Magnolia Oil & Gas Corp - Annual Report: 2018 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)


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

For the year ended December 31, 2018


¨	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, Houston, TX 77046
(Address of principal executive offices)
Registrant’s telephone number, including area code: (713) 842-9050

Securities Registered Pursuant to Section 12(b) of the Act:



Title of Each Class		Name of Each Exchange on which Registered
Class A Common Stock, Par Value $0.0001 Per Share		New York Stock Exchange
Warrants to purchase Class A Common Stock		New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: None

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

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 x

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 x 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 x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy of information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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	x	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 x

The aggregate market value of the common stock held by non‑affiliates of the registrant as of June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $704.8 million based on the closing price on that day on the New York Stock Exchange.

As of February 22, 2019, there were 156,332,733 shares of Class A Common Stock, $0.0001 par value per share, and 93,346,725 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 2019 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
Cautionary Statement Concerning Forward-Looking Statements

	PART I.
Items 1 and 2.	Business and Properties	1
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	25
Item 3.	Legal Proceedings	25
Item 4.	Mine Safety Disclosures	25

	PART II.
Item 5.	Market for the Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data	28
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 8.	Financial Statements and Supplementary Data	F-1
Item 9.	Changes in Disagreements with Accountants on Accounting and Financial Disclosure	F-37
Item 9A.	Controls and Procedures	F-37
Item 9B.	Other Information	F-38

	PART III.
Item 10.	Directors, Executive Officers and Corporate Governance	F-38
Item 11.	Executive Compensation	F-38
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	F-38
Item 13.	Certain Relationships and Related Transactions, and Director Independence	F-38
Item 14.	Principal Accounting Fees and Services	F-38

	PART IV.
Item 15.	Exhibits and Financial Statement Schedules	F-38
Item 16.	Form 10-K Summary	F-41

Signatures		F-41

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, NGLs, 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 hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“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.” The total acres or wells, as the case may be, in which a 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.

“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.” The percentage of total acres an owner has out of a particular number of gross acres, or a specified tract. An owner who has 50% working interest in 100 acres has 50 net acres.

“Net well.” The percentage ownership interest in a well that an owner has based on the working interest. An owner who has a 50% working interest in a well has a 0.50 net well.

“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 and to produce and 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 expenditure and other contractual obligations;


•	currency exchange rates;


•	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;


•	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 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, 2018, Magnolia owned a 62.6% 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 has continued to operate Magnolia’s assets under the direction of its management by providing services 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.” 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 period from January 1, 2018 to July 30, 2018 (the “2018 Predecessor Period”); the year ended December 31, 2017 (the “2017 Predecessor Period”); the year ended December 31, 2016 (the “2016 Predecessor Period”); and, together with the 2018 Predecessor Period and 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 “Successor Period”).

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

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.” Magnolia’s warrants are traded on the NYSE under the symbol “MGY.WS.” In connection with Magnolia’s initial public offering, the company issued units in Magnolia, which consisted of one share of Magnolia’s Class A Common Stock and one-third of one warrant. The units outstanding separated into their component securities upon closing of the Business Combination and, as a result, no longer trade as a reportable security.

Properties

As of December 31, 2018, Magnolia’s assets consisted of a total leasehold position of 677,794 gross (455,964 net) acres, including 31,078 gross (16,841 net) acres in the Karnes County portion of the Eagle Ford Shale and 646,716 gross (439,123 net) acres in the

Giddings Field of the Austin Chalk. As of December 31, 2018, Magnolia had 1,458 gross wells (1,046 net) with total production of 61.9 Mboe/d in the fourth quarter of 2018. In the fourth quarter of 2018, Magnolia operated three drilling rigs across its acreage with two rigs in Karnes County and one rig in the Giddings Field and brought 14 gross operated horizontal wells on production. For the Successor Period, approximately 54.6%, 25.4% and 20.0% of production from Magnolia’s assets was attributable to oil, natural gas and NGLs, respectively.

Karnes County Assets

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. As of December 31, 2018, the Karnes County Assets included 31,078 gross (16,841 net) acres, approximately 97.2% of which were held by production.

As of December 31, 2018, Magnolia had approximately 200 net producing wells in Karnes County with total production of 41.3 Mboe/d in the fourth quarter of 2018. As of December 31, 2018, 67.4% of the 68.0 MMboe of proved reserves of the Karnes County Assets were developed, 79.2% of which were liquids.

Giddings Assets

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. The Giddings Assets have been developed with a focus on maximizing returns and improving operational efficiencies to extend beyond the existing drilling inventory to additional horizons. Future development results may allow for the expansion of existing location inventory throughout the leasehold. Wells previously drilled across the Giddings Assets have shown a strong track record of increasing returns with the application of improved completion techniques.

As of December 31, 2018, the Giddings Assets included 646,716 gross (439,123 net) acres, approximately 98.4% of which were held by production. As of December 31, 2018, 94.2% of the 32.6 MMboe of proved reserves located in the Giddings Field were developed, 50.1% of which were liquids. As of December 31, 2018, Magnolia’s assets included approximately 846 net producing wells in the Giddings Field with total production of 20.6 Mboe/d in the fourth quarter of 2018.

Reserve Data

Preparation of Reserve Estimates

The reserve estimates as of December 31, 2018 included in this Annual Report on Form 10-K are based on evaluations prepared by Cawley, Gillespie & Associates, Inc., Magnolia’s independent petroleum engineers (“CGA”), 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. CGA was selected for its historical experience and expertise in evaluating hydrocarbon resources.

Proved 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 the project within a reasonable time. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90.0% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. The technical and economic data used in the estimation of the 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. CGA uses this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and EURs per well are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy).

Internal Controls

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

Reserve engineering is and must be recognized as a subjective process of 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 and 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 and future production rates and costs. Please read “Risk Factors” in Item 1A in this Annual Report on Form 10-K.

Proved reserves as of December 31, 2018 were prepared by CGA. Magnolia’s Senior Vice President of Operations, Steve Millican, is the technical person primarily responsible for overseeing the internal reserves estimation process, and the work performed by CGA. Mr. Millican has over 20 years of industry experience with positions of increasing responsibility in operations, engineering and evaluations with companies such as Marathon Oil Corporation and EnerVest, Ltd. He holds a Bachelor of Science degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers.

The reserve reports were prepared by a team of geologists and reservoir engineers who integrate geological, geophysical, engineering and economic data to produce reserve estimates and economic forecasts. The process for the 2018 Reserve Report was supervised by Todd Brooker, President of CGA. Prior to joining CGA, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron. Mr. Brooker has been an employee of CGA since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.

Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves of Magnolia as of December 31, 2018. 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 6 Mcf to 1 bbl. This ratio is not reflective of the current price ratio between the two products.



	December 31, 2018
	Oil (MMbbls)	Natural Gas (Bcf)	NGLs (MMbbls)	Total (MMboe)
Proved Reserves
Total Proved Developed	35.2	149.0	16.5	76.5
Total Proved Undeveloped	15.4	27.1	4.1	24.0
Total Proved Reserves	50.6	176.1	20.6	100.5

Development of Proved Undeveloped Reserves

The Predecessor’s reserves are 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. The following table summarizes the changes in the Company’s proved undeveloped reserves during the Predecessor Period:



	Predecessor
	Total (MMboe)
Proved undeveloped reserves at January 1, 2018	93.6
Conversions into proved developed reserves	(9.4	)
Extensions	6.8
Acquisitions	3.4
Changes in commodity prices and differentials	2.1
Technical revisions	(20.0	)
Proved undeveloped reserves at July 30, 2018	76.5

The following table summarizes the changes in Magnolia’s proved undeveloped reserves during the Successor Period:



		Successor
		Total (MMboe)
Proved undeveloped reserves at July 31, 2018		16.1
Conversions into proved developed reserves		(7.5)
Extensions		19.4
Acquisitions		0.2
Changes in commodity prices and differentials		0.1
Technical revisions		(4.3)
Proved undeveloped reserves at December 31, 2018		24.0

As of December 31, 2018, Magnolia’s assets contained approximately 24.0 MMboe of proved undeveloped reserves, consisting of 15.4 MMbbls of oil, 27.1 Bcf of natural gas and 4.1 MMBbls of NGLs. Proved undeveloped reserves will be converted from undeveloped to developed as the applicable wells begin production.

Proved undeveloped reserves changed during the 2018 Successor Period primarily as a result of the following significant factors:

•Extensions of 19.4 MMboe related to Magnolia’s drilling activities;

•Conversions of 7.5 MMboe to proved developed reserves as a result of the ongoing drilling program.

From January 1, 2018 through July 30, 2018, the Predecessor incurred costs of approximately $61.3 million to convert the reserves associated with 21.8 of the net proved undeveloped locations of Predecessor to proved developed reserves of 9.4 MMboe. During the period from July 31, 2018 through December 31, 2018, Magnolia incurred costs of approximately $78.2 million to convert the reserves associated with 20.2 of its net proved undeveloped locations to proved developed reserves of 7.5 MMboe.

Overview

The following table sets out a brief comparative summary of certain key Successor Period data for each of Magnolia’s operating areas. Additional data and discussion is provided in Part II, Item 7- Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.



	Successor Period from July 31, 2018 to December 31, 2018
	Production (in MMboe)	Percentage of Total Production		Production Revenue (in millions)		Year-End Proved Reserves (in MMboe)	Percentage of Total Proved Reserves		Gross Wells Drilled
Giddings Assets	2.9	31.5	%	$	98.9	32.6	32.4	%	11
Karnes County Assets	6.4	68.5	%	334.3		67.9	67.6	%	28
	9.3	100	%	$	433.2	100.5	100	%	39

Drilling Statistics

The following table describes new development and exploratory wells drilled within Magnolia’s assets during the years ended December 31, 2018, 2017 and 2016. 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. 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, 2018, 75 gross (42 net) wells were in various stages of completion. As of December 31, 2018, Magnolia was running a two-rig program in Karnes County and a one-rig program in the Giddings Field. Magnolia plans to operate an average of one drilling rig in Karnes County and an average of one drilling rig in the Giddings Field in 2019.



	Net Exploratory			Net Development			Net Total Wells
	Productive	Dry	Total	Productive	Dry	Total	Productive	Dry	Total
July 31, 2018 through December 31, 2018 (Successor)
Giddings Assets	—	—	—	7	—	7	7	—	7
Karnes County Assets	—	—	—	18	—	18	18	—	18
Total	—	—	—	25	—	25	25	—	25

January 1, 2018 through July 30, 2018 (Predecessor and Giddings)
Giddings Assets	—	—	—	2	—	2	2	—	2
Predecessor (Karnes County)	—	—	—	40	—	40	40	—	40
Total	—	—	—	42	—	42	42	—	42

Year Ended December 31, 2017 (Predecessor and Giddings)
Giddings Assets	—	—	—	1	—	1	1	—	1
Predecessor (Karnes County)	—	—	—	57	—	57	57	—	57
Total	—	—	—	58	—	58	58	—	58

Year Ended December 31, 2016 (Predecessor and Giddings)
Giddings Assets	—	—	—	—	—	—	—	—	—
Predecessor (Karnes County)	—	—	—	18	—	18	18	—	18
Total	—	—	—	18	—	18	18	—	18

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 holds 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 held a working interest as of December 31, 2018.



	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Giddings Assets	620	465	442	381	1,062	846
Karnes County Assets	396	200	—	—	396	200
Total	1,016	665	442	381	1,458	1,046

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 for each of the regions where Magnolia has operations:



	Production					Average Sale Price
	Crude Oil (MMbbls)	Natural Gas (Bcf)	Natural Gas Liquids (MMbbls)	Average Lease Operating Cost per Boe		Crude Oil (MMBbls)		Natural Gas (Bcf)		Natural Gas Liquids (MMBbls)
July 31, 2018 through December 31, 2018 (Successor)
Giddings Assets	0.8	7.7	0.9	$	7.06	$	65.31	$	3.21	$	27.45
Karnes County Assets	4.3	6.4	1.0	3.80		67.73		2.84		24.59
Total	5.1	14.1	1.9	4.83		67.37		3.04		25.93

January 1, 2018 through July 30, 2018 (Predecessor and Giddings)
Giddings Assets	0.6	5.9	0.6	8.93		67.11		2.70		27.02
Predecessor (Karnes County)	5.8	7.6	1.1	4.49		69.35		2.91		25.46
Total	6.4	13.5	1.7	5.42		69.14		2.82		25.99

Year Ended December 31, 2017 (Predecessor and Giddings)
Giddings Assets	0.6	8.2	0.7	8.31		49.88		2.86		23.13
Predecessor (Karnes County)	7.2	8.6	1.3	4.44		48.95		3.02		21.04
Total	7.8	16.8	2.0	5.28		49.03		2.94		21.80

Year Ended December 31, 2016 (Predecessor and Giddings)
Giddings Assets	0.7	8.6	0.8	7.12		39.56		2.21		16.20
Predecessor (Karnes County)	2.3	2.9	0.4	5.35		41.97		2.67		15.08
Total	3.0	11.4	1.2	6.20		41.40		2.33		15.83

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, 2018. Approximately 97.2% of the net acreage included with the Karnes County Assets and 98.4% of the net acreage included with the Giddings Assets were held by production at December 31, 2018.



	Undeveloped Acreage		Developed Acreage (1)		Total Acreage
	Gross (2)	Net (3)	Gross (2)	Net (3)	Gross (2)	Net (3)
December 31, 2018 (Successor)
Giddings Assets	36,938	29,376	609,778	409,747	646,716	439,123
Karnes County Assets	18,398	10,300	12,680	6,541	31,078	16,841
Total	55,336	39,676	622,458	416,288	677,794	455,964


(1)	Developed acres are acres spaced or assigned to productive wells or wells capable of production.


(2)	A gross acre is an acre in which Magnolia holds a working interest. The number of gross acres is the total number of acres in which Magnolia holds a working interest.


(3)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Delivery Commitments

There are no material commitments to deliver a fixed and determinable quantity of oil or natural gas production from the Karnes County Assets or oil production from the Giddings Assets to customers in the near future under existing contracts. However, 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 has reserved firm capacity between 20,000 MMBtu/d and 30,000 MMBtu/d, which amount Magnolia has the right to set on a quarterly basis, through October 31, 2024. This contract requires Magnolia to pay a pipeline demand fee for the quarterly reserved capacity amount. Furthermore, Magnolia has a one-time right to reduce the reserved capacity amount on November 1, 2019 through the remaining term of the agreement. Magnolia expects that the Giddings Assets will be able to fulfill delivery 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 delivery 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 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 the 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 and on a competitive pricing basis. The majority of gas production related to the Karnes County Assets is currently processed to collect natural gas liquids. The Karnes County Assets also include a salt water disposal well, which currently handles the majority 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 if processing is economically justified. The majority of gas production related to the Giddings Assets is currently processed to collect natural gas liquids. Produced gas can be sold to various intrastate and interstate markets on a competitive pricing basis. The Giddings Assets also include a salt water disposal well that handles a small portion of water production from the Giddings Assets.

Marketing and Customers

For the Successor Period, two customers accounted for 42.2% and 19.1% of Magnolia’s revenue. For the 2018 Predecessor Period, three customers accounted for 47.6%, 14.5%, and 12.2% 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% of the combined oil, natural gas and natural gas liquids revenues. For the 2016 Predecessor Period, four customers accounted for 35.8%, 19.5%, 17.0%, and 14.4% of the combined oil, natural gas and natural gas liquids revenues.

No other purchaser accounted for 10.0% 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 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.” 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 (12) 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 (12) 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 their implementing regulations and other similar state and local laws and rules can impose certain operational controls for minimization of pollution or recordkeeping, monitoring and reporting requirements or other operational or siting constraints on the Company’s business, result in costs to remediate releases of regulated substances, including crude oil, into the environment, or require 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 and 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 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. For more information, see Item 1A - Risk Factors of 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 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 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 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, the EPA proposed a revised rule in September 2018 following the change in presidential administrations. Litigation surrounding EPA’s attempts to redefine the scope of CWA jurisdiction remains ongoing, and Magnolia cannot predict the outcome. 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 U.S. Environmental Protection Agency (“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 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. Were the EPA to propose a rulemaking, the consent decree requires that EPA take final action by no later than July 15, 2021. 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

ESA and Migratory Birds

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.

Related Insurance

Magnolia maintains insurance against some risks associated with above or underground contamination that may occur as a result of development activities. However, this insurance will likely be limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase.

Employees

As of December 31, 2018, Magnolia had approximately 27 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 and results of operations and Magnolia’s 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. For example, commodity prices dropped significantly from 2014 highs of $107.95 per barrel of oil and $8.15 per MMBtu for natural gas down to lows of $26.19 per barrel of oil in February 2016 and $1.49 per MMBtu for natural gas in March 2016. Since 2016, prices have increased but recently experienced downward pressure, settling as low as $44.48 per barrel on the WTI spot price on December 27, 2018 and $3.10 per MMBtu on the Henry Hub spot price for natural gas. 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, depends 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 and 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; and


•	U.S. federal, state and 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 may realize the benefit of any short-term increase in the price of oil, natural gas and NGLs, but it will not be protected against decreases in price, and if the price of oil and natural gas decreases significantly, Magnolia’s business, results of operation 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 seeks and obtains additional financing , subject to the restrictions in the instruments governing its existing debt, the addition of new debt to existing debt levels could intensify the operational risks that Magnolia faces. Further, adding new debt could limit Magnolia’s ability to service 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 on the Company’s assets may cause Magnolia to be unable to develop such assets in line with current expectations and projections. Further, recent well results may not be indicative of Magnolia’s 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.

In order to prepare the reserve estimates included herein, Magnolia’s management team has provided Magnolia’s reserve engineers estimates primarily for the first year following the date of the reserve report and has not created a five year development plan. 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, natural gas and 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, and recovery efficiencies may be worse than expected and production declines may be greater than estimated 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.

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. 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, nor may it 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 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 newly 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 does not always control decisions made under joint operating agreements and the parties under such agreements may fail to meet their obligations.

Magnolia conducts many of its exploration and production (“E&P”) 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 which are not what the Company believes is in its best interest. Moreover, parties to these agreements may be unable 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 currently provides operating services for many oil and natural gas assets, including the substantial majority of Magnolia’s assets and will continue to provide operating services for Magnolia’s assets through at least October 29, 2020 pursuant to the Services Agreement, subject to possible earlier termination pursuant to the terms of the Services Agreement. 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 assure you that its use of EVOC to provide contract operating services will continue to be economical. 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 will 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 remainder 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, 2018, Magnolia’s assets contained 24.0 MMboe of proved undeveloped reserves consisting of 15.4 MMBbls of oil, 27.1 Bcf of natural gas, and 4.1 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 and specific market factors and circumstances at the time of prospective impairment reviews, and 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, in particular oil prices, have recently experienced downward pressure, settling as low as $44.48 per barrel on the WTI spot price on December 27, 2018 and $3.10 per MMBtu on the Henry Hub spot price for natural gas. Likewise, NGLs have suffered significant recent declines 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. For the 2018 Successor Period, there were two purchasers who accounted for an aggregate 61% of the total revenue attributable to Magnolia’s assets. No other purchaser accounted for 10% or more of such revenues. The loss of any purchaser greater than 10% 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 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.

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 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. Magnolia cannot be certain that its cash flow will be sufficient to allow it to pay the principal and interest on its debt and meet its other obligations. If Magnolia does not have enough money, Magnolia may be required to refinance all or part of its debt, sell assets, borrow more money or raise equity. Magnolia may not be able to refinance its debt, sell assets, borrow more money or raise equity on terms acceptable to it, or at all. For example, Magnolia’s debt agreements require the satisfaction of certain conditions, including coverage and leverage ratios, 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 and future events and circumstances beyond Magnolia’s control. Breach of these covenants or restrictions will result in a default under Magnolia’s financing arrangements, which if not cured or waived, would permit the lenders to accelerate all indebtedness outstanding thereunder. Upon acceleration, the debt would become immediately due and payable, together with accrued and unpaid interest, and any lenders’ commitment 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. Additionally, upon the occurrence of an event of default under Magnolia’s financing agreements, the affected lenders may exercise remedies, including through foreclosure, on 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, 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.

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. 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 assure you 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 complement or expand the Company’s current business, however, there is no guarantee 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 integrate effectively 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, had increased, as did 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 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 and 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 performance standards that establish new controls, known as Subpart OOOOa, for emissions of methane from new, modified or reconstructed sources in the oil and gas sector. Following the change in presidential administration, there have been attempts to modify these regulations, and litigation concerning the regulations is ongoing. 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. However, in June 2017, the President stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process. The United States’ adherence to the exit process is uncertain and/or 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. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040, and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other climatic events; if any such effects were to occur, they could have a material adverse effect on Magnolia’s operations.

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 and 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 seriously harm 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 costs. 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 or 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.

If Magnolia fails to maintain an effective system of internal controls, Magnolia may not be able to accurately report its financial results.

Magnolia is required to comply with Section 404 of the Sarbanes Oxley Act, which requires, among other things, that companies maintain disclosure controls and procedures to ensure timely disclosure of material information, and that management review the effectiveness of those controls on a quarterly basis. Effective internal controls are necessary for Magnolia to provide reliable financial reports and to help prevent fraud, and Magnolia’s management and other personnel will devote a substantial amount of time to these compliance requirements. Moreover, these rules and regulations will increase Magnolia’s legal and financial compliance costs and make some activities more time-consuming and costly. Magnolia cannot be certain that it will be able to maintain adequate controls over its financial processes and reporting in the future or that it will be able to comply with its obligations under Section 404 of the Sarbanes Oxley Act. Section 404 of the Sarbanes-Oxley Act also requires Magnolia to evaluate annually the effectiveness of its internal controls over financial reporting as of the end of each fiscal year and to include a management report assessing the effectiveness of Magnolia’s internal control over financial reporting in its Annual Report on Form 10-K. As discussed in “Item 9A-Controls and Procedures,” the design of internal control over financial reporting for Magnolia following the Business Combination has required and will require significant time and resources from management and other personnel. Therefore, management was unable, without incurring unreasonable effort and expense, to conduct an assessment of Magnolia’s internal control over financial reporting, and accordingly, in compliance with SEC guidance Magnolia has not included a management report on internal control over financial reporting in this Annual Report on Form 10-K. If Magnolia fails to maintain the adequacy of its internal controls, Magnolia cannot assure you that it will be able to conclude in the future that it has effective internal control over financial reporting and/or Magnolia may encounter difficulties in implementing or improving its internal controls, which could harm its operating results or cause Magnolia to fail to meet its reporting obligations. If Magnolia fails to maintain effective internal controls, it might be subject to sanctions or investigation by regulatory authorities, such as the SEC. Any such action could adversely affect Magnolia’s financial results and may also result in delayed filings with the SEC.

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 amended and restated certificate of incorporation and amended and restated 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 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 amended and restated certificate of incorporation and its amended and restated 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 amended and restated 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 have the effect of accelerating any payments due under Magnolia’s RBL Facility, and could, in certain defined circumstances, accelerate payments required by the indentures 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 the perception that such sales could occur, may adversely affect prevailing market prices of its Class A Common Stock.

On August 28, 2018, Magnolia filed a registration statement with the SEC on Form S-3 providing for (i) the registration of 190,680,358 shares of the Company’s Class A Common Stock collectively representing shares of Class A Common Stock issuable upon exercise of certain of Magnolia’s warrants sold in a private placement concurrently with the Company’s initial public offering, Class A Common Stock issued in connection with the Business Combination, shares issued in a transaction to acquire certain assets owned by EV Properties, L.P., and shares of Class A Common Stock issuable upon exchange of units representing limited liability company interests in Magnolia LLC with an equal number of shares of Class B Common Stock, and (ii) the registration of an additional 21,666,666 shares of Magnolia’s Class A Common Stock issuable upon the exercise of the Company’s outstanding warrants held by the public.

On October 5, 2018, Magnolia filed a registration statement with the SEC on Form S-8 providing for the registration of 11,800,000 shares of its Class A Common Stock issued or reserved for issuance under Magnolia’s equity incentive plan. Subject to the satisfaction of vesting conditions, the expiration or waiver of lock-up agreements and the requirements of Rule 144 under the Securities Act, shares registered under the registration statement on Form S-8 are available for resale immediately in the public market without restriction.

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.

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 and warrants are currently traded on the NYSE under the ticker symbols “MGY” and “MGY.WS,” respectively. 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.

(b) Holders

At February 27, 2019, there were 49 holders of record of Magnolia’s separately traded Class A Common Stock, 5 holders of record of the Company’s Class B Common Stock, par value $0.0001 per share (“Class B Common Stock”), and 5 holders of record of the Company’s warrants.

Not applicable.

(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 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.

COMPARISON OF CUMULATIVE TOTAL RETURN

AMONG MAGNOLIA OIL AND GAS, THE S&P 500 INDEX,

AND THE S&P 500 OIL & GAS EXPLORATION AND PRODUCTION INDEX

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 four-year period ended December 31, 2018. The selected historical financial information of certain oil and natural gas assets previously owned by certain affiliates of EnerVest before being acquired by Magnolia in the Business Combination (the “Karnes County Business”) as of December 31, 2017, 2016, and 2015 and for the period from January 1, 2018 to July 30, 2018, the years ended December 31, 2017 and 2016, and the period from September 30, 2015 (the inception of the Karnes County Business) to December 31, 2015, was derived from the audited historical combined financial statements of the Karnes County Business. The selected historical financial information for the period from January 1, 2015 to September 30, 2015 was 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)	July 31, 2018 through December 31, 2018			January 1, 2018 through July 30, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016			September 30, 2015 to December 31, 2015		January 1, 2015 to September 30, 2015
Income Statement Data
Revenues	$	433,218		$	449,186		$	403,194		$	110,926		$	6,187	$	20,177
Operating expenses	319,260			211,382			213,183			82,067			5,432		23,031
Operating income	113,958			237,804			190,011			28,859			755		(2,854		)
Other income (expense)	(20,055		)	(17,466		)	(8,396		)	(6,715		)	1,558		(41		)
Income tax expense	11,455			1,785			2,741			673			58		32
Net income	82,448			218,553			178,874			21,471			2,255		(2,927		)
Net income attributed to noncontrolling interest	43,353			—			—			—			—		—
NET INCOME ATTRIBUTABLE TO CLASS A COMMON STOCK	$	39,095		$	218,553		$	178,874		$	21,471		$	2,255	$	(2,927	)
Basic	$	0.25
Diluted	$	0.25
Weighted average number of common shares outstanding
Basic	154,527
Diluted	158,232



	Successor		Predecessor
(in thousands)	December 31, 2018		December 31, 2017		December 31, 2016		December 31, 2015
Balance Sheet Data
Total assets	$	3,433,523	$	1,688,974	$	1,427,368	$	125,995
Long-term debt	388,635		—		—		—
Total equity	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 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 Magnolia’s consolidated and combined financial statements and the related notes thereto.

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.

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 Company and Magnolia Oil & Gas Parent LLC (“Magnolia LLC”), as applicable, consummated the previously announced 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; (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 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”).

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, 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 and the Ironwood Sellers received $25.0 million in cash.

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.” 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 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 period from January 1, 2018 to July 30, 2018 (the “2018 Predecessor Period”); the year ended December 31, 2017 (the “2017 Predecessor Period”); the year ended December 31, 2016 (the “2016 Predecessor Period”); and, together with the 2018 Predecessor Period and the 2017 Predecessor Period, (the “Predecessor Period”); and the period on and after the consummation of the Business Combination, which is from the Closing Date to December 31, 2018 (the “Successor Period”).

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. 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 formation.

As of December 31, 2018, Magnolia's assets included 16,841 net acres in Karnes County and 439,123 net acres in the Giddings Field. As of December 31, 2018, Magnolia had 1,458 gross operated wells (1,046 net) with total production of 61.9 Mboe/d in the fourth quarter of 2018. In the fourth quarter ended December 31, 2018, Magnolia operated three drilling rigs across its acreage, with two rigs in Karnes County and one rig in the Giddings Field, and brought 14 gross operated horizontal wells on production.

Magnolia reported net income attributable to Class A common stock of $39.1 million, or $0.25 per diluted common share, for the Successor Period. Magnolia reported net income of $82.4 million which includes noncontrolling interest of $43.4 million related to the Class B Common Stock issued to certain affiliates of EnerVest in connection with the Business Combination. As of December 31, 2018, the noncontrolling interest ownership was 37.4%. Net income attributable to Class A Common Stock for the Successor Period includes the one-time transaction costs of $24.3 million incurred in connection with the Business Combination as well as federal income tax expense of $10.4 million.

Results of Operations

Factors Affecting the Comparability of the Historical Financial Results

The Successor Period financial statements reflect a new basis of accounting for the assets and liabilities acquired by the Company in the Business Combination that is based on the fair value of the assets acquired and liabilities assumed. As a result, the statements 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 Interest, 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 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 oil and gas assets from GulfTex Karnes EFS, LP on April 27, 2016, BlackBrush Karnes Properties, LLC on July 6, 2016, the subsequent acquisition of certain assets from BlackBrush Karnes Properties, LLC on January 31, 2017, and the Subsequent GulfTex Assets from GulfTex Energy III, L.P. and GulfTex Energy IV, L.P. on March 1, 2018 each during the Predecessor Period, and accordingly the results of operations of the Predecessor reflect the impact of the assets acquired in such acquisitions only from their respective acquisition date;

•

As a corporation, the Company is subject to federal income taxes at a statutory rate of 21% of pretax earnings whereas the Karnes County Contributors elected to be treated as individual partnerships for tax purposes. As a result, 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 is included in the financial statements of the Predecessor; and

•

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 newly issued 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.

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, 2018 Compared to the Years Ended December 31, 2017 and December 31, 2016

Oil, Natural Gas and NGL 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 6 Mcf to 1 barrel. This ratio is not reflective of the current price ratio between the two products.



	Successor		Predecessor
(in thousands, except per unit data)	July 31, 2018 through December 31, 2018		January 1, 2018 through July 30, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
PRODUCTION VOLUMES:
Oil (MBbls)	5,078		5,755		7,154		2,314
Natural gas (MMcf)	14,136		7,595		8,579		2,876
NGLs (MBbls)	1,857		1,097		1,287		406
Total (Mboe)	9,291		8,118		9,871		3,199

Average daily production volume:
Oil (Bbls/d)	33,190		27,146		19,600		6,322
Natural gas (Mcf/d)	92,392		35,825		23,504		7,858
NGLs (Bbls/d)	12,137		5,175		3,526		1,109
Total (Boe/d)	60,725		38,292		27,044		8,740

REVENUES:
Oil revenues	$	342,093	$	399,124	$	350,204	$	97,125
Natural gas revenues	42,979		22,135		25,916		7,677
Natural gas liquids revenues	48,146		27,927		27,074		6,124
Total revenues	$	433,218	$	449,186	$	403,194	$	110,926

AVERAGE PRICE:
Oil (per barrel)	$	67.37	$	69.35	$	48.95	$	41.97
Natural gas (per Mcf)	3.04		2.91		3.02		2.67
NGLs (per barrel)	25.93		25.46		21.04		15.08

Oil revenues were 79%, 89%, 87%, and 88% of the Company’s total revenues for the Successor Period, the 2018 Predecessor Period, 2017 Predecessor Period, and 2016 Predecessor Period, respectively. Oil production was 55%, 71%, 72%, and 72% of total production volume for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. Total oil revenues for the combined Successor Period and 2018 Predecessor Period increased $391.0 million compared to the 2017 Predecessor Period due to higher average prices and higher production. Higher realized oil prices in 2018 contributed 36% of the oil revenue difference. Oil production increased by 3,679 MBbls, or 51%, due to the inclusion of the Giddings Assets, recent acquisitions, and continued development in 2018. Oil revenues for the 2017 Predecessor Period were higher than for the 2016 Predecessor Period by $253.1 million due to higher average prices and production. Higher realized oil prices in 2017 contributed 6% of the oil revenue difference. Oil production increased by 4,840 MBbls, or 209% due to the Subsequent BlackBrush acquisition and other development activities. Oil production as a percentage of total production volumes for the Successor Period was lower than the Predecessor Periods primarily due to the inclusion of the results from the heavily gas-weighted Giddings Assets during the Successor Period.

Natural gas revenues were 10%, 5%, 6%, and 7% of the Company’s total revenues for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. Natural gas production was 25%, 16%, 15%, and 15% of total production volume for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. The total natural gas revenues for the combined Successor Period and 2018 Predecessor Period increased by $39.2 million compared to the 2017 Predecessor Period due to an increase in production. Natural gas production was 13,152 MMcf, 153% higher for the combined Successor and 2018 Predecessor Period, due to the inclusion of the Giddings Assets, recent acquisitions, and continued development in 2018. Natural gas revenues for the 2017 Predecessor Period were $18.2 million higher than for the 2016

Predecessor Period due to higher average prices and increased production. Higher realized natural gas prices in 2017 contributed 6% of the natural gas revenue difference. Natural gas production increased by 5,703 MMcf, or 198%, due to the Subsequent BlackBrush acquisition and other development activities. Natural gas production as a percentage of total production volumes for the Successor Period was higher than the Predecessor Periods primarily due to the inclusion of the results from the heavily gas-weighted Giddings Assets during the Successor Period.

Natural gas liquid revenues were 11%, 6%, 7%, and 6% of the Company’s total revenues for the Successor Period, the 2018 Predecessor Period, 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. NGL production was 20%, 14%, 13%, and 13% of total production volume for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. The $49.0 million increase in NGL revenues for the combined Successor Period and 2018 Predecessor Period compared to the 2017 Predecessor Period is due to higher average prices and production. Higher realized NGL prices in 2018 contributed 12% of the NGL revenue difference. NGL production was 1,667 MBbls, 130% higher for the combined Successor and 2018 Predecessor Period due to the inclusion of the Giddings Assets, recent acquisitions, and continued development in 2018. NGL revenues for the 2017 Predecessor Period were $21.0 million higher than for the 2016 Predecessor Period due to higher average prices and production. Higher realized NGL prices in 2017 contributed 12% of the NGL revenue difference. NGL production increased by 881 MBbls, or 217%, due to the Subsequent BlackBrush acquisition and other development activities.

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)	July 31, 2018 through December 31, 2018			January 1, 2018 through July 30, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
OPERATING EXPENSES:
Lease operating expenses	$	30,753		$	23,513		$	27,520		$	11,638
Gathering, transportation and processing	14,445			12,929			16,259			5,484
Taxes other than income	23,170			23,763			20,193			6,448
Exploration expenses	11,882			492			700			13,123
Asset retirement obligations accretion	1,668			104			232			94
Depreciation, depletion and amortization	177,890			137,871			129,711			33,123
Amortization of intangible assets	6,044			—			—			—
General & administrative expenses	28,801			12,710			18,568			12,157
Transaction related costs	24,607			—			—			—
Total operating costs and expenses	$	319,260		$	211,382		$	213,183		$	82,067

OTHER INCOME (EXPENSE):
Income from equity method investee	$	773		$	711		$	113		$	—
Interest expense	(12,454		)	—			—			—
Loss on derivatives, net	—			(18,127		)	(8,488		)	(6,717		)
Other income (expense), net	(8,374		)	(50		)	(21		)	2
Total other income (expense)	$	(20,055	)	$	(17,466	)	$	(8,396	)	$	(6,715	)

AVERAGE OPERATING COSTS PER BOE:
Lease operating expenses	$	3.31		$	2.90		$	2.79		$	3.64
Gathering, transportation and processing	1.55			1.59			1.65			1.71
Taxes other than income	2.49			2.93			2.05			2.02
Exploration costs	1.28			0.06			0.07			4.10
Asset retirement obligation accretion	0.18			0.01			0.02			0.03
Amortization of intangible assets	0.65			—			—			—
Depreciation, depletion and amortization	19.15			16.98			13.14			10.35
General and administrative expenses	3.10			1.57			1.88			3.80
Transaction related costs	2.65			—			—			—

Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and certain workover costs and include expenses for utilities, direct labor, water disposal, workover rigs, and workover expenses, materials and supplies. Lease operating expenses were $30.8 million, $23.5 million, $27.5 million, and $11.6 million for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. Lease operating expenses were $3.31 per boe, $2.90 per boe, $2.79 per boe, and $3.64 for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. The increase in cost per boe in the combined Successor Period and 2018 Predecessor Period compared to the 2017 Predecessor Period was primarily attributable to the Successor’s inclusion of the Giddings Assets as the Giddings Assets deliver less production per well than the newer Karnes County wells, resulting in lease operating costs spread over fewer volumes. The decrease in cost per boe in the 2017 Predecessor Period compared to the 2016 Predecessor Period was due to certain items, such as direct labor and materials and supplies, generally remaining relatively fixed across broad production volume ranges.

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 natural gas liquids produced as well as the cost of commodity processing. Gathering, transportation and processing costs were $14.4 million, $12.9 million, $16.3 million, and $5.5 million for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. Gathering,

transportation and processing costs were $1.55 per boe, $1.59 per boe, $1.65 per boe, and $1.71 per boe for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. The decrease in cost per boe in the combined Successor Period and 2018 Predecessor Period compared to the 2017 Predecessor Period was primarily attributable to the adoption of Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASC 606”), which resulted in an equal and offsetting reduction to both revenues and gathering, transportation and processing expenses. The decrease in cost per boe in the 2017 Predecessor Period compared to the 2016 Predecessor Period was primarily due to increased production from drilling successful wells in the Eagle Ford Shale.

Taxes other than income include production, ad valorem taxes, and franchise taxes. These taxes are based on rates established by federal, 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. Taxes other than income were $23.2 million, $23.8 million, $20.2 million, and $6.4 million for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. The higher taxes other than income incurred during the combined Successor Period and 2018 Predecessor Period are primarily due to higher production taxes coupled with higher ad valorem taxes. The higher taxes other than income incurred during the 2017 Predecessor Period compared to the 2016 Predecessor Period was primarily attributable to the impact of the Initial GulfTex, Initial BlackBrush, and Subsequent BlackBrush Acquisitions during 2016 and early 2017 as well as increased production from drilling successful wells in the Eagle Ford Shale. Taxes other than income were $2.49 per boe, $2.93 per boe, $2.05 per boe, and $2.02 per boe for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively.

Exploration costs are geological and geophysical costs that include seismic surveying costs, costs of unsuccessful exploratory dry holes and lease abandonment, and delay rentals. Exploration expenses increased in the combined Successor Period and 2018 Predecessor Period from the 2017 Predecessor Period and 2016 Predecessor Period. The higher exploration costs during the Successor Period are primarily due to the Company incurring $11.0 million in exploration expense in the Successor Period related to the purchase of seismic license continuation in connection with the Business Combination. The $12.4 million reduction in exploration costs from the 2016 Predecessor Period to the 2017 Predecessor Period was primarily due to higher cost in 2016 related to the Initial BlackBrush Acquisition.

Asset retirement obligation accretion increased during the combined Successor Period and 2018 Predecessor Period as compared to the 2017 Predecessor Period and the 2016 Predecessor Period. The higher asset retirement obligation accretion incurred during the Successor Period was driven by the inclusion of the Giddings Assets in the Successor Period. This resulted in higher accretion expense of $0.18 per boe in the Successor Period, as compared to $0.01 per boe, $0.02 per boe, and $0.03 per boe for the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively.

Depreciation, depletion and amortization (“DD&A”) was $177.9 million, $137.9 million, $129.7 million, and $33.1 million for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and 2016 Predecessor Period, respectively. DD&A was $19.15 per boe for the Successor Period as compared to $16.98 per boe, $13.14 per boe, and $10.35 per boe for the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. The higher rate per boe for the Successor Period is 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 and an increase in production volumes as well as a decrease in proved reserves. The higher rate per boe for the 2017 Predecessor Period compared to the 2016 Predecessor Period was primarily due to the impact of the Initial GulfTex, Initial BlackBrush, and Subsequent BlackBrush Acquisitions during 2016 and early 2017.

The amortization of intangible assets was $6.0 million for the Successor Period. In connection with the close of the Business Combination, the Company recorded an estimated cost of $44.4 million for the Non-Compete Agreement (the “Non-Compete”) entered into with EnerVest on the Closing Date as an intangible asset on the consolidated balance sheet of the Successor. This intangible asset has a definite life and is subject to amortization utilizing the straight-line method over its economic life, currently estimated to be two and one half to four years. There was no amortization of intangible assets in any of the Predecessor Periods.

General and administrative ("G&A") expenses for the Successor Period are costs primarily related to the Services Agreement (the "Services Agreement") with EVOC, and also include costs incurred for overhead, including payroll and benefits for corporate staff, costs of maintaining a headquarters, IT expenses, and audit and other fees for professional services, including legal compliance expenses. G&A expenses were $28.8 million, $12.7 million, $18.6 million, and $12.2 million for the Successor Period, the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively. The higher G&A expenses incurred during the Successor Period are due to fees payable to EVOC under the Services Agreement as well as corporate payroll expenses. The EVOC Services Agreement covers services provided for the Karnes County Business and the Giddings Assets, relative to the G&A expenses only relating to Karnes County Business in the Predecessor Periods. EVOC provides the Company's day-to-day field-level and back office operations and support for the operation and development of the assets, subject to certain exceptions. Magnolia incurred general and administrative fees of $13.7 million for the Successor Period as consideration for the services provided under the Services Agreement as well as industry

standard per well overhead payments. The higher G&A expenses incurred during the 2017 Predecessor Period compared to the 2016 Predecessor Period were due to G&A expenses being higher as a result of the Initial GulfTex Acquisition and the Initial BlackBrush Acquisition in 2016 and the Subsequent BlackBrush Acquisition in 2017.

Transaction related costs incurred during the Successor Period were $24.6 million. Transaction related 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.

Interest expense was $12.5 million for the Successor Period. Interest expense incurred in the 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 senior secured reserve-based revolving credit facility (the “RBL Facility”) entered into in connection with the Business Combination.

Loss on derivatives, net, was $18.1 million for the 2018 Predecessor Period as compared with a loss of $8.5 million and loss of $6.7 million for the 2017 Predecessor Period and 2016 Predecessor Period, respectively. This change was attributable to unfavorable hedging positions during the 2018 Predecessor Period and the extinguishment of all of the derivative contracts in July 2018. The Company did not have any hedging arrangements during the Successor Period.

Other expense of $8.4 million in the Successor Period included a loss of $6.7 million related to the difference in fair market value of the Giddings 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 issuances of equity and debt securities and cash flows from operations. The Company’s primary uses of cash have been 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, net cash flows generated from operations, and borrowings under the RBL Facility will be adequate to fund Magnolia’s capital budget 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, 2018, the Company had $400.0 million of the 2026 Senior Notes outstanding and no outstanding borrowings related to the Company’s RBL Facility. As of December 31, 2018, the Company has $685.8 million of liquidity between the $550.0 million of borrowing base capacity and $135.8 million cash on hand. As of December 31, 2018, 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 $3.0 billion. Magnolia’s next borrowing base redetermination is April 1, 2019.

For additional information about the Company's long-term debt, such as interest rates and covenants, please see Note 9 - Long Term Debt (Successor) contained herein.

Cash

At December 31, 2018, Magnolia had $135.8 million of cash. The Company’s cash is maintained with a major financial institution in the United States. Deposits with this financial institution may exceed the amount of insurance provided on such deposits, however, the Company regularly monitors the financial stability of this financial institution and believes that it is not exposed to any significant default risk.

Sources and Uses of Cash

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



	Successor			Predecessor
(in thousands)	July 31, 2018 through December 31, 2018			January 1, 2018 through July 30, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
Net cash provided by operating activities	$	305,470		$	284,812		$	257,371		$	30,458
Net cash used in investing activities	(877,640		)	(347,453		)	(314,417		)	(1,249,421		)
Net cash provided by financing activities	707,905			62,641			57,046			1,218,963

Operating Activities

Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the 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 non-cash expenses such as DD&A, asset impairments, asset retirement obligation accretion expense, and deferred income tax expense. Net cash provided by operating activities was $305.5 million and $284.8 million for the Successor Period and the 2018 Predecessor Period, respectively. Net cash provided by operations for the Successor Period included oil and gas revenues reduced by one-time transaction costs of $24.6 million associated with the Business Combination and the Harvest Acquisition and exploration expense of $11.0 million associated with a one-time purchase of a seismic license and other operating expenditures. Net cash provided by operating activities was $257.4 million for 2017, compared to $30.5 million of net provided by operations for 2016. Production increased 6.7 MMboe (approximately 209%) and average realized sales prices increased to $40.85 per boe for 2017 compared to $34.68 per boe during 2016.

Investing Activities

Cash used in investing activities was approximately $877.6 million in the Successor Period which included cash paid to effect the Business Combination of approximately $1.2 billion, $146.5 million for other acquisitions, a $26.0 million payment to the Giddings Sellers to fully settle an earnout agreement, and capital expenditures for oil and gas properties, which were partially offset by proceeds withdrawn from the trust account the Company maintained prior to the Business Combination of approximately $656.1 million. Cash used in investing activities was $347.5 million, $314.4 million, and $1.2 billion for the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively, and was comprised primarily of capital expenditures for property and equipment of approximately $197.3 million, $247.4 million, and $26.0 million. Acquisitions of oil and gas properties for the 2018 Predecessor Period, 2017 Predecessor Period, and 2016 Predecessor Period were approximately $150.1 million, $58.7 million, and $1.2 billion respectively. The decrease in cash used in investing activities between the 2017 Predecessor Period and the 2016 Predecessor Period is due to higher acquisition activity in 2016 related to the Initial GulfTex Acquisition and the Initial BlackBrush Acquisition.

Financing Activities

Cash provided by financing activities was $707.9 million in the Successor Period. Proceeds provided by the issuance of Class A Common Stock of approximately $355.0 million and proceeds from offering of the 2026 Senior Notes of $400.0 million were partially offset by cash payments of approximately $22.8 million for deferred underwriting compensation and $23.3 million for debt issuance costs. Cash provided by financing activities was $62.6 million, $57.0 million, and $1.2 billion for the 2018 Predecessor Period, the 2017 Predecessor Period, and the 2016 Predecessor Period, respectively, and was comprised of net effect of parents’ contribution and distributions.

Contractual Obligations and Commitments

As of December 31, 2018, amounts due under the Company’s contractual commitments were as follows:



Contractual Obligations (in thousands)	Total		Less than 1 Year		2020-2021		2022-2023		More than 5 years
On-Balance Sheet:
Debt, at face value	$	400,000	$	—	$	—	$	—	$	400,000
Interest payments⁽¹⁾	201,585		26,158		52,188		51,306		71,933
Off-Balance Sheet:
Purchase obligation ⁽²⁾	4,821		3,601		847		263		110
Operating lease obligations ⁽³⁾	1,817		881		844		29		63
Service fee commitment ⁽⁴⁾	37,309		23,564		13,745		—		—
Drilling rigs	7,201		7,201		—		—		—
Total Contractual Obligations	$	652,733	$	61,405	$	67,624	$	51,598	$	472,106


(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 frac sand commitments.


(3)	Amounts include long-term lease payments for compressors, vehicles and office space.

(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 five years, but the Services Agreement is subject to termination by either party after two years.

Off-Balance Sheet Arrangements

Magnolia enters into customary agreements in the oil and gas industry for field equipment, vehicles, and other obligations as described below in “Contractual Obligations” in this Item 2. Other than the off-balance sheet arrangements described herein, Magnolia does not have any off-balance sheet arrangements with unconsolidated entities that are reasonably likely to materially affect the Company’s liquidity or capital resource positions.

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.

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 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. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

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

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 and liabilities and tax-related carryforwards at the acquisition 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 as described above in “Reserve Estimates” of this Item 7. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future.

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 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 did not record a proved property impairment in the Successor Period ended December 31, 2018 or Predecessor Periods ended December 31, 2017 and December 31, 2016. 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 Magnolia's RBL Facility. Interest on borrowings under the RBL Facility is based on adjusted LIBOR plus or base rate plus an applicable margin as stated in the agreement. At December 31, 2018, the Company had no borrowings outstanding under Magnolia’s RBL Facility.

Magnolia's 2026 Senior Notes bear interest at a fixed rate and fair value will fluctuate based on changes in prevailing market interest rates and market perceptions of the Company's credit risk. The fair value of Magnolia's 2026 Senior Notes was approximately $387.0 million at December 31, 2018, compared to the carrying value of $388.6 million.

Commodity Price Risk

The Company has not engaged in hedging activities since inception. Magnolia does not expect to engage in any hedging activities with respect to the market risk to which the Company is exposed.

Magnolia's primary market risk exposure is to the prices it receives for its oil, natural gas, and NGL production. Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot market prices for natural gas production. Pricing for oil, natural gas, and NGLs has been volatile and unpredictable for several years, and the Company expects this volatility 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 Successor Period would have increased (decreased) the Company’s revenues by approximately $12.2 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the Successor Period would have increased (decreased) Magnolia’s revenues by approximately $3.4 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 sheet of Magnolia Oil & Gas Corporation (formerly TPG Pace Energy Holdings Corp.) (the Company) as of December 31, 2018, the related consolidated statements of operations, stockholders’ equity, and cash flows 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, 2018, and the results of its operations and its cash flows for the period from July 31, 2018 to December 31, 2018 (Successor Period), in conformity with U.S. generally accepted accounting principles.

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 audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our 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 the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit 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 audit 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 audit provide a reasonable basis for our opinion.

/s/ KPMG

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

Houston, Texas

February 27, 2019

F-1

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 balance sheet 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), as of December 31, 2017, the related combined statements of operations, changes in parents’ net investment, and cash flows for the period from January 1, 2018 to July 30, 2018, and for the years ended December 31, 2017 and 2016, 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 financial position of the Karnes County Business as of December 31, 2017, and the results of its operations and its cash flows for the period from January 1, 2018 to July 30, 2018 and for the years ended December 31, 2017 and 2016, 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, financial position 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.

F-2

Magnolia Oil & Gas Corporation

Consolidated and Combined Balance Sheets

(in thousands)



	Successor December 31, 2018			Predecessor December 31, 2017
ASSETS
CURRENT ASSETS:
Cash	$	135,758		$	—
Accounts receivable	140,284			100,512
Accounts receivable - related party	—			13,692
Drilling advances	12,259			—
Other current assets	4,058			332
Total current assets	292,359			114,536
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties	3,250,742			1,731,696
Other	360			—
Accumulated depreciation, depletion and amortization	(177,898		)	(166,159		)
Total property, plant and equipment, net	3,073,204			1,565,537
OTHER ASSETS
Deferred financing costs, net	10,731			—
Equity method investment	18,873			8,901
Intangible assets, net	38,356			—
TOTAL ASSETS	$	3,433,523		$	1,688,974

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	196,357		$	74,536
Asset retirement obligations	1,004			—
Derivative liability	—			6,764
Total current liabilities	197,361			81,300
LONG-TERM LIABILITIES:
Long-term debt, net	388,635			—
Asset retirement obligations, net of current	84,979			3,929
Long-term derivative liability	—			3,052
Deferred taxes, net	54,593			2,724
Other long term liabilities	—			131
Total long-term liabilities	528,207			9,836

COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS’ EQUITY
Class A Common stock, $0.0001 par value, 1,300,000 shares authorized, 156,333 shares issued and outstanding	16			—
Class B Common stock, $0.0001 par value, 225,000 shares authorized, 93,346 shares issued and outstanding	9			—
Additional paid-in capital	1,641,237			—
Retained earnings	35,507			—
Noncontrolling interest	1,031,186			—
PARENTS’ NET INVESTMENT	—			1,597,838
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,433,523		$	1,688,974

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

F-3

Magnolia Oil & Gas Corporation

Consolidated and Combined Statements of Operations

(in thousands, except per share data)



	Successor			Predecessor
	July 31, 2018 through December 31, 2018			January 1, 2018 through July 30, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
REVENUES:
Oil revenues	$	342,093		$	399,124		$	350,204		$	97,125
Natural gas revenues	42,979			22,135			25,916			7,677
Natural gas liquids revenues	48,146			27,927			27,074			6,124
Total revenues	433,218			449,186			403,194			110,926

OPERATING EXPENSES
Lease operating expenses	30,753			23,513			27,520			11,638
Gathering, transportation and processing	14,445			12,929			16,259			5,484
Taxes other than income	23,170			23,763			20,193			6,448
Exploration expense	11,882			492			700			13,123
Asset retirement obligation accretion	1,668			104			232			94
Depreciation, depletion and amortization	177,890			137,871			129,711			33,123
Amortization of intangible assets	6,044			—			—			—
General and administrative expenses	28,801			12,710			18,568			12,157
Transaction related costs	24,607			—			—			—
Total operating costs and expenses	319,260			211,382			213,183			82,067

OPERATING INCOME	113,958			237,804			190,011			28,859

OTHER INCOME (EXPENSE):
Income from equity method investee	773			711			113			—
Interest expense	(12,454		)	—			—			—
Loss on derivatives, net	—			(18,127		)	(8,488		)	(6,717		)
Other income (expense), net	(8,374		)	(50		)	(21		)	2
Total other income (expense)	(20,055		)	(17,466		)	(8,396		)	(6,715		)

INCOME BEFORE INCOME TAXES	93,903			220,338			181,615			22,144
Income tax expense	11,455			1,785			2,741			673
NET INCOME	82,448			218,553			178,874			21,471
LESS: Net income attributable to noncontrolling interest	43,353			—			—			—
NET INCOME ATTRIBUTABLE TO CLASS A COMMON STOCK	$	39,095		$	218,553		$	178,874		$	21,471

NET INCOME PER COMMON SHARE
Basic	$	0.25
Diluted	$	0.25
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic	154,527
Diluted	158,232

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

F-4

Magnolia Oil & Gas Corporation

Combined Statement of Changes in Parents’ Net Investment

(in thousands)



	Predecessor
BALANCE, JANUARY 1, 2016	$	121,484
Parents’ contribution, net	1,218,963
Net income	21,471
BALANCE, DECEMBER 31, 2016	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.

F-5

Magnolia Oil & Gas Corporation

Consolidated Statements of Changes in Stockholders’ Equity (Successor)

(in thousands)



	Class A Common Stock				Class B Common Stock			Class F Common Stock					Additional Paid-in Capital			Accumulated Deficit/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 the 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
Class A Common Stock issuance in private placement	35,500		4		—	—		—		—			354,996			—			355,000			—			355,000
Earnout consideration issued as part of 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	—		—		—			—			—			—			—			—
Issuance of shares in connection with the 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.

F-6

Magnolia Oil & Gas Corporation

Consolidated and Combined Statements of Cash Flows (in thousands)



	Successor			Predecessor
	July 31, 2018 through December 31, 2018			January 1, 2018 through July 30, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	82,448		$	218,553		$	178,874		$	21,471
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	177,890			137,871			129,711			33,123
Amortization of intangible assets	6,044			—			—			—
Exploration expense, non-cash	567			—			—			—
Asset retirement obligations accretion expense	1,668			104			232			94
Amortization of deferred financing costs	1,461			—			—			—
Non-cash interest expense	10,085			—			—			—
(Gain) loss on derivatives, net	—			18,127			8,488			6,717
Cash settlements of matured derivative contracts	—			(27,617		)	(1,097		)	(3,178		)
Deferred taxes	12,128			324			2,052			615
Contingent consideration change in fair value	6,700			—			—			—
Stock based compensation	1,851			—			—			—
Other	(773		)	(796		)	(397		)	2
Changes in assets and liabilities:
Account receivable	(50,610		)	(61,405		)	(70,822		)	(20,358		)
Prepaid expenses and other assets	(2,551		)	—			—			—
Accounts payable and accrued liabilities	68,929			36			10,522			(8,092		)
Drilling advances	(9,559		)	—			—			—
Other assets and liabilities, net	(808		)	(385		)	(192		)	64
Net cash provided by (used in) operating activities	305,470			284,812			257,371			30,458
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds withdrawn from trust account	656,078			—			—			—
Acquisition of EnerVest properties	(1,219,217		)	—			—			—
Acquisitions, other	(146,532		)	(150,139		)	(58,653		)	(1,223,458		)
Additions to oil and gas properties	(141,619		)	(197,314		)	(247,426		)	(25,963		)
Purchase of and contributions to equity method investment	—			—			(8,338		)	—
Payment of contingent consideration	(26,000		)	—			—			—
Other investing	(350		)	—			—			—
Net cash used in investing activities	(877,640		)	(347,453		)	(314,417		)	(1,249,421		)
CASH FLOW FROM FINANCING ACTIVITIES:
Parents’ contribution, net	—			62,641			57,046			1,218,963
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		)	—			—			—
Other financing activities	(1,009		)	—			—			—
Net cash provided by financing activities	707,905			62,641			57,046			1,218,963
NET CHANGE IN CASH AND CASH EQUIVALENTS	135,735			—			—			—
CASH AND CASH EQUIVALENTS – Beginning of period	23			—			—			—
CASH AND CASH EQUIVALENTS – End of period	$	135,758		$	—		$	—		$	—

F-7



SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for income taxes	$	—	$	336	$	43	$	—
Cash paid for interest	889		—		—		—
Supplemental non-cash investing and financing activity
Accruals or liabilities for capital expenditures	50,633		38,028		53,274		51,435
Contributions of assets to purchase equity method investment	—		—		450		—
Contingent consideration issued in Business Combination	149,700		—		—		—
Non-compete	44,400		—		—		—
Equity issuances in connection with business combinations	1,481,692		—		—		—

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

F-8

Magnolia Oil & Gas Corporation

Notes to Consolidated and Combined Financial Statements

1. Description of Business and Basis of Presentation

Organization and General

Magnolia Oil & Gas Corporation (formerly TPG Pace Energy Holdings Corp.) (the “Company” or “Magnolia”) was incorporated in Delaware on February 14, 2017 (“Inception”).

On March 15, 2018, the Company formed three indirect 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 three entities are Delaware limited liability companies and were 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 previously announced 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, Ltd. (the “Giddings Sellers”); and

•

a 35% membership interest (the “Ironwood Interests” and together with the Karnes County Assets and the Giddings Assets, the “Acquired Assets”) 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 (the “Ironwood MIPA” and, 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”) and, together with the Karnes County Contributors and the Giddings Sellers, (the “Sellers”).

The Company consummated the Business Combination for 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”), and 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 Notes were used to fund a portion of the cash consideration required to effect the Business Combination.

Business Operations and Strategy

Magnolia is an independent oil and natural gas company engaged in the acquisition, development, exploration, and production of oil, natural gas, and 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 primarily 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.

F-9

Basis of Presentation

As a result of the Business Combination, the Company is the acquirer for accounting purposes and the Karnes County Business, the Giddings Assets, and the Ironwood Interests are the acquirees. The Karnes County Business, including as applicable, its ownership of the Ironwood Interests, was deemed the Predecessor (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 are managed by the same managing general partner, EnerVest, and as such, these Predecessor financial statements have been presented on a combined basis for financial reporting purposes.

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, the 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 utilize 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 Contribution. As such, the net results of the cash transactions between the Karnes County Business and the Karnes County Contributors are reflected as Parents’ Net Investment in the accompanying Predecessor balance sheet.

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, provides 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 properties that were not part of the Contribution. 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 years ended December 31, 2016 and 2017, and the period from January 1, 2018 to July 30, 2018.

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 Contribution, on a combined basis. The commodity derivative activity was allocated to the Karnes County Business using a ratio of expected crude oil and condensate, natural gas liquids (“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 years ended December 31, 2016 and 2017, and the period from January 1, 2018 to July 30, 2018.

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/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.

F-10

For the period 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 Successor (the “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 period from January 1, 2018 to July 30, 2018 (the “2018 Predecessor Period”), the year ended December 31, 2017 (the “2017 Predecessor Period”), the year ended December 31, 2016 (the “2016 Predecessor Period”); and together with the 2018 Predecessor Period and the 2017 Predecessor Period, (the “Predecessor Period”); and the period on and after the consummation of the Business Combination, which is from July 31, 2018 to December 31, 2018 (the “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 accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and in accordance with the rules and regulations of the SEC.

2. Summary of Significant Accounting Policies

Principles of Consolidation (Successor)

The consolidated financial statements have been prepared in accordance with U.S. 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 10—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, 2018, the Company had an approximate 62.6% economic interest in Magnolia LLC and 100% of Magnolia LLC’s assets and liabilities and results of operations are consolidated in the Company’s consolidated financial statements contained herein. At December 31, 2018, the Karnes County Contributors had approximately 37.4% 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 10—Stockholders’ Equity for further discussion of noncontrolling interest.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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.

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, 2018 (Successor), or December 31, 2017 (Predecessor).

F-11

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 utilizes 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.

F-12

Intangible Assets (Successor)

Concurrent with the closing of the Business Combination, the Company and EnerVest entered into a 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, 2018, 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.

F-13

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 years ended December 31, 2017 or December 31, 2016. 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 years ended December 31, 2017 and December 31, 2016. 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 natural gas liquids 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 statements of operations.

Purchase Price Allocation

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 and 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 14 - 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.

F-14

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 generally accepted accounting principles in the United States. 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. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. Effective December 31, 2018, the Company ceased to be an emerging growth company and adopted ASC 606 for the Successor Period, using a modified retrospective approach.

There were no significant changes to the timing of revenue recognized for sales of production. However, the adoption of 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. These 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 (MMBtu) 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.

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’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. All 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 significant 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 $100.1 million as of December 31, 2018 and $89.7 million as of July 31, 2018. Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts.

The Company has concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenues 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.

The Company does not disclose the value of unsatisfied performance obligations for contracts as all contracts are either with 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.

F-15

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, performance-based stock units, warrants for Class A Common Stock and exchanges of Class B Common Stock if the inclusion of these items is dilutive. Refer to Note 12 - 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 that includes granting restricted stock units ("RSUs") and performance stock units ("PSUs"). Stock based compensation awards granted are valued on the date of grant using the quoted market price of Magnolia's Class A Common Stock and 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 is included within general and administrative expense in the accompanying consolidated 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 11- Stock Based Compensation.

Recent Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which will require 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. Currently the guidance would be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. However, 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. This standard is effective in the first quarter of 2019 and will be applied using the optional transition method provided by ASU 2018-11. The Company plans to elect the practical expedients provided in the standard that allow entities to not reassess under the new standard the Company’s prior conclusions about lease identification and classification related to contracts that commenced prior to adoption and allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. The Company also intends to elect a policy to not recognize right of use assets and lease liabilities related to short-term leases.

The Company has determined its portfolio of leased assets and is completing its review of all related contracts to determine the impact the adoption will have on its consolidated financial statements and related disclosures. Upon adoption, the Company will recognize right of use assets and lease liabilities for certain commitments related to real estate, vehicles, and field equipment that are currently accounted for as operating leases. To track these lease arrangements and facilitate compliance with this ASU, the Company has implemented a third-party lease accounting software solution and is in the process of designing processes and internal controls. The adoption of this ASU will increase asset and liability balances on the consolidated balance sheets due to the required recognition of right of use assets and corresponding lease liabilities, however, the overall financial impact to the consolidated financial statements is not expected to be material. The Company expects the adoption of this ASU to result in changes to the Company’s existing accounting policies, business processes, and internal controls.

In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows, Classification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017 for public companies and for fiscal years beginning after December 15, 2018 for all other entities. The Company ceased to be an emerging growth company on December 31, 2018 and adopted the standard on December 31, 2018. The adoption of this guidance did not impact the Company’s financial position or results of operations.

In January 2017, the FASB issued ASU 2017-01 "Business Combinations (Topic 805): Clarifying the Definition of a Business" ("ASU 2017-01"), which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for interim and annual periods after December 15, 2017 for public companies and annual periods beginning after December 15, 2018 for all other entities. No disclosures are required at transition. The Company early adopted ASU 2017-01 upon the closing of the Business Combination. There was no material impact to the Company's financial statements as a result of this adoption, however the new standard may result in more transactions being accounted for as acquisitions (and dispositions) of assets rather than businesses in the future.

F-16

3. Acquisitions

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; 31.8 million shares of Class A Common Stock; and approximately $911.5 million in cash. The sales price per the Karnes County Contribution Agreement was adjusted for customary purchase price adjustments to reflect the economic activity from the effective date of January 1, 2018 to June 30, 2018. The Company is entitled to an additional cash purchase price adjustment for the revenues after expenses (and other purchase price adjustments) attributable to the Acquired Assets from July 1, 2018 through July 31, 2018. The Giddings Sellers received approximately $282.7 million in cash, after customary purchase price adjustments. The Ironwood Sellers received $25.0 million in cash in exchange for the Ironwood Interests. The final adjustments to the respective purchase price agreements have not yet been made.

The Business Combination has been accounted for using the acquisition method. The acquisition method of accounting is based on ASC 805 “Business Combination” (“ASC 805”), 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 Class B Common Stock 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 for all three tranches as defined in the Karnes County Contribution Agreement and 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.

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. In conjunction with this payment, Magnolia recognized a loss of $6.7 million included in “Other income (expense)” in the consolidated and combined statements of operations.

The purchase consideration for the Business Combination was as follows:



(in thousands)	At July 31, 2018
Preliminary Purchase Consideration:
Cash consideration	$	1,219,217
Stock consideration ⁽¹⁾	1,423,483
Fair value of contingent earnout purchase consideration⁽²⁾	169,000
Total purchase price consideration	$	2,811,700


(1)	At closing of the Business Combination, the Karnes County Contributors received 83.9 million shares of Class B Common Stock and 31.8 million shares of Class A Common Stock.

(2)

Pursuant to ASC 805, ASC 480, “Distinguishing Liabilities from Equity” and ASC 815, “Derivatives and Hedging”, the Karnes County earnout consideration has been valued at fair value as of the Closing Date and has been classified in stockholders’ equity. The Giddings earnout has been valued at fair value as of the Closing Date and has been 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.

F-17

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



(in thousands)	At July 31, 2018
Estimated fair value of assets acquired
Accounts receivable	$	89,674
Other current assets	2,853
Oil and natural gas properties ⁽¹⁾	2,805,159
Ironwood equity investment	18,100
Total fair value of assets acquired	2,915,786
Estimated fair value of liabilities assumed
Accounts payable and other current liabilities	(56,315		)
Asset retirement obligations	(34,132		)
Deferred tax liability	(13,639		)
Fair value of net assets acquired	$	2,811,700

(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. These inputs required significant judgments and estimates by management at the time of the valuation and may be subject to change.

The total purchase consideration and the related purchase consideration allocation above are preliminary as the Company has not yet completed all the necessary fair value assessments, including the assessments of property, plant and equipment, intangible assets, contingent consideration, and the related tax impacts on these items. Any changes within the measurement period in the estimated fair values of the assets acquired, liabilities assumed, and the working capital adjustments may change the allocation of the purchase consideration. The fair value and related tax impact assessments are to be completed within twelve months of the Closing Date and could have a material impact on the components of the total purchase consideration and the purchase consideration allocation.

Transaction costs incurred by the Company associated with the Business Combination were $24.3 million for the Successor Period. 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.

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 up to 4,000,000 shares of Class A Common Stock issuable in two and half to four years provided EnerVest does not compete with Magnolia in the Eagle Ford Shale until the later of July 31, 2022 and the date the Services Agreement is terminated. For more discussion on the Non-Compete, refer to Note 6 - Intangible Assets.

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 $37.1 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.

F-18

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.



(in thousands)	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
Income per share - basic	$	1.22	$	0.54
Income per share - diluted	$	1.19	$	0.51

Harvest Acquisition

On August 31, 2018, the Company completed the acquisition to purchase substantially all of the South Texas assets of Harvest Oil & Gas Corporation for approximately $133.3 million in cash and 4.2 million newly issued shares of the Company’s 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.

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



(in thousands)	At August 31, 2018
Estimated fair value of assets acquired
Other current assets	$	1,290
Oil and natural gas properties ⁽¹⁾	200,035
Total fair value of assets acquired	201,325
Estimated fair value of liabilities assumed
Asset retirement obligations and other current liabilities	(9,812		)
Fair value of net assets acquired	$	191,513

(1)

The total purchase consideration and the related purchase consideration allocation above are preliminary as the Company has not yet completed all the necessary fair value assessments, including the assessments of property, plant and equipment. Any changes within the measurement period in the estimated fair values of the assets acquired and liabilities assumed and the working capital adjustments may change the allocation of the purchase consideration. The fair value assessments are to be completed within twelve months of the Closing Date and could have a material impact on the components of the total purchase consideration and the purchase consideration allocation.

Acquisitions (Predecessor)

Subsequent 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 “Subsequent GulfTex Acquisition”).

F-19

The recognized fair value of identifiable assets and acquired liabilities assumed in connection with the Subsequent 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

Subsequent 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 “Subsequent BlackBrush Acquisition”).

The recognized fair value of identifiable assets and acquired liabilities assumed in connection with the Subsequent 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

Initial BlackBrush Acquisition

On July 6, 2016, the Predecessor acquired certain assets from BlackBrush Karnes Properties, LLC for aggregate consideration of approximately $682.5 million. Subsequently during 2016, the Predecessor acquired additional working interests in the “the Initial BlackBrush Assets” from unrelated parties for aggregate consideration of approximately $45.5 million.



(in thousands)
Purchase price allocation:
Accounts receivable	$	4,387
Proved oil and natural gas properties	653,480
Unproved oil and natural gas properties	72,705
Accounts payable and accrued liabilities	(538		)
Asset retirement obligations	(2,051		)
	$	727,983

F-20

Initial GulfTex Acquisition

On April 27, 2016, the Predecessor acquired certain assets from GulfTex Karnes EFS, LP for aggregate consideration of approximately $495.5 million.



(in thousands)
Purchase price allocation:
Accounts receivable	$	12,252
Proved oil and natural gas properties	423,383
Unproved oil and natural gas properties	73,953
Accounts payable and accrued liabilities	(13,667		)
Asset retirement obligations	(446		)
	$	495,475

The Predecessor accounted for these acquisitions as business combinations. The assets acquired and the liabilities assumed have been measured at fair value based on various estimates. These estimates are based on key assumptions related to the business combination, including reviews of publicly disclosed information for other acquisitions in the industry, historical experience of the companies, data that was available through the public domain, and due diligence reviews of the acquired business. Any acquisition related transaction costs are not included as components of consideration transferred, but are accounted for as expenses in the period in which the costs are incurred.

The results of operations for these acquisitions are included in the Predecessor combined financial statements from the date of closing of each acquisition.

4. 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 natural gas liquids. As such, future earnings are subject to fluctuation due to changes in the market price of oil, natural gas and natural gas liquids. 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 natural gas liquids 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 “Loss on derivatives, net” in the combined statements of operations. 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 approximately $27.6 million.

F-21

The following table sets forth the fair values and classification of the outstanding derivatives entered into by the Karnes County Contributors, on behalf of the Predecessor, as of December 31, 2017:



(in thousands)	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivatives
As of December 31, 2017 (Predecessor):
Derivative asset	$	180	$	(180	)	$	—
Long-term derivative asset	48		(48		)	—
Total	$	228	$	(228	)	$	—

(in thousands)	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Liabilities Presented in the Balance Sheet
Derivatives
As of December 31, 2017 (Predecessor):
Derivative liability	$	6,944	$	(180	)	$	6,764
Long-term derivative liability	3,100		(48		)	3,052
Total	$	10,044	$	(228	)	$	9,816

The Predecessor entered into master netting arrangements with its counterparties. The amounts above are presented on a net basis in the Predecessor’s combined balance sheet when such amounts are with the same counterparty. In addition, the Predecessor has recorded accounts payable and receivable balances related to settled derivatives that are subject to the master netting agreements. These amounts are not included in the above table; however, under the master netting agreements, the Predecessor has the right to offset these positions against forward exposure related to outstanding derivatives.

5. 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. See Note 2 - Summary of Significant Accounting Policies for more information regarding the valuation hierarchy.

Fair Values - Recurring (Predecessor)

The Predecessor’s derivatives consisted of over-the-counter (“OTC”) contracts which 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 have been 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.

F-22

The following table presents the fair value hierarchy table for the Predecessor’s assets and liabilities that were required to be measured at fair value on a recurring basis:



(in thousands)	Level 1		Level 2		Level 3		Total Fair Value
As of December 31, 2017 (Predecessor):
Assets:
Oil, natural gas and natural gas liquids derivatives	$	—	$	228	$	—	$	228
Liabilities:
Oil, natural gas and natural gas liquids derivatives	$	—	$	10,044	$	—	$	10,044

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.

Debt Obligations

Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheet as of December 31, 2018 are as follows:



	December 31, 2018
(in thousands)	Carrying Value		Fair Value
Long-term debt	$	388,635	$	387,000

The fair value of the 2026 Senior Notes at December 31, 2018 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 Combination and asset retirement obligations.

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 and the date the Services Agreement is terminated. Under the Non-Compete, an affiliate of EnerVest will have the right to receive up to 4.0 million shares of Class A Common Stock, subject to the achievement of certain stock price thresholds that were met by October 4, 2018. The shares are issuable in two and one half to four years 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 consolidated balance sheet of the Successor. These intangible assets have a definite life and are subject to amortization utilizing the straight-line method over its 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 statement of operations. The Company’s estimated amortization expense related to the intangible assets will be $14.5 million in 2019, $14.5 million in 2020, $6.2 million in 2021, $3.2 million in 2022.

F-23



(in thousands)	December 31, 2018 (Successor)
Non-compete intangible assets	$	44,400
Accumulated amortization	(6,044		)
Intangible assets, net	$	38,356
Weighted average amortization (years)	3.25

7. Asset Retirement Obligations

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



	Successor			Predecessor
(in thousands)	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	$	—		$	3,929		$	2,421
Revisions to estimates	39,584			—			805
Liabilities incurred and assumed through acquisitions	44,897			553			774
Liabilities settled	(166		)	(85		)	(303		)
Accretion expense	1,668			104			232
Asset retirement obligations, end of period	$	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.

8. Income Taxes

The Company’s income tax provision (benefit) consisted of the following components:



	Successor			Predecessor
(in thousands)	July 31, 2018 through December 31, 2018			January 1, 2018 through July 30, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Current:
Federal	$	(1,054	)	$	—	$	—	$	—
State	381			1,461		689		58
	(673		)	1,461		689		58
Deferred:
Federal	11,431			—		—		—
State	697			324		2,052		615
	12,128			324		2,052		615
Total provision	$	11,455		$	1,785	$	2,741	$	673

The Company is subject to U.S. federal income tax as well as the margin tax in the state of Texas. No amounts have been accrued for income tax uncertainties or interest and penalties as of December 31, 2018. 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 is open to possible income tax examinations by its major taxing authorities since Inception.

F-24

A reconciliation of the statutory federal income tax expense to the income tax expense or benefit from continuing operations provided at December 31, 2018, is as follows:



	Successor			Predecessor
(in thousands)	July 31, 2018 through December 31, 2018			January 1, 2018 through July 30, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Income tax expense at the federal statutory rate	$	19,706		$	—	$	—	$	—
State income tax expense, net of federal income tax benefits	1,028			1,785		2,741		673
Noncontrolling interest in partnership	(9,103		)	—		—		—
Other	(176		)	—		—		—
Income tax expense	$	11,455		$	1,785	$	2,741	$	673

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



	Successor			Predecessor
(in thousands)	December 31, 2018			December 31, 2017
Deferred tax assets:
Net operating loss carryforwards	$	7,336		$	—
Capitalized transaction costs	6,677			—
Other assets	102			—
Total deferred tax assets	14,115			—
Deferred tax liabilities:
Investment in partnership	(63,110)			—
Oil and natural gas properties	(5,598)			(2,724		)
Other liabilities	—			—
Total deferred tax liabilities	(68,708)			(2,724		)

Net deferred tax asset (liabilities)	$	(54,593	)	$	(2,724	)

As of December 31, 2018, the Company had $34.9 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. 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. As of December 31, 2018, in part because the Company achieved cumulative pre-tax income, management determined that sufficient positive evidence exists as of December 31, 2018, to conclude that it is more likely than not that the deferred tax assets will be realized.

The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon the examination by the Internal Revenue Service or other governmental agency. As of December 31, 2018, the Company did not have any 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. The Company’s annual effective tax rate as of December 31, 2018 was 12.2%. The primary differences between the annual effective tax rate and the statutory rate of 21.0% were income attributable to noncontrolling interest, state taxes, and non-deductible expenses.

F-25

9. Long Term Debt (Successor)

The Company’s debt is comprised of the following:



(in thousands)	Successor December 31, 2018
Revolving credit facility	$	—
6.0% Senior Notes due 2026	400,000
Total long-term debt	400,000

Less: unamortized deferred financing cost	(11,365		)
Total debt, net	$	388,635

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 holdings, 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, 2018 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’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 adjusted 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 4.00 to 1.00 and, if the leverage ratio is in excess of 3.00 to 1.00, current ratio of 1.00 to 1.00. As of December 31, 2018, the Company was in compliance with all covenants (including the financial covenants) under the RBL Facility.

Deferred financing costs incurred in connection with securing the RBL Facility were $11.7 million which will be amortized on a straight-line basis over a period of five years and included in “Interest expense” in the Company’s consolidated statement of operations. During the Successor Period ended December 31, 2018, the Company recognized interest expense of $1.9 million, 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, 2018.

The Company did not have any outstanding borrowings under its RBL Facility as of December 31, 2018.

2026 Senior Notes

On the Closing Date, the Issuers closed the previously announced private offering of $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, 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. The Notes bear interest at the rate of 6.0% per annum, payable semi-annually in arrears on each February 1st and August 1st, commencing February 1, 2019.

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 Notes redeemed, plus a “make whole” premium on accrued and unpaid interest, if any, to, but excluding, the date of redemption.

Deferred financing costs incurred in connection with securing the 2026 Senior Notes were $11.8 million which were capitalized and will be amortized using the effective interest method over the term of the 2026 Senior Notes and included in “Interest expense” in the Company’s consolidated statement 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

F-26

December 31, 2018. During the Successor Period, the Company recognized interest expense of $10.5 million, related to the 2026 Senior Notes.

Affiliate Guarantors

All of the Company’s wholly owned subsidiaries are guarantors under the terms of its Senior Notes and RBL Facility. The parent guarantees may be released upon the request of Magnolia Operating. Magnolia’s consolidated financial statements reflect the financial position of these subsidiary guarantors. As the parent company, Magnolia has no independent operations, assets, or liabilities. 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. Stockholders’ Equity

Stockholders’ Equity (Successor)

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, 2018, there were 156.3 million shares of Class A Common Stock issued and outstanding. 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 shareholders agreement. 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 Company’s common stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the common stock.

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, 2018, there were 93.3 million shares of Class B Common Stock issued and outstanding. Holders of Class B Common Stock will 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 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 Company’s common stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the common stock.

Warrants

As of December 31, 2018, the Company had 31.7 million warrants outstanding, consisting of 21.7 million public warrants originally sold as part of the units sold in the initial public offering (the “IPO”) of TPG Pace Energy Holdings Corp., a Delaware corporation that later became Magnolia after the completion of the Business Combination, and 10.0 million warrants (the “Private Placement Warrants”) sold in a private placement concurrently with the IPO to the TPG Pace Energy Sponsor LLC, a Delaware limited liability company (the “Sponsor”). Each whole warrant entitles the holder to purchase one whole share of Class A Common Stock for $11.50 per share. The warrants became exercisable on August 30, 2018 and will expire on July 31, 2023 or earlier upon redemption or liquidation. The Company may redeem the outstanding warrants at a price of $0.01 per existing warrant, if the last sale price of Magnolia’s Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within a 30 trading day period ending on the third business day before Magnolia sends the notice of redemption to the warrant holders. The Private Placement Warrants, however, are non-redeemable so long as they are held by the Sponsor or its permitted transferees.

F-27

Noncontrolling Interest

The noncontrolling interest relates 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, exercise of warrants and conversion of Class B Common Stock to Class A Common Stock. As of December 31, 2018, the Company owned approximately 62.6% of the interest in Magnolia LLC and the noncontrolling interest was 37.4%. Net income attributable to Class A Common Stock for the Successor Period includes one-time transaction costs of $24.3 million incurred in connection with Business Combination as well as all of the federal income tax expense of $10.4 million.

11. 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, and as of December 31, 2018, the Company had 10.5 million shares of Class A Common Stock available for future grants. The Company granted employees stock based compensation awards in the form of restricted stock units (“RSUs”) and performance stock units (“PSUs”) 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 common shares.

Stock based compensation expense is recognized within general and administrative expense on the consolidated statement of operations. 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. 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 granted. RSUs are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to vesting of the award. The Company granted RSU awards with respect to 807,431 shares during the period October 8, 2018 through December 31, 2018. 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, the vesting period, for each separately vesting portion of the award, as if the award was, in-substance, multiple awards. Weighted average grant date fair value for RSUs granted was $13.97 per share for the year ended December 31, 2018. None of the RSUs issued by the Company have vested for the year ended December 31, 2018. Unrecognized compensation expense related to unvested restricted shares at December 31, 2018 was $10.2 million, which the Company expected to recognize over a weighted average period of 1.6 years.

Performance Stock Units

For the year ended December 31, 2018, the Company awarded PSUs to certain of its employees under the Plan that are subject to market-based vesting criteria as well as a three-year service period. The performance period covered by the PSU agreements is August 1, 2018 through July 31, 2021. On October 8, 2018, the Company granted PSUs with respect to 316,875 shares of Class A Common Stock. Once the performance condition was met, the Company granted additional PSUs with respect to 158,438 shares of Class A Common Stock. Since a service condition is still required in order for the PSUs to fully vest, the PSUs will be accounted for using the same approach as the Company’s RSUs and will be expensed ratably over the requisite service period, which mirrors the vesting period. Total outstanding PSUs with respect to 475,313 shares of Class A Common Stock are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient is no longer an employee of the Company for any reason prior to vesting of the award. Compensation expense for the PSU 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, the vesting period, for each separately vesting portion of the award, as if the award was, in-substance, multiple awards. Weighted average grant date fair value for PSUs granted was $14.58 per share for the year ended December 31, 2018. None of the PSUs issued by the Company have vested for the year ended December 31, 2018. Unrecognized compensation expense related to unvested PSUs at December 31, 2018 was $6.2 million, which the Company expected to recognize over a weighted average period of 2.2 years.

F-28

12. 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 periods as the Predecessor was not previously accounted for as a standalone legal entity and did not have publicly traded shares.



	Successor
(in thousands)	July 31, 2018 through December 31, 2018
Basic:
Net Income attributable to Class A Common Stock	$	39,095
Weighted average number of common shares outstanding during the period	154,527
Net income per common share - basic	$	0.25

Diluted:
Net Income attributable to Class A Common Stock	$	39,095
Basic weighted average number of common shares outstanding during the period	154,527
Add: Dilutive effect of warrants and stock based compensation	3,705
Diluted weighted average number of common shares outstanding during the period	158,232
Net income per common share - diluted	$	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. For the period presented, the Company excluded 90.9 million shares of Class A Common Stock issuable upon conversion of the Company’s Class B Common Stock (and the corresponding Magnolia LLC Units) as the effect was anti-dilutive.

13. Related Party Transactions

As of December 31, 2018, 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 entities which are part of the Karnes County Contributors group as defined in Note 1 - Description of Business and Basis of Presentation, 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 became 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 the Karnes County Contributors, the Sponsor, 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 hold as of July 31, 2018 and that they may acquire thereafter, including upon conversion, exchange or redemption of any other security therefor. Under the New 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.

On August 10, 2018, the Company filed a Registration Statement on Form S-3 (subsequently amended by Amendment No. 1 on August 28, 2018, the “Registration Statement”) to register the Private Placement Warrants and shares of the Company’s Class A Common Stock, including all of shares of Class A Common Stock held by Holders as of July 31, 2018. The Registration Statement was declared effective by the Securities and Exchange Commission on August 30, 2018.

On December 21, 2018, Sponsor completed a distribution of shares of the Company’s common stock and warrants (the “Distribution”) by Sponsor to TPG Pace Energy Sponsor Successor, LLC (“Sponsor Successor”) and certain other of its members, including Stephen Chazen and Michael MacDougall (the “Specified Members”). Related to that Distribution, on February 25, 2019, the Company entered into the First Amendment to the Registration Rights Agreement, with Sponsor Successor and the Specified Members, pursuant to which Sponsor Successor would become a party to the Registration Rights Agreement with the same rights and obligations

F-29

that Sponsor had under the Registration Rights Agreement. The Specified Members were also provided with certain rights and obligations that were a subset of the rights Sponsor had under the Registration Rights Agreement prior to the Distribution.

Stockholder Agreement

On the Closing Date, the Company, Sponsor, and the Karnes County Contributors entered into the Stockholder Agreement (the “Stockholder Agreement”). Under the Stockholder Agreement, the Karnes County Contributors were 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 owned 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). Sponsor is entitled to nominate two directors for appointment to the Board so long as it owns at least 60% of the voting common stock that it owns at the Closing Date (including any shares of common stock issuable upon the exercise of any Private Placement Warrants held by Sponsor), and one director so long as it owns at least 25% of the voting common stock that it owns at the Closing Date (including any shares of common stock issuable upon the exercise of any Private Placement Warrants held by Sponsor). The Karnes County Contributors and Sponsor are each entitled to appoint one director to each committee of the Board (subject to applicable laws and stock exchange rules).

Contingent Consideration

Pursuant to the Karnes County Contribution Agreement, for a period of five years following the Closing Date, the Company agreed to issue to the Karnes County Contributors up to 13.0 million additional shares of the Company’s stock 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 for all three tranches as defined in the Karnes County Contribution Agreement and 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.

Predecessor Transactions

EnerVest, as managing general partner of the Karnes County Contributors, provides 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 have been 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 period of January 1, 2018 through July 30, 2018, $17.2 million for the year ended December 31, 2017, and $9.6 million for the year ended December 31, 2016.

The Karnes County Contributors also entered into operating agreements with EnerVest Operating, LLC (“EVOC”), a wholly-owned subsidiary of EnerVest, 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 is charged or received by EVOC). These costs are included in “Lease operating expenses” in the combined statements of operations in the Predecessor Period. Additionally, in its role as contract operator, EVOC also collected proceeds from oil, natural gas and natural gas liquids sales and distributed them to the Predecessor and other working interest owners. Accounts receivable from EVOC and other related parties was $13.7 million at December 31, 2017.

14. 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 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 discovery 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. In the Successor Period, the Company does not believe the outcome of any such disputes or legal actions will have a material effect on its financial statements. No amounts were accrued with respect to outstanding litigation at December 31, 2018 or December 31, 2017.

F-30

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, 2018, contractual obligations for long-term operating leases and purchase obligations are as follows:



Net Minimum Commitments⁽⁴⁾ (in thousands)	Total		2019-2020		2021-2022		2023 & Beyond
Purchase obligations ⁽¹⁾	$	4,821	$	4,317	$	263	$	241
Operating lease obligations ⁽²⁾	1,817		1,527		213		77
Service fee commitment ⁽³⁾	37,309		37,309		—		—
Total Net Minimum Commitments	$	43,947	$	43,153	$	476	$	318

(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, natural gas throughput agreements, and frac sand commitments. The costs incurred under these obligations were $5.3 million, $0.5 million, and $0.5 million for the 2018 Predecessor Period, the 2017 Predecessor Period, and 2016 Predecessor Period, respectively.


(2)	Amounts include long-term lease payments for compressors, vehicles and office space.

(3)

On the Closing Date, the Company and EVOC entered into a Services Agreement (the “Services Agreement”), pursuant to which EVOC, under the direction of the Company’s management, provides the Company services identical to the services historically provided by EVOC in operating the Acquired Assets, including administrative, back office and day-to-day field-level services reasonably necessary to operate the business of the Company and its assets, subject to certain exceptions. As consideration for the services provided under the Services Agreement, the Company pays EVOC a fixed annual service fee of approximately $23.6 million. The annual service 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 five years, but the Services Agreement is subject to termination by either party after two years.


(4)	For the Successor Period, the costs incurred under these obligations were $15.7 million.

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.

15. Major Customers

Successor

For the 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 period from January 1, 2018 to July 30, 2018, three customers accounted for 47.6%, 14.5% and 12.2% respectively, of the combined oil, natural gas and natural gas liquids revenues. In 2017, 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. In 2016, four customers accounted for 35.8%, 19.5%, 17.0%, and 14.4% respectively, of the combined oil, natural gas and natural gas liquids revenues.

F-31

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			Predecessor
	December 31, 2018			December 31, 2017
(in thousands)
Proved properties	$	2,054,285		$	1,654,988
Unproved properties	1,196,457			76,708
Total proved and unproved properties	3,250,742			1,731,696
Accumulated depreciation, depletion and amortization	(177,897		)	(166,159		)
Net capitalized costs	$	3,072,845		$	1,565,537

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
	July 31, 2018 through December 31, 2018		January 1, 2018 through July 30, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
(in thousands)
Acquisition costs:
Proved properties	$	1,617,131	$	118,572	$	57,263	$	1,076,863
Unproved properties	1,400,302		22,802		1,552		146,658
Exploration and development costs	245,017		183,130		251,454		88,931
Total	$	3,262,450	$	324,504	$	310,269	$	1,312,452

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 Securities and Exchange Commission (“SEC”) rules for oil and natural gas reporting reserves estimation and disclosure.

Estimates of the Company’s proved oil and natural gas reserves at December 31, 2018 were prepared by Cawley, Gillespie & Associates. 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.

F-32

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 periods from July 31, 2018 through December 31, 2018 (Successor), January 1, 2018 through July 30, 2018 (Predecessor), and for the years ended December 31, 2017 and 2016. 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
	July 31, 2018 through December 31, 2018		January 1, 2018 through July 30, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016

Oil (per Bbl)	$	67.61	$	63.37	$	51.34	$	42.75
Gas (per Mcf)	2.78		2.84		2.98		2.48
NGLs (per Bbl)	26.25		23.74		27.32		21.63

F-33

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 the vast majority of the Successor’s proved undeveloped reserves are planned to be developed within one year.



	Successor								Predecessor
	July 31, 2018 through December 31, 2018								January 1, 2018, through July 30, 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	44.2		136.8		17.4		84.3		91.7		148.2		21.4		137.8
Extensions and discoveries	12.9		25.6		3.8		21.0		3.9		8.7		1.3		6.7
Revisions of previous estimates	(4.9	)	2.6		(1.4	)	(5.9	)	(14.5	)	(22.2	)	(2.7	)	(20.9	)
Purchases of reserves in place	3.5		25.2		2.7		10.4		6.1		7.9		1.2		8.6
Production	(5.1	)	(14.1	)	(1.9	)	(9.3	)	(5.8	)	(7.6	)	(1.1	)	(8.2	)
End of period	50.6		176.1		20.6		100.5		81.4		135.0		20.1		124.0

Proved developed reserves:
Beginning of period	34.3		117.8		14.4		68.3		28.0		52.3		7.5		44.2
End of period	35.2		149.0		16.5		76.5		29.5		57.1		8.5		47.5
Proved undeveloped reserves:
Beginning of period	9.9		19.0		3.0		16.1		63.7		95.9		13.9		93.6
End of period	15.4		27.1		4.1		24.0		51.9		77.9		11.6		76.5

	Predecessor
	Year Ended December 31, 2017								Year Ended December 31, 2016
	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	87.2		165.3		23.4		138.2		5.1		4.9		0.8		6.7
Extensions and discoveries	27.6		53.4		7.6		44.1		7.3		20.2		2.9		13.6
Revisions of previous estimates	(20.3	)	(69.6	)	(9.5	)	(41.4	)	1.3		49.0		6.6		16.1
Purchases of reserves in place	4.4		7.7		1.2		6.8		75.8		94.1		13.5		105.0
Production	(7.2	)	(8.6	)	(1.3	)	(9.9	)	(2.3	)	(2.9	)	(0.4	)	(3.2	)
End of period	91.7		148.2		21.4		137.8		87.2		165.3		23.4		138.2

Proved developed reserves:
Beginning of period	21.1		46.8		6.6		35.4		1.5		1.4		0.2		2.0
End of period	28.0		52.3		7.5		44.2		21.1		46.8		6.6		35.4
Proved undeveloped reserves:
Beginning of period	66.1		118.5		16.8		102.8		3.6		3.5		0.6		4.7
End of period	63.7		95.9		13.9		93.6		66.1		118.5		16.8		102.8

For the Successor Period, extensions and discoveries contributed 21.0 MMboe primarily due to additions from successful drilling and completion activity and continual refinement of the development program. Additionally, the Successor had net negative revisions of 5.9 MMboe primarily due to performance based revisions. The Successor 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,

F-34

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 Subsequent 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 and 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.

For the year ended December 31, 2016, the Predecessor added 105.0 MMboe related to the acquisitions of proved reserves in the Eagle Ford Shale and 13.6 MMboe of extensions and discoveries resulting from successful drilling and completion activities.

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 Predecessor’s 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. 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
	July 31, 2018 through December 31, 2018			January 1, 2018 through July 30, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
(in thousands)
Future cash inflows	$	4,451,628		$	6,020,768		$	5,410,210		$	4,048,481
Future production costs	(1,463,023		)	(1,773,608		)	(1,510,903		)	(1,202,153		)
Future development costs	(260,057)			(835,632)			(1,009,922)			(800,257)
Future income tax expenses	(96,311		)	(31,609		)	(28,404		)	(21,255		)
Future net cash flows	2,632,237			3,379,919			2,860,981			2,024,816
10% discount to reflect timing of cash flows	(754,709		)	(1,122,055		)	(1,096,819		)	(774,263		)
Standardized measure of discounted future net cash flows	$	1,877,528		$	2,257,864		$	1,764,162		$	1,250,553

F-35

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



	Successor			Predecessor
(in thousands)	July 31, 2018 through December 31, 2018			January 1, 2018 through July 30, 2018
Standardized measure of discounted future net cash flows, beginning of period	$	1,457,656		$	1,764,162
Sales of oil, natural gas and NGLs produced during the period	(364,850		)	(388,982		)
Purchases of minerals in place	141,585			150,622
Extensions, discoveries, and improved recovery	429,295			125,067
Changes in estimated future development costs	1,372			(39,154		)
Net change in prices and production costs	223,177			552,761
Development costs incurred during the period	98,407			144,273
Revisions in quantity estimates	(87,852		)	(201,417		)
Accretion of discount	61,237			103,931
Net change in income taxes	(65,004		)	(2,817		)
Net change in timing of production and other	(17,495		)	49,418
Standardized measure of discounted future net cash flows, end of period	$	1,877,528		$	2,257,864


	Predecessor
	Year Ended December 31,
(in thousands)	2017			2016
Standardized measure of discounted future net cash flows, beginning of period	$	1,250,553		$	67,339
Sales of oil, natural gas and NGLs produced during the period	(339,222		)	(87,355		)
Purchases of minerals in place	71,822			742,104
Extensions, discoveries, and improved recovery	565,171			126,010
Development costs incurred during the period	234,100			72,989
Net change in prices and production costs	668,850			112,246
Changes in estimated future development costs	(11,136		)	143,836
Revisions in quantity estimates	(797,957		)	78,911
Accretion of discount	126,368			6,813
Net change in income taxes	(4,387		)	(12,340		)
Standardized measure of discounted future net cash flows, end of period	$	1,764,162		$	1,250,553

Selected Quarterly Financial Data (Unaudited)



	Predecessor								Successor
(in thousands)	January 1, 2018 through March 31, 2018			April 1, 2018 through June 30, 2018			July 1, 2018 through July 30, 2018		July 31, 2018 through September 30, 2018			October 1, 2018 through 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
Net income attributed to noncontrolling interest	—			—			—		18,466			24,887
NET INCOME ATTRIBUTABLE TO CLASS A COMMON STOCK	$	85,366		$	86,449		$	46,738	$	6,174		$	32,921
Income per share:
Basic									$	0.04		$	0.21
Diluted									$	0.04		$	0.21

F-36



	Predecessor
	Quarters Ended
(in thousands)	March 31, 2017		June 30, 2017		September 30, 2017			December 31, 2017

Revenues	$	99,006	$	92,595	$	86,615		$	124,978
Operating expenses	46,209		57,366		48,248			61,360
Operating income	52,797		35,229		38,367			63,618
Other income (expense)	1,296		1,372		(1,732		)	(9,332		)
Income tax expense	797		540		630			774
Net income	$	53,296	$	36,061	$	36,005		$	53,512

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

Magnolia had no changes in, and no disagreements with, Magnolia’s accountants on accounting and financial disclosure.

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.

As discussed elsewhere in this Annual Report on Form 10-K, the Company completed the Business Combination on July 31, 2018 pursuant to which Magnolia obtained the Acquired Assets. Prior to the Business Combination, Magnolia was a special purpose acquisition company formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization, or other similar Business Combination with one or more target businesses. As a result, previously existing internal controls are no longer applicable or comprehensive enough as of the assessment date as the Company’s operations prior to the Business Combination were insignificant compared to those of the consolidated entity post-Business Combination. The design and implementation of internal controls over financial reporting for the Company’s post-Business Combination has required and will continue to require significant time and resources from management and other personnel. Because of this, the design and ongoing development of Magnolia’s framework for implementation and evaluation of internal control over financial reporting is in its preliminary stages. As a result, management was unable, without incurring unreasonable effort or expense, to conduct an assessment of Magnolia’s internal controls over financial reporting as of December 31, 2018. Accordingly, the Company is excluding management’s report on internal control over financial reporting pursuant to Section 215.02 of the SEC Division of Corporation Finance’s Regulation S-K Compliance & Disclosure Interpretations.

Changes in Internal Control Over Financial Reporting

As of December 31, 2018, the Company completed the Business Combination and is engaged in the process of the design and implementation of Magnolia’s internal controls over financial reporting in a manner commensurate with the scale of Magnolia’s operations post-Business Combination.

F-37

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 and Combined Balance Sheets as of December 31, 2018 and 2017		F-3
Consolidated and Combined Statements of Operations for the periods July 31, 2018 through December 31, 2018 and January 1, 2018 through July 30, 2018, the year ended December 31, 2017, and the year ended December 31, 2016		F-4
Combined Statement of Changes in Parents’ Net Investment for the years ended December 31, 2016, December 31, 2017, and December 31, 2018		F-5
Consolidated and Combined Statements of Changes in Stockholders’ Equity for the period July 30, 2018 through December 31, 2018		F-6
Consolidated and Combined Statements of Cash Flows for the periods July 31, 2018 through December 31, 2018 and January 1, 2018 through July 30, 2018, the year ended December 31, 2017, and the year ended December 31, 2016		F-7
Notes to Consolidated and Combined Financial Statements for the periods July 31, 2018 through December 31, 2018 and January 1, 2018 through July 30, 2018, the year ended December 31, 2017, and the year ended December 31, 2016		F-9

(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

F-38



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)).

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*		Specimen Warrants Certificate (incorporated herein by reference to Exhibit 4.3 filed with the Registration Statement on Form S-1 filed on April 17, 2017 (File No. 333-217338)).

4.3*		Warrant Agreement, dated as of May 4, 2017, between the Company and Continental Stock Transfer & Trust Company, as warrant agent (incorporated herein by reference to Exhibit 4.4 filed with the Current Report on Form 8-K filed on May 10, 2017 (File No. 001-38083)).

4.4*		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)).

4.5*		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)).

4.6**		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.

4.7*		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)).

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Exhibit Number		Description
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, 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, 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, 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, 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, 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, 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)).

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, filed on August 6, 2018 (File No. 001-38083)).

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 Cawley, Gillespie & Associates, Inc.

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***		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

F-40



Exhibit Number		Description
32.2***		Certification of Chief Financial Officer 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 Cawley, Gillespie & Associates, dated as of January 28, 2019, for proved reserves as of December 31, 2018.

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


*	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 supplementally to the SEC upon request.


††	Management contract or 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 27, 2019	By:	/s/ Stephen Chazen
		Stephen Chazen
		Chief Executive Officer (Principal Executive Officer)

F-41

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 27, 2019

/s/ Christopher Stavros Christopher Stavros	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	February 27, 2019


/s/ Arcilia Acosta* Arcilia Acosta	Director	February 27, 2019

/s/ Edward Djerejian* Edward Djerejian	Director	February 27, 2019

/s/ Michael MacDougall* Michael MacDougall	Director	February 27, 2019

/s/ Dan F. Smith* Dan F. Smith	Director	February 27, 2019

/s/ James R. Larson* James R. Larson	Director	February 27, 2019

/s/ John B. Walker* John B. Walker	Director	February 27, 2019

/s/ Angela Busch* Angela Busch	Director	February 27, 2019

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

F-42