Indemnity Agreement (incorporated herein by reference to Exhibit 10.4 filed with the Current Report on Form 8-K/A, filed on August 6, 2018 (File No. 001-38083)).

10.6*††		Magnolia Oil & Gas Corporation Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.6 filed with the Current Report on Form 8-K/A, filed on August 6, 2018 (File No. 001-38083)).

10.7*††		Form of Standard Restricted Stock Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan (incorporated herein by reference to Exhibit 4.8 filed with the Registration Statement on Form S-8, filed on October 5, 2018 (File No. 333-227722)).

10.8*††		Form of Non-Standard Restricted Stock Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan (incorporated herein by reference to Exhibit 4.9 filed with the Registration Statement on Form S-8, filed on October 5, 2018 (File No. 333-227722)).

10.9*††		Form of Non-Employee Director Restricted Stock Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan (incorporated herein by reference to Exhibit 4.10 filed with the Registration Statement on Form S-8, filed on October 5, 2018 (File No. 333-227722)).



Exhibit Number		Description
10.10*††		Form of Standard Performance Share Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan (incorporated herein by reference to Exhibit 4.11 filed with the Registration Statement on Form S-8, filed on October 5, 2018 (File No. 333-227722).

10.11*††		Form of Non-Standard Performance Share Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan (incorporated herein by reference to Exhibit 4.12 filed with the Registration Statement on Form S-8, filed on October 5, 2018 (File No. 333-227722)).

10.12*††		Director Compensation Program (incorporated herein by reference to Exhibit 10.10 filed with the Current Report on Form 8-K/A, filed on August 6, 2018 (File No. 001-38083)).

10.13*††		Form of 2019 Non-Employee Director Restricted Stock Unit Grant Notice and attached Restricted Stock Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 filed with the Quarterly Report on Form 10-Q, filed on August 7, 2019 (File No. 001-38083)).

10.14*††		Form of 2019 Restricted Stock Unit Grant Notice and attached Restricted Stock Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan, Standard Employee (incorporated herein by reference to Exhibit 4.2 filed with the Quarterly Report on Form 10-Q, filed on May 7, 2019 (File No. 001-38083)).

10.15*††		Form of Restricted Stock Unit Grant Notice and attached Restricted Stock Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan, Annual Bonus (incorporated herein by reference to Exhibit 4.3 filed with the Quarterly Report on Form 10-Q, filed on May 7, 2019 (File No. 001-38083)).

10.16*††		Form of Performance Share Unit Grant Notice and attached Performance Share Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan (incorporated herein by reference to Exhibit 4.4 filed with the Quarterly Report on Form 10-Q, filed on May 7, 2019 (File No. 001-38083)).

10.17**††		Form of Restricted Stock Unit Grant Notice and attached Restricted Stock Unit Agreement under the Magnolia Oil & Gas Corporation Long Term Incentive Plan.

10.18**††		Form of Performance Share Unit Grant Notice and attached Performance Share Unit Agreement under Magnolia Oil & Gas Corporation Long Term Incentive Plan.

21.1**		Subsidiaries of Magnolia Oil and Gas Corporation.

23.1**		Consent of KPMG LLP.

23.2**		Consent of Deloitte & Touche LLP.

23.3**		Consent of Miller and Lents, Ltd.

24.1**		Power of Attorney.

31.1**		Certification of Chief Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2**		Certification of Chief Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1***		Certifications Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1**		Summary Report of Miller and Lents, Ltd., dated as of January 29, 2020, for proved reserves as of December 31, 2019.

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Taxonomy Extension Schema Document.

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB**		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document.

104**		Cover Page Interactive Data File (embedded within the Inline XBRL document).


*	Incorporated herein by reference as indicated.


**	Filed herewith.


***	Furnished herewith.


†	Certain schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished supplemental to the SEC upon request.


††	Management contract of compensatory plan or agreement.

Item 16. Form 10-K Summary

None.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	MAGNOLIA OIL & GAS CORPORATION

Date: February 26, 2020	By:	/s/ Stephen Chazen
		Stephen Chazen
		Chief Executive Officer (Principal Executive Officer)

Pursuant to the requirements of the Securities Act of 1934, this registration statement has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.




Name	Title	Date

/s/ Stephen Chazen Stephen Chazen	President, Chief Executive Officer and Chairman (Principal Executive Officer)	February 26, 2020

/s/ Christopher Stavros Christopher Stavros	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	February 26, 2020


/s/ Arcilia Acosta* Arcilia Acosta	Director	February 26, 2020

/s/ Edward Djerejian* Edward Djerejian	Director	February 26, 2020

/s/ Michael MacDougall* Michael MacDougall	Director	February 26, 2020

/s/ Dan F. Smith* Dan F. Smith	Director	February 26, 2020

/s/ James R. Larson* James R. Larson	Director	February 26, 2020

/s/ John B. Walker* John B. Walker	Director	February 26, 2020

/s/ Angela Busch* Angela Busch	Director	February 26, 2020

By* /s/ Valerie Chase Valerie Chase as Attorney-in-fact

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